SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For fiscal year ended December 31, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
<TABLE>
<CAPTION>
Registrant; State of
Incorporation or I.R.S. Employer
Commission Organization; Address; Identification
File Number and Telephone Number Number
- ------------ ---------------------- ---------------
<S> <C> <C>
1-6564 NEW ENGLAND POWER COMPANY 04-1663070
(A Massachusetts corporation)
25 Research Drive
Westborough, Massachusetts 01582
Telephone: 508-389-2000
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements
for the past 90 days.
(X) Yes ( ) No
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. (X)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Aggregate market value
of the voting stock Number of shares of
held by nonaffiliates common stock outstanding
of the registrant at of the registrant at
March 15, 2000 March 15, 2000
---------------------- ------------------------
<S> <C> <C>
New England $1,285,104 3,619,896($20 par value)
Power Company
Documents Incorporated by Reference
</TABLE>
<TABLE>
<CAPTION>
Part of Form 10-K into which
Description document is incorporated
- ---------------------------------- ----------------------------
<S> <C>
Portions of New England Power Company Parts I and II
Annual Report to Shareholders for the
year ended December 31, 1999 as set
forth in Parts I and II
</TABLE>
<PAGE>
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS.......................................... iii
FORWARD LOOKING INFORMATION................................ v
PART I
ITEM 1. BUSINESS............................................ 1
THE COMPANY................................................. 1
Merger Agreement with National Grid ................... 1
Employees.............................................. 2
ELECTRIC UTILITY OPERATIONS................................. 2
Industry Restructuring................................. 2
Accounting Implications............................. 2
Overview of Financial Results....................... 2
Year 2000 Disclosure................................... 2
Eastern Utilities Associates Merger.................... 2
Transmission and Nuclear Generation Business........... 3
Description of Business............................. 3
Rates............................................... 3
Standard Offer Service.............................. 5
Operating Revenues.................................. 6
Electric Utility Properties............................ 7
Transmission Properties............................. 7
Interconnection with Quebec ........................ 8
Nuclear Generation Properties....................... 8
Nuclear Units..................................... 9
Purchased Power Transfer Agreement................ 14
Regulatory and Environmental Matters................... 15
Regulation.......................................... 15
Environmental Requirements.......................... 15
Construction and Financing............................. 16
EXECUTIVE OFFICERS.......................................... 19
ITEM 2. PROPERTIES.......................................... 20
ITEM 3. LEGAL PROCEEDINGS................................... 20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS................................................ 21
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDER MATTERS........................ 21
ITEM 6. SELECTED FINANCIAL DATA............................. 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................... 22
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................ 22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......... 22
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................... 22
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT............................................. 22
ITEM 11. EXECUTIVE COMPENSATION............................ 24
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT......................................... 33
PART IV
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.... 33
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K.................. 33
INDEX TO FINANCIAL STATEMENTS............................... 44
<PAGE>
GLOSSARY OF TERMS
Term Meaning
---- -------
AFDC allowance for funds used during
construction
Connecticut Yankee Connecticut Yankee Atomic Power Company
CTC contract termination charges
DOE U.S. Department of Energy
EUA Eastern Utilities Associates
Electricity Delivery Mass. Electric, Narragansett, Granite
Companies State, and Nantucket
FERC Federal Energy Regulatory Commission
Granite State Granite State Electric Company
Interconnection transmission interconnection between
participating New England utilities
and Hydro-Quebec
ISO Independent System Operator
kWh kilowatthour
Maine Yankee Maine Yankee Atomic Power Company
Mass. Electric Massachusetts Electric Company
Mass. Hydro New England Hydro-Transmission Electric
Company, Inc.
MDTE Massachusetts Department of
Telecommunications and Energy
MW megawatts
Nantucket Nantucket Electric Company
Narragansett The Narragansett Electric Company
National Grid The National Grid Group plc
National Grid USA Successor to NEES and a wholly-owned
subsidiary of The National Grid Group plc
N.E. Hydro Finance New England Hydro Finance Company, Inc.
NEEI New England Energy Incorporated
NEES New England Electric System (renamed
National Grid USA)
NEES Energy NEES Energy, Inc.
NEET New England Electric Transmission
Corporation
NEP New England Power Company
NEPOOL New England Power Pool
N.H. Hydro New England Hydro-Transmission
Corporation
NRC Nuclear Regulatory Commission
PG&E Gen PG&E Generating, formerly USGen New
England, Inc.
GLOSSARY OF TERMS
Term Meaning
---- -------
Research Drive Research Drive LLC
Seabrook 1 Seabrook Nuclear Generating Station
Unit 1
SEC Securities and Exchange Commission
Sellers NEP and Narragansett
Service Company New England Power Service Company
spent nuclear fuel high level radioactive waste
stranded costs the amounts by which prudently
incurred costs incurred to supply
customers electricity under a
regulated industry structure
exceed market prices under an
unregulated industry structure
Vermont Yankee Vermont Yankee Nuclear Power
Corporation
VPSB Vermont Public Service Board
Yankee Atomic Yankee Atomic Electric Company
Yankee Companies Yankee Atomic, Vermont Yankee,
Maine Yankee, and Connecticut
Yankee
1935 Act Public Utility Holding Company Act
of 1935, as amended
<PAGE>
FORWARD LOOKING INFORMATION
This report and other presentations made by New England Power
Company (NEP or the Company) contain forward looking statements
within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended. Throughout this report, forward looking
statements can be identified by the words or phrases "will likely
result", "are expected to", "will continue", "is anticipated",
"estimated", "projected", "believe", "hopes", or similar
expressions. Although NEP believes that, in making any such
statements, its expectations are based on reasonable assumptions,
any such statements may be influenced by factors that could cause
actual outcomes and results to be materially different from those
projected. Important factors that could cause actual results to
differ materially from those in the forward looking statements
include, but are not limited to:
(a) the impact of ongoing industry restructuring, as more
fully set out in the Industry Restructuring section of the 1999 NEP
Annual Report;
(b) timing and nature of SEC action on the proposed merger of
National Grid USA with Eastern Utilities Associates (EUA) as more
fully set out below under EASTERN UTILITIES ASSOCIATES MERGER, PAGE
2;
(c) the impact of general economic changes in New England;
(d) federal and state regulatory developments and changes in
law which may have a substantial adverse impact on the value of
NEP's assets;
(e) changes in accounting rules and interpretations which may
have an adverse impact on NEP's statements of financial position
and reported earnings;
(f) timing and adequacy of rate relief;
(g) adverse changes in electric load;
(h) climatic changes or unexpected changes in weather
patterns; and
(i) operation and decommissioning costs associated with
nuclear generating facilities, as set out under Nuclear Units
below, page 9.
PART I
ITEM 1. BUSINESS
THE COMPANY
Merger Agreement with National Grid
On March 22, 2000, the merger of New England Electric System (NEES) and The
National Grid Group plc (National Grid) was completed, with NEES (renamed
National Grid USA) becoming a wholly owned subsidiary of National Grid. New
England Power Company (NEP) will maintain its existing name and will remain a
wholly owned subsidiary of National Grid USA.
<TABLE>
<CAPTION>
New England Power Company, a wholly owned subsidiary of National Grid USA
(formerly New England Electric System), is a Massachusetts corporation qualified
to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. NEP is subject, for certain purposes, to the jurisdiction of the
regulatory commissions of these six states, the Securities and Exchange
Commission, under the Public Utility Holding Company Act of 1935 (the 1935 Act),
the Federal Energy Regulatory Commission, and the Nuclear Regulatory Commission.
NEP's business is primarily the transmission of electric energy in wholesale
quantities to other electric utilities, principally its distribution affiliates
Granite State Electric Company, Massachusetts Electric Company, Nantucket
Electric Company, and The Narragansett Electric Company. NEP's transmission
business will also do business under the name of National Grid Transmission USA.
Holders of common stock and 6% Cumulative Preferred Stock have general voting
rights. National Grid USA owns 99.57% of the voting stock of NEP and the NEP 6%
preferred holders own 0.43%. NEP owns voting stock in the amounts indicated of
the following companies:
% Voting
Securities
State of Type of Owned by
Name of Company Organization Business NEP
--------------- ------------ -------- ---------
<S> <C> <C> <C>
Connecticut Yankee Atomic Conn. Ownership of 15%
Power Company Nuclear Unit (a)
Maine Yankee Atomic Maine Ownership of 20%
Power Company Nuclear Unit (a)
Vermont Yankee Nuclear Vermont Ownership of 20%
Power Corporation Nuclear Unit (a)
Yankee Atomic Electric Company Mass. Ownership of 30%
Nuclear Unit (a)
</TABLE>
<PAGE>
(a) For information on NEP's ownership interest in nuclear
generating units, see Nuclear Units, page 9.
The facilities of NEP, together with National Grid USA's four
electricity delivery companies, Massachusetts Electric Company
(Mass. Electric), The Narragansett Electric Company (Narragansett),
Granite State Electric Company (Granite State), and Nantucket
Electric Company (Nantucket), (together, the Electric Delivery
Companies) constitute an electrical transmission and distribution
system that is directly interconnected with other utilities in New
England and New York State, and indirectly interconnected with
utilities in Canada. See ELECTRIC UTILITY OPERATIONS, page 2.
EMPLOYEES
At December 31, 1999, NEP had 83 employees, approximately 17
are members of labor organizations. Collective bargaining
agreements with the Brotherhood of Utility Workers of New England,
Inc., the International Brotherhood of Electrical Workers, and the
Utility Workers Union of America, AFL-CIO expire in May, 2004.
ELECTRIC UTILITY OPERATIONS
INDUSTRY RESTRUCTURING
For a full discussion of Industry Restructuring see the
Industry Restructuring section of the 1999 NEP Annual Report,
incorporated herein by reference.
Accounting Implications
For a full discussion of Accounting Implications see the
Accounting Implications section of the 1999 NEP Annual Report,
incorporated herein by reference.
Overview of Financial Results
For a full discussion of Overview of Financial Results see the
Overview of Financial Results section of the 1999 NEP Annual
Report, incorporated herein by reference.
YEAR 2000 DISCLOSURE
For a full discussion of Year 2000 disclosure, see the Year
2000 Disclosure section of the 1999 NEP Annual Report, incorporated
herein by reference.
<PAGE>
EASTERN UTILITIES ASSOCIATES MERGER
In February 1999, NEES, Eastern Utilities Associates (EUA),
and Research Drive LLC (Research Drive), a wholly owned
subsidiary of NEES, entered into an Agreement and Plan of Merger
(EUA Agreement). Pursuant to the EUA Agreement, Research Drive
will merge with and into EUA, with EUA becoming a wholly owned
subsidiary of National Grid USA.
The acquisition of EUA has received approval or support from
EUA shareholders, the Federal Trade Commission (FTC), the Federal
Energy Regulatory Commission (FERC), the Nuclear Regulatory
Commission (NRC), the Connecticut Department of Public Utility
Control, the Rhode Island Public Utilities Commission, and the
Massachusetts Department of Telecommunications and Energy (MDTE),
and the Vermont Public Service Board (VPSB). An application has
also been filed for approval with the Securities and Exchange
Commission (SEC), under the 1935 Act. The acquisition of EUA,
including the consolidation of Montaup Electric Company (Montaup
Electric ), a wholly owned subsidiary of EUA, into NEP, is
expected to be completed following the receipt of an SEC order
approving the acquisition, which could come at any time. If the
SEC order is not received in time to close the transaction by
April 28, 2000, the approval by the FTC, under the Hart-Scott-
Rodino Antitrust Improvements Act of 1976, as amended, expires
and will have to be renewed prior to completion of the
acquisition.
TRANSMISSION AND NUCLEAR GENERATION BUSINESS
Description of Business
On September 1, 1998, NEP completed the sale of substantially
all of its nonnuclear generating business to PG&E Generating
(PG&E Gen) an indirect wholly-owned subsidiary of PG&E
Corporation. NEP's primary business is now the transmission of
electric energy to other electric utilities, principally its
distribution affiliates, the Electricity Delivery Companies. NEP
owns a system of transmission lines and substations. NEP
continues to own minority interests in two joint owned nuclear
generating units as well as minority equity interests in four
nuclear generating companies (see Nuclear Units, page 9).
<PAGE>
Rates
From January 1995 to March 1998, NEP collected the majority
of its generation and transmission revenues pursuant to the rates
under Tariff No. 1 established in the FERC approved W-95
settlement agreement, including the revenues from the Electricity
Delivery Companies. Under Tariff No. 1, NEP was obligated to
sell to its customers, and its customers were obligated to
purchase from NEP, the requirements of their respective retail
service territories, and they could only terminate those mutual
obligations upon seven years' notice. In addition, NEP
established an open access transmission Tariff No. 9 applicable
to non-Tariff No. 1 customers in July 1996. NEP continues to
serve a small number of non-affiliated customers pursuant to
Tariff No. 1.
Under the settlement agreements between NEP and the
Electricity Delivery Companies implemented in 1997 and 1998, an
amendment to the Tariff No. 1 service agreement reformed the
contractual relationship to allow for the early termination of
the Electricity Delivery Companies' obligation to purchase
wholesale all-requirements service from NEP, in consideration for
the payment of contract termination charges. The Electricity
Delivery Companies are recovering contract termination charges
through a transition access charge (see the Industry
Restructuring section of the 1999 NEP Annual Report). NEP has
also reached similar agreements with three unaffiliated
wholesale customers. In addition, one unaffiliated wholesale
customer has terminated service under Tariff No. 1. NEP has
obtained FERC approval to collect the associated stranded costs.
These agreements amend the provisions of Tariff No. 1 and allow
for the provision of unbundled service by NEP. See Legal
Proceedings, Page 20.
NEP's unbundled rates consist of contract termination
charges, transmission charges, standard offer charges where
applicable, and market revenues where applicable. The Contract
Termination Charges (CTC) rate was originally set at 2.8 cents
per kilowatthour (kWh), and subsequently reduced to approximately
1.5 cents or less per kWh upon completion of the sale of NEP's
nonnuclear generating business (see the Industry Restructuring
section of the 1999 NEP Annual Report). The transmission rate
pursuant to the open access Tariff No. 9 is a formula rate which
recovers NEP's actual costs plus a return on actual capital
investment and equals approximately 0.5 cents per kWh. This
includes the transmission element of the New England Power Pool
(NEPOOL) Tariff charges as well as Tariff No. 9. The standard
offer revenues equaled 3.5 cents per kWh in 1999 and equals 3.8
cents in 2000 and, with respect to NEP's continuing obligation to
supply standard offer service to Narragansett, the rate will
escalate in the years thereafter. Revenues from sale in the
marketplace will vary.
<PAGE>
In March 2000, the MDTE approved the merger of Montaup
Electric into NEP, which is contingent upon the approval of the
pending acquisition of EUA. Under a rate consolidation plan
accepted by the FERC in September 1999, upon National Grid USA's
acquisition of EUA, Montaup Electric's open access transmission
tariffs will adopt the same terms and conditions for service as
those contained in NEP's tariffs. Upon the merger of Montaup
Electric into NEP, the combined company will charge a single
system transmission tariff based upon its total transmission
costs. The CTC rates for the companies will not initially be
combined.
The electric utility business of NEP is not highly seasonal.
In 1999, 47% of NEP's total transmission billings was derived
from affiliated companies, and 53% was from municipal and other
utilities. In addition, NEP's distribution affiliates are
responsible for 98% of NEP's revenues associated with stranded
cost recovery.
Standard Offer Service
Prior to divesting its nonnuclear generation business, NEP
was the wholesale supplier of the electric energy requirements of
the Electricity Delivery Companies under contracts that required
seven years' notice of termination. NEP's contracts with the
Electricity Delivery Companies were amended to remove the
obligation to sell electrical energy and related products. PG&E
Gen, TransCanada Power Marketing, Ltd. and Constellation Power
Source, Inc. retain the backstop obligation to supply the
electric energy requirements of the Electricity Delivery
Companies for retail customers eligible to continue to buy
standard offer generation service from their electricity delivery
company at regulated prices. NEP remains obligated to provide
transition power supply service at fixed rates to new customer
load in Rhode Island. NEP meets these obligations by
periodically procuring the necessary power supply at market
prices. NEP cannot predict whether the resulting revenues will
be sufficient to cover the costs to procure such power.
<PAGE>
OPERATING REVENUES
The following is the detail of kWh sales and deliveries,
electric sales and other operating revenue, and operating income
for the last three years.
<TABLE>
<CAPTION>
Sales and Deliveries of Electricity
(in thousands of kWh)
------------------------------------
1999 1998 1997
---- ----
<S> <C> <C> <C>
Total Sales
and Deliveries 2,970,433 18,214,193 26,405,204
========== ========== ==========
Operating Revenues
(in thousands of dollars)
------------------------------------
1999 1998 1997
---- ---- ----
Total Electric Sales Revenue 90,639 631,943 1,616,598
Other Operating 505,702 586,397 61,305
Revenue
---------- ---------- ----------
Total Operating
Revenue $596,341 $1,218,340 $1,677,903
========== ========== ==========
Operating Income $78,563 $ 157,362 $ 190,852
========== ========== ==========
</TABLE>
Operating revenue for 1999 decreased $622 million compared
with 1998 due to the divestiture and reduced CTC charges.
<PAGE>
ELECTRIC UTILITY PROPERTIES
Transmission Properties
NEP's integrated system consists of 2,236 circuit miles of
transmission lines, 108 substations with an aggregate capacity of
13,209,382 kVA, and 7 pole or conduit miles of distribution
lines.
The properties of National Grid USA subsidiaries also
include the ownership interests of NEET, Mass. Hydro, and
N.H. Hydro in the Hydro-Quebec Interconnection, and an integrated
system of transmission lines, substations, and distribution
facilities.
NEP is a participant in NEPOOL. The NEPOOL Agreement
provides for coordination of the operation of the generation and
transmission facilities of its members. The NEPOOL Agreement
further provides for New England-wide central dispatch of
generation by the Independent System Operator (ISO).
ISO-New England was activated on July 1, 1997 and has been
operating the control area since that time. It operates under
contract with NEPOOL and is governed by an independent Board of
Directors. NEPOOL's Open Access Transmission Tariff, which
covers service across pool transmission facilities is
administered by ISO-New England.
In May 1999, NEPOOL and ISO-New England commenced
implementation of the NEPOOL competitive market system. The
market system establishes markets for several tradable energy and
reserve products. Implementation of the markets also has
resulted in the imposition of certain costs including congestion
related costs. As ordered by FERC, NEPOOL is currently working
to develop a Congestion Management System and a Multi-Settlement
System.
NEPOOL's governance structure consists of five sectors:
transmission owners, generators, suppliers, public power, and end
users. National Grid USA participates in the transmission owners
sector. As of December 31, 1999, the Transmission sector
accounted for 25 percent of the NEPOOL vote and the National Grid
USA Companies accounted for one-eighth of the Transmission sector
vote. Under NEPOOL's revised governance structure, all National
Grid USA companies are considered "related persons" and therefore
receive only a single vote.
<PAGE>
Interconnection with Quebec
New England Electric Transmission Corporation (NEET) owns
and operates a portion of an international transmission
interconnection between the electric systems of Hydro-Quebec and
New England. New England Hydro-Transmission Electric Company,
Inc. (Mass. Hydro) and New England Hydro-Transmission Corporation
(N.H. Hydro) own and operate facilities in connection with an
expanded second phase of this interconnection. New England Hydro
Finance Company, Inc. (N.E. Hydro Finance) provides the debt
financing to Mass. Hydro and N.H. Hydro for the capital costs of
the interconnection. National Grid USA owns 100% of the voting
stock of NEET and 53.97% of the voting stock of Mass. Hydro and
N.H. Hydro. Mass. Hydro and N.H. Hydro each own 50% of the
voting securities of N.E. Hydro Finance.
NEET, Mass. Hydro, and N.H. Hydro own and operate, on behalf
of NEPOOL participants in the project, a 450 kV direct current
transmission line and related terminals to interconnect the New
England and Quebec transmission systems (the Interconnection).
The transfer capability of the Interconnection is currently rated
at 1,800 MW. Operating limits implemented by adjacent Power
Pools covering New York, New Jersey, Pennsylvania, and Maryland
often restrict the effective transfer capability to levels of
1,200 MW to 1,400 MW.
The Interconnection has two phases. NEP's participation in
both is approximately 18 percent. NEP and the other participants
have entered into support agreements that end in 2020. Under the
support agreements, NEP has agreed to guarantee its share of
debt financing for the second phase. At December 31, 1999, NEP
had guaranteed approximately $21 million of project debt. NEP's
rights and obligations under its support agreements were
transferred to PG&E Gen upon completion of the sale of NEP's
nonnuclear generating business, but NEP remains an obligor in the
event of PG&E Gen nonperformance (see the Industry Restructuring
section of the 1999 NEP Annual Report).
Nuclear Generation Properties
On September 1, 1998, NEP and its affiliate Narragansett,
completed the sale of substantially all of their nonnuclear
generating business to PG&E Gen. NEP also plans to seek offers
to sell its nuclear generating interests. For more information,
on pending sales of Vermont Yankee and Millstone 3, see Nuclear
Units, page 9.
<PAGE>
Nuclear Units
General
NEP has interests in six nuclear units. Three of the units
have been permanently shut down. The remaining three are
currently operating.
NEP is a stockholder of Yankee Atomic Electric Company
(Yankee Atomic), Vermont Yankee Nuclear Power Corporation
(Vermont Yankee), Maine Yankee Atomic Power Company (Maine
Yankee), and Connecticut Yankee Atomic Power Company (Connecticut
Yankee). Each of these companies (collectively referred to as
the Yankee Companies) owns a single nuclear generating unit. The
stockholders of three Yankee Companies (Vermont Yankee, Maine
Yankee, and Connecticut Yankee) have agreed, subject to
regulatory approval, to provide capital requirements in the same
proportion as their ownership percentages of the particular
Yankee Company. NEP also has power contracts with each Yankee
Company that require NEP to pay an amount equal to its share of
total fixed and operating costs (including decommissioning costs)
of the plant plus a return on equity. Yankee Atomic, Connecticut
Yankee, and Maine Yankee have permanently ceased operations. NEP
purchases the output of the Vermont Yankee plant in the same
percentage as its stock ownership, less small entitlements taken
by municipal utilities.
In addition, NEP is a joint owner of the Millstone 3 nuclear
generating unit in Connecticut and the Seabrook Nuclear
Generating Station Unit 1 (Seabrook 1) nuclear generating unit in
New Hampshire. Millstone 3 and Seabrook 1 are operated by
subsidiaries of Northeast Utilities. NEP pays its proportionate
share of costs and receives its proportionate share of output
from Millstone 3 and Seabrook 1. Listed below is certain
information on each nuclear plant in which NEP has an ownership
interest.
Under restructuring settlement agreements approved by
regulators in Massachusetts, New Hampshire and Rhode Island, NEP
has agreed to attempt to divest its nuclear holdings.
In November 1999, the Vermont Yankee Nuclear Power
Corporation entered into an agreement with AmerGen Energy Company
(Amergen), a joint venture between PECO Energy and British
Energy, to sell the assets of Vermont Yankee. Under the terms of
the agreement, after a Vermont Yankee contribution toward the
plant's decommissioning trust fund, AmerGen will take over the
fund and assume responsibility for the actual cost of
decommissioning the plant. The agreement also requires the
existing power purchasers (including NEP) to continue to purchase
the output of the plant or to buy out of the purchased power
<PAGE>
obligation. In November 1999, NEP signed an agreement to buy out
of its obligation, requiring future payments which will be
recovered through NEP's CTC. NEP has recorded an accrued
liability and offsetting regulatory asset of $80 million for its
share of future liabilities related to Vermont Yankee, including
the purchased power contract termination payment obligation, but
excluding interest and a return allowance. The proposed sale is
contingent upon regulatory approvals by the NRC, the SEC, under
the 1935 Act, and the VPSB, among others. NEP has a 20 percent
ownership interest in Vermont Yankee and an equity investment of
approximately $11 million at December 31, 1999.
As part of its restructuring settlement with the State of
New Hampshire, Public Service Company of New Hampshire (PSNH),
through its affiliate North Atlantic Energy Corporation (NAEC),
has committed to sell its interest in Seabrook 1 by the end of
2003. NAEC is the lead owner with a 35.98% interest and the
operator of the plant. Also as a part of that settlement, PSNH
has agreed to endeavor to bundle its interests with those of
other owners seeking to sell their interests. This should allow
for an auction of a majority interest. Action on the PSNH
settlement by the New Hampshire Public Utilities Commission is
expected during the second quarter with subsequent action
required by the New Hampshire legislature by June.
For information on the potential sale of Millstone 3, please
see Legal Proceedings page 20.
Operating Nuclear Units
<TABLE>
<CAPTION>
NEP's Share of
NEP's Net Plant
Ownership Assets
Unit Interest (%) ($ in millions)
---- ------------ ---------------
<S> <C> <C>
Vermont Yankee 20 34
Millstone 3 12 12*
Seabrook 1 10 14*
*See Note C of the 1999 NEP annual report for a discussion of an
impairment writedown and establishment of an offsetting
regulatory asset.
</TABLE>
<PAGE>
Decommissioning Estimates
<TABLE>
<CAPTION>
NEP's share of
($ in millions)
--------------------------------
Estimated Decommissioning
Decommissioning Fund
Costs Balances (1) License
Unit (in 1999 $) (12/31/99) Expiration
---- --------------- --------------- ----------
<S> <C> <C> <C>
Vermont Yankee $86 $42 2012
Millstone 3 $76 $23 2025
Seabrook 1 $56 $13 2026
(1) Certain additional amounts are anticipated to be available
through tax deductions.
</TABLE>
Nuclear Units Permanently Shut Down
<TABLE>
<CAPTION>
NEP's Investment Future Estimated
------------------- Date Billings to NEP
Unit % $(millions) Retired $(millions)
---- --- ----------- ------------ ----------------
<S> <C> <C> <C> <C>
Yankee Atomic 30 5 February 1992 7
Connecticut Yankee 15 16 December 1996 63
Maine Yankee 20 15 August 1997 128
</TABLE>
For a discussion of NEP's investment in both operating and
retired nuclear units, the Millstone 3 unit, nuclear
decommissioning costs and nuclear insurance issues, Note D of the
1999 NEP Annual Report. For information on legal proceedings
related to Millstone 3, see LEGAL PROCEEDINGS, page 20.
High-Level Waste Disposal
The Nuclear Waste Policy Act of 1982 provides a framework
and timetable for selection of sites for repositories of
high-level radioactive waste (spent nuclear fuel) from United
States nuclear plants. The U.S. Department of Energy (DOE) has
entered into contracts with the Yankee Companies, the Millstone 3
joint owners, and the Seabrook 1 joint owners for acceptance of
title to, and transportation and storage of, this waste. Under
these contracts, each operating unit will pay fees to the DOE to
cover the development and creation of waste repositories. Fees
for fuel burned since April 1983 have been collected by the DOE
on an ongoing basis at the rate of one tenth of a cent per kWh of
net generation. Fees for generation up through April 1983 were
determined by the DOE as follows: $13.2 million for Yankee
Atomic, $48.7 million for Connecticut Yankee, $50.4 million for
Maine Yankee, and $39.3 million for Vermont Yankee. Neither
Millstone 3 nor Seabrook 1 has been assessed any fees for fuel
burned through April 1983 because they did not enter commercial
operation until 1986 and 1990, respectively.
The Yankee Companies had several options to pay these fees.
Yankee Atomic paid its fee to the DOE for the period through
April 1983. The other three Yankee Companies elected to defer
payment until a future date, thereby incurring interest expense.
However, payment to the DOE must occur prior to the first
delivery of spent fuel. Connecticut, Maine, and Vermont Yankee
have segregated a portion of their respective DOE obligations in
external accounts. The remainder of the funds have been used to
support general capital requirements. All expect to separately
fund in full in external accounts their DOE obligation (including
accrued interest) prior to payment to the DOE. To the extent
that any of the three Yankee Companies is unable to fully meet
its DOE obligation at the prescribed time, NEP might be required
to provide additional funds.
Prior to such time that the DOE takes delivery of a plant's
spent nuclear fuel, it is stored on site in spent fuel pools.
Millstone 3, Seabrook 1, and Vermont Yankee are in the process of
reconfiguring their spent fuel pools to allow for additional
storage capability. Upon successful completion of the
reconfiguring, Millstone 3 will have sufficient spent fuel pool
capacity to support plant operation through the expiration of its
current NRC license. Seabrook 1's licensed storage capacity will
allow a full core discharge until 2011. Vermont Yankee will be
able to maintain a full core discharge capability until 2004.
Yankee Atomic, Connecticut Yankee and Maine Yankee all have
adequate on-site storage capacity for all their spent fuel.
The Nuclear Waste Policy Act of 1982 establishes that the
federal government (through the DOE)is responsible for the
disposal of spent nuclear fuel. The federal government requires
NEP to pay a fee based on its share of the net generation from
the Millstone 3 and Seabrook 1 nuclear generating units. Prior to
1998, NEP recovered this fee through its fuel clause. Under the
Settlement Agreements, substantially all of these costs are
recovered through CTCs. Similar costs are billed to NEP by
Vermont Yankee and are also recovered from customers through
CTCs. In 1997, ruling on a lawsuit brought against the DOE by
numerous utilities and state regulatory commissions, the U.S.
Court of Appeals for the District of Columbia, held that the DOE
was obligated to begin disposing of utilities' spent nuclear fuel
by January 1998. The DOE failed to meet this deadline, and is
<PAGE>
not expected to have a temporary or permanent repository for
spent nuclear fuel before 2010, at the earliest. Many utilities,
including Yankee Atomic, Connecticut Yankee, and Maine Yankee,
are plaintiffs in on-going litigation related to the DOE's
failure to accept spent nuclear fuel.
Low-Level Waste Disposal
Federal law allows the states in which the three existing
low-level waste disposal sites were located to deny access to
nonregional waste generators after 1992. Under the statute,
individual states are responsible for finding local sites for
disposal or forming regional disposal compacts by defined
milestone dates.
None of the states in which NEP holds an interest in a
nuclear facility has met the statutory milestones toward
developing disposal sites. Currently, two low-level waste
disposal sites in the U.S. are accepting nonregional waste, Chem-
Nuclear Systems, Inc.'s site in Barnwell, South Carolina and
Envirocare of Utah, Inc's site in Clive, Utah. Following a
closure in the early 1990s, the Barnwell facility reopened its
services to most nonregional generators on July 1, 1995 and is
authorized to remain open until July 1, 2005. In 1996, the South
Carolina Supreme Court upheld the constitutionality of the
legislative action that reopened Barnwell to nonregional
generators. Envirocare began accepting Class A low-level waste
in 1995. Class A waste is the least contaminated of the three
categories defining low-level waste. The Barnwell facility
accepts all three categories of waste. All the units in which
NEP has an interest are currently shipping low-level waste to
these sites. Chem-Nuclear Systems, as operator of the Barnwell
facility, is obligated to make certain payments to the State of
South Carolina. Chem-Nuclear has indicated that projected
revenues from its disposal activities at Barnwell are not likely
to be sufficient to reimburse it for these payments, and is
exploring alternatives to increase revenues from utilities
disposing waste at Barnwell. NEP cannot predict what impact, if
any, this situation will have on the continued availability of
the Barnwell site. Recently, the State of South Carolina has
begun contemplating the closure of the Barnwell site. Should the
Barnwell facility become unavailable, the cost of decommissioning
the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants
could increase.
The States of Maine and Vermont have established a compact
with Texas for the disposal of low-level waste at a yet to be
determined location in Texas. The compact agreement has been
approved in all three states, ratified by the U.S. Congress and
signed into law by the President. NEP cannot predict when a
disposal facility will be selected, licensed and become
<PAGE>
operational in Texas. The compact relieves Maine and Vermont
from having to site an in-state disposal facility. Connecticut,
Massachusetts, and New Hampshire are still required to pursue
local or regional low-level waste disposal facilities. However,
Massachusetts suspended its search for a local disposal facility
in 1996.
Nuclear Fuel Supply
The utilities responsible for the fuel supply for these
operating nuclear units are not experiencing any difficulties in
obtaining commitments for the supply of each element of the
nuclear fuel cycle.
Other Items
Federal legislation requires emergency response plans,
approved by federal authorities, for nuclear generating units.
The Yankee Companies, Seabrook 1, and Millstone 3 are not
currently experiencing difficulty in maintaining approval of
their emergency response plans.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall. The definition of owner
under the statute covers NEP and may cover companies affiliated
with it. NEP and the Electricity Delivery Companies cannot
determine, at this time, the constitutionality, applicability, or
effect of this statute. If NEP or the Electricity Delivery
Companies were required to make payments under this statute, they
would assess their legal remedies at that time. In any event,
NEP and the Electricity Delivery Companies would attempt to
recover through rates any payments required. If any claim in
excess of NEP's ownership share were enforced against a National
Grid USA company, that company would seek reimbursement from any
other Maine Yankee stockholder which failed to pay its share of
such costs.
Purchased Power Transfer Agreement
As part of the sale of NEP's nonnuclear generating business
to PG&E Gen on September 1, 1998, NEP signed a purchased power
transfer agreement through which PG&E Gen purchased NEP's
entitlement to approximately 1,100 MW of power procured under
long-term contracts. For more information, see the Industry
Restructuring section of the 1999 NEP Annual Report.
<PAGE>
REGULATORY AND ENVIRONMENTAL MATTERS
Regulation
Numerous activities of NEP are subject to regulation by
various federal agencies. Under the 1935 Act, many transactions
of NEP are subject to the jurisdiction of the SEC. With the
intensifying competitive pressures within the electric utility
industry, there has been increasing debate about modifying or
repealing the 1935 Act. Under the Federal Power Act, NEP is
subject to the jurisdiction of the FERC with respect to rates and
accounting. In addition, the NRC has broad jurisdiction over
nuclear units and federal environmental agencies have broad
jurisdiction over environmental matters.
For more information, see Industry Restructuring section of
the 1999 NEP Annual Report; Rates, page 3; Nuclear Units, page
9; and Environmental Requirements, page 15.
Environmental Requirements
Existing Operations
NEP is subject to federal, state, and local environmental
regulation of, among other things, wetlands and flood plains; air
and water quality; storage, transportation, and disposal of
hazardous wastes and substances; underground storage tanks; and
land-use. Upon completion of the sale of substantially all of
NEES' nonnuclear generating business to PG&E Gen, PG&E Gen
assumed responsibility for environmental conditions at the
Sellers' nonnuclear generating stations (see the Industry
Restructuring section of the 1999 NEP Annual Report.)
Siting and Construction Activities for New Transmission
Facilities
All New England states require, in certain circumstances,
regulatory approval for site selection or construction of major
transmission facilities. Connecticut, Maine, Massachusetts, New
Hampshire, and Rhode Island also have programs of coastal zone
management that might restrict construction of electrical
facilities in, or potentially affecting, coastal areas. The
New England states have environmental laws which require project
proponents to prepare reports of the environmental impact of
certain proposed actions for review by various agencies.
<PAGE>
Environmental Protection Facilities Expenditures
Due to the divestiture of its nonnuclear generating
business, NEP estimates that capital expenditures for
environmental protection facilities in 2000 and 2001 will not be
material.
Hazardous Substances
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. For more information regarding sites
for which NEP has been named as potentially responsible parties,
other sites, a settlement agreement covering rate recovery of
certain remediation costs, and reserves, see Note D of the Notes
to the Financial Statements of the NEP 1999 Annual Report.
Nuclear
The NRC, along with other federal and state agencies, has
extensive regulations pertaining to environmental aspects of
nuclear reactors. Safety aspects of nuclear reactors, including
design controls and inspection programs to mitigate any
possibility of nuclear accidents and to reduce any damages
therefrom, are also subject to NRC regulation. See Nuclear
Units, page 9.
CONSTRUCTION AND FINANCING
NEP's estimated construction expenditures (including nuclear
fuel) are shown below for 2000 through 2002.
NEP conducts a continuing review of its construction and
financing programs. These programs and the estimates shown below
are subject to revision based upon changes in assumptions as to
load growth, rates of inflation, receipt of adequate and timely
rate relief, the availability and timing of regulatory approvals,
new environmental and legal or regulatory requirements, total
costs of major projects, technological changes, and the
availability and costs of external sources of capital.
<PAGE>
<TABLE>
<CAPTION>
Estimated Construction Expenditures
-----------------------------------
2000 2001 2002 Total
---- ---- ---- -----
<S> <C> <C> <C> <C>
($ in Millions - excluding AFDC)
Nuclear Generation (1) 10 10 10 30
Transmission 45 45 65 155
---- ---- ---- ----
Total NEP 55 55 75 185
---- ---- ---- ----
<FN>
(1) Includes nuclear fuel.
</FN>
</TABLE>
Financing
All of NEP's construction expenditures during the period
2000 to 2002 are expected to be financed by internally generated
funds.
NEP's general practice has been to finance construction
expenditures in excess of internally generated funds initially by
issuing unsecured short-term debt. This short-term debt is
subsequently reduced through sales of long-term debt securities
and through capital contributions from its parent.
The ability of NEP to issue short-term debt is limited by
the need to obtain regulatory approval from the SEC under the
1935 Act and from the New Hampshire Public Utilities Commission.
The following table summarizes the short-term debt amounts for
which regulatory approval has been granted at December 31, 1999,
and the amount of outstanding short-term debt and lines of credit
and standby bond facilities at such date.
<TABLE>
<CAPTION>
($ millions)
Lines of Credit/
Regulatory Standby Bond
Limit Outstanding Facilities
---------- ----------- ----------------
<S> <C> <C> <C>
NEP 375 39(a) 460
(a) NEP plans to seek the necessary regulatory approvals in 2000 which would
allow the $39 million of variable rate debt to remain outstanding through
2015. This would result in classifying the debt as long-term rather than
short-term.
</TABLE>
<PAGE>
NEP and certain affiliates, with regulatory approval,
operate a money pool to more effectively utilize cash resources
and to reduce outside short-term borrowings. Short-term
borrowing needs are met first by available funds of the money
pool participants. Borrowing companies pay interest at a rate
designed to approximate the cost of outside short-term
borrowings. Companies which invest in the pool share the
interest earned on a basis proportionate to their average monthly
investment in the money pool. Funds may be withdrawn from or
repaid to the pool at any time without prior notice. At December
31, 1999, NEP had no moneypool borrowings outstanding.
<PAGE>
EXECUTIVE OFFICERS
The Treasurer is elected by the stockholders to hold office
until the next annual meeting of stockholders and until the
successor is duly chosen and qualified. The other executive
officers are elected by the Board of Directors to hold office
subject to the pleasure of the directors and until the first
meeting of directors after the next annual meeting of
stockholders and until their successors are duly chosen and
qualified. Certain officers of NEP are, or at various times in
the past have been, officers and/or directors of the affiliated
companies with which NEP has entered into contracts and had other
business relations.
Alfred D. Houston - Age: 59 - Chairman since 1998 - NEES
Chairman 1998 to 2000 - NEES Executive Vice President from
1994 to 1998 - NEES Senior Vice President from 1987 to 1994
- NEES Chief Financial Officer from 1984 to 1998 - Vice
President of NEP from 1987 to 1994 - Vice President of
Narragansett from 1976 to 1998 - Treasurer of Narragansett
from 1977 to 1998.
Peter G. Flynn - Age: 46 - Elected President in 1999 - Vice
President and Director of Rates for the Service Company from
1996 to 1999 - Assistant General Counsel for the Service
Company during 1996 - Senior Counsel for the Service Company
from 1992 to 1996.
Cynthia A. Arcate - Age: 43 - Elected Vice President in 2000
- Executive Vice President of Granite State from 1997 to
2000 - Vice President of Granite State from 1995 to 1997.
Michael E. Jesanis - Age: 43 - Vice President since 1998 -
National Grid USA (formerly NEES) Senior Vice President and
Chief Financial Officer since 1998 - NEES Vice President
from 1997 to 1998 - NEES Treasurer from 1992 to 1998 -
Elected Vice President of Narragansett in 1998 -
Treasurer of Mass. Electric and NEP from 1992 to 1998.
Cheryl A. LaFleur - Age: 45 - Vice President since 1995.
National Grid USA (formerly NEES) Senior Vice President
since 1998 - NEES Vice President from 1995 to 1998 -
Secretary and General Counsel since 1995 - Vice President of
Mass. Electric from 1993 to 1995.
John F. Malley - Age: 51 - Vice President since 1992.
James S. Robinson - Age: 46 - Vice President since 1998 -
Director of Nuclear Investments from 1997 to 1998 - Manager,
Wholesale Business Administration from 1993 to 1997.
<PAGE>
Masheed H. Rosenqvist - Age: 45 - Vice President since 1998
- Manager, Transmission Tariffs and Contracts for NEP or
Service Company since 1997 - Consulting Engineer for the
Service Company from 1995 to 1997.
John G. Cochrane - Age: 42 - National Grid USA (formerly
NEES) Vice President since 1999 - National Grid USA
(formerly NEES) Treasurer since 1998 - Treasurer of Mass.
Electric, NEP, and the Service Company since 1998 - Vice
President of the Service Company and Treasurer of
Narragansett since 1993.
Kwong O. Nuey - Age: 51 - Elected Controller in 2000 - Vice
President and Director, Retail Information Services for
Mass. Electric from 1993 to 2000.
ITEM 2. PROPERTIES
See ITEM 1. Business - Transmission Properties, Page 7 and
Nuclear Generation Properties, page 8.
ITEM 3. LEGAL PROCEEDINGS
See Item 1. BUSINESS - Nuclear Units, page 9.
In August 1997, NEP sued Northeast Utilities (NU) in
Massachusetts Superior Court for damages resulting from the
tortious conduct of NU that caused the shutdown of Millstone 3.
NEP's claim for damages included the costs of replacement power
during the outage, costs necessary to return Millstone 3 to safe
operation, and other additional costs. Most of NEP's incremental
replacement power costs have been recovered from customers,
either through fuel adjustment clauses or through provisions in
the Settlement Agreements.
In August 1997, NEP also sent a demand for arbitration to
Connecticut Light & Power Company and Western Massachusetts
Electric Company, both subsidiaries of NU (subsidiaries), seeking
damages resulting from their breach of obligations under an
agreement with NEP and others regarding the operation and
ownership of Millstone 3.
In November 1999, NEP, NU, and the subsidiaries executed an
agreement which settled the litigation and the arbitration
described above. Under the settlement, NU paid NEP approximately
$24 million. In addition, NU also agreed to include NEP's
Millstone 3 interest when NU sells its Millstone 3 interest at
auction. Amounts received pursuant to a sale will, after
reimbursement of NEP's transaction costs and net investment in
Millstone 3, be credited to customers.
<PAGE>
From 1983 until 1998, NEP was the wholesale power supplier
for the Town of Norwood, Massachusetts (Norwood). In April 1998,
Norwood began taking power from another supplier. Pursuant to a
tariff amendment approved by the FERC in May 1998, NEP has been
assessing Norwood a CTC. Through December 1999, the charges
assessed Norwood amount to approximately $15 million, all of
which remain unpaid. NEP is pursuing a collection action in
Massachusetts Superior Court.
Separately, Norwood filed suit in Federal District Court
(District Court) in April 1997 alleging that NEP's divestiture
violated the terms of the 1983 power contract and contravened
antitrust laws. The District Court dismissed the lawsuit. On
appeal, the First Circuit Court of Appeals (First Circuit) also
consolidated appeals Norwood made from FERC's orders approving
the divestiture, the wholesale rate settlement between NEP and
its distribution affiliates, and the CTC tariff amendment. On
February 2, 2000, the First Circuit dismissed Norwood's appeal
from the FERC orders and dismissed its appeal from all but one of
Norwood's District Court claims, which relates to the creation of
generation market power. On February 28, 2000, and March 3,
2000, respectively, the First Circuit denied Norwood's petition
for further review of its District Court claims decision and its
decision on the FERC orders.
Norwood has also appealed a 1999 FERC decision that rejected
Norwood's challenge to the calculation of the CTC based on the
term of the 1983 power contract.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders
during the last quarter of 1999.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SECURITY HOLDER MATTERS
The information required by this item is not applicable as
the common stock of NEP is held solely by National Grid USA.
Information pertaining to payment of dividends and restrictions
on payment of dividends is incorporated herein by reference to
the NEP 1999 Annual Report.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is incorporated herein
by reference to Selected Financial Information, Note K of the NEP
1999 Annual Report.
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
The information required by this item is incorporated herein
by reference to the Financial Review section of the NEP 1999
Annual Report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by this item is incorporated herein
by reference to the Risk Management section of the NEP 1999
Annual Report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is incorporated herein
by reference to the financial statements and Notes to Financial
Statements in the NEP 1999 Annual Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The names of the directors of NEP, their ages, and a brief
account of their business experience during the past five years
appear below. Information required by this item for Executive
Officers is provided under the caption EXECUTIVE OFFICERS in Part
I of this report.
Directors are elected to hold office until the next annual
meeting of stockholders or special meeting held in lieu thereof
and until their respective successors are chosen and qualified.
Cynthia A. Arcate* - Elected Director in 2000.
L. Joseph Callan - Age: 52 - Elected Director in 2000 -
Consultant since 1998 - Several positions at the NRC,
including Regional Administrator and Executive Director of
Operations, from 1979 to 1998.
Peter G. Flynn* - Elected Director in 1999.
<PAGE>
Alfred D. Houston* - Director since 1984. Directorships of
National Grid USA companies: Granite State Energy, Inc.,
NEES Communications, Inc., NEES Energy, Inc., New England
Electric Transmission Corporation, New England Energy
Incorporated, New England Hydro Finance Company, Inc., New
England Hydro-Transmission Corporation, New England
Hydro-Transmission Electric Company, Inc., New England Power
Service Company, and Wayfinder Group.
Cheryl A. LaFleur* - Director since 1995. Directorships of
National Grid USA companies: Granite State Electric Company,
Granite State Energy, Inc., Massachusetts Electric Company,
Nantucket Electric Company, The Narragansett Electric
Company, NEES Communications, Inc., NEES Energy, Inc., New
England Electric Transmission Corporation, New England
Energy Incorporated, New England Hydro Finance Company,
Inc., New England Hydro-Transmission Corporation, New
England Hydro- Transmission Electric Company, Inc., New
England Power Service Company, and Wayfinder Group, Inc.
Richard P. Sergel* - Director since 1998. Director of
National Grid Group, plc. Directorships of National Grid
USA companies: Granite State Electric Company, Granite State
Energy, Inc., Massachusetts Electric Company, Nantucket
Electric Company, The Narragansett Electric Company, NEES
Communications, Inc., NEES Energy, Inc., New England Energy
Incorporated, New England Electric Transmission Corporation,
New England Hydro Finance Company, Inc., New England Hydro-
Transmission Corporation, New England Hydro-Transmission
Electric Company, Inc., New England Power Service Company,
and Wayfinder Group, Inc.
Philip R. Sharp - Age: 57 - Elected Director in 2000 -
Lecturer, Harvard University John F. Kennedy School of
Government since 1995 - US Congressman from 1975 to 1995.
Other directorship: Cinergy Corporation.
*Please refer to the material supplied under the caption
EXECUTIVE OFFICERS in Part I of this report for other
information regarding these directors.
<PAGE>
Section 16(a) Beneficial Ownership Reporting Compliance
-------------------------------------------------------
Section 16(a) of the Securities Exchange Act of 1934
requires NEP's officers and directors, and persons who own more
than 10 percent of a registered class of NEP's equity securities,
to file reports on Forms 3, 4, and 5 of share ownership and
changes in share ownership with the SEC and the New York Stock
Exchange and to furnish NEP with copies of all Section 16(a)
forms they file.
Based solely on NEP's, review of the copies of such forms
received by it, or written representations from certain reporting
persons that such forms were not required for those persons, NEP
believes that, during 1999, all filing requirements applicable to
its officers, directors, and 10 percent beneficial owners were
complied with.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table gives information with respect to all
compensation (whether paid directly by NEP or billed to it as
hourly charges) for services in all capacities for NEP for the
years 1997 through 1999 to or for the benefit of the Chief
Executive Officer and the four other most highly compensated
executive officers.
<PAGE>
NEP
<TABLE>
SUMMARY COMPENSATION TABLE
<CAPTION>
Long-Term
Annual Compensation (b) Compensation
-------------------------- -------------------
Other Restricted
Name and Annual & Deferred All Other
Principal Compensa- Share LTIP Compensa-
Position Year Salary Bonus tion Awards Payouts tion
(a) ($) ($)(c) ($)(d) ($)(e) ($) ($)(f)
- ---------- ---- ------- ------ --------- ---------- ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Peter G. 1999 154,707 74,812 3,616 30,220 46,464 359
Flynn 1998 57,838 29,383 1,151 12,176 6,864 75
President
(Elected 1/99)
Alfred D. 1999 40,385 20,766 1,054 11,576 20,235 219
Houston 1998 49,236 32,804 1,137 18,677 17,545 288
Chairman
Cheryl A. 1999 36,268 17,321 1,278 7,871 19,015 82
LaFleur 1998 32,922 18,509 1,258 8,562 6,143 69
Vice 1997 85,555 93,340 3,311 1,832 0 149
President
Masheed H. 1999 124,740 45,569 2,538 17,671 0 412
Rosenqvist 1998 113,697 44,654 2,285 17,618 0 366
Vice
President
James S. 1999 115,920 42,415 2,693 16,405 22,018 167
Robinson 1998 108,205 39,143 2,510 17,734 13,641 149
Vice
President
</TABLE>
(a) Certain officers of NEP are also officers of affiliate
companies.
(b) Includes deferred compensation in category and year earned.
(c) The bonus figure represents: cash bonuses under an incentive
compensation plan, the all-employee goals program, the
variable match of the incentive thrift plan, including related
deferred compensation plan matches, special cash bonuses, and
unrestricted shares under the incentive share plan. In
<PAGE>
1997, the bonus amounts were all cash or contributions to the
incentive thrift plan, including related deferred compensation
plan matches. See descriptions under Plan Summaries.
(d) Includes amounts reimbursed by NEP for the payment of taxes on
certain noncash benefits and NEP contributions to the
incentive thrift plan that are not bonus contributions
including related deferred compensation plan match. See
description under Plan Summaries.
(e) The incentive share awards for the named executives who were
also NEES executives (1997 - 1999) and the other named
executives (in 1998 only) were in the form of restricted
shares (with a five-year restriction) or deferred share
equivalents, deferred for receipt for at least five years, at
the executive's option. As cash dividends were declared, the
number of deferred share equivalents increased as if the
dividends were reinvested in shares. The shares awarded for
the other named executives in 1997 were not restricted and the
value of the awards is included in the bonus column.
As of December 31, 1999, the following executive officers held
the amount of restricted and deferred shares with the value
indicated: Mr. Flynn 3,691 shares, $191,009 value; Mr. Houston
19,545 shares, $1,011,454 value; Ms. LaFleur 8,306 shares,
$429,836 value; Ms. Rosenqvist 376 shares, $19,458 value; and
Mr. Robinson 131 shares, $6,779 value. The value was
calculated by multiplying the closing market price on December
31, 1999 by the number of shares.
(f) Includes NEP contributions to life insurance. See description
under Plan Summaries. The life insurance contribution is
calculated based on the value of term life insurance for the
named individuals. The premium costs for most of these
policies have been or will be recovered by NEP.
<PAGE>
Directors' Compensation
Members of the NEP Board who are employees of National Grid
USA companies receive no fees for service on the Board. Non-
employee directors receive an annual retainer of $20,000 plus a
meeting fee of $1,000 for each Board or committee meeting attended.
Retirement Plans
The following table shows estimated annual benefits payable to
executive officers under the qualified pension plan and the
supplemental retirement plan, assuming retirement at age 65 in
2000.
<TABLE>
PENSION TABLE
<CAPTION>
Five-Year
Average 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years
Compensa- of of of of of of
tion Service Service Service Service Service Service
- --------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
$100,000 18,926 29,276 39,626 49,976 60,326 70,676
$150,000 29,276 42,414 57,439 72,464 87,489 102,514
$200,000 39,626 57,439 75,251 94,951 114,651 134,351
$250,000 49,976 72,464 94,951 116,814 141,064 165,314
$300,000 60,326 87,489 114,651 141,064 167,477 184,123
$350,000 70,676 102,514 134,351 165,314 196,277 215,865
$400,000 81,026 117,539 154,051 189,564 225,077 241,590
$450,000 91,376 132,564 173,751 213,814 253,877 279,315
$500,000 101,726 147,589 193,451 238,064 282,677 311,040
</TABLE>
For purposes of the retirement plans, Mr. Flynn, Mr. Houston,
Ms. LaFleur, Ms. Rosenqvist, and Mr. Robinson currently have 18,
21, 14, 18, and 12 credited years of service, respectively.
Benefits under the pension plans are computed using formulae
based on percentages of highest average compensation computed over
five consecutive years. The compensation covered by the pension
plan includes salary, bonus, and incentive share awards. Long-Term
Performance Share awards are not included. The benefits listed in
the pension table are not subject to deduction for Social Security
and are shown without any joint and survivor benefits. If the
participant elected at age 65 a 100 percent joint and survivor
benefit with a spouse of the same age, the benefit shown would be
reduced by approximately 16 percent.
<PAGE>
The pension plan table above does not include annuity payments
to be received in lieu of life insurance for Mr. Houston. The
payments are described below under Plan Summaries.
NEP contributes the full cost of post-retirement health
benefits for senior executives.
PAYMENTS UPON A CHANGE OF CONTROL AND TERMINATION OF EMPLOYMENT
National Grid USA is a party to agreements with each of Mr.
Houston, Ms. LaFleur, and Mr. Flynn (each, an Executive and each
agreement, a Severance Agreement), which Severance Agreements were
entered into in 1995 with Mr. Houston and on March 1, 1998 with the
other Executives and which remain in effect for the three year
period following (1) a Change in Control of NEES (as defined in the
Severance Agreements) or (2) a Major Transaction (as defined in the
Severance Agreements). In accordance with the terms of the
Severance Agreements, if the applicable Executive's employment is
terminated within three years following the event described in
clause (1) or (2), as applicable, National Grid USA will pay to the
Executive the severance payments and will provide to the Executive
the severance benefits described below, unless the Executive's
employment is terminated (x) by National Grid USA for Cause, (y) by
the Executive without Good Reason or (z) by reason of the
Executive's death, Disability or Retirement (each term, as defined
in the Severance Agreements).
The shareholder approval of the merger agreement with The
National Grid Group plc (May 1999) constituted a Major Transaction
and the merger with The National Grid Group plc on March 22, 2000
constituted a Change in Control. Accordingly, in the event an
Executive's employment is terminated within three years following
the Major Transaction or Change in Control, such Executive will be
entitled to receive, in lieu of any other payments due to the
Executive: (1) lump sum cash payment equal to three times (two
times, in certain cases) the sum of (a) the higher of (i) such
Executive's annual base compensation in effect at the time of
termination and (ii) such Executive's annual base compensation in
effect immediately prior to the Change in Control or Major
Transaction and (b) the higher of (i) the average of the annual
bonuses awarded to such Executive under the New England Electric
Companies' Senior Incentive Compensation Plan, New England Electric
Companies' Incentive Compensation Plan I, II and III and the
Incentive Share Plan (collectively, the Incentive Plans) for the
three performance years ended prior to the date of termination and
(ii) the average of the annual bonuses awarded to such Executive
pursuant to the Incentive Plans for the three performance years
ended prior to the Change in Control or Major Transaction; (2) a
cash lump sum payment equal to the excess of (a) the actuarial
equivalent of the retirement pension which the Executive would have
accrued under the terms of each pension plan of National Grid USA
(determined as if the Executive (i) were fully vested thereunder
and had accumulated 36 additional months (24 additional months, in
certain cases) of service credit thereunder and (ii) had been
credited under each such pension plan of National Grid USA during
such 36 month period with compensation at the higher of (A) the
Executive's compensation during the 12 months prior to the date of
termination and (B) the Executive's compensation during the 12
months ending on the date of the Change in Control or Major
Transaction) over (b) the actuarial equivalent of the retirement
pension which the Executive had actually accrued pursuant to the
provisions of National Grid USA's pension plans as of the date of
his or her termination of employment; (3) the continuation of
employee welfare benefits for three years (two years, in certain
cases) following the date of termination, reduced to the extent the
Executive receives such benefits from a subsequent employer; (4) if
the Executive would have otherwise been entitled to post-retirement
health care or life insurance had he continued to be employed for
three additional years (two additional years, in certain cases),
such post-retirement health care and life insurance commencing on
the later of (a) the date that such coverage would have first
become available to the Executive and (b) the date that the
benefits described in clause (3) above terminate and (5) the
reimbursement of legal fees and expenses, if any, incurred by the
Executive in disputing any issue relating to the termination of his
employment. Notwithstanding the above, payments to be made and
benefits to be provided to the Executives will be reduced to the
extent necessary to avoid imposition of the excise tax (the Excise
Tax) pursuant to Section 4999 of the Code; in certain cases,
however, such payments and benefits will be reduced only if such
reduction would yield a greater result to the Executive than actual
payment by the Executive of the Excise Tax.
Pursuant to the merger agreement with National Grid, National
Grid and National Grid USA entered into a consulting contract with
Mr. Houston. The consulting contract is for a term of two years
and provides for payments to Mr. Houston of $200,000 per year.
Upon a change in control a participant in the deferred
compensation plan has the option of receiving a full distribution
of the participant's cash and share accounts and the actuarial
value of future benefits from the insurance related benefits under
a prior plan, all less 10 percent.
<PAGE>
NEES's bonus plans, including the incentive compensation plans,
the Incentive Thrift Plan, and the Goals Program, provided for
payments equal to the average of the bonuses for the three prior
years in the event of a Change of Control. These payments would be
made in lieu of the regular bonuses for the year in which the
Change in Control occurs. The Long-Term Performance Share Award
Plan provided for a cash payment equal to the value of the
performance shares in the participants' account times the average
target achievement percentage for the Incentive Thrift Plan for the
three prior years. The Retirees Health and Life Insurance Plan has
provisions preventing changes in benefits adverse to the
participants for three years following a Change in Control.
PLAN SUMMARIES
A brief description of the various plans through which
compensation and benefits have been provided to the named executive
officers is presented below to better enable shareholders to
understand the information presented in the tables shown earlier.
The amounts of compensation and benefits provided to the named
executive officers under the plans described below (and charged to
NEP) are presented in the Summary Compensation Table.
Goals Program
The Goals Program establishes goals annually. For 1999, these
included goals related to core operating income, costs for
customers for electricity delivery, safety, absenteeism,
transmission and distribution reliability, environmental and OSHA
compliance, and customer satisfaction. Some goals apply to all
employees, while others apply to particular functional groups.
Depending upon the number of goals met, and provided the minimum
earnings goal is met, employees may earn a cash bonus of 1 percent
to 4-1/2 percent of their compensation.
Incentive Thrift Plan
The incentive thrift plan (a 401(k) program) provides for a
match of 40 percent of up to the first 5 percent of base
compensation contributed to the incentive thrift plan (shown under
Other Annual Compensation in the Summary Compensation Table) and,
based on an incentive formula tied to core operating income, may
fully match the first 5 percent of base compensation contributed
(the additional amount, if any, is shown under Bonus in the Summary
<PAGE>
Compensation Table). Under Federal law, contributions to these
plans are limited. In 1999, the salary reduction amount was
limited to $10,000.
Deferred Compensation Plan
The Deferred Compensation Plan offered executives the
opportunity to defer base pay and bonuses. The plan offered the
option of investing at the prime rate or in NEES common shares.
Under Federal law, the Incentive Thrift Plan, described above, was
required to limit participant base compensation to $160,000 in
calculating the NEES match. Under the Deferred Compensation Plan,
NEES made a contribution to an executive's share account equivalent
to the resultant reduction in his or her match under the Incentive
Thrift Plan.
Life Insurance
National Grid USA has established for certain senior executives
life insurance plans funded by individual policies. The combined
death benefit under these insurance plans is three times the
participant's annual salary. These plans are structured so that,
over time, National Grid USA should recover the cost of the
insurance premiums.
After termination of employment, Mr. Houston may elect,
commencing at age 55 or later, to receive an annuity income equal
to 22.5 percent of 1998 annual salary plus 40 percent of final
annual salary. In that event, the life insurance is reduced over
15 years to an amount equal to his final annual salary.
Incentive Compensation Plan
Under the bonus plan for certain senior employees, bonuses are
tied to achievement of core business operating income and strategic
objectives. Annual income targets and strategic objectives are
established for each year. Bonuses are also dependent upon the
achievement of individual goals. An individual's award of shares
under the incentive share plan has been a fixed percentage of her
or his cash bonus for that year. If no cash award was made, no
shares would be distributed.
<PAGE>
Financial Counseling
NEP pays for personal financial counseling for certain
executives. As required by the IRS, a portion of the amount paid
is reported as taxable income for the executive. Financial
counseling is also offered to other employees through seminars
conducted at various locations each year.
Other
NEP has not had any share option plans.
LONG-TERM INCENTIVE PLAN - AWARDS IN LAST FISCAL YEAR
-----------------------------------------------------
The Long-Term Performance Share Award Plan provided awards
based on various measures of NEES performance over a three-year
period. Each award factor functioned independently. The
performance targets for each cycle were set by the Compensation
Committee of the NEES Board. Performance was rated on rolling
three-year periods, with a new cycle beginning each year. An
individual's potential award under the plan was a fixed percentage
(ranging from 15 percent to 50 percent) of base pay. At the end of
the three-year cycle, the participant received NEES shares based
upon the performance against the various factors.
The only measure of performance for the cycle commencing
January 1, 1999 was the successful completion of the merger with
National Grid.
The following table shows the awards, for those executive
officers named in the Summary Compensation Table, under the Long-
Term Performance Share Award Plan for the performance cycle
commencing January 1, 1999. Due to the change of control
provisions in the plan, triggered by the merger with National Grid
on March 22, 2000, the listed participants received awards in the
amounts indicated in the table. The amount awarded was based upon
the average of incentive compensation target achievement for the
prior three years and not upon the measure specified above.
<PAGE>
NEP
---
ESTIMATED FUTURE PAYOUTS UNDER NON-STOCK PRICE-BASED PLANS
------------------------------------------------
<TABLE>
<CAPTION>
Number of Actual Change
Common Shares Performance in Control
Name Allotted Period Award (a)
--------- ----------- ------------
<S> <C> <C> <C>
Peter G. Flynn 856 3 years 744
Alfred D. Houston 5187 3 years 4512
Cheryl A. LaFleur 2534 3 years 2204
Masheed H. Rosenqvist 388 3 years 338
James S. Robinson 361 3 years 314
</TABLE>
(a) The awards in this column were made as a result of the change
in control on March 22, 2000. The listed participants
received awards in the amounts indicated in the table. The
amount awarded was based upon the average of incentive
compensation target achievement for the prior three years and
not upon the measure specified above.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
National Grid USA owns 99.57 percent of the voting securities of
NEP.
As of March 23, 2000, there were no outstanding NEES common
shares due to the completion of the merger with The National Grid
Group plc and no officers or directors of NEP owned any NEP
securities.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is made to ITEM 11. EXECUTIVE COMPENSATION.
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
List of Exhibits
Unless otherwise indicated, the exhibits listed below are
incorporated by reference to the appropriate exhibit numbers and
the Commission file numbers indicated in parentheses.
<PAGE>
(3) (a) Articles of Organization as amended through June 25, 1987
(Exhibit 3(a) to 1988 Form 10-K, File No. 0-1229).
(b) By-laws of the Company as amended December 12, 1997
(Exhibit 3(b) to 1997 Form 10-K, File No. 0-1229).
(10) Material Contracts
(a) Boston Edison Company et al. and the Company: Amended
REMVEC Agreement dated August 12, 1977 (Exhibit 5-4(d),
File No. 2-61881).
(i) Boston Edison Company et al. and the Company:
REMVEC II Agreement dated on or about July 1, 1997
(Exhibit 10(a)(I) to NEES' 1997 Form 10- K, File
No. 1-3446).
(ii) Boston Edison Company et al. and the Company:
Security Analysis Services Agreement dated on or
about July 1, 1997 (Exhibit 10(a)(ii) to NEES'
1997 Form 10-K, File No. 1-3446).
(b) The Connecticut Light and Power Company et al. and the
Company: Sharing Agreement for Joint Ownership,
Construction and Operation of Millstone Unit No. 3
dated as of September 1, 1973, and Amendment dated as
of August 1, 1974 (Exhibit 10-5, File No. 2-52820);
Amendments dated as of December 15, 1975 and April 1,
1986 (Exhibit 10(b) to NEES' 1990 Form 10-K File No.
1-3446). Transmission Support Agreement dated
August 9, 1974; Instrument of Transfer to the Company
with respect to the 1979 Connecticut Nuclear Unit, and
Assumption of Obligations, dated December 17, 1975
(Exhibit 10-6(b), File No. 2-57831).
(c) Connecticut Yankee Atomic Power Company et al. and the
Company: Stockholders Agreement dated July 1, 1964
(Exhibit 13-9-A, File No. 2-2006); Power Purchase
Contract dated July 1, 1964 (Exhibit 13-9-B, File No.
2-23006); Additional Power Contract dated as of April
30, 1984 and 1996; Amendatory Agreement dated as of
December 4, 1996 (Exhibit 10(c) to 1996 Form 10-K, File
No. 1-3446); Supplementary Power Contract dated as of
April 1, 1987 (Exhibit 10(c) to 1987 Form 10-K, File
No. 0-1229); Capital Funds Agreement dated September 1,
1964 (Exhibit 13-9-C, File No. 2-23006); Transmission
Agreement dated October 1, 1964 (Exhibit 13-9-D, File
No. 2-23006); Agreement revising Transmission Agreement
dated July 1, 1979 (Exhibit to NEES' 1979 Form 10-K,
File No. 1-3446); Amendment revising Transmission
Agreement dated as of January 19, 1994 (Exhibit 10(c)
to NEES' 1995 Form 10-K, File No. 1-3446); Five Year
Capital Contribution Agreement dated November 1, 1980
(Exhibit 10(e) to NEES' 1980 Form 10-K, File No.
1-3446).
<PAGE>
(d) Maine Yankee Atomic Power Company et al. and the
Company: Capital Funds Agreement dated May 20, 1968
and Power Purchase Contract dated May 20, 1968 (Exhibit
4-5, File No. 2-29145); Amendments dated as of January
1, 1984, March 1, 1984 (Exhibit 10(d) to NEES' 1983
Form 10-K, File No. 1-3446); October 1, 1984, and
August 1, 1985 (Exhibit 10(d) to NEES' 1985 Form 10-K,
File No. 1-3446); Stockholders Agreement dated May 20,
1968 (Exhibit 10-20; File No. 2-34267); Additional
Power Contract dated as of February 1, 1984 (Exhibit
10(d) to NEES' 1985 Form 10-K, File No. 1-3446); 1997
Amendatory Agreement dated as of August 6, 1997
(Exhibit 10(d) to NEES' 1997 Form 10-K, File No. 1-
3446).
(e) Mass. Electric and the Company: Primary Service for
Resale dated February 15, 1974 (Exhibit 5-17(a), File
No. 2-52969); Amendment of Service Agreement dated
June 22, 1983 (Exhibit 10(b) to Mass. Electric's 1986
Form 10-K, File No. 0-5464); Amendment of Service
Agreement effective November 1, 1993 (Exhibit 10(e) to
1993 Form 10-K, File No. 0-1229); Memorandum of
Understanding effective May 22, 1994 (Exhibit 10(e) to
1994 Form 10-K, File No. 0-1229); Amendment of Service
Agreement effective July 1, 1996 and, Amendment to
Service Agreement dated as of February 1, 1997 (Exhibit
10(e) to 1997 Form 10-K, File No. 1-3446); Supplement
to Amendment to Service Agreement dated as of March 1,
1998; (Exhibit 10(e) to 1998 Form 10-K, File No. 1-
3446); Supplement to Service Agreement effective
December 31, 1999 (filed herewith).
(f) The Narragansett Electric Company and the Company:
Primary Service for Resale dated February 15, 1974
(Exhibit 4-1(b), File No. 2-51292); Amendment of
Service Agreement dated July 26, 1990 (Exhibit 4(f) to
New England Power Company's 1990 Form 10-K, File No.
0-1229). Amendment of Service Agreement dated July 24,
1991 (Exhibit 10(f) to 1991 Form 10-K, File No. 0-
1229); Amendment of Service Agreement effective
November 1, 1993 (Exhibit 10(f) to 1993 Form 10-K, File
No. 0-1229); Memorandum of Understanding effective May
22, 1994 (Exhibit 10(e) to 1994 Form 10-K, File No. 0-
1229); Amendment of Service Agreement effective January
1, 1995 (Exhibit 10(f) to 1995 Form 10-K, File No. 0-
1229); Amendment of Service Agreement effective October
30, 1995 and, Amendment to Service Agreement dated as
<PAGE>
of February 1, 1997 (Exhibit 10(f) to 1997 Form 10-K,
File No. 1-3446); Supplement to Amendment to Service
Agreement dated as of December 31, 1998 (Exhibit 10(f)
to 1998 Form 10-K, File No. 1-3446); Supplement to
Service Agreement effective December 31, 1999 (filed
herewith).
(g) New England Electric Transmission Corporation et al.
and the Company: Phase I Terminal Facility Support
Agreement dated as of December 1, 1981 (Exhibit 10(g)
to NEES' 1981 Form 10-K, File No. 1-3446); Amendments
dated as of June 1, 1982 and November 1, 1982 (Exhibit
10(f) to NEES' 1982 Form 10-K, File No. 1-3446);
Agreement with respect to Use of the Quebec
Interconnection dated as of December 1, 1981 (Exhibit
10(g) to NEES' 1981 Form 10-K, File No. 1-3446);
Amendments dated as of May 1, 1982 and November 1, 1982
(Exhibit 10(f) to NEES' 1982 Form 10-K, File No.
1-3446); Amendment dated as of January 1, 1986 (Exhibit
10(f) to NEES' 1986 Form 10-K, File No. 1-3446);
Agreement for Reinforcement and Improvement of the
Company's Transmission System dated as of April 1, 1983
(Exhibit 10(f) to NEES' 1983 Form 10-K, File No.
1-3446); Lease dated as of May 16, 1983 (Exhibit 10(f)
to NEES' 1983 Form 10-K, File No. 1-3446); Upper
Development-Lower Development Transmission Line Support
Agreement dated as of May 16, 1983 (Exhibit 10(f) to
NEES' 1983 Form 10-K, File No. 1-3446).
(h) Vermont Electric Transmission Company, Inc. et al. and
the Company: Phase I Vermont Transmission Line Support
Agreement dated as of December 1, 1981; Amendments
dated as of June 1, 1982 and November 1, 1982 (Exhibit
10(g) to NEES' 1982 Form 10-K, File No. 1-3446);
Amendment dated as of January 1, 1986 (Exhibit 10(h) to
NEES' 1986 Form 10-K, File No. 1-3446).
(i) New England Power Pool Agreement: (Exhibit 4(e), File
No. 2-43025); Amendments dated July 1, 1972, March 1,
1973 (Exhibit 10-15, File No. 2-48543); Amendment dated
March 15, 1974 (Exhibit 10-5, File No. 2-52775);
Amendment dated June 1, 1975 (Exhibit 10-14, File No.
2-57831); Amendment dated September 1, 1975 (Exhibit
10-13, File No. 2-59182); Amendments dated December 31,
1976, January 31, 1977, July 1, 1977, and August 1,
1977 (Exhibit 10-16, File No. 2-61881); Amendments
dated August 15, 1978, January 3, 1980, and February
<PAGE>
1980 (Exhibit 10-3, File No. 2-68283); Amendment dated
September 1, 1981 (Exhibit 10(h) to NEES' 1981 Form
10-K, File No. 1-3446); Amendment dated December 1,
1981 (Exhibit 10(h) to NEES' 1982 Form 10-K, File No.
1-3446); Amendments dated June 1, 1982, June 15, 1983,
and October 1, 1983 (Exhibit 10(i) to NEES' 1983 Form
10-K, File 1-3446); Amendments dated August 1, 1985,
August 15, 1985, September 1, 1985, and January 1, 1986
(Exhibit 10(i) to NEES' 1985 Form 10-K, File No.
1-3446); Amendment dated September 1, 1986 (Exhibit
10(i) to NEES' 1986 Form 10-K, File No. 1-3446);
Amendment dated April 30, 1987 (Exhibit 10(i) to NEES'
1987 Form 10-K, File No. 1-3446); Amendments dated
March 1, 1988 and May 1, 1988 (Exhibit 10(i) to NEES'
1988 Form 10-K, File No. 1-3446); Amendment dated
March 15, 1989 (Exhibit 10(i) to 1989 NEES Form 10-K,
File No. 1-3446); Amendment dated October 1, 1990
(Exhibit 10(i) to 1990 NEES Form 10-K, File No.
1-3446); Amendment dated October 1, 1990 Exhibit 10(i)
to 1990 NEES Form 10-K, File No. 1-3446); Amendment
dated as of September 15, 1992 (Exhibit 10(i) to 1992
NEES Form 10-K, File No. 1-3446); Amendments dated as
of June 1, 1993, July 1, 1995, and September 1, 1995
(Exhibit 10(i) to 1995 NEES Form 10-K, File No. 1-
3446); Amendment dated as of December 1, 1996 (Exhibit
10(i) to 1996 NEES Form 10-K, File No. 1-3446).
Amendment dated as of September 1, 1997 and Amendment
dated as of November 15, 1997 (Exhibit 10(i) to 1997
NEES Form 10-K, File No. 1-3446); Second Restated New
England Power Pool Agreement as amended through the
Fifty-first Agreement amending the New England Power
Pool Agreement issued on December 30, 1999 (filed
herewith)
(j) New England Power Service Company and the Company:
Specimen of Service Contract (Exhibit 10(l) to 1994
Form 10-K, File No. 0-1229).
(k) Massachusetts Electric Company, et al. and the Company:
Form of Mutual Assistance Agreement (Exhibit 10(n) to
1996 Form 10-K, File No. 0-1229).
(l) Massachusetts Electric Company, et al. and the Company:
Restructuring Settlement Agreement approved by the
Massachusetts Department of Public Utilities (Exhibit
10(o) to 1996 Form 10-K, File No. 0-1229).
<PAGE>
(m) Public Service Company of New Hampshire et al. and the
Company: Agreement for Joint Ownership, Construction
and Operation of New Hampshire Nuclear Units dated as
of May 1, 1973; Amendments dated May 24, 1974, June 21,
1974, September 25, 1974 and October 25, 1974 (Exhibit
10-18(b), File No. 2-52820); Amendment dated
January 31, 1975 (Exhibit 10-16(b), File No. 2-57831);
Amendments dated April 18, 1979, April 25, 1979,
June 8, 1979, October 11, 1979, December 15, 1979,
June 16, 1980, and December 31, 1980 (Exhibit 10(i) to
NEES' 1980 Form 10-K, File No. 1-3446); Amendments
dated June 1, 1982, April 27, 1984, and June 15, 1984
(Exhibit 10(j) to NEES' 1984 Form 10-K, File No.
1-3446); Amendments dated March 8, 1985, March 14,
1986, May 1, 1986, and September 19, 1986 (Exhibit
10(j) to NEES' 1986 Form 10-K, File No. 1-3446);
Amendment dated November 12, 1987 (Exhibit 10(j) to
NEES' 1987 Form 10-K, File No. 1-3446); Amendment dated
January 13, 1989 (Exhibit 10(j) to NEES' 1990 Form
10-K, File No. 1-3446); Seventh Amendment as of
November 1, 1990 (Exhibit 10(m) to NEES' 1991 Form
10-K, File No. 1-3446). Transmission Support Agreement
dated as of May 1, 1973 (Exhibit 10-23, File No.
2-49184); Instrument of Transfer to the Company with
respect to the New Hampshire Nuclear Units and
Assumptions of Obligations dated December 17, 1975 and
Agreement Among Participants in New Hampshire Nuclear
Units, certain Massachusetts Municipal Systems and
Massachusetts Municipal Wholesale Electric Company
dated May 28, 1976 (Exhibit 16(c), File No. 2-57831);
Seventh Amendment To and Restated Agreement for
Seabrook Project Disbursing Agent dated as of
November 1, 1990 (Exhibit 10(m) to NEES' 1991 Form
10-K, File No. 1-3446); Amendments dated as of June 29,
1992 (Exhibit 10(j) to NEES' 1992 Form 10-K, File No.
1- 3446). Settlement Agreement dated as of July 19,
1990 between Northeast Utilities Service Company and
the Company (Exhibit 10(m) to NEES' 1991 Form 10-K,
File No. 1-3446). Seabrook Project Managing Agent
Operating Agreement dated as of June 29, 1992,
Amendment to Seabrook Project Managing Agent Operating
Agreement dated as of June 29, 1992 (Exhibit 10(j) to
NEES' 1992 Form 10-K, File No. 1- 3446).
<PAGE>
(n) Vermont Yankee Nuclear Power Corporation et al. and the
Company: Capital Funds Agreement dated February 1,
1968, Amendment dated March 12, 1968 and Power Purchase
Contract dated February 1, 1968 (Exhibit 4-6, File No.
2-29145); Amendments dated as of June 1, 1972,
April 15, 1983 (Exhibit 10(k) to NEES' 1983 Form 10-K,
File No. 0-1229) and April 24, 1985 (Exhibit 10(n) to
NEES' 1985 Form 10-K, File No. 1-3446); Amendment dated
as of June 1, 1985 (Exhibit 10(n) to 1988 Form 10-K,
File No. 0-1229); Amendments dated May 6, 1988 (Exhibit
10(n) to 1988 Form 10-K, File No. 0-1229); Amendment
dated as of June 15, 1989 (Exhibit 10(k) to 1989 NEES
Form 10-K, File No. 1-3446); Additional Power Contract
dated as of February 1, 1984 (Exhibit 10(k) to NEES'
1983 Form 10-K, File No. 1-3446); Guarantee Agreement
dated as of November 5, 1981 (Exhibit 10(j) to NEES'
1981 Form 10-K, File No. 1-3446); 1999 Amendatory
Agreement dated as of November 17, 1999 and 1999
Restated Amendatory Agreement dated as of November 17,
1999 (filed herewith)
(o) Yankee Atomic Electric Company et al. and the Company:
Amended and Restated Power Contract dated April 1, 1985
(Exhibit 10(l) to NEES' 1985 Form 10-K, File No.
1-3446); Amendment dated May 6, 1988 (Exhibit 10(l) to
NEES' 1988 Form 10-K, File No. 1-3446); Amendments
dated as of June 26, 1989 and July 1, 1989 (Exhibit
10(l) to 1989 NEES Form 10-K, File No. 1-3446);
Amendment dated as of February 1, 1992 (Exhibit 10(l)
to 1992 NEES Form 10-K, File No. 1-3446).
*(p) New England Electric Companies' Deferred Compensation
Plan as amended through February 28, 1998 (Exhibit
10(l) to NEES' 1998 Form 10-K, File No. 1-3446);
Amendments effective as of March 1, 1999 and September
1, 1999 (filed herewith)
*(q) New England Electric System Companies Retirement
Supplement Plan as amended through June 1, 1996
(Exhibit 10(n) to NEES' 1996 Form 10-K, File No.
1-3446); Amendment dated as of March 1, 1999 (filed
herewith)
*(r) New England Electric Companies' Executive Supplemental
Retirement Plan I as amended through December 11, 1998
(Exhibit 10(n) to NEES' 1998 Form 10-K, File No.
1-3446); Amendment dated as of March 1, 1999 (filed
herewith)
<PAGE>
*(s) New England Electric Companies Executive Retirees
Health and Life Insurance Plan as Amended and Restated
January 1, 1996 (Exhibit 10(o) to NEES' 1998 Form 10-K,
File No. 1-3446).
*(t) New England Electric Companies' Incentive Compensation
Plan I as amended through January 1, 1998 (Exhibit
10(p) to NEES' 1998 Form 10-K, File No. 1-3446).
*(u) New England Electric Companies' Incentive Compensation
Plan II as amended through January 1, 1998 (Exhibit
10(q) to NEES' 1998 Form 10-K, File No. 1-3446).
*(v) New England Electric Companies' Incentive Compensation
Plan III as amended through January 1, 1998 (Exhibit
10(r) to NEES' 1998 Form 10-K, File No. 1-3446).
*(w) New England Electric Companies' Senior Incentive
Compensation Plan as amended through January 1, 1998
(Exhibit 10(s) to NEES' 1998 Form 10-K, File No.
1-3446).
*(x) Forms of Life Insurance Program (Exhibit 10(s) to NEES'
1986 Form 10-K, File No. 1-3446); and Form of Life
Insurance (Collateral Assignment) (Exhibit 10(t) to
NEES' 1991 Form 10-K, File No. 1-3446).
*(y) New England Electric Companies' Incentive Share Plan as
amended through February 24, 1997 (Exhibit 10(w) to
NEES' 1996 Form 10-K, File No. 1-3446); Amendment dated
as of March 1, 1999 (filed herewith)
*(z) Forms of Severance Protection Agreement (Exhibit 10(z)
to NEES' 1996 Form 10-K, File No. 1-3446). Forms of
Severance Protection Agreements (Exhibit 10(y) to NEES'
1998 Form 10-K, File No. 1-3446).
*(aa) New England Electric Companies' Long-Term
Performance Share Award Plan amended through
August 25, 1998 (Exhibit 10(w) to NEES' 1998 Form
10-K, File No. 1-3446); Amendment dated as of
March 1, 1999 (filed herewith)
<PAGE>
(bb) New England Hydro-Transmission Electric Company,
Inc. et al. and the Company: Phase II
Massachusetts Transmission Facilities Support
Agreement dated as of June 1, 1985 (Exhibit 10(t)
to NEES' 1986 Form 10-K, File No. 1-3446);
Amendment dated as of May 1, 1986 (Exhibit 10(t)
to NEES' 1986 Form 10-K, File No. 1-3446);
Amendments dated as of February 1, 1987, June 1,
1987, September 1, 1987, and October 1, 1987
(Exhibit 10(u) to NEES' 1987 Form 10-K, File No.
1-3446); Amendment dated as of August 1, 1988
(Exhibit 10(u) to NEES' 1988 Form 10-K, File No.
1-3446); Amendment dated January 1, 1989 (Exhibit
10(u) to NEES' 1990 Form 10-K, File No. 1-3446).
(cc) New England Hydro-Transmission Corporation et al.
and the Company: Phase II New Hampshire
Transmission Facilities Support Agreement dated as
of June 1, 1985 (Exhibit 10(u) to NEES' 1986 Form
10-K, File No. 1-3446); Amendment dated as of
May 1, 1986 (Exhibit 10(u) to NEES' 1986 Form
10-K, File No. 1-3446); Amendments dated as of
February 1, 1987, June 1, 1987, September 1, 1987,
and October 1, 1987 (Exhibit 10(v) to NEES' 1987
Form 10-K, File No. 1-3446). Amendment dated as
of August 1, 1988 (Exhibit 10(v) to NEES' 1988
Form 10-K, File No. 1-3446); Amendments dated
January 1, 1989 and January 1, 1990 (Exhibit 10
(v) to NEES' 1990 Form 10-K, File No. 1-3446).
(dd) Vermont Electric Power Company et al. and the
Company: Phase II New England Power AC Facilities
Support Agreement dated as of June 1, 1985
(Exhibit 10(v) to NEES' 1986 Form 10-K, File No.
1-3446); Amendment dated as of May 1, 1986
(Exhibit 10(v) to NEES' 1986 Form 10-K, File No.
1-3446). Amendments dated as of February 1, 1987,
June 1, 1987, and September 1, 1987 (Exhibit 10(w)
to NEES' 1987 Form 10-K, File No. 1-3446);
Amendment dated as of August 1, 1988 (Exhibit
10(w) to NEES' 1988 Form 10-K, File No. 1-3446).
<PAGE>
(ee) USGen New England Contracts
(i) Asset Purchase Agreement among the Company,
The Narragansett Electric Company and, USGen
New England, Inc. dated as of August 5, 1997
(Exhibit 2 to NEES' Form 10-Q for period
ended September 30, 1997, File No. 1-3446);
Amendment No. 1 dated as of September 25,
1997, Amendment No. 2 dated as of October 29,
1997, Amendment No. 3 dated as of August 5,
1997, Amendment No. 4 dated as of September
1, 1998 (filed herewith)
(ii) Wholesale Sales Agreement between the Company
and USGen New England, Inc. dated as of
August 5, 1997 (Exhibit 10(gg)(ii) to 1997
Form 10-K, File No. 1-6564); Amendment No. 1
dated as of September 25, 1997, Amendment No.
2 dated as of September 1, 1998 (filed
herewith)
(iii) PPA Transfer Agreement between the Company
and USGen New England, Inc. dated as of
August 5, 1997 (Exhibit 10(gg)(iii) to 1997
Form 10-K, File No. 1-6564).
(iv) Form of PSA Performance Support Agreement
between the Company, USGen New England, Inc.,
and each of the following; North Attleboro
Electric Department, Groton Electric Light
Department, Middleton Municipal Electric
Department, Hingham Municipal Lighting Plant,
Town of Holden Municipal Light Department,
Unitil Power Corp. (Salem Harbor), Unitil
Power Corp. (Ocean State), Bangor Hydro-
Electric Company, Montaup Electric Company,
Central Vermont Public Service Corporation,
Braintree Electric Light Department,
Littleton Electric Light Department,
Massachusetts Government Land Bank, Reading
(MA) Municipal Light Department, Shrewsbury
Electric Light Plant, Taunton Municipal Light
Plant, and Vermont Electric Company, dated as
of August 5, 1997 (Exhibit 10(gg)(iv) to 1997
Form 10-K, File No. 1-6564).
<PAGE>
(v) Quebec Interconnection Transfer Agreement
between the Company, The Narragansett
Electric Company, and USGen New England, Inc.
dated as of September 1, 1998 (filed
herewith).
* Compensation related plan, contract, or arrangement.
(13) 1999 Annual Report to Stockholders (filed herewith).
(21) Subsidiary list (filed herewith).
(24) Power of Attorney (filed herewith).
(27) Financial Data Schedule (filed herewith).
<PAGE>
Reports on Form 8-K
NEP filed reports on Form 8-K dated October 21, 1999, October
29, 1999, November 29, 1999, and December 10, 1999, each of which
contained ITEM 5.
<PAGE>
NEW ENGLAND 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 signature
of the undersigned company shall be deemed to relate only to matters having
reference to such company.
NEW ENGLAND POWER COMPANY
s/Peter G. Flynn
Peter G. Flynn
President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated. The signature of
each of the undersigned shall be deemed to relate only to matters having
reference to the above-named company.
(Signature and Title)
Principal Executive Officer
s/Peter G. Flynn
Peter G. Flynn
President
Principal Financial Officer
s/John G. Cochrane
John G. Cochrane
Treasurer
Principal Accounting Officer
s/Kwong O. Nuey
Kwong O. Nuey
Controller
Directors (a majority)
Cynthia A. Arcate
L. Joseph Callan
Peter G. Flynn
Alfred D. Houston
Cheryl A. LaFleur s/John G. Cochrane
Richard P. Sergel All by:
Philip R. Sharp John G. Cochrane
Attorney-in-fact
Date (as to all signatures on this page)
March 30, 2000
<PAGE>
<TABLE>
NEW ENGLAND POWER COMPANY
INDEX TO FINANCIAL STATEMENTS
<CAPTION>
References (Page)
----------------------
1999 Annual
Form Report to
10-K Shareholders*
---- -------------
<S> <C> <C>
Report of Independent Accountants........................... 4
Statements of Income,
Year Ended December 31, 1999, 1998 and 1997............... 15
Statements of Retained Earnings,
Year Ended December 31, 1999, 1998 and 1997............... 15
Balance Sheets, December 31, 1999 and 1998.................. 16
Statements of Cash Flows,
Year Ended December 31, 1999, 1998 and 1997............... 17
Notes to Financial Statements............................... 18-42
* Incorporated by Reference.
</TABLE>
<PAGE>
NEP
EXHIBIT INDEX
-------------
Exhibit No. Description Page
- ----------- ----------- ----
(3)(a) Articles of Organization as Incorporated
amended through June 25, 1987 by Reference
(3)(b) By-laws of the Company as Incorporated
amended December 12, 1997 by Reference
(10)(a) Boston Edison Company et al. Incorporated
and the Company: Amended by Reference
REMVEC Agreement dated
August 12, 1977
(10)(a)(i) Boston Edison Company et al. Incorporated
and the Company: REMVEC II by Reference
Agreement dated on or about
July 1, 1997
(10)(a)(ii) Boston Edison Company et al. Incorporated
and the Company: Security by Reference
Analysis Services Agreement
dated on or about July 1, 1997
(10)(b) The Connecticut Light and Power Incorporated
Company et al. and the Company: by Reference
Sharing Agreement for Joint
Ownership, Construction and
Operation of Millstone Unit No. 3
dated as of September 1, 1973,
and Amendments thereto;
Transmission Support Agreement
dated August 9, 1974; Instrument
of Transfer to the Company with
respect to the 1979 Connecticut
Nuclear Unit, and Assumption of
Obligations, dated December 17,
1975
<PAGE>
(10)(c) Connecticut Yankee Atomic Power Incorporated
Company et al. and the Company: by Reference
Stockholders Agreement dated
July 1, 1964; Power Purchase
Contract dated July 1, 1964;
Additional Power Contract dated
as of April 30, 1984 and 1996;
Amendatory Agreement dated as
of December 4, 1996;
Supplementary Power Contract
dated as of April 1, 1987;
Capital Funds Agreement dated
September 1, 1964; Transmission
Agreement dated October 1, 1964;
Agreement revising Transmission
Agreement dated July 1, 1979;
Amendment revising Transmission
Agreement dated as of January 19,
1994; Five Year Capital Contribution
Agreement dated November 1, 1980
(10)(d) Maine Yankee Atomic Power Incorporated
Company et al. and the Company: by Reference
Capital Funds Agreement dated
May 20, 1968 and Power Purchase
Contract dated May 20, 1968;
and Amendments thereto;
Stockholders Agreement dated
May 20, 1968; Additional Power
Contract dated as of February 1,
1984; 1997 Amendatory Agreement
dated as of August 6, 1997
(10)(e) Mass. Electric and the Company: Incorporated
Primary Service for Resale dated by Reference
February 15, 1974; and Amendments
thereto; Memorandum of Understanding
effective May 22, 1994;
Amendment of Service Agreement
effective July 1, 1996;
Amendment to Service Agreement
dated as of February 1, 1997;
Supplement to Amendment to Service
Agreement dated as of March 1, 1998
<PAGE>
Supplement to Service Filed herewith
Agreement dated as of
December 31, 1999
(10)(f) The Narragansett Electric Incorporated
Company and the Company: by Reference
Primary Service for Resale
dated February 15, 1974
and Amendments thereto;
Memorandum of Understanding
effective May 22, 1994 and
Amendment thereto;
Amendment of Service Agreement
effective October 30, 1995;
Amendment to Service Agreement
dated as of February 1, 1997;
Supplement to Amendment to
Service Agreement dated as of
December 31, 1998
Supplement to Service Filed herewith
Agreement dated as of
December 31, 1999
(10)(g) New England Electric Incorporated
Transmission Corporation et al. by Reference
and the Company: Phase I
Terminal Facility Support
Agreement dated as of
December 1, 1981; Amendments
dated as of June 1, 1982 and
November 1, 1982; Agreement with
respect to Use of the Quebec
Interconnection dated as of
December 1, 1981; Amendments
dated as of May 1, 1982 and
November 1, 1982; Amendment
dated as of January 1, 1986;
Agreement for Reinforcement
and Improvement of the Company's
Transmission System dated as
of April 1, 1983; Lease dated
as of May 16, 1983; Upper
Development-Lower Development
Transmission Line Support
Agreement dated as of May 16,
1983
<PAGE>
(10)(h) Vermont Electric Transmission Incorporated
Company, Inc. et al. and the by Reference
Company: Phase I Vermont
Transmission Line Support
Agreement dated as of
December 1, 1981 and Amendments
thereto
(10)(i) New England Power Pool Filed herewith
Agreement and Amendments
thereto
(10)(j) New England Power Service Incorporated
Company and the Company: by Reference
Specimen of Service Contract
(10)(k) Massachusetts Electric Incorporated
Company, et al. and the by Reference
Company: Form of Mutual
Assistance Agreement
(10)(l) Massachusetts Electric Incorporated
Company, et al. and the by Reference
Company: Restructuring
Settlement Agreement
approved by the Massachusetts
Department of Public Utilities
(10)(m) Public Service Company of New Incorporated
Hampshire et al. and the by Reference
Company: Agreement for Joint
Ownership, Construction and
Operation of New Hampshire
Nuclear Units dated as of
May 1, 1973 and Amendments
thereto; Seventh Amendment
as of November 1, 1990;
Transmission Support Agreement
dated as of May 1, 1973;
Instrument of Transfer to the
Company with respect to the New
Hampshire Nuclear Units and
Assumptions of Obligations
dated December 17, 1975 and
Agreement Among Participants
in New Hampshire Nuclear Units,
<PAGE>
certain Massachusetts Municipal
Systems and Massachusetts
Municipal Wholesale Electric
Company dated May 28, 1976;
Seventh Amendment To and
Restated Agreement for Seabrook
Project Disbursing Agent dated
as of November 1, 1990;
Amendments dated as of
June 29, 1992;
Settlement Agreement dated as
of July 19, 1990 between
Northeast Utilities Service
Company and the Company;
Seabrook Project Managing
Agent Operating Agreement
dated as of June 29, 1992;
and Amendment thereto
(10)(n) Vermont Yankee Nuclear Power Incorporated
Corporation et al. and the by Reference
Company: Capital Funds
Agreement dated February 1,
1968, Amendment dated March 12,
1968 and Power Purchase Contract
dated February 1, 1968 and
Amendments thereto; Additional
Power Contract dated as of
February 1, 1984; Guarantee
Agreement dated as of November 5,
1981
1999 Amendatory Agreements Filed herewith
(10)(o) Yankee Atomic Electric Company Incorporated
et al. and the Company: by Reference
Amended and Restated Power
Contract dated April 1, 1985
and Amendments thereto
(10)(p) New England Electric Companies' Filed herewith
Deferred Compensation Plan as
amended through February 28,
1998 and amendments thereto
<PAGE>
(10)(q) New England Electric System Filed herewith
Companies Retirement Supplement
Plan as amended through June 1,
1996 and an Amendment thereto
(10)(r) New England Electric Companies' Filed herewith
Executive Supplemental Retirement
Plan I as amended through
December 11, 1998 and an Amendment
thereto
(10)(s) New England Electric Companies' Incorporated
Executive Retirees Health and Life by Reference
Insurance Plan as Amended and
Restated January 1, 1996
(10)(t) New England Electric Companies' Incorporated
Incentive Compensation Plan I as by Reference
amended through January 1, 1998
(10)(u) New England Electric Companies' Incorporated
Incentive Compensation Plan II as by Reference
amended through January 1, 1998
(10)(v) New England Electric Companies' Incorporated
Incentive Compensation Plan III as by Reference
amended through January 1, 1998
(10)(w) New England Electric Companies' Incorporated
Senior Incentive Compensation by Reference
Plan as amended through
January 1, 1998
(10)(x) Forms of Life Insurance Program Incorporated
and Form of Life Insurance by Reference
(Collateral Assignment)
(10)(y) New England Electric Companies' Filed herewith
Incentive Share Plan as amended
through February 24, 1997 and an
Amendment thereto
(10)(z) Forms of Severance Protection Incorporated
Agreements by Reference
<PAGE>
(10)(aa) New England Electric Companies' Filed herewith
Long-Term Performance Share
Award Plan amended through
August 25, 1998 and Amendments
thereto
(10)(bb) New England Hydro-Transmission Incorporated
Electric Company, Inc. et al. by Reference
and the Company: Phase II
Massachusetts Transmission
Facilities Support Agreement
dated as of June 1, 1985
and Amendments thereto
(10)(cc) New England Hydro-Transmission Incorporated
Corporation et al. and the by Reference
Company: Phase II New Hampshire
Transmission Facilities Support
Agreement dated as of June 1,
1985 and Amendments thereto
(10)(dd) Vermont Electric Power Company Incorporated
et al. and the Company: Phase by Reference
II New England Power AC
Facilities Support Agreement
dated as of June 1, 1985 and
Amendments thereto
(10)(ee)(i) Asset Purchase Agreement between Incorporated
USGen New England and the Company by Reference
and The Narragansett Electric
Company dated as of August 5, 1997
(10)(ee)(ii) Wholesale Sales Agreement between Incorporated
the Company and USGen New England, by Reference
Inc. dated as of August 5, 1997
(10)(ee)(iii) PPA Transfer Agreement between Incorporated
the Company and USGen New England, by Reference
Inc. dated as of August 5, 1997
(10)(ee)(iv) Form of PSA Performance Support Incorporated
Agreement between the Company, by Reference
USGen New England, Inc., and
various Wholesale Customers
dated as of August 5, 1997
<PAGE>
(10)(ee)(v) Quebec Interconnection Transfer Filed herewith
Agreement between the Company,
The Narragansett Electric Company,
and USGen New England, Inc.,
dated as of September 1, 1998
(13) 1999 Annual Report to Filed herewith
Stockholders
(21) Subsidiary list Filed herewith
(24) Power of Attorney Filed herewith
(27) Financial Data Schedule Filed herewith
<PAGE> ATTACHMENT 2
SECOND COMPOSITE
RESTATED
NEW ENGLAND
POWER POOL AGREEMENT
(As amended through the Fifty-First Agreement
Amending New England Power Pool Agreement)
<PAGE>TABLE OF CONTENTS
PART ONE
INTRODUCTION12
SECTION 1
DEFINITIONS12
1.1Adjusted Load13
1.2Adjusted Monthly Peak13
1.3Adjusted Net Interchange13
1.3AAdministrative Procedures14
1.4AGC Capability14
1.5AGC Entitlement14
1.6Agreement15
1.7Annual Transmission Revenue Requirements15
1.8Automatic Generation Control or AGC15
1.8ABalloting Agent16
1.9Bid Price16
1.10Commission16
1.11Control Area17
1.12Curtailment18
1.13Direct Assignment Facilities18
1.14Dispatch Price18
1.15EHV PTF19
1.16Electrical Load19
1.17Eligible Customer20
1.17AEnd User Participant21
1.18Energy21
1.19Energy Entitlement21
1.20Entitlement22
1.21Entity22
1.22Excepted Transaction23
1.23[Deleted.]23
1.24Facilities Study23
1.25Firm Contract24
1.26First Effective Date24
1.27Good Utility Practice24
1.28HQ Contracts25
1.29HQ Energy Banking Agreement25
1.30HQ Interconnection25
1.31HQ Interconnection Agreement26
1.32HQ Interconnection Capability Credit26
1.33HQ Interconnection Transfer Capability27
1.34HQ Net Interconnection Capability Credit28
1.35HQ Phase I Energy Contract28
1.36HQ Phase I Percentage28
1.37HQ Phase I Transfer Credit28
1.38HQ Phase II Firm Energy Contract29
1.39HQ Phase II Gross Transfer Responsibility29
1.40HQ Phase II Net Transfer Responsibility29
1.41HQ Phase II Percentage30
1.42HQ Phase II Transfer Credit30
1.43HQ Use Agreement30
1.44Installed Capability30
1.45Installed Capability Entitlement31
1.46Installed Capability Responsibility31
1.47Installed System Capability31
1.48Interchange Transactions32
1.49Internal Point-to-Point Service32
<PAGE>
1.50Interruption32
1.51ISO32
1.52Kilowatt33
1.52ALiaison Committee33
1.53Load33
1.54Local Network35
1.55Local Network Service35
1.56Lower Voltage PTF35
1.57Market Products35
1.57AMarket Rules36
1.58[Deleted.]36
1.58AMarkets Committee36
1.59Monthly Peak36
1.60NEPOOL36
1.61NEPOOL Control Area37
1.62NEPOOL Installed Capability38
1.63NEPOOL Installed Capability Responsibility38
1.64NEPOOL Objective Capability38
1.64ANEPOOL Market38
1.64BNEPOOL System Rules39
1.64CNERC39
1.65New Unit39
1.66Non-Participant39
1.66ANPCC39
1.66BOASIS39
1.67Operable Capability40
1.68[Deleted].40
1.69[Deleted]. 40
1.70[Deleted]. 40
1.71Operating Reserve40
1.72Operating Reserve Entitlement40
1.73Other HQ Energy41
1.74Participant41
1.74AParticipants Committee42
1.75Pool-Planned Facility42
1.76Pool-Planned Unit42
1.77Power Year42
1.78Prior NEPOOL Agreement43
1.79Proxy Unit43
1.80PTF43
1.80APublicly Owned Entity43
1.81[Deleted.]44
1.82Regional Network Service44
1.83[Deleted.]44
1.84[Deleted.]44
1.85Related Person44
1.85AReliability Committee45
1.85BReliability Standards45
1.85CReview Board45
1.86Scheduled Dispatch Period46
1.87Second Effective Date46
1.87ASector46
1.88Service Agreement46
1.89Summer Capability46
1.90Summer Period47
1.91System Contract47
1.92System Impact Study47
<PAGE>
1.93System Operator48
1.94Target Availability Rate48
1.95Tariff48
1.95ATariff Committee48
1.95BTechnical Committees49
1.96Third Effective Date49
1.97Through or Out Service49
1.98Transition Period49
1.99Transmission Customer50
1.99ATransmission Owner50
1.99BTransmission Owners Committee51
1.100Transmission Provider51
1.101Unit Contract51
1.102[Deleted.]52
1.103Winter Capability52
1.104Winter Period52
1.10510-Minute Spinning Reserve52
1.10610-Minute Non-Spinning Reserve53
1.10730-Minute Operating Reserve54
1.108[Deleted.]55
1.109Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another
Participant Pursuant to Firm Contract55
SECTION 2
PURPOSE; EFFECTIVE DATES58
2.1Purpose58
2.2Effective Dates; Transitional Provisions59
SECTION 3
MEMBERSHIP60
3.1Membership60
3.2Operations Outside the Control Area61
3.3Lack of Place of Business in New England62
3.4Obligation for Deferred Expenses63
3.5Financial Security63
SECTION 4
STATUS OF PARTICIPANTS64
4.1Treatment of Certain Entities as Single Participant64
4.2Participants to Retain Separate Identities65
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS65
5.1NEPOOL Objectives65
5.2Cooperation by Participants67
PART TWO GOVERNANCE68
SECTION 6
COMMITTEE ORGANIZATION AND VOTING68
6.1Principal Committees68
6.2Sector Representation69
6.3Appointment of Members and Alternates77
6.4Term of Members78
6.5Regular and Special Meetings78
6.6Notice of Meetings79
6.7Attendance79
6.8Quorum80
<PAGE>
6.9Voting Definitions80
6.10Voting On Proposed Actions84
6.11Voting On Amendments84
6.12Designated Representatives and Proxies88
6.13Limits on Representatives89
6.14Adoption of Bylaws89
6.15Joint Meetings of Technical Committees90
SECTION 7
PARTICIPANTS COMMITTEE91
7.1Officers91
7.2Adoption of Budgets91
7.3Establishing Reliability Standards91
7.4Appointment and Compensation of NEPOOL Personnel92
7.5Duties and Authority92
7.6Attendance of Participants at Committee Meeting99
7.7Appeal of Actions to Review Board99
SECTION 8
RELIABILITY COMMITTEE101
8.1Officers101
8.2Notice to Members and Alternates of Participants Committee102
8.3Voting; Appeal of Actions102
8.4Responsibilities103
8.5Establishment of Subcommittees and Task Forces108
8.6Further Powers and Duties109
SECTION 9
TARIFF COMMITTEE109
9.1Officers109
9.2Notice to Members and Alternates of Participants Committee110
9.3Voting; Appeal of Actions110
9.4Responsibilities111
9.5Establishment of Subcommittees and Task Forces112
9.6Further Powers and Duties113
SECTION 10
MARKETS COMMITTEE113
10.1Officers113
10.2Notice to Members and Alternates of Participants Committee114
10.3Voting; Appeal of Actions114
10.4Responsibilities115
10.5Establishment of Subcommittees and Task Forces118
10.6Further Powers and Duties118
10.7Development of Rules Relating to Non-Participant
Supply and Demand-side Resources118
SECTION 11
FURTHER RESTRUCTURING119
SECTION 11A
REVIEW BOARD120
11A.1Organization120
11A.2Composition121
11A.3Qualifications122
11A.4Term123
11A.5Meetings123
11A.6Bylaws123
11A.7Procedure on Appeal of Participant Committee Action or
Failure to Take Action124
11A.8Effect of a Review Board Decision127
<PAGE>SECTION 11B
TRANSMISSION OWNERS COMMITTEE129
11B.1Organization129
11B.2Membership130
11B.3Appointment of Members and Alternates130
11B.4Term of Members130
11B.5Regular and Special Meetings131
11B.6Notice of Meetings131
11B.7Attendance131
11B.8Votes132
11B.9Appointment of Task Forces or Working Groups133
11B.10 Officers133
11B.11 Adoption of Bylaws133
11B.12 Review of Committee Actions134
SECTION 11C
LIAISON COMMITTEE135
11C.1Organization; Duties135
11C.2Membership135
11C.3Regular and Special Meetings136
11C.4Notice of Meetings136
11C.5Attendance136
11C.6Officers137
PART THREE
MARKET PROVISIONS138
SECTION 12
INSTALLED CAPABILITY
OBLIGATIONS AND PAYMENTS138
12.1Obligations to Provide Installed Capability.138
12.2Computation of Installed Capability Responsibilities138
12.3[Deleted].159
12.4Bids to Furnish Installed Capability159
12.5Consequences of Deficiencies in Installed Capability
Responsibility160
12.6[Deleted]. 162
12.7Payments to Participants Furnishing Installed Capability162
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE CONTRACTS164
13.1Maintenance and Operation in Accordance with
Good Utility Practice164
13.2Central Dispatch164
13.3Maintenance and Repair165
13.4Objectives of Day-to-Day System Operation165
13.5Satellite Membership166
SECTION 14
INTERCHANGE TRANSACTIONS167
14.1Obligation for Energy, Operating Reserve and Automatic Generation
Control167
14.2Obligation to Bid or Schedule, and Right to Receive Energy, Operating
Reserve and Automatic Generation Control170
14.3Amount of Energy, Operating Reserve and Automatic Generation Control
Received or Furnished176
14.4Payments by Participants Receiving Energy Service, Operating Reserve
and Automatic Generation Control179
14.5Payments to Participants Furnishing Energy Service, Operating
Reserve, and Automatic Generation Control181
14.6Energy Transactions with Non-Participants184
14.7Participant Purchases Pursuant to Firm Contracts and System
Contracts187
<PAGE>
14.8Determination of Energy Clearing Price188
14.9Determination of Operating Reserve Clearing Price189
14.10Determination of AGC Clearing Price192
14.11Funds to or from which Payments are to be Made193
14.12Development of Rules Relating to Nuclear and
Hydroelectric Generating Facilities, Limited-Fuel
Generating Facilities, and Interruptible Loads201
14.13Dispatch and Billing Rules During Energy Shortages202
14.14Congestion Uplift.203
14.15Additional Uplift Charges. 207
PART FOUR
TRANSMISSION PROVISIONS208
SECTION 15
OPERATION OF TRANSMISSION FACILITIES208
15.1Definition of PTF208
15.2Maintenance and Operation in Accordance with
Good Utility Practice213
15.3Central Dispatch213
15.4Maintenance and Repair214
15.5Additions to or Upgrades of PTF214
SECTION 16
SERVICE UNDER TARIFF217
16.1Effect of Tariff217
16.2Obligation to Provide Regional Service217
16.3Obligation to Provide Local Network Service218
16.4Transmission Service Availability221
16.5Transmission Information222
16.6Distribution of Transmission Revenues222
SECTION 17
POOL-PLANNED UNIT SERVICE226
17.1Effective Period226
17.2Obligation to Provide Service226
17.3Rules for Determination of Facilities Covered by Particular
Transactions227
17.4Payments for Uses of EHV PTF During the Transition Period229
17.5Payments for Uses of Lower Voltage PTF233
17.6Use of Other Transmission Facilities by Participants234
17.7Limits on Individual Transmission Charges235
SECTION 17A
TRANSMISSION OWNERS RESERVED RIGHTS235
17A.1236
17A.2236
17A.3237
17A.4237
17A.5238
17A.6238
17A.7238
17A.8239
PART FIVE
GENERAL241
SECTION 18
GENERATION AND TRANSMISSION FACILITIES241
18.1Designation of Pool-Planned Facilities241
18.2Construction of Facilities241
<PAGE>
18.3Protective Devices for Transmission Facilities and Automatic
Generation Control Equipment242
18.4Review of Participant's Proposed Plans243
18.5Participant to Avoid Adverse Effect244
SECTION 19
EXPENSES245
19.1Annual Fee.245
19.2NEPOOL Expenses247
19.3Restructuring Costs249
SECTION 20
INDEPENDENT SYSTEM OPERATOR255
SECTION 21
MISCELLANEOUS PROVISIONS263
21.1Alternative Dispute Resolution263
21.2Payment of Pool Charges; Termination of Status as
Participant276
21.3Assignment280
21.4Force Majeure281
21.5Waiver of Defaults282
21.6Other Contracts282
21.7Liability and Insurance283
21.8Records and Information284
21.9Consistency with NPCC and NERC Standards285
21.10Construction285
21.11Amendment285
21.12Termination286
21.13Notices to Participants, Committees, Committee Members,
or the System Operator287
21.14Severability and Renegotiation291
21.15No Third-Party Beneficiaries292
21.16Counterparts292
<PAGE>COMPOSITE RESTATED NEW ENGLAND 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 May 7, 1999.
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):
1.1Adjusted 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.
1.2Adjusted 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.
1.3Adjusted 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 Markets
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.
1.3AAdministrative Procedures are procedures adopted by the System Operator in
order to fulfill its responsibilities to apply and implement NEPOOL System
Rules.
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 Markets 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.
1.5AGC 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
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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, Energy Entitlement, or Operating Reserve Entitlements.
1.6Agreement is this restated contract and attachments, including the Tariff,
as amended and restated from time to time.
1.7Annual 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.
1.8Automatic 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.
1.8ABalloting Agent is the Secretary of the Participants Committee.
1.9Bid 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 Markets Committee, as compensation for
(i) furnishing Installed 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, Energy, Operating
Reserve and/or AGC pursuant to a Firm Contract or System Contract in
accordance with Section 14.7.
1.10Commission is the Federal Energy Regulatory Commission.
1.11Control 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 NERC; and
(4)provide sufficient generating capacity to maintain operating reserves
in accordance with Good Utility Practice.
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1.12Curtailment is a reduction in firm or non-firm transmission service in
response to a transmission capacity shortage as a result of system reliability
conditions.
1.13Direct 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
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 in accordance
with the separate agreement and not under the Tariff.
1.14Dispatch 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
Markets Committee to incorporate the Bid Price for such Energy and any loss
adjustments, if and as appropriate under such market operation rules.
1.15EHV 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.
1.16Electrical 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.
1.17Eligible 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 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
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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 with which that
end user is directly interconnected, is an Eligible Customer under the Tariff.
1.17AEnd User Participant is a Participant which is a consumer of electricity
in the NEPOOL Control Area that generates or purchases electricity primarily
for its own consumption or a non-profit group representing such consumers.
1.18Energy is power produced in the form of electricity, measured in
kilowatthours or megawatthours.
1.19Energy 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,
Operating Reserve Entitlements, or AGC Entitlement.
1.20Entitlement is an Installed 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.
1.21Entity 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, Energy, Operating
Reserve, and/or AGC for resale); or
(b)a consumer of electricity in the NEPOOL Control Area that generates or
purchases electricity primarily for its own consumption or a non-profit group
representing such consumers.
1.22Excepted Transaction is a transaction specified in Section 25 of the
Tariff for the applicable period specified in that Section, or in Sections 25A
and 25B of the Tariff.
1.23[Deleted.]
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1.24Facilities 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.
1.25Firm Contract is any contract, other than a Unit Contract, for the
purchase of Installed Capability, Energy, Operating Reserves, and/or AGC,
pursuant to which the purchaser's right to receive such Installed 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.
1.26First Effective Date is March 1, 1997.
1.27Good 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.
1.28HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I Energy
Contract, and the HQ Phase II Firm Energy Contract.
1.29HQ 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.
1.30HQ 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.
1.31HQ 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.
1.32HQ 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
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percentage share, if any, of the HQ Phase II Transfer Capability, times (b)
the HQ Phase II Transfer Credit. The Participants 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.
1.33HQ 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 Markets 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.
1.34HQ 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.
1.35HQ 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.
1.36HQ Phase I Percentage is the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase I Transfer Capability.
1.37HQ 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
Participants Committee may establish.
1.38HQ 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.
1.39HQ 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 Participants Committee shall establish an
appropriate HQ Phase II Gross Transfer Responsibility that shall remain in
effect concurrently with the HQ Interconnection Capability Credit.
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1.40HQ 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.
1.41HQ Phase II Percentage is the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase II Transfer Capability.
1.42HQ 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 Participants Committee may establish.
1.43HQ 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.
1.44Installed 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.
1.45Installed 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 Energy Entitlement, Operating Reserve Entitlements, or AGC
Entitlement.
1.46Installed Capability Responsibility * of a Participant for any month is
the number of Kilowatts determined in accordance with Section 12.2.
1.47Installed 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.
1.48Interchange 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.
1.49Internal Point-to-Point Service is the transmission service by that name
provided pursuant to Section 19 of the Tariff.
1.50Interruption 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.
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1.51ISO 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.
1.52Kilowatt is a kilowatthour per hour.
1.52ALiaison Committee is the committee whose responsibilities are specified
in Section 11C.
1.53Load * (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 Markets 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 Markets 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.
1.54Local 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
Participants Committee may designate or approve from time to time. The
Participants Committee may not unreasonably withhold approval of a request by
a Participant that it effect such a change or designation.
1.55Local 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.
1.56Lower Voltage PTF are all PTF facilities other than EHV PTF.
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1.57Market Products are Installed Capability, Operable Capability, Energy,
each category of Operating Reserve and AGC.
1.57AMarket Rules are the system rules and operating procedures adopted
pursuant to the System Operator Agreement in connection with the
administration of the NEPOOL Market.
1.58[Deleted.]
1.58AMarkets Committee is the committee whose responsibilities are specified
in Section 10 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Markets Committee shall
include the prior Regional Market Operations Committee as the predecessor of
the Markets Committee.
1.59Monthly Peak of a Participant for a month is the maximum Adjusted Load of
the Participant during any hour in the month.
1.60NEPOOL 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.
1.61NEPOOL 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 NPCC and NERC; and
(iv)provide sufficient generating capacity to maintain operating reserves
in accordance with Good Utility Practice.
1.62NEPOOL Installed Capability at any particular time is the sum of the
Installed System Capabilities of all Participants at such time.
1.63NEPOOL Installed Capability Responsibility for any month is the sum of the
Installed Capability Responsibilities of all Participants during that month.
1.64NEPOOL 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 Participants
Committee, required to be provided by the Participants in aggregate for the
period to meet the reliability standards established by the Participants
Committee pursuant to Section 7.5(e).
1.64ANEPOOL Market is the market for electric energy, capacity and certain
ancillary services within the NEPOOL Control Area.
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1.64BNEPOOL System Rules are the Market Rules, the NEPOOL Information Policy
and any other system rules for the operation of the System and administration
of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.
1.64CNERC is the North American Electric Reliability Council.
1.65New 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.
1.66Non-Participant is any entity which is not a Participant.
1.66ANPCC is the Northeast Power Coordinating Council.
1.66BOASIS is the Open Access Same-Time Information System of the System
Operator.
1.67Operable 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 Markets 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 Markets Committee.
1.68[Deleted].
1.69[Deleted].
1.70[Deleted].
1.71Operating 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.
1.72Operating 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, Energy Entitlement, or AGC
Entitlement.
1.73Other HQ Energy is Energy purchased under the HQ Phase I Energy Contract
which is classified as "Other Energy" under that contract.
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1.74Participant 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.
1.74AParticipants Committee is the committee whose responsibilities are
specified in Section 7. To the extent applicable, references in the Agreement
to the Participants Committee shall include the prior Management Committee or
Executive Committee as the predecessor of the Participants Committee.
1.75Pool-Planned Facility is a generation or transmission facility designated
as "pool-planned" pursuant to Section 18.1.
1.76Pool-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).
1.77Power 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.
1.78Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December 1,
1996.
1.79Proxy 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).
1.80PTF are the pool transmission facilities defined in Section 15.1, and any
other new transmission facilities which the Reliability Committee determines,
in accordance with criteria approved by the Participants Committee and subject
to review by the System Operator, should be included in PTF.
1.80APublicly Owned Entity is an Entity which is either a municipality or an
agency thereof, or a body politic and public corporation created under the
authority of one of the New England states, authorized to own, lease and
operate electric generation, transmission or distribution facilities, or an
electric cooperative, or an organization of any such entities.
1.81[Deleted.]
1.82Regional Network Service is the transmission service by that name provided
pursuant to Section 14 of the Tariff.
1.83[Deleted.]
1.84[Deleted.]
1.85Related 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
<PAGE>
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.
1.85AReliability Committee is the committee whose responsibilities are
specified in Section 8 and which may have additional responsibilities under a
proper delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Reliability Committee shall
include the prior Market Reliability Planning Committee or the prior Regional
Transmission Planning Committee as the predecessor of the Reliability
Committee.
1.85BReliability Standards are those rules, standards, procedures and
protocols approved by the Participants Committee pursuant to Section 7.3, or
its predecessors, that set forth specifics concerning how the System Operator
shall exercise its authority over matters pertaining to the reliability of the
bulk power system.
1.85CReview Board is the board whose responsibilities are specified in Section
11A.
1.86Scheduled 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).
1.87Second Effective Date is May 1, 1999.
1.87ASector has the meaning specified in Section 6.2.
1.88Service 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.
1.89Summer 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 Markets Committee in accordance with Section
10.4(d).
1.90Summer Period in each Power Year is the four-month period from June
through September.
1.91System Contract is any contract for the purchase of Installed 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, Energy,
Operating Reserves and/or AGC.
1.92System 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-
<PAGE>
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.
1.93System 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 ISO New England Inc., unless replaced by a substitute
independent system operator, a regional transmission organization or an entity
that forms a part of a regional transmission organization that has, in each
case, been approved by the Commission.
1.94Target Availability Rate is the assumed availability of a type of
generating unit utilized by the Participants Committee in its determination
pursuant to Section 7.5(e) of NEPOOL Objective Capability.
1.95Tariff is the NEPOOL Open Access Transmission Tariff set out in Attachment
B to the Agreement, as modified and amended from time to time.
1.95ATariff Committee is the committee whose responsibilities are specified in
Section 9 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Tariff Committee shall include
the prior Regional Transmission Operations Committee as the predecessor of the
Tariff Committee.
1.95BTechnical Committees are the Reliability Committee, the Tariff Committee
and the Markets Committee.
1.96Third 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 Participants 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 Participants Committee.
1.97Through or Out Service is the transmission service by that name provided
pursuant to Section 18 of the Tariff.
1.98Transition Period is the six-year period commencing on March 1, 1997.
1.99Transmission 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.
1.99ATransmission Owner is a Transmission Provider which makes its PTF
available under the Tariff and owns a Local Network listed in Attachment E to
the Tariff which is not a Publicly Owned Entity, including any affiliate of a
Transmission Provider that owns transmission facilities that are made
available as part of the Transmission Provider's Local Network; provided that
if a Transmission Provider is not listed in Attachment E to the Tariff on May
10, 1999, the Transmission Provider must also (1) own, or lease with rights
equivalent to ownership, PTF
<PAGE>with an original capital investment in its PTF as of the end of the most
recent year for which figures are available from annual reports submitted to
the Commission in Form 1 or any similar form containing comparable annualized
data of at least $30,000,000, and (2) provide transmission service to
non-affiliated customers pursuant to an open access transmission tariff on
file with the Commission.
1.99BTransmission Owners Committee is the committee whose responsibilities are
specified in Section 11B.
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 state or
municipal or cooperatively-owned 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 Energy, Operating Reserves and/or AGC if, or to the extent that, a
specific electric generating unit or units is or can be operated.
1.102[Deleted.]
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 Markets Committee in accordance with Section
10.4(d).
1.104Winter 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.
1.10510-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 Markets 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 Markets 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 Markets Committee is
necessary.
<PAGE>
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 Markets 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 any portion of a
Participant's Electrical Load that the System Operator is able to verify as
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 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
Markets 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
Markets 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 Markets 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 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 Markets 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 Markets 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.
1.108[Deleted.]
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):
<PAGE>
(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 Rl;
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 Rl.
The quantity Rl 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/Y wherein:
Xis the maximum Load of the purchasing Participant in the month, and
Yis 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
2.1Purpose. 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.
<PAGE>
2.2Effective 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 became effective on the
Second Effective Date and replaced on the Second Effective Date the remaining
provisions of the Prior NEPOOL Agreement, which continued in effect until the
Second Effective Date.
As provided in Section 14, certain portions of Section 14 which became
effective on the Second Effective Date will be superseded on the Third
Effective Date by other portions of Section 14.
SECTION 3
MEMBERSHIP
3.1Membership. 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
Participants 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 Participants 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
Participants 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 for an applicant which qualifies for membership only as an End User
Participant, and $5,000 for all other applicants, or such other amount as may
be fixed by the Participants Committee.
3.2Operations 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.
<PAGE>
3.3Lack 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 Participants Committee as
set out in the NEPOOL roster or at the address of its principal place of
business.
3.4Obligation 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.
3.5Financial Security. For an Entity applying to become a Participant or any
continuing Participant that the Participants Committee reasonably determines
may fail to meet its financial obligations under the Agreement, the
Participants Committee may require reasonable credit review procedures which
shall be made in accordance with standard commercial practices. In addition,
the Participants 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 Participants 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
4.1Treatment 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; provided, however, that any Vermont electric
utility which is a Publicly Owned Entity may elect to join the Publicly Owned
Entity Sector and be treated as a member of that Sector for purposes of
governance, annual fees and NEPOOL expense allocation, without losing the
benefits of single Participant status for any other purpose under this
Agreement.
<PAGE>
4.2Participants 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
5.1NEPOOL 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.
5.2Cooperation 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.
PART TWO
GOVERNANCE
SECTION 6
COMMITTEE ORGANIZATION AND VOTING
6.1Principal Committees. There shall be four principal NEPOOL Committees (the
"Principal Committees"), as follows:
<PAGE>
(a)the Participants Committee which shall have the responsibilities specified
in Section 7;
(b)the Reliability Committee which shall have the responsibilities specified
in Section 8;
(c)the Tariff Committee which shall have the responsibilities specified in
Section 9; and
(d)the Markets Committee which shall have the responsibilities specified in
Section 10.
In addition, there shall be a Transmission Owners Committee and a Liaison
Committee, which shall have the responsibilities specified in Sections 11B and
11C, respectively, and such other committees as may be established from time
to time by the Participants Committee.
6.2Sector Representation. The members of each Principal Committee shall each
belong to a single sector for voting purposes ("Sector"). Each Participant
shall be obligated to designate in a notice to the Secretary of the
Participants Committee a Sector that it or its Related Persons is eligible to
join and that it elects to join for purposes of all of the Principal
Committees. A Participant and its Related Persons shall together be entitled
to join only one Sector and shall have no more than one vote on each Principal
Committee.
The Sectors for each Principal Committee, the criteria for eligibility for
membership in each Sector and the minimum requirement which a Participant must
meet as a member of a Sector in order to appoint a voting member of the Sector
and Committee are as follows:
(a)a Generation Sector, which a Participant shall be eligible to join if (i)
it (A) owns or leases with rights equivalent to ownership facilities for the
generation of electric energy that are located within the NEPOOL Control Area
which are currently in operation, or (B) has proposed generation for operation
within the NEPOOL Control Area either which has received approvals under
Sections 18.4 and/or 18.5 within the past two years or for which completed
environmental air or environmental siting applications have been filed or
permits exist, and (ii) it is not a Publicly Owned Entity. Purchasing all or
a portion of the output of a generation facility shall not be sufficient to
qualify a Participant to join the Generation Sector.
A Participant which joins the Generation Sector shall be entitled but not
required to designate an individual voting member of each Principal Committee,
and an alternate to the member, if its operating or proposed generation
facilities in the NEPOOL Control Area have or will have, when placed in
operation, an aggregate Winter Capability of at least 15 MW.
A Participant which joins the Generation Sector but elects not to or is not
eligible to designate an individual voting member, shall be represented by a
group voting member and an alternate to that member for each Principal
Committee (collectively, the "Generation Group Member"). The Generation Group
Member shall be appointed by a majority of the Participants in the Generation
Sector electing or required to be represented by that member. The Generation
Group Member shall have the same percentage of the Sector vote as the
individual voting members designated by other Participants in the Generation
Sector which meet the 15 MW threshold and designate an individual voting
member. The Generation Group Member shall be entitled to split his or her
vote.
<PAGE>
(b)a Transmission Sector, which a Participant shall be eligible to join if it
is a Transmission Provider and is not a Publicly Owned Entity. Taking
transmission service shall not be sufficient to qualify a Participant to join
the Transmission Sector.
A Participant which joins the Transmission Sector shall be entitled to
designate an individual voting member of each Principal Committee, and an
alternate to the member, if it owns or leases with rights equivalent to
ownership PTF with an original capital investment in its PTF as of the end of
the most recent year for which figures are available from annual reports
submitted to the Commission in Form 1 or any similar form containing
comparable annualized data of at least $30,000,000. A Transmission Provider
with facilities which were included as PTF prior to December 31, 1998 only
pursuant to clause (3) of the definition of PTF pursuant to Section 15.1 shall
be entitled to designate an individual voting member of each Principal
Committee, and an alternate to the member, whether or not PTF which it owns or
leases with rights equivalent to ownership which has an original capital
investment of at least $30,000,000, so long as such Transmission Provider
continues to own PTF.
A Participant which joins the Transmission Sector but which is not entitled to
designate an individual voting member of each Principal Committee because (i)
it, together with all of its Related Persons, does not meet the $30,000,000
threshold or (ii) it no longer owns PTF and it does not have a Related Person
that is entitled to designate an individual voting member for each Principal
Committee in another Sector, together with the other Participants in the
Transmission Sector which for the same reasons are unable to designate an
individual voting member, shall be represented by a group voting member of
each Principal Committee (the "Transmission Group Member"), and an alternate
to that member. The Transmission Group Member and alternate shall be
appointed by a majority vote of all Participants in the Transmission Sector
required to be represented by that Member. The Transmission Group Member
shall have the same percentage of the Sector vote as the individual voting
members designated by other Participants in the Transmission Sector which meet
the $30,000,000 threshold unless and until the original capital investment in
PTF of the Participants represented by the Transmission Group Member equals or
exceeds twice the $30,000,000 threshold amount. If the aggregate original
capital investment in PTF equals or exceeds twice the $30,000,000 threshold
amount, the percentage of the Sector votes assigned to the Transmission Group
Member shall equal the number of full multiples of the $30,000,000 threshold,
provided that the Transmission Group Member shall in no event be entitled to
more than twenty-five percent (25%) of the Sector vote. For example, if
Participants represented by the Transmission Group Member have an aggregate
original capital investment in PTF in the NEPOOL Control Area totaling
$70,000,000, the Transmission Group Member will have the same percentage of
such votes as two ($70,000,000/$30,000,000 Threshold = 2.33) individual
voting members designated by individual Participants, provided that there are
at least six other members in the Sector so the Transmission Group Member does
not have more than twenty- five percent (25%) of the Transmission Sector
vote. The Transmission Group Member shall be entitled to split his or her
vote.
<PAGE>
(c)a Supplier Sector, which a Participant shall be eligible to join if (i) it
engages in, or is licensed or otherwise authorized by a state or federal
agency with jurisdiction to engage in, power marketing, power brokering or
load aggregation within the NEPOOL Control Area or it had been engaged on and
before December 31, 1998 solely in the distribution of electricity in the
NEPOOL Control Area, and (ii) it is not a Publicly Owned Entity. A
Participant which joins the Supplier Sector shall be entitled to designate a
voting member of each Principal Committee, and an alternate to the member.
(d)a Publicly Owned Entity Sector, which all Participants which are Publicly
Owned Entities are eligible to join and shall join, and which End User
Participants are eligible to join if there is not an activated End User
Sector. A Participant which joins the Publicly Owned Entity Sector shall be
entitled to designate a voting member of each Principal Committee, and an
alternate to the member, except for End User Participants whose voting
interests while they are in the Publicly Owned Entity Sector are defined in
Section 6.2(e) below.
(e)an End User Sector, which an End User Participant is eligible to join.
Participants which join the End User Sector shall be entitled to designate a
voting member of each Principal Committee and an alternate to the member.
Until there are at least ten End User Participants, all End User Participants
shall be members of the Publicly Owned Entity Sector. So long as there are
less than three End User Participants, the End User Participants in the
Publicly Owned Entity Sector shall be represented on each Principal Committee
by a single voting member. At such time as there are at least three, but less
than ten, End User Participants, End User Participants shall become a
sub-sector of the Publicly Owned Entity Sector. Such sub-sector shall have
twenty percent (20%) of the Publicly Owned Entity Sector's vote, and each End
User Participant shall be entitled to designate a voting member of each
Principal Committee, and an alternate to that member, and each voting member
shall be allocated a per capita share of the sub-sector's vote. The End User
Sector shall become fully operational automatically as soon, and shall remain
operational so long as, there are at least ten End User Participants.
The System Operator shall have the right to designate, by written notice
delivered to the Secretary of the appropriate Principal Committee, a
non-voting member and an alternate to each Principal Committee. All
Participants have the right to join and be a member of a Sector. If a
Participant ceases to be eligible to be a member of the Sector which it
previously joined and is not eligible to join another existing Sector other
than the End User Sector, it shall have the right to remain and vote in the
Sector in which the Participant is currently a member for up to one year. By
the end of such year, the NEPOOL Participants Committee shall make a filing
with the Commission pursuant to which the Participant can join another Sector
that either exists or is created pursuant to the NEPOOL Participants Committee
filing. Separate Sectors may be created, and the membership of existing
Sectors may be modified, by amendment of the Agreement.
6.3Appointment of Members and Alternates. A Participant or group of
Participants shall designate, by a written notice delivered to the Secretary
of the appropriate Committee, the voting member appointed by it for the
Committee and an alternate of the member. In the absence of the member, the
alternate shall have all the powers of the member,
<PAGE>
including the power to vote. A Participant may change the Sector of which it
is a member. Other than for Sector changes required by Section 6.4(c), a
change in the Sector in which a Participant is a member shall become effective
beginning on the first annual meeting of the Participants Committee following
notice of such change.
6.4Term of Members. Each voting member of a Principal Committee shall hold
office until either (a) such member is replaced by the Participant or group of
Participants which appointed the member, or (b) the appointing Participant
ceases to be a Participant, or (c) the appointing Participant (or its Related
Person) is no longer eligible to be in the Sector to which it belongs, but is
eligible to join a different Sector. Replacement of a member shall be
effected by delivery by a Participant or group of Participants of written
notice of such replacement to the Secretary of the appropriate Committee.
6.5Regular and Special Meetings. Each Principal 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. Five or more voting
members of a Principal Committee may call subject to the notice provisions of
Section 6.6 a special meeting of the Committee in the event that the Chair
fails to schedule 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.
6.6Notice of Meetings. Written or electronic notice of each meeting of a
Principal Committee shall be given to each Participant, whether or not such
Participant is entitled to appoint an individual voting member of the
Committee, not less than three business days prior to the date of the meeting
in the case of the Technical Committees and five business days prior to the
date of the meeting for the Participants Committee.
A notice of meeting shall specify the principal subject matters expected to be
acted upon at the meeting. In addition, such notice shall include, or specify
internet location of, all draft resolutions to be voted at the meeting (which
draft resolutions may be subject to amendment of intent but not subject matter
during the meeting), and all background materials deemed by the Chair or
Secretary to be necessary to the Committee to have an informed opinion on such
matters. Motions raised for which no draft resolutions or background
materials have been provided may not be acted upon at a meeting and shall be
deferred to a subsequent meeting which is properly noticed.
6.7Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each other. In
order to vote during the course of a meeting, attendance is required in person
or by telephone or other real time electronic means by a voting member or its
alternate or a duly designated agent who has been given, in writing, the
authority to vote for the member on all matters or on specific matters in
accordance with Section 6.12.
6.8Quorum. All actions by a Principal Committee, other than a vote by the
Participants Committee by written ballot to amend the NEPOOL Agreement or
Tariff, shall be taken at a meeting at which the members in attendance
pursuant to Section 6.7 constitute a Quorum. A Quorum requires the attendance
by members which satisfy the Sector Quorum requirements (as defined in Section
6.9) for a majority of the activated Sectors. No action may be taken by a
Principal Committee unless a Quorum is present; provided, however, that if a
Quorum is not present,
<PAGE>
the voting members then present shall have the power to adjourn the meeting
from time to time until a quorum shall be present.
6.9Voting Definitions. For purposes of this Section 6.9 and Sections 6.10,
6.11 and 6.13, the following terms shall have the following respective
meanings:
(a)Sector Voting Share: for each active Sector, is the quotient obtained by
dividing one hundred percent (100%) by the number of active Sectors. For
example, if there are five active Sectors, the Sector Voting Share of each of
the Sectors is twenty percent (20%). The aggregate Sector Voting Shares shall
equal one hundred percent 100%.
(b)Sector Quorum: for a Sector shall be the lesser of (i) fifty percent (50%)
or more (rounded to the next higher whole number) of the voting members of the
Sector, or (ii) five (5) or more voting members of the Sector for the
Participants Committee or three (3) or more voting members of the Sector for
the Technical Committees.
(c)Member Fixed Voting Share: for a Committee voting member, whether or not
the member is in attendance, is the quotient obtained by dividing (i) the
Sector Voting Share of the Sector to which the Participant or group of
Participants which appointed the Committee voting member belongs by (ii) the
total number of Committee voting members appointed by members of that Sector,
adjusted, if necessary, to take into account (A) the manner in which the
voting shares of End User Participants are to be determined while they are
members of the Publicly Owned Entity Sector, and (B) any required change in
the voting share of a Group Member, in each case as determined in accordance
with Section 6.2.
(d)Member Adjusted Voting Share: for a Committee voting member which casts an
affirmative or negative vote on a proposed action or amendment and which has
been appointed by a Participant or group of Participants which are members of
a Sector satisfying its Sector Quorum requirement for the proposed action or
amendment, is the quotient obtained by dividing (i) the Sector Voting Share of
that Sector by (ii) the number of voting members appointed by members of that
Sector which cast affirmative or negative votes on the matter, adjusted, if
necessary, for End User Participants and group voting members as provided in
the definition of "Member Fixed Voting Share".
(e)NEPOOL Vote: with respect to a proposed action or amendment is the sum of
(i) the Member Adjusted Voting Shares of the voting members of the Committee
which cast an affirmative vote on the proposed action or amendment and which
have been appointed by a Participant or group of Participants which are
members of a Sector satisfying its Sector Quorum requirements and (ii) the
Member Fixed Voting Shares of the voting members of the Committee which cast
an affirmative vote on the proposed action or amendment and which have been
appointed by a Participant or group of Participants which are members of a
Sector which fails to satisfy its Sector Quorum requirements.
(f)Minimum Response Requirement: with respect to a proposed amendment to this
Agreement or Tariff means that the ballots received by the Balloting Agent
from Participants relating to the proposed amendment before the end of the
appropriate time specified in Section 6.11(c) must satisfy the following
thresholds:
<PAGE>
(i)the sum of the Member Fixed Voting Shares of the Participant voting members
whose ballots are received must equal at least fifty percent (50%); and
(ii)the Participants whose voting members timely return ballots for
or against the amendment must include Participants that are represented by
voting members having at least fifty percent (50%) of the Member Fixed Voting
Shares in each of a majority of the activated Sectors.
6.10Voting On Proposed Actions. All matters to be acted upon by a Principal
Committee shall be stated in the form of a motion by a voting member, which
must be seconded. Only one motion and any one amendment to that motion may be
pending at one time. Passage of a motion requires a NEPOOL Vote as determined
pursuant to Section 6.9 equal to or greater than two thirds of the aggregate
Sector Voting Shares. Voting members not in attendance or represented at a
meeting as specified in Section 6.7 or abstaining shall not be counted as
affirmative or negative votes.
6.11Voting On Amendments. Subject to Section 21.11 and Section 17A,
amendments to the NEPOOL Agreement or Tariff shall be accomplished as follows:
(a)Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a
Participant and sent to the Participants Committee for its consideration.
(b)The Participants Committee shall take action pursuant to Section 6.10 to
direct the Balloting Agent to circulate ballots for approval of the draft
Amendment to each Participant for execution by its voting member or alternate
on the Participants Committee or such Participant's duly authorized officer.
(c)In order to be counted, ballots must be executed and returned to the
Balloting Agent for NEPOOL in accordance with the following schedule:
(i)If the ballots are delivered to each Participant by regular mail,
properly executed ballots must be returned to and received by the Balloting
Agent within ten (10) business days after deposit of such ballots in the mail
by the Balloting Agent, and
(ii)If the ballots are delivered to each Participant by overnight
delivery, facsimile, electronic mail or hand delivery, then properly executed
ballots must be returned to and received by the Balloting Agent within five
(5) business days after (A) deposit of such ballots with an overnight delivery
courier if delivered by overnight delivery, or (B) transmission of such
ballots by the Balloting Agent if delivered by facsimile or electronic mail,
or (C) receipt by the Participant if delivered by hand delivery.
(iii)If the Minimum Response Requirement for an amendment has not
been received by the Balloting Agent within the schedule identified in
subsection (i) or (ii) above, the Balloting Agent shall send notice by
overnight delivery, facsimile, electronic mail or hand delivery to all
non-responding Participants and shall count any additional properly executed
ballots which it receives within five (5) business
<PAGE>
days after such notice. The date by which properly executed ballots must be
returned and received by the Balloting Agent shall be specified by the
Balloting Agent in the notice accompanying such ballots.
(d)A Participant may appeal to the Review Board or submit for resolution
pursuant to the alternative dispute resolution provisions of Section 21.1 a
proposed amendment for which ballots have been circulated, provided that such
appeal is taken or submission is presented before the end of the tenth (10th)
business day after the Participants Committee has taken action to direct the
Balloting Agent to circulate ballots for approval of the draft amendment, by
giving to the Secretary of the Participants Committee a signed and written
notice of appeal or submission. The appeal shall be moot, or submission shall
be deemed withdrawn, if the amendment is not approved in balloting by the
Participants Committee. If the amendment is approved, a valid appeal or
submission shall stay the filing with the Commission of any amendment to the
NEPOOL Agreement or Tariff until either (i) a decision on the appeal by the
Review Board, or (ii) the earlier of resolution pursuant to Section 21.1 or
termination pursuant to Section 21.1.B(2) of the suspension effects of the
submission.
(e)In order for a proposed amendment to the NEPOOL Agreement or Tariff to be
approved by the Participants Committee, the following criteria must be
satisfied:
(i)The Minimum Response Requirement must be satisfied with respect
to the proposed amendment.
(ii)The affirmative ballot votes with respect to the proposed
amendment must equal or exceed two thirds of the aggregate Sector Voting
Shares.
6.12Designated Representatives and Proxies. The vote of any member of a
Principal Committee or the member's alternate, other than a ballot on an
amendment, may be cast by another person pursuant to a written, standing
designation or proxy. A designation or proxy shall be dated not more than one
year previous to the meeting and shall be delivered by the member or alternate
to the Secretary of the Committee at or prior to any votes being taken at the
meeting at which the vote is cast pursuant to such designation or proxy. A
single individual may be the designated representative of or be given the
proxy of the voting members representing any number of Participants of any one
Sector or Participants from multiple Sectors.
6.13Limits on Representatives. In the Generation Sector, no one person may
exercise more than twenty-five percent (25%) of that Sector's total Member
Fixed Voting Shares without the unanimous written agreement of all members of
the Generation Sector. Other Sectors may by unanimous written agreement elect
to impose limits on the voting power any one individual may have in that
Sector through being the designated representative of multiple voting members
or carrying multiple proxies from voting members of that Sector. Notice of
any such limits on voting power must be posted on the System Operator home
page and be capable of being accessed by all Participants.
6.14Adoption of Bylaws. The Participants Committee shall adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings and those of the other Principal Committees. If there
is any conflict between such bylaws and the Agreement, the Agreement shall
control. A Principal Committee may vote to waive its bylaws for a particular
meeting, provided the motion to effect the waiver is approved in accordance
with Section 6.10.
<PAGE>
6.15Joint Meetings of Technical Committees. It is recognized that
responsibilities of the Technical Committees may overlap in certain areas. In
areas of overlap, the Reliability Committee is responsible for addressing
reliability matters, the Markets Committee is responsible for addressing
market implications of actions or recommendations, and the Tariff Committee is
responsible for addressing issues relating to transmission and ancillary
services. The Chairs of the Technical Committees, with input from the Liaison
Committee Co-Chairs or entire Liaison Committee, as appropriate, shall
prioritize and sequence Technical Committee activities to ensure full and
proper input by Participants while maximizing the efficiency of the decision
making process. To the extent appropriate and desirable, the Technical
Committees are authorized and encouraged to hold meetings, and to conduct
studies and exercise responsibilities, jointly with other Technical
Committees.
SECTION 7
PARTICIPANTS COMMITTEE
7.1Officers. At its annual meeting, the Participants Committee shall elect
from among its members a Chair and Vice-Chair; it shall also elect a Secretary
who shall not be a member. These officers shall have the powers and duties
usually incident to such offices and as set forth in the Committee bylaws.
7.2Adoption of Budgets. At each annual meeting, the Participants Committee
shall adopt a NEPOOL budget for the ensuing calendar year. In adopting
budgets the Participants Committee shall give due consideration to the
budgetary requests of each committee. The Participants Committee may modify
any NEPOOL budget from time to time after its adoption.
7.3Establishing Reliability Standards. It shall be the duty of the
Participants Committee, after review of reports, recommendations and actions
of the System Operator and the Reliability Committee and such other matters as
the Participants Committee deems pertinent, to establish or approve
Reliability Standards for the bulk power supply of NEPOOL. Such Reliability
Standards shall be consistent with the directives of NERC and the NPCC and
shall be reviewed periodically by the Participants Committee and revised as
the Participants Committee deems appropriate.
7.4Appointment and Compensation of NEPOOL Personnel. The Participants
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. In addition, the Participants Committee
shall determine what resources are desirable for the effective operation of
the Technical Committees and shall, on its own or pursuant to the
recommendation of a Technical Committee, authorize the incurrence of such
expenses as may be required to enable the Technical Committee, or its
subgroups, to properly perform their duties, including, but not limited to,
the retention of a consultant or the procurement of computer time.
7.5Duties and Authority.
(a)The Participants Committee shall have the duty and requisite authority to
administer, enforce and interpret the provisions of this Agreement and any
other agreement or document approved by the Participants Committee or its
predecessor in order to accomplish the objectives of NEPOOL including the
making of any decision or determination necessary under any provision of this
Agreement or any other agreement or document approved by the Participants
<PAGE>
Committee or its predecessor and not expressly specified to be decided or
determined by any other body.
(b)The Participants Committee shall have the authority to provide for such
facilities, materials and supplies as the Participants Committee may determine
are necessary or desirable to carry out the provisions of this Agreement.
(c)The Participants Committee shall have, in addition to the authority
provided in Section 7.3, 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 Participants 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 Participants 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 System Operator,
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 System
Operator, and (iii) related tariffs, rate schedules and certificates of
concurrence. The Participants Committee shall, in addition, have the
authority to represent NEPOOL in proceedings before the Commission.
(e)The Participants 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 Participants Committee may determine on the basis
of such review. Since changes in the circumstances which must be assumed by
the Participants Committee in fixing NEPOOL Objective Capability for a future
period can significantly affect the required level of NEPOOL Objective
Capability for that period, the Participants 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 Participants 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.
<PAGE>
(g)The Participants Committee shall have the duty and requisite authority to
provide for the sharing by Participants, on such basis as the Participants
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 Participants 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
Participants 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)The Participants Committee shall have the authority to establish standard
conditions and waivers with respect to applications by Entities for membership
in NEPOOL and to modify such standard conditions and waivers as appropriate in
connection with changed circumstances with respect to such applicants,
provided that the Participants Committee determines that the standard
conditions and waivers for such Entities will not impose an additional burden
on other Participants.
(j)The Participants Committee shall have the duty and requisite authority to
act on appeals to it from the actions of other Principal Committees if
delegated to such Committees by the Participants Committee pursuant to Section
7.5(k), to appoint the Review Board, 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 Participants Committee shall have the authority to delegate its powers
and duties to one or more of the Technical Committees, the System Operator, or
other entity as it sees fit provided that (i) such delegation is clearly
stated and approved by a Participant Committee action, (ii) such delegation
does not violate any other provision set forth herein, and (iii) the action of
such entity on any matter delegated to it may be appealed by any Participant
to the Participants Committee provided such an appeal is taken prior to the
end of the tenth business day following the action of the Technical Committee,
the System Operator, or such entity by giving to the Secretary of the
Participants Committee a signed and written notice of appeal, a copy of which
the Secretary shall provide to the System Operator and each member and
alternate of the Participants Committee. Pending action on the appeal by the
Participants Committee, the giving of a notice of appeal as aforesaid shall
suspend the action appealed from.
(l)The Participants Committee shall have the duty and requisite authority to
establish the NEPOOL Information Policy.
<PAGE>
(m)The Participants Committee shall have the duty and requisite authority to
adopt and approve, amend and approve or resubmit to one or more Technical
Committees for additional comment, any matter submitted to the Participants
Committee by a Technical Committee.
(n)The Participants Committee shall have such further powers and duties as are
conferred or imposed upon it by other sections of this Agreement.
7.6Attendance of Participants at Committee Meeting. Each Participant which
does not have the right to designate an individual voting member of the
Participants Committee shall, with the exception of meetings held pursuant to
Section 11B.9 and meetings in executive session pursuant to Section 11B.10, be
entitled to attend any meeting of the Committee or any other NEPOOL committee,
and shall have a reasonable opportunity to express views on any matter to be
acted upon at the meeting.
7.7Appeal of Actions to Review Board. Any Participant which otherwise has the
ability to submit a matter for resolution under Section 21.1 may, in lieu of
submitting a dispute as to a Participants Committee action or failure to take
action for resolution pursuant to Section 21.1, appeal such matter to the
Review Board. Except as otherwise provided in Section 6.11, such an appeal
shall be taken prior to the end of the tenth business day following the
meeting of the Participants Committee to which the appeal relates by giving to
the Secretary of the Participants Committee by hand delivery, facsimile,
electronic mail or regular mail a signed and written notice of appeal, a copy
of which the Secretary shall provide to each Participant. If no appeal of a
Participants Committee action or failure to take action is taken, and the
action or failure to take action is not submitted for resolution pursuant to
Section 21.1, within such time period, that Participants Committee action or
failure to take action shall be final and effective. If an appeal is taken,
pending action on the appeal by the Review Board, the giving of a notice of
appeal as aforesaid shall suspend the action appealed from. To the extent any
action taken relates to the approval of a rule or procedure which must be
filed with the Commission, the rule or procedure shall not be filed until the
time for appeal or submission for dispute resolution has elapsed and, if an
appeal has been filed or submission for dispute resolution has been made,
either (i) a decision on the appeal has been issued by the Review Board, or
(ii) the earlier of resolution pursuant to Section 21.1 of the matter
submitted for dispute resolution or the termination pursuant to Section
21.1.B(2) of the suspension effect of such submission.
SECTION 8
RELIABILITY COMMITTEE
8.1Officers. The Reliability Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Reliability Committee shall be
appointed by the System Operator from time to time in accordance with Section
20(j). The Chair will be responsible for presiding at meetings of the
Committee and establishing agendas for its meetings in conjunction with the
Vice-Chair and shall have the powers and duties as set forth in the Committee
bylaws. The Secretary shall have the powers and duties usually incident to
such office and as set forth in the Committee bylaws. The Chair and Secretary
shall have no voting rights. The Vice-Chair shall be elected by the
Reliability Committee from among its voting members from time to time. The
Vice-Chair shall have the powers and duties usually incident to such office
and such powers and duties as set forth in the Committee bylaws, including,
without limitation, the responsibility to develop in conjunction with the
Chair, Committee meeting agendas.
<PAGE>
8.2Notice to Members and Alternates of Participants Committee. Prior to the
end of the fifth business day following a meeting of the Reliability
Committee, the Secretary of the Reliability Committee shall give written
notice to the System Operator and each member and alternate of the
Participants Committee of any action taken by the Reliability Committee at
such meeting.
8.3Voting; Appeal of Actions. Votes taken by the Reliability Committee shall
be binding on the Participants only for those matters in which the Committee
has specifically designated authority under this Agreement or has been
properly delegated authority by the Participants Committee pursuant to Section
7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Reliability Committee. Such an appeal shall be taken prior to
the end of the tenth business day following the meeting of the Reliability
Committee to which the appeal relates by giving to the Secretary of the
Participants Committee a signed and written notice of appeal, a copy of which
the Secretary shall provide to the System Operator and each member and
alternate of the Participants Committee. Pending action on the appeal by the
Participants Committee, the giving of a notice of appeal as aforesaid shall
suspend the action appealed from.
8.4Responsibilities. The Reliability Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or
Transmission Owners, as appropriate, with respect thereto:
(a)provide input to the Participants Committee, Transmission Owners, and
System Operator, as appropriate, on transmission facilities and the
development of a regional transmission plan in order to achieve the objectives
of NEPOOL;
(b)following appropriate study, recommend NEPOOL Objective Capability for each
Power Year;
(c)periodically review the procedures used to calculate NEPOOL Installed
Capability, NEPOOL Objective Capability and NEPOOL Capability Responsibility;
(d)periodically prepare short and long term load forecasts for use in NEPOOL
studies and operations and to meet requirements of regulatory agencies;
(e)review communications and liaison arrangements between NEPOOL and
governmental authorities on power supply, environmental, load forecasting, and
transmission issues;
(f)coordinate the collection and exchange of necessary system data and future
plans related to reliability for use in NEPOOL planning and to meet
requirements of regulatory agencies;
(g)coordination of studies of, and provide information to Participants on,
maintenance schedules for the supply and demand- side resources and
transmission facilities of the Participants;
(h)based on appropriate studies, recommend for Participants Committee approval
Reliability Standards to assure the reliable operation and facilitate the
efficient operation of the NEPOOL Control Area bulk power system and those
operating rules which guide the
<PAGE>
implementation of the Reliability Standards. Such Reliability Standards and
operating rules shall include, without limitation, the following:
(i)standards to determine the current Annual Peak, Adjusted Annual
Peak, Monthly Peak, Adjusted Monthly Peak, and aggregate obligations of the
Participants in each of the NEPOOL Markets;
(ii)standards to establish short and long term load forecasts for
use in NEPOOL operations and to meet requirements of regulatory agencies;
(iii)standards with respect to the administration and enforcement
of, and reporting pursuant to, NERC and NPCC policies and requirements;
(iv)standards for use in planning and design of the NEPOOL
interconnected bulk power system;
(v)standards to ensure the continuous reliability of the bulk power
transmission system, such standards to include, without limitation, criteria
and rules relating to protective equipment, transfer limits, voltage
schedules, voltage guides, operating guides, sub-area reserves, switching,
voltage control, load shedding, emergency and restoration procedures, and the
coordination of scheduling of the operation and maintenance of supply and
demand-side resources and transmission facilities of the Participants;
(vi)standards for determining the 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; and
(vii)as appropriate, reliability standards for interpool
coordination transactions.
(i)review proposed supply and demand-side resource plans and the proposed
transmission and interconnection plans of Participants pursuant to Section
18.4 and, based on such review, recommend action regarding such proposed
plans.
(j)make recommendations regarding procedures for dispatch infrastructure (i.e.
voice and data communications protocols, AGC pulsing arrangements, Energy
Management System and System Control and Data Acquisition interfaces,
Satellite relations, etc.);
(k)provide input and make recommendations with respect to the reliability
considerations of general system operations (i.e. commitment/decommitment,
real time dispatch, review and approval of distribution of reserves, etc.);
(l)recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Reliability Committee, its
subcommittees, and task forces properly to perform their duties;
(m)make recommendations to the Participants Committee, Transmission Owners,
and System Operator, as appropriate, with respect to development and amendment
of interconnection procedures and documents related to such procedures;
<PAGE>
(n)to the extent appropriate, develop criteria, guidelines and methodologies
to assure consistency in monitoring and assessing conformance of Participant
and regional transmission plans to accepted reliability criteria.
8.5Establishment of Subcommittees and Task Forces. The Reliability Committee
shall have the authority to establish subcommittees and task forces for
particular studies.
8.6Further Powers and Duties. The Reliability Committee shall have such
further powers and duties as are consistent with the duties and
responsibilities set forth herein or as may be properly delegated to it by the
Participants Committee.
SECTION 9
TARIFF COMMITTEE
9.1Officers. The Tariff Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Tariff Committee shall be appointed
by the System Operator from time to time in accordance with Section 20(j).
The Chair will be responsible for presiding at meetings of the Committee and
establishing agendas for its meetings in conjunction with the Vice-Chair and
shall have the powers and duties as set forth in the Committee bylaws. The
Secretary shall have the powers and duties usually incident to such office and
as set forth in the Committee bylaws. The Chair and Secretary shall have no
voting rights. The Vice-Chair shall be elected by the Tariff Committee from
among its voting members from time to time. The Vice-Chair shall have the
powers and duties usually incident to such office and such powers and duties
as set forth in the Committee bylaws, including, without limitation, the
responsibility to develop in conjunction with the Chair, Committee meeting
agendas.
9.2Notice to Members and Alternates of Participants Committee. Prior to the
end of the fifth business day following a meeting of the Tariff Committee, the
Secretary of the Tariff Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Tariff Committee at such meeting.
9.3Voting; Appeal of Actions. Votes taken by the Tariff Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Tariff Committee. Such an appeal shall be taken prior to the end
of the tenth business day following the meeting of the Tariff Committee to
which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.
9.4Responsibilities. The Tariff Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or
Transmission Owners, as appropriate, with respect thereto:
<PAGE>
(a)develop appropriate billing procedures for transmission and ancillary
services pursuant to this Agreement and the Tariff;
(b)develop and recommend to the Participants Committee and the Transmission
Owners Committee, as appropriate, (i) amendments, additions and other changes
to the Tariff and (ii) related Tariff rules;
(c)providing input to the System Operator on the development of Administrative
Procedures with respect to the administration of the Tariff and the OASIS;
(d)to the extent appropriate, conduct and/or review such studies and make such
determinations as are assigned to the Committee pursuant to this Agreement and
the Tariff with respect to financial treatment of additions to or upgrades of
PTF;
(e)recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Tariff Committee, its
subcommittees, and task forces properly to perform their duties.
9.5Establishment of Subcommittees and Task Forces. The Tariff Committee shall
have the authority to establish subcommittees and task forces for particular
studies.
9.6Further Powers and Duties. The Tariff Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.
SECTION 10
MARKETS COMMITTEE
10.1Officers. The Markets Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Markets Committee shall be
appointed by the System Operator from time to time in accordance with Section
20(j). The Chair will be responsible for presiding at meetings of the
Committee and establishing agendas for its meetings in conjunction with the
Vice-Chair and shall have the powers and duties as set forth in the Committee
bylaws. The Secretary shall have the powers and duties usually incident to
such office and as set forth in the Committee bylaws. The Chair and Secretary
shall have no voting rights. The Vice-Chair shall be elected by the Markets
Committee from among its voting members from time to time. The Vice-Chair
shall have the powers and duties usually incident to such office and such
powers and duties as set forth in the Committee bylaws, including, without
limitation, the responsibility to develop in conjunction with the Chair,
Committee meeting agendas.
10.2Notice to Members and Alternates of Participants Committee. Prior to the
end of the fifth business day following a meeting of the Markets Committee,
the Secretary of the Markets Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Markets Committee at such meeting.
<PAGE>
10.3Voting; Appeal of Actions. Votes taken by the Markets Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Markets Committee. Such an appeal shall be taken prior to the
end of the tenth business day following the meeting of the Markets Committee
to which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.
10.4Responsibilities. The Markets Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or
Transmission Owners, as appropriate, with respect thereto:
(a)based on appropriate studies, develop market procedures to assure the
reliable operation and facilitate the efficient operation of the NEPOOL
Control Area bulk power supply;
(b)(i) evaluate studies of the market implications of maintenance schedules
for the supply and demand-side resources and transmission facilities of the
Participants and operable capacity margins, and (ii) develop market procedures
for scheduling maintenance for supply and demand resources and transmission
resources.
(c)to the extent appropriate to assure the efficient operation of the NEPOOL
Markets, develop 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)develop procedures for determining the market implications of the seasonal
capabilities of each electric generating unit or combination of units in which
a Participant has an Entitlement;
(e)develop procedures for determining as appropriate from time to time the
current Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted Monthly
Peak, Installed Capability Responsibility, and obligations for Energy,
Operating Reserve and AGC of each Participant;
(f)develop Market Rules and periodically review and recommend changes thereto
as appropriate. Such Market Rules shall include, without limitation, the
following:
(i)submission of Bid Prices and the determination of prices for each
of the NEPOOL Markets;
(ii)determination for each Participants of its obligations under
each of the NEPOOL Markets;
(iii)establishment or approval of appropriate billing procedures for
market transactions pursuant to this Agreement;
<PAGE>
(iv)calculation and equitable apportionment of losses incurred in
connection with Interchange Transactions; and
(v)interpool market contract coordination as appropriate.
(g)develop operating procedures relating to the administration of the NEPOOL
Markets and periodically review and recommend changes thereto as appropriate;
(h)recommend the retention of a consultant, procurement of computer time, or
the incurrence of consultant expenses or such other expenses as may be
required to enable the Markets Committee, its subcommittees, and task forces
properly to perform their duties.
10.5Establishment of Subcommittees and Task Forces. The Markets Committee
shall have the authority to establish subcommittees and task forces for
particular studies.
10.6Further Powers and Duties. The Markets Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.
10.7Development 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 Markets Committee shall analyze such special problems
and recommend to the Participants Committee appropriate rules for reflecting
such resources in the Installed 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 Participants
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 upon acceptance by the Commission.
SECTION 11
FURTHER RESTRUCTURING
The NEPOOL Participants undertake to finalize by March 31, 2000 the
negotiation of more comprehensive arrangements for the reassignment of
appropriate administrative responsibilities to the System Operator in the
Interim ISO Agreement.
SECTION 11A
REVIEW BOARD
11A.1Organization. There shall be a Review Board which, in addition to
responsibility under Section 11B.12, shall be responsible for ruling on
appeals taken from actions of the Participants Committee and for advising the
Participants Committee as to the issues raised on any appeals before it
provided that appeals from actions of the System Operator shall not be taken
to the Review Board. In ruling on appeals, the Review Board shall consider,
among other things, whether the action is consistent with Commission
policies. In addition, if the appeal relates to an amendment to the Agreement
or market rule, the Review Board shall consider the extent to which such
amendment imposes a burden on the Participants which do not vote in favor of
the amendment that is materially greater in degree than that imposed on the
Participants which have voted in favor of the amendment. The Review Board
shall not have
<PAGE>
the right to review or otherwise participate in actions of the System Operator
or to take any action with respect to any matter involving a dispute between
the System Operator and either NEPOOL or any Participant. The Participants
agree that the process of selecting the Review Board shall commence upon the
initial formation of the Participants Committee. Until the initial
organization of the Review Board is completed, the Board of Directors of the
System Operator or a committee thereof consisting of not less than three
System Operator Directors designated by the System Operator Board of Directors
shall perform the functions of the Review Board, provided that the provisions
of Sections 11A.2 through 11A.6 shall not be applicable to the Board of
Directors of the System Operator acting as a Review Board. All expenses
incurred by the System Operator as a result of the Board of Directors in
acting as the Review Board shall be NEPOOL expenses.
11A.2Composition. The Review Board shall be composed of five members. The
Review Board Members shall initially be selected by the Participants Committee
from a slate of candidates. An independent consultant, retained by the
Participants Committee, shall prepare a list of persons qualified and willing
to serve on the Review Board. A subcommittee appointed by the Participants
Committee shall review the list and distribute to the members of the
Participants Committee a slate from among the list proposed by the independent
consultant, along with information on the background and experience of the
persons on the slate appropriate to evaluating their fitness for service on
the Review Board. If the Participants Committee fails to select a full Review
Board from the slate proposed by the subcommittee, the Committee shall direct
the independent consultant to propose a further list of nominees for
consideration at the next regular meeting of the Participants Committee.
Thereafter, prior to the expiration of a Review Board Member's term, and upon
the occurrence of any vacancy on the Board, the Participants Committee shall
select a successor Member.
11A.3Qualifications. The Review Board Members shall be independent experts
knowledgeable about issues typically faced by entities engaged in energy
production, transmission, distribution and sale under Federal or State
regulation. A Review Board Member shall not be, and shall not have been at
any time within five years of election to the Review Board, a director,
officer or employee of a Participant or of a Related Person of a Participant.
While serving on the Review Board, a Review Board Member shall have no direct
business relationship or other affiliation with any Participant or its Related
Persons and shall otherwise be subject to the same independence requirements
imposed on Directors of the System Operator Board of Directors.
11A.4Term. A Review Board Member shall serve for a term of three years;
provided, however, that two of the Review Board Members selected initially
shall be chosen by lot to serve a term of two years, two of the Review Board
Members selected initially shall be chosen by lot to serve a term of three
years and the other Review Board Member selected initially shall serve a term
of four years.
11A.5Meetings. Meetings of the Review Board may be conducted in person or by
telephone or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each other.
11A.6Bylaws. To the extent not inconsistent with any provision of this
Agreement, the Participants Committee shall adopt bylaws establishing
procedures for the Review Board's activities as it may deem appropriate,
including but not limited to bylaws governing the scheduling, noticing and
conduct of meetings of the Review Board, a code of conduct,
<PAGE>
selection of a Chair and Vice-Chair of the Review Board, and action by the
Review Board without a meeting. Such bylaws shall not modify or be
inconsistent with any of the rights or obligations established by this
Agreement.
11A.7Procedure on Appeal of Participant Committee Action or Failure to Take
Action.
(a)Submission of an Appeal: A Participant seeking review ("Appealing
Party") by the Review Board of action of the Participants Committee shall give
written notice of the appeal in accordance with Section 7.7, and the appeal
shall have the suspension effect specified in Section 7.7.
(b)Intervenors and Time Limits: Any other Participant that wishes to
participate in the appeal proceeding hereunder shall give signed written
notice to the Secretary of the Participants Committee no later than ten (10)
business days after the Appealing Party has given notice of appeal and shall
upon the approval of the Review Board be permitted to participate in the
appeal.
(c)Procedural Rules: The procedural rules (if any), for the conduct of
the appeal shall be determined by the Review Board in consultation with the
Participants Committee and each Appealing Party on a case-by-case basis.
(d)Pre-hearing Submissions: Each Appealing Party shall provide the
Review Board, within 15 days of the giving of its notice of appeal or such
other time as permitted by the Review Board, 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 Review Board to
review. The Participants Committee and, as appropriate, any other Participant
participating in the appeal will provide the Review Board, within 10 days of
the Appealing Party's submission or such other time as permitted by the Review
Board, copies of the minutes of all NEPOOL committee meetings at which the
matter was discussed and if deemed appropriate by the Participants Committee
or otherwise requested by the Review Board a brief description of the action
(or failure to act) being appealed and a brief statement explaining why the
Participants Committee believes its action (or failure to act) should be
upheld by the Review Board, together with copies of documents or other
materials referenced in such submission for the Review Board to review and
materials, if any, which interested Participants provide to the Secretary of
the Participants Committee and reasonably request be submitted to the Review
Board.
In addition, each party shall designate one or more individuals to be
available to answer questions the Review Board may have on the documents or
other materials submitted. The answers to all such questions shall be reduced
to writing by the party providing the answer and a copy shall be made
available to any requesting Participant.
(e)Hearing: A hearing (if any) will be held as soon as is reasonably
practicable.
(f)Decision: The Review Board's decision, to the extent practicable,
shall be due, within ninety (90) days of the giving of notice of the appeal.
<PAGE>11A.8Effect of a Review Board Decision.
(a)Each Review Board Member shall have one vote and a decision of the
Review Board, either to grant or deny an appeal, shall require affirmative
votes by a majority of the Review Board Members but not less than three (3)
such Members.
(b) (i)Appeal denied. If the Review Board denies the appeal, the
action of the Participants Committee will be final and effective, subject to
Commission acceptance if and as required.
(ii)Appeal granted. If the Review Board grants the appeal, the
Review Board's determination (granting the appeal) will be final and the
action of the Participants Committee shall not take effect.
(c)If the Review Board grants an appeal, the Review Board may submit a
proposed resolution of the matter that was the subject of the appeal to the
Participants Committee. The Participants Committee may, but is not required
to, take further action with regard to the matter. If the Participants
Committee votes on an action regarding the matter (including a vote not to act
on the matter), the action or non-action of the Participants Committee shall
be subject to further appeal by any Participant to the Review Board in
accordance with Section 7.7. Any proposed resolution that the Review Board
submits to the Participants Committee is advisory only.
11A.9An action or failure to act once appealed by a Participant to the Review
Board may not be subject to the alternative dispute resolution provisions of
Section 21.1, regardless of the outcome of the appeal. Conversely, an action
or failure to act submitted for resolution by a Participant pursuant to
Section 21.1 may not be brought before the Review Board. If more than one
Participant appeals and/or submits for alternative dispute resolution under
Section 21.1 the same issue, the Participant that first takes such action
shall determine whether the issue is to be heard by the Review Board or
considered under Section 21.1; provided that each Participant challenging an
action or failure to take action shall have the same opportunity to present
its case and may not be excluded from participating under Section 11A.7(b).
11A.10 Any action taken or failure to take action by the
Review Board does not restrict or limit in any way the rights of a
Participant to seek review by the Commission, or a review in any other forum
available to the Participant and there shall be no requirement to submit an
appeal to the Review Board concerning any amendment, action or inaction by the
Participants Committee prior to a Participant exercising any such rights to
seek review by the Commission or any other forum with jurisdiction.
11A.11 The Review Board may not take action that is inconsistent with or
infringes upon any of the rights set forth in Section 17A.
SECTION 11B
TRANSMISSION OWNERS COMMITTEE
11B.1Organization. There shall be a Transmission Owners Committee established
pursuant to this Section 11B which shall implement the rights reserved to
Transmission Owners by Section 17A.
<PAGE>
11B.2Membership. Membership on the Transmission Owners Committee shall be
open to all Transmission Owners, regardless of their individual choices in
Sector membership under Section 6.2.
11B.3Appointment of Members and Alternates. A Transmission Owner shall join
the Transmission Owners Committee by written notice delivered to the Secretary
of the Transmission Owners Committee, and shall designate in the notice the
initial member appointed by it for the Committee and an alternate of the
member. In the absence of the member, the alternate shall have all the powers
of the member, including the power to vote.
11B.4Term of Members. A member of the Transmission Owners Committee appointed
by a Transmission Owner shall serve until replaced by the Transmission Owner
which appointed it or until such Transmission Owner ceases to be a Participant
or otherwise lose its right to appoint the member. Appointment or replacement
of a member shall be effected by a Transmission Owner by giving written notice
of such appointment or replacement to the Secretary of the Transmission Owners
Committee.
11B.5Regular and Special Meetings. The Transmission Owners 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. Thirty percent
(30%) or more of the voting members of the Transmission Owners Committee may
call a special meeting of the 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.
11B.6Notice of Meetings. Written notice of each meeting of the Transmission
Owners Committee shall be given to each Transmission Owner and to other
Participants not less than five (5) business days prior to the date of the
meeting.
11B.7Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each other. In
order to vote during the course of a meeting, attendance is required in person
or by telephone or other real time electronic means by a voting member or its
alternate or a duly designated agent who has been given, in writing, the
authority to vote for the member on all matters or the proxy to vote for the
member on specific matters.
11B.8Votes. Any action taken by the Transmission Owners Committee shall
require the concurrence of:
(i)representatives of at least two-thirds of the Transmission Owners
provided that Transmission Owners that are Related Persons to one another
shall together have a single vote; and
(ii)representatives of Transmission Owners having at least two-thirds of
the Weighted Votes of all Transmission Owners, where each Transmission Owner's
Weighted Vote is equal to its original capital investment in its PTF as of the
end of the most recent year for which figures are available.
Notwithstanding the foregoing, if a vote is taken and paragraph (i) above is
satisfied but paragraph (ii) above is not, the action being voted on by the
Transmission Owners Committee shall pass if (1) there are seven or more
Transmission Owners on the Committee and fewer than three Transmission Owners
oppose the action or (2) there are less than seven Transmission Owners on the
Committee and only one Transmission Owner opposes the action.
<PAGE>
11B.9Appointment of Task Forces or Working Groups. The Transmission Owners
Committee shall have the authority to appoint task forces or working groups to
address matters for which the Committee is responsible. Notwithstanding
Section 7.6, such tasks force or working groups may be limited to Transmission
Owners only.
11B.10Officers. At its annual meeting, the Transmission Owners Committee
shall elect from its 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, including the
right to convene an executive session of the Transmission Owners Committee to
consider and vote upon submittals to the Commission or litigation strategy.
11B.11Adoption of Bylaws. The Transmission Owners Committee may adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings.
11B.12Review of Committee Actions. To the extent the Commission determines,
pursuant to Section 17A.7, that Transmission Owners have the exclusive right
to make unilateral filings under Section 205 of the Federal Power Act, a
Transmission Owner may either submit a dispute for resolution pursuant to
Section 21.1 or appeal to the Review Board any action taken by the
Transmission Owners Committee with respect to such a Section 205 filing. Such
a submission or appeal shall be taken prior to the end of the tenth business
day following the meeting of the Transmission Owners Committee to which the
submission or appeal relates by giving to the Secretary of the Transmission
Owners Committee a signed and written notice of submission or appeal. Pending
action on an appeal by the Review Board, the giving of a notice of appeal as
aforesaid shall suspend the action appealed from. For purposes of the
application of the dispute resolution process of Section 21.1 and the
suspension effect of a submission to alternative dispute resolution, Section
21.1 shall be applied as if the Transmission Owners Committee were the
Participants Committee.
SECTION 11C
LIAISON COMMITTEE
11C.1Organization; Duties. There shall be a Liaison Committee which shall be
an advisory committee only responsible to act as a steering committee for
managing NEPOOL business through the committee process and facilitating
communications between NEPOOL and the System Operator and among Participants.
The Liaison Committee's duties as a steering committee include, without
limitation, recommending that matters be assigned to particular committees for
action where the subject matter of a proposed rule or other action potentially
falls in the purview of more than one committee and assuring appropriate input
from other committees as needed.
11C.2Membership. The Liaison Committee shall have the following members: the
Chair and Vice-Chair of each of the Principal Committees; the Chair of the
Transmission Owners Committee; a Participant representative of each Sector
that is not otherwise represented on the Liaison Committee; the chief
executive officer of the System Operator; and two members of the System
Operator's Board of Directors.
11C.3Regular and Special Meetings. The Liaison Committee shall hold meetings
in accordance with a schedule adopted by the Committee or at the call of the
Co-Chairs.
<PAGE>
11C.4Notice of Meetings. Written notice of each meeting of the Liaison
Committee shall be given to each member of the Committee and all members of
the Participants Committee not less than five business days prior to the date
of the meeting.
11C.5Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each other.
Participants Committee members and alternates may attend meetings of the
Liaison Committee. Any individual that is not a member of the Liaison
Committee may participate at a meeting at the invitation of a Co-Chair.
11C.6Officers. The Co-Chairs of the Liaison Committee shall be the chief
executive officer of the System Operator and the Chair of the Participants
Committee. The Liaison Committee shall 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.
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY
OBLIGATIONS AND PAYMENTS
12.1Obligations to Provide Installed 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)[Deleted].
12.2Computation of Installed Capability Responsibilities.
(a) (1)At the conclusion of each month, the System Operator under the
direction of the Participants 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) - C(D p)
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:
Xis the Participant's tentative Installed Capability Responsibility for the
month.
Pis the value of the Participant's fraction for the month as determined in
accordance with the following formula:
P = (F p + D p) / (F + D), wherein:
F pis the Participant's Adjusted Monthly Peak for the month less any
Kilowatts received by such Participant pursuant to a contract of a type that
traditionally has been treated by NEPOOL as a firm contract for the purposes
of this Section
<PAGE>
prior to January 1, 1999, but which does not constitute a Firm Contract as
defined in this Agreement.
D pis the Participant's actual or potential load reduction resulting from its
NEPOOL Interruptible and Dispatchable Loads for the month.
Fis the aggregate for the month of the Adjusted Monthly Peaks for all
Participants less any Kilowatts received by any Participant pursuant to a
contract of a type that traditionally has been treated by NEPOOL as a firm
contract for the purposes of this Section prior to January 1, 1999, but which
does not constitute a Firm Contract as defined in this Agreement.
Dis the aggregate for the month of the actual or potential load reduction
resulting from all Participants' NEPOOL Interruptible and Dispatchable Loads.
Cis the factor, which when multiplied by D in megawatts, results in the
reduction to NEPOOL Objective Capability that would result from including D in
the determination of NEPOOL Objective Capability. The value for C shall be
adopted by the Participants Committee each time it fixes NEPOOL Objective
Capability pursuant to Section 7.6(e).
Ais the NEPOOL Objective Capability in megawatts for the month as fixed by the
Participants Committee pursuant to Section 7.
Nis the aggregate of the New Unit Adjustments for all Participants for the
month as determined by the Participants Committee in accordance with Section
12.2(a)(2).
N pis the aggregate of the Participant's New Unit Adjustments for the month,
as determined by the Participants 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).
Tis 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
<PAGE>
Ifor 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 Participants Committee in its most recent determination of NEPOOL
Objective Capability pursuant to Section 7.
Hfor 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 H1 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,
<PAGE>
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 H1 for an Installed
Capability Entitlement shall be the four sequential Twelve-Month Measurement
Periods out of the twelve possible combinations which yield the highest H1.
H1for 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 Participants Committee in its most recent determination of NEPOOL
Objective Capability pursuant to Section 7.
Jfor 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 Participants Committee each time it fixes
NEPOOL Objective Capability pursuant to Section 7.
Rfor the month is the phase-out factor for the month, which
shall be as follows:
<PAGE>
R=0.75for the Power Year beginning November 1, 1997.
R=0.50for the 12 month period beginning November 1, 1998.
R=0.25for the 12 month period beginning November 1, 1999.
R=0for the 12 month period beginning November 1, 2000 and
all subsequent 12 month periods.
(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 System
Operator under the direction of the Participants 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:
Ris the phase out factor as defined in Section 12.2(a)(1)
above.
nis the New Unit Adjustment Factor, expressed as a fraction, for the month for
a New Unit.
cis the Winter Capability of the New Unit.
Cis the Winter Capability of the Proxy Unit, which shall be the number of
Kilowatts, as determined by the Participants 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.
fis the equivalent forced outage rate of the New Unit, expressed as a fraction
of a year, utilized in the determination by the Participants Committee of
NEPOOL Objective Capability for the month.
Fis 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.
mis 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 Participants Committee of NEPOOL Objective
Capability pursuant to Section 7.
<PAGE>
Mis 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.
dis the summer derating of the New Unit, expressed as a fraction of the Winter
Capability of the New Unit.
Dis 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 Participants Committee and reviewed every five
years (or more frequently if the Participants 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 Participants 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 5 MW, 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:
<PAGE>
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 Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter.
(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 System Operator under the direction of the Participants
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 System Operator under the direction of the Participants
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.
<PAGE>
(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 Markets Committee shall analyze
such special problems and recommend to the Participants Committee for approval
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[Deleted].
12.4Bids to Furnish Installed Capability. Each Participant shall submit to or
have on file with the System Operator, in accordance with the market operation
rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter, 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 through NEPOOL to
other Participants. If no bid is submitted for a month for any surplus
Installed System Capability, the Bid Price for any such surplus for which
there is no bid shall be deemed to be zero.
12.5Consequences 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.
<PAGE>
(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[Deleted].
12.7Payments to Participants Furnishing Installed 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)[Deleted].
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS
13.1Maintenance 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.
13.2Central 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 Participants
Committee.
<PAGE>
13.3Maintenance 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 Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter, (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
Markets Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter.
13.4Objectives 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.
13.5Satellite 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
14.1Obligation 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.
<PAGE>
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 pis the Participant's share of that category of Operating
Reserve for the hour.
SA pis the number of Kilowatts, if any, of that category of
Operating Reserve for the hour that the Participants Committee determines
should be assigned specifically to such Participant and not be shared by all
Participants.
ORis the aggregate number of Kilowatts of that category of
Operating Reserve determined by the System Operator in accordance with the
directions of the Participants Committee to be required for the NEPOOL Control
Area for the hour that is not assigned to Non-Participants.
SAis the aggregate number of Kilowatts of that category of
Operating Reserve for the hour that the Participants Committee determines
should not be shared by all Participants, but not including Operating Reserve
assigned to Non-Participants.
EL pis the Participant's Electrical Load for the hour.
ELis 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 pis the Participant's share of AGC for the hour.
AGCis the total amount of AGC determined by the System Operator
in accordance with market operation rules approved by the Markets Committee
prior to the activation of the Participants Committee or the Participants
Committee thereafter 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).
14.2Obligation 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 Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter, 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
<PAGE>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 Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter, 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).
(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 Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter. 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
<PAGE>
as is specified in the market operation rules approved by the Markets
Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter. 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 Markets Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter 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.
14.3Amount of Energy, Operating Reserve and Automatic Generation Control
Received or Furnished.
<PAGE>
(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 Markets Committee
prior to the activation of the Participants Committee or the Participants
Committee thereafter 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.
14.4Payments 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.
<PAGE>
(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.
14.5Payments 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
Markets Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter. 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 Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter.
(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 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:
<PAGE>
(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 Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter; 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 Markets Committee prior to the activation of the Participants Committee
or the Participants Committee thereafter.
14.6Energy Transactions with Non-Participants.
(a)The Participants 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 Participants 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
<PAGE>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).
14.7Participant Purchases Pursuant to Firm Contracts and System Contracts.
(a)For Firm Contracts and System Contracts, the treatment of Installed
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 Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter. If and to the extent necessary to implement the agreement between
the parties, such market operation rules, upon approval by the Participants
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 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 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 Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter.
14.8Determination 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 Markets Committee prior to the activation of the Participants Committee or
the Participants Committee thereafter to reflect those resources with the
highest
<PAGE>
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 Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter.
14.9Determination 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 Markets Committee
prior to the activation of the Participants Committee or the Participants
Committee thereafter) 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 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 1000 Kilowatts
(or such other number as may be specified by the Markets Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter) 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.
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
<PAGE>
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 Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter 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:
<PAGE>
(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;
<PAGE>
(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.
<PAGE>
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
Markets Committee shall analyze such special problems and recommend to the
Participants Committee for approval 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 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 Participants 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 Markets Committee
shall analyze such special problems and recommend to the Participants
Committee for approval appropriate dispatch and billing rules to be applied
during periods when the Participants 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 Participants 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 Participants 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 March 1, 2000 and
after the preparation of necessary implementing rules and computer software or
on an earlier or later effective date. If the Participants 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 Participants
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.
<PAGE>
(b)Commencing on the earlier of June 1, 2000 or the beginning of the
first calendar month sixty (60) days after the filing of an amendment to the
Agreement and/or the Tariff by the Participants Committee, any Participant or
group of Participants, 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 Participants 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 prior to the activation of the
Participants Committee or the Participants Committee thereafter, 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 prior to the activation of the Participants Committee or the
Participants Committee thereafter, 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
<PAGE>
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 prior to the activation of the Participants Committee or
the Participants Committee thereafter.
PART FOUR
TRANSMISSION PROVISIONS
1.
OPERATION OF TRANSMISSION FACILITIES
15.1Definition 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:
<PAGE> (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 Reliability 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 Participants Committee its consent to such treatment; and (ii) the
Participants 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.
15.2Maintenance 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.
15.3Central 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.
<PAGE>
15.4Maintenance 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 Tariff 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 Tariff Committee.
15.5Additions 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 Reliability 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 Reliability Committee, subject to review by the
System Operator, one or more Transmission Providers shall be designated by the
Reliability 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 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
<PAGE>
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
16.1Effect 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.
16.2Obligation 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.
16.3Obligation 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 Eligible
Customers taking Regional Network Service and 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;
<PAGE>
(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:
Year Year Year Year Years Five
One Two Three Four and Six
% of
charge to 100% 80% 60% 40% 20%
be paid
(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
(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, except that any reductions to the amount due
from Eligible Customers for Excepted Transactions identified in Section 25(1)
and (2) of the Tariff shall be made only for service rendered through February
28, 1999, and such reductions shall cease and shall be replaced thereafter in
their entirety with the credits under the NEPOOL Tariff, provided in
accordance with Sections 25A and 25B of the Tariff.
16.4Transmission 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.
16.5Transmission 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
<PAGE>
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.
16.6Distribution 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 those Participants owning PTF or those load-serving
Participants supporting PTF which are obligated to take and pay for Regional
Network Service and/or Internal Point-to-Point Service in accordance with the
Tariff, 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 such owners and supporters, in accordance with the
following Schedule:
Year One Year Two Year Three Year Four Year Five Year
Six
Allocated
Flows: 25% 20% 15% 10% 5% 2.5%
Annual 75% 80% 85% 90% 95% 97.5%
Transmission
Revenue
Requirements:
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.
<PAGE>
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 those load-serving Participants owning or supporting PTF
which are obligated to take and pay for Regional Network Service and/or
Internal Point- to-Point Service in accordance with the Tariff, in proportion
to their 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.
SECTION 17
POOL-PLANNED UNIT SERVICE
17.1Effective Period. The provisions contained in this Section 17 shall
continue in effect for the period to and including February 28, 2001, and
shall be of no effect after that date.
17.2Obligation to Provide Service. Until February 28, 2001, 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 Participants Committee.
17.3Rules 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:
<PAGE>
(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 Participants Committee.
17.4Payments 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
<PAGE>
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 Participants 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 Participants 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.
<PAGE>
17.5Payments 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; except that
the requirements for such payments shall terminate on March 1, 1999 for
Participants receiving network service under both the Tariff and applicable
Local Network Service Tariff.
17.6Use of Other Transmission Facilities by Participants. For the period to
and including February 28, 1999, 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.
17.7Limits 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.
SECTION 17A
TRANSMISSION OWNERS RESERVED RIGHTS
Notwithstanding any other provision of this Agreement, or any other
agreement or amendment made in connection with the restructuring of NEPOOL,
each Transmission Owner shall retain all of the rights set forth in this
Section 17A; provided, however, that such rights shall be exercised in a
manner consistent with the Transmission Owner's rights and obligations under
the Federal Power Act and the Commission's rules and regulations thereunder.
17A.1Each Transmission Owner shall have the right at any time unilaterally to
file pursuant to Section 205 of the Federal Power Act to change the revenue
requirements underlying its component of the rates for service under the
NEPOOL Tariff and the transmission-related provisions of this Agreement.
17A.2Nothing in this Agreement shall restrict any rights, to the extent such
rights exist: (a) of Transmission Owners that are parties to a merger,
acquisition or other restructuring transaction to make a filing under Section
205 of the Federal Power Act with respect to the reallocation or
redistribution of revenues among such Transmission Owners; or (b) of any
Transmission Owner to terminate its participation in NEPOOL pursuant to
Section 21.2 of this Agreement, notwithstanding any effect its withdrawal from
NEPOOL may have on the distribution of transmission revenues among other
Transmission Owners. Further, nothing in this Agreement shall be interpreted
to permit the adoption of a rate design change that is inconsistent with any
settlement under the Tariff accepted by the Commission without the consent of
all signatories to the settlement.
<PAGE>
17A.3Each Transmission Owner retains all rights that it otherwise has incident
to its ownership of its assets, including, without limitation, its PTF and
non-PTF, including the right to build, acquire, sell, merge, dispose of,
retire, use as security, or otherwise transfer or convey all or any part of
its assets, including, without limitation, the right, individually or
collectively, to amend or terminate the Transmission Owner's relationship with
the ISO in connection with the creation of an alternative arrangement for the
ownership and/or operation of its transmission facilities on an unbundled
basis (e.g., a transmission company), subject to necessary regulatory
approvals and to any approvals required under applicable provisions of this
Agreement. This section is not intended to reduce or limit any other rights
of a Transmission Owner as a signatory to this Agreement.
17A.4The obligation of any Transmission Owner to expand or modify its
transmission facilities in accordance with the Tariff shall be subject to the
Transmission Owners' right to recover, pursuant to appropriate financial
arrangements contained in Commission-accepted tariffs or agreements, all
reasonably incurred costs, plus a reasonable return on investment, associated
with constructing and owning or financing such expansions or modifications to
its facilities.
17A.5Each Transmission Owner shall have the right to adopt and implement
procedures it deems necessary to protect its electric facilities from physical
damage or to prevent injury or damage to persons or property.
17A.6Each Transmission Owner retains the right to take whatever actions it
deems necessary to fulfill its obligations under local, state or federal law.
17A.7In addition to having the rights reserved under other provisions of this
Section 17A, all Participants retain the right to take any position before the
Commission, and any appellate court with jurisdiction to review a Commission
determination, or to seek a determination by the Commission, regarding
whether, and the extent to which, the Transmission Owners may retain the
exclusive right to make unilateral filings under Section 205 of the Federal
Power Act to amend the Tariff and the transmission related provisions of this
Agreement. If and to the extent the Commission rules that the Transmission
Owners do not retain such rights, then any such amendment that is not subject
to any of Section 17A.1 through 17A.6 may be filed with the Commission only
upon the approval by the Participants Committee of the amendment under Section
6.11, including Section 6.11(d). If and to the extent the Commission rules
that the Transmission Owners do retain such rights, then the Transmission
Owners, acting through the Transmission Owners Committee, shall have the
exclusive right to make unilateral filings under Section 205 of the Federal
Power Act to amend the Tariff and the transmission- related provisions of this
Agreement, other than filings subject to Sections 17A.1 or 17A.2.
17A.8(a) Notwithstanding anything to the contrary in this Agreement, the
rights of each Participant under the Federal Power Act shall be preserved.
(b) Any dispute over whether a matter falls within the scope of any of the
rights reserved under this Section 17A will be subject to resolution pursuant
to Section 11.A.
(c) No amendment to any provision of this Section 17A or Section 11B may
be adopted without the agreement of the Transmission Owners specified in
Section 11B.
<PAGE>
(d) Any agreement entered into between NEPOOL and a System Operator shall
require the System Operator to respect the rights reserved under this Section
17A.
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
18.1Designation of Pool-Planned Facilities. At the request of a Participant,
the Participants Committee shall designate as "pool- planned" a generating or
transmission facility to be constructed by the Participant or its Related
Person if the Participants Committee determines that the facility is
consistent with NEPOOL planning. The Participants 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.
18.2Construction 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 Participants 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.
18.3Protective 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
Participants 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 Participants 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.
18.4Review of Participant's Proposed Plans. Each Participant shall submit to
the System Operator, Participants Committee, the Reliability Committee, and
the Markets Committee or the Tariff Committee, as appropriate, for review by
them, in such form, manner and detail as the Participants 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 Participants Committee
<PAGE>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 Participants 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 Participants Committee and the Participant
required to submit the plan.
18.5Participant to Avoid Adverse Effect. If the Participants 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 or the Non- Participant on whose
behalf the Participant has submitted its plan takes such action or constructs
at its expense such facilities as the Participants 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 Participants Committee to address the adverse
effects on reliability or operating characteristics, the negotiations either
address the adverse effects to the satisfaction of the Participants Committee,
or no satisfactory resolution can be achieved on terms acceptable to the
parties within 90 days of the Participant's receipt of the Participants
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
19.1Annual Fee. Each Participant shall pay to NEPOOL in January of each year
an annual fee, which shall be applied toward NEPOOL expenses, as follows:
(a)Each End User Participant which is a non-profit residential or small
business consumer, or non-profit group representing such entities, shall pay
an annual fee of $500.
(b)Each End User Participant, other than non-profit residential or small
business consumers or non-profit groups representing such entities, shall pay
an annual fee of $500; plus an additional fee of $500 per megawatt hour of its
highest Energy use during any hour in the preceding year (net of any use of
on-site generation) up to a maximum of $5,000; plus an additional fee of $200
per megawatt hour for each megawatt hour by which its highest Energy use
during any hour in the preceding year (net of any use of on-site generation
during such hour) exceeded 20 megawatt hours.
(c)Each Participant which is a Publicly Owned Entity and a member of the
Publicly Owned Entity Sector shall pay an annual fee of $5,000, except that
any such Participant which is engaged in electricity distribution and had
annual Energy sales of less than 30,000 megawatt hours in the preceding year
shall pay an annual fee of $500, and the difference between $5,000 and $500
<PAGE>
for each such Participant shall be paid, as an additional fee, by the
remaining Participants which are Publicly Owned Entities and members of the
Publicly Owned Entity Sector.
(d)Each Participant other than an End User Participant or a Publicly Owned
Entity shall pay an annual fee of $5,000.
19.2NEPOOL Expenses. Commencing on January 1, 1999, most expenses of the
System Operator are recovered by it directly from Participants and Non-
Participants under the ISO's Tariff for Transmission Dispatch and Power
Administration (the "ISO Tariff") or through direct charges for services
rendered by the ISO, and have ceased to be NEPOOL expenses. At that time, the
payment of a portion of NEPEX expenses from the Savings Fund in accordance
with the Prior NEPOOL Agreement also terminated.
Further, commencing on January 1, 1999 through June 30, 1999, 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 Section 19.3, be
allocated among and paid monthly by the Participants in accordance with their
respective voting shares, as determined in accordance with the Agreement
provisions in effect during such period.
Commencing as of July 1, 1999, such balance of NEPOOL expenses for July and
subsequent months shall be divided equally into as many shares as there are
active Sectors pursuant to Sector 6.2 (other than an End User Sector) and each
Sector's share shall be paid monthly by the Participants in each such Sector
(other than an End User Sector) in such manner as the Participants in each
Sector may determine by unanimous vote and advise the ISO, provided that if
the Participants in a Sector fail to agree unanimously on the allocation of
their Sector's share, the Participants in the Sector shall pay for such Sector
share in the same proportion as the vote they are entitled to in the Sector.
Participants in the Sector that are represented by a group voting member shall
subdivide their portion of the Sector's share of expenses in such a manner as
they may determine by unanimous agreement; provided that if there is not
unanimous agreement among the Participants represented by a group member as to
how to allocate their portion of the Sector's share of expenses, such portion
shall be allocated among the Participants represented by that group member as
follows: (i) for each Participant in the Generation Sector represented by a
group voting member, the portion will be allocated in the same proportion that
the Megawatts of generation owned by the Participants represents of the total
Megawatts owned by Participants represented by the group voting member; and
(ii) for Participants in the Transmission Sector, the portion will be
allocated equally among the Participants represented by the group member.
Notwithstanding the foregoing, no portion of such balance shall be paid by End
User Participants and, until such time as an End User Sector is activated, the
monthly share allocated to the Publicly Owned Entity Sector shall be reduced
by one-twelfth of the aggregate annual fees paid by End Users for the year
pursuant to Section 19.1 and one- third of the amount of such reduction shall
be allocated to each of the other three Sectors.
19.3Restructuring Costs.
(a)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
<PAGE>
Independent System Operator and related separation costs, (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, and (iv) capital expenditures and capitalized project
costs of the Independent System Operator, shall be funded (to the extent not
already funded) and amortized according to this Section 19.3.
(b)The Restructuring Expense incurred (other than certain capital
expenditures and capitalized project costs funded separately by the ISO)
before the Second Effective Date (the "Early Restructuring Expense") has been
funded during the period prior to such date by those entities which have been
the Participants during such period. Commencing at the Second Effective Date,
the Early 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 Early Restructuring Expense, plus accumulated
interest, and each Participant or other Entity which previously paid an
unreimbursed portion of the aggregate Early 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 / A 1 in which
X is the percentage to be paid for a month by a Participant of the
aggregate amount payable pursuant to this subsection (b) by all Participants
for the month.
Ais the amount payable by the Participant for the month under Schedule 2
(Energy Administration Services) of the ISO Tariff (as defined in Section
19.2) as amended or revised from time to time.
A 1is the aggregate amount payable by all Participants for the month
under Schedule 2 (Energy Administration Services) of the ISO Tariff as amended
or revised from time to time.
Y =B / B 1 in which
Yis the percentage to be received for a month by a Participant or other
Entity of the aggregate amount to be received pursuant to this subsection (b)
by all Participants or other Entities for the month.
Bis the amount of Early Restructuring Expense paid by the Participant or
other Entity which has not previously been reimbursed.
B 1is the aggregate amount of Early Restructuring Expense paid by all
Participants and other Entities which has not previously been reimbursed.
<PAGE>
(c)The Restructuring Expense incurred on the Second Effective Date and to but
not including January 1, 2000 or thereafter shall be funded each month by the
Participants in proportion to the Member Fixed Voting Shares (as defined in
Section 6.9(c)) of each Participant as in effect at the beginning of the month
provided, however, that in calculating the allocation of this portion of the
Restructuring Expense, the Member Fixed Voting Shares of End User Participants
that participate in NEPOOL for governance purposes only in accordance with
NEPOOL's Standard Membership Conditions, Waivers and Reminders ("Governance
Only End User Participants") shall not be included in such calculations and
the amounts that would otherwise have been payable by such Governance Only End
User Participants will be allocated to all of the other Participants on the
basis of their Member Fixed Voting Shares.
(d)The Restructuring Expense incurred on or after January 1, 2000 (the "Late
Restructuring Expense") shall initially be funded for each month, on an as
incurred basis, by the Participants in proportion to their charges under the
ISO Tariff for the prior month. The aggregate Late Restructuring Expense
funded in any calendar year shall be amortized in equal monthly amounts and
repaid over the next 60 months, commencing in January of the immediately
succeeding calendar year, with interest thereon from the date of payment at
the rate equal to the average Weighted Costs of Capital of all Transmission
Providers in effect on October 20, 1999 (without subsequent adjustment)
determined pursuant to Section II(A)(2)(a) of the Implementation Rule for
Calculating Annual Transmission Revenue Requirements filed as a supplement to
the Tariff. Thus, for example, the Late Restructuring Expense incurred in
2000 will be amortized and repaid over a 60-month period commencing in January
2001. Each month during the applicable amortization period each Participant
shall pay its share of the portion of the Late Restructuring Expense being
amortized during such period, plus accumulated interest, and each Participant
or other Entity which previously paid an unreimbursed portion of the aggregate
Late Restructuring Expense being amortized during such period shall be
entitled to receive its share of the aggregate amount paid for such month,
including accumulated interest, according to an allocation methodology that is
based on the appropriate schedules of the ISO Tariff, which allocation
methodology will be established under subsection (e) below.
(e)The Participants agree to amend the Agreement within twelve months after
the Second Effective Date to specify how the balance of the Early
Restructuring Expense is to be paid. The Participants agree to amend the
Agreement by November 1, 2000 to provide for the amortization and repayment of
the Late Restructuring Expense, according to an allocation methodology that
is based on the appropriate schedules of the ISO Tariff as approved by the
Commission.
(f)The funding methodology set forth in subsection (d) shall terminate
automatically upon the implementation of a permanent restructuring funding
methodology acceptable to the Participants Committee and the ISO, to the
extent superseded by such permanent restructuring funding methodology.
SECTION 20
INDEPENDENT SYSTEM OPERATOR
<PAGE>
(a)The Participants 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 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.
(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 and capitalized project 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 Participants
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 Participants
Committee. For those Participants subject to the Public Utility Holding
Company Act of 1935 ("PUHCA"), any such acquisition by those Participants is
subject to PUHCA approval to the extent such acquisition requires approval
under PUHCA. Unless otherwise agreed by the Participants, the funding of the
acquisition, or lease, of land, structures, fixtures, equipment and
facilities, and other capital and/or capitalized project related expenditures,
or the acquisition of other assets, and the ownership thereof, or the
obligations of Participants as lessees, shall be in accordance with Section
19.3 of this Agreement. 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,
<PAGE>
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 Participants 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
Participants Committee any action taken by any other NEPOOL committee, and
shall be entitled to appear before the Participants Committee on any such
appeal. Further, the ISO shall be entitled to submit any dispute with respect
to a vote of the Participants 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 Participants Committee which denies an appeal to
the Participants 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 Participants 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 Participants
Committee within ten days of the action of the Participants Committee and
shall mail a copy of such notice to each member of the Participants
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
Participants Committee's action. Unless the Board of Directors of the ISO
acts within 60 days of the ISO's notice to the Participants Committee, the
Participants 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.
<PAGE>
(j)Appointment of Technical Committee Officers. The System Operator
shall, after its chief executive officer has conferred with the Participant
members of the Liaison Committee regarding such appointment(s), appoint the
Chair and Secretary of each of the Technical Committees. Each individual
appointed by the System Operator shall be an independent person not affiliated
with any Participant. Before appointing an individual to the position of
Chair or Secretary, the System Operator shall notify the Committee to which
such officer is being appointed of the proposed assignment and, consistent
with its personnel practices, provide any other information about the
individual reasonably requested by the Committee. In the event that a
Technical Committee determines that the performance of the Chair or Secretary
of the Committee is not satisfactory, the Committee shall provide notice to
the System Operator that such performance deficiencies must be corrected
within 60 days. If the Committee determines that the performance deficiencies
have not been corrected within the 60-day period, the Committee may vote to
remove the officer, subject to appeal to the Participants Committee. A vote
of the Technical Committee to remove its officer shall be immediately
effective and binding on the System Operator and shall cause the System
Operator to appoint a replacement officer in accordance with the provisions of
this Section 20(j) unless an appeal to the Participants Committee has been
taken prior to the end of the tenth business day following the vote to remove
the officer in which case the vote for removal shall be subject to the outcome
of such appeal. A vote of the Participants Committee with respect to any such
appeal shall be immediately effective and binding on the System Operator and
not subject to any further appeals.
SECTION 21
MISCELLANEOUS PROVISIONS
21.1 Alternative Dispute Resolution.
A. General:
If the ISO is aggrieved by a vote of the Participants 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 Participants
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 Participants Committee may submit the matter
for resolution hereunder; provided, however, that if the action of the ISO
relates to rulemaking, the Participants 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 Participants 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
<PAGE>
(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 Participants Committee shall give written notice to the
Secretary of the Participants Committee within ten business days of the vote,
and shall mail or telecopy a copy of its notice to each member of the
Participants Committee. Where the Participants Committee is seeking review of
an action of the ISO Board, the Participants 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
Participants 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 Participants 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 Participants Committee, the Aggrieved Party's notice to the
Participants 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 Participants 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 Participants 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.
<PAGE>
(ii)If the notice is to seek review of an ISO action, the
Participants 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 Participants Committee's right to proceed with
the arbitration if mediation does not resolve the matter within 20 days of the
giving of the Participants Committee's notice or such longer period as may be
fixed by mutual agreement of the ISO Board and the Participants 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 Participants 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 Participants 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 Participants Committee shall attempt to choose by mutual
agreement a single neutral arbitrator to hear the dispute. If the ISO or the
Participant and the Participants Committee fail to agree upon a single
arbitrator within ten calendar days of the giving of notice of arbitration to
the Secretary of the Participants 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 Participants Committee.
<PAGE>
(2)Costs: NEPOOL shall be responsible for all of the costs of
the proceeding if it is initiated by the ISO or by the Participants
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 Participants 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 Participants
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 Participants
Committee believes its decision should be upheld by the arbitrator, and copies
of any documents or other materials the Participants Committee wishes the
arbitrator to review. If the Participants 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.
<PAGE>
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 Participants 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:
Oif 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
Oon 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 Participants
Committee. In the event the Non- Participant is aggrieved by the Participants
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
<PAGE>
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 Participants 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 Participants 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
Participants 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
<PAGE>
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 incurred prior to the
effective time of such termination.
21.3Assignment. 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 Participants 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 Participants 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.
21.4Force 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 Participants Committee of
the commencement and end of any event of Force Majeure.
<PAGE>
21.5Waiver 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 Participants Committee. Any such waiver by the Participants
Committee in any particular instance shall not be deemed a waiver with respect
to any subsequent performance, default or matter.
21.6Other Contracts. No Participant shall be a party to any other agreement
which in any manner is inconsistent with its obligations under this
Agreement.
21.7Liability 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 Participants Committee may reasonably require with respect to
its obligation pursuant to Section 21.7(a).
21.8Records 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.
21.9Consistency 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 NPCC and NERC or any successor to either.
<PAGE>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. Subject to Section 17A and the provisions of this Section,
this Agreement, including the Tariff, and any attachment or exhibit hereto may
be amended from time to time by vote of the Participants in accordance with
Section 6.11.
Any amendment to this Agreement approved in accordance with Section 6.11
and/or Section 17A shall be in writing and shall become effective, and shall
bind all Participants regardless of whether they have executed a ballot in
favor of such amendment, on the date specified in the amendment, subject to
acceptance or approval by the Commission. 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 Agreement.
21.12Termination. This Agreement shall continue in effect until terminated,
in accordance with the Commission's regulations, by Participants represented
by members of the Participants Committee having Member Fixed Voting Shares
equal to at least 70% of the Member Fixed 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, Committees, Committee Members, or the System
Operator.
(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 Participants Committee
member or alternate representing that Participant; (2) mailed, postage
prepaid, to the Participant at the address of its member on the Participants
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 Participants 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 Participants
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 Participants 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.
<PAGE>
(c)Any notice, demand, request or other communication required or
authorized by this Agreement to be given to a member or alternate to that
member of a Principal Committee (for the purposes of this Section 21.13,
individually or collectively, the "Committee Member") shall be (1) personally
delivered to the Committee Member; (2) mailed, postage prepaid, to the
Committee Member at the address of the Committee Member set out in the NEPOOL
roster; (3) sent by facsimile ("faxed") to the Committee Member at the fax
number of the Committee Member set out in the NEPOOL roster; or (4) delivered
electronically to the Committee Member at the electronic mail address of the
Committee Member set out in the NEPOOL roster. The designation of any such
address may be changed at any time by written notice delivered to the
Secretary of the Principal Committee on which the Committee Member serves, who
shall cause such change to be reflected in the NEPOOL roster.
(d)Any notice, demand, request or other communication required or
authorized by this Agreement to be given to the System Operator shall be in
writing, and shall be (1) personally delivered to the Participants Committee
member or alternate appointed by the System Operator; (2) mailed, postage
prepaid, to the System Operator at the address of its member on the
Participants Committee as set out in the NEPOOL roster; (3) sent by facsimile
("faxed") to the System Operator at the fax number of its member on the
Participants Committee as set out in the NEPOOL roster; or (4) delivered
electronically to the System Operator at the electronic mail address of its
member on the Participants 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 Participants Committee, who
shall cause such change to be reflected in the NEPOOL roster.
(e)To the extent that the Participants Committee is required to serve
upon any Participant a copy of any document or correspondence filed with the
Commission under the Federal Power Act or the Commission's rules and regulations
thereunder, by or on behalf of any Principal Committee, such service may be
accomplished by electronic delivery to the Participant at the electronic mail
address of its Participants Committee member and alternate. The designation
of any such address may be changed at any time by written notice delivered to
the Secretary of the Participants Committee.
(f)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, Committee Member, System Operator, or Secretary
of the NEPOOL 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.
<PAGE>
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 Reliability
Committee.
B. Periodic Review
Calculations of MW-Mile allocations shall be performed whenever
significant changes to the transmission system load flows, as determined by
the Reliability Committee, 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 Reliability
Committee.
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
<PAGE>
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 Reliability Committee. 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 and for which there are
no arrangements in effect by which other Participants support the facility.
For facilities that are jointly owned and/or supported, each Participant shall
be assigned MW-miles in proportion to the percentage of its ownership of
jointly-owned facilities and/or the percentage of its support for facilities
that are jointly supported to the extent such support payments are included in
the determination of Annual Transmission Revenue Requirements.
<PAGE> Execution Copy
Restated 1999 Amendatory Agreement
(Cash-Out)
This Restated Amendatory Agreement, dated as of November 17, 1999 between
VERMONT YANKEE NUCLEAR POWER CORPORATION ("Vermont Yankee"), a Vermont
corporation, and [NAME OF PURCHASER], a ______________ corporation (the
"Purchaser"), amending both the Power Contract, dated February 1, 1968, as
heretofore amended by eight amendments dated June 1, 1972, April 15, 1983,
April 24, 1985, June 1, 1985, May 6, 1988, June 15, 1989 and December 1, 1989
between Vermont Yankee and the Purchaser (the "Power Contract") and the
Additional Power Contract, dated as of February 1, 1984, between Vermont
Yankee and the Purchaser (the "Additional Power Contract"), supersedes and
replaces the original Amendatory Agreement, dated as of November 17, 1999, and
reflects certain technical corrections in that original.
For good and valuable consideration, the receipt of which is hereby
acknowledged, it is agreed as follows:
1. Basic Understandings.
--------------------
Vermont Yankee was organized in 1966 to provide for the supply of power
to its sponsoring utility companies, including the Purchaser (collectively,
the "Purchasers"). It constructed a nuclear electric generating unit, having
a net capability of approximately 510 megawatts electric (the "Unit") at a
site in Vernon, Vermont. Vermont Yankee was issued a full-term, Facility
Operating License for the Unit by the Atomic Energy Commission (now the
Nuclear Regulatory Commission, which, together with any successor agencies, is
hereafter called the "NRC"), which license is now stated to expire on March
21, 2012 (the "End of License Term"). The Unit has been in commercial
operation since December 1, 1972 and continues to operate.
The names of the Purchasers of Vermont Yankee and their respective
interests ("entitlement percentages") in Vermont Yankee and the net capacity
and output of the Unit are as follows:
<TABLE>
<CAPTION>
Purchaser Entitlement Percentage
--------- -----------------------
<S> <C>
Central Vermont Public Service Corporation 35.0%
Green Mountain Power Corporation 20.0%
New England Power Company 20.0%
The Connecticut Light and Power Company 9.5%
Central Maine Power Company 4.0%
Public Service Company of New Hampshire 4.0%
Western Massachusetts Electric Company 2.5%
Montaup Electric Company 2.5%
Cambridge Electric Light Company 2.5%
</TABLE>
<PAGE>
The Unit was conceived to supply economic power on a cost of service
formula basis to the Purchasers. Pursuant to the Power Contract, Vermont
Yankee has agreed to supply to the Purchaser and, pursuant to separate power
contracts substantially identical to the Power Contract except for the names
of the parties (collectively, the "Initial Power Contracts"), to the other
Purchasers all of the capacity and the electric energy available from the Unit
for a thirty year term extending through November 30, 2002.
Pursuant to the Additional Power Contract, Vermont Yankee has agreed to
supply to the Purchaser, and pursuant to separate additional power contracts
substantially identical to the Additional Power Contract except for the names
of the parties (collectively, the "Additional Power Contracts"), to the other
Purchasers all the capacity and electric energy available from the Unit during
an operative term stated to commence on December 1, 2002 (when the Initial
Power Contracts terminate) and extending until a date which is 30 days after
the later of the date on which the last of the financial obligations of
Vermont Yankee has been extinguished or the date on which Vermont Yankee is
finally relieved of any obligations under the last of the licenses (operating
or possessory) which it holds, or hereafter receives, from the NRC with
respect to the Unit. The Additional Power Contracts also provide, in the
event of their earlier cancellation, that the decommissioning cost obligation
and the other applicable provisions of the Additional Power Contracts shall
remain in effect to permit final billings of costs incurred prior to such
cancellation.
Pursuant to the Initial Power Contracts and the Additional Power
Contracts, the Purchasers are entitled and obligated to take their respective
entitlement percentages of the capacity and net electrical output of the Unit
during the service life of the Unit and are obligated to pay therefor monthly
their respective entitlement percentages of Vermont Yankee's cost of service,
including decommissioning costs, whether or not the Unit is operated.
On October 15, 1999, the Board of Directors of Vermont Yankee, which
includes representatives of the Purchasers (including the Purchaser), after
conducting a thorough review of the economics of continued operation of the
Unit until End of License Term in comparison to other alternatives (including
the early shut-down of the Unit) available to Vermont Yankee, voted to approve
an Asset Purchase Agreement (the "APA") between Vermont Yankee and AmerGen
Energy Company L.L.C., a Delaware limited liability company ("AmerGen"),
pursuant to which the Unit and related assets of Vermont Yankee, including a
pre-funded decommissioning trust, would be sold to AmerGen. The APA provides,
among other things, that Vermont Yankee will enter into a Power Purchase
Agreement (the "PPA") with AmerGen to purchase from AmerGen one hundred
percent (100%) of the actual net output of the Unit up to its present
operating level of approximately 510 megawatts electric (the "Future Power")
for a period ending at the End of License Term or the earlier permanent shut-
down of the Unit, such percentage being subject to reduction to the extent
that certain Purchasers, including the Purchaser, having entitlement
percentages aggregating 45% or less, elect the option of "cashing-out" of the
obligation to purchase Future Power and later "cash-outs" by remaining long-
term Purchasers. It is intended that the Future Power will be resold by
Vermont Yankee to the other Purchasers, excluding Purchaser, pursuant to the
Power Contracts and Additional Power Contracts as amended by amendatory
agreements similar to this agreement. Concurrently, the Directors of Vermont
Yankee also approved a Transmission Asset Purchase Agreement (the "TAPA")
providing for the sale of certain transmission assets to Vermont Electric
Power Company, Inc. ("Velco) and the payment by Vermont Yankee of certain
support charges to Velco (the "TAPA Obligations").
<PAGE>
As a consequence of the APA, the PPA and the TAPA, Vermont Yankee and the
Purchaser propose to further amend the Power Contract and the Additional Power
Contract in various respects in order (I) to release Vermont Yankee from any
further obligations under said contracts with respect to the operation of the
Unit, (ii) to clarify and confirm provisions for the recovery under said
contracts of the remaining unamortized costs previously incurred by Vermont
Yankee in providing capacity and energy from the Unit prior to the Effective
Date (as hereinafter defined) and of the costs of decommissioning the Unit at
the end of its useful life (including, without limitation, the costs of
maintaining the Unit in a safe condition following its shutdown and prior to
its decontamination and dismantlement and the costs of storing the Unit's
spent nuclear fuel until it is removed by the Department of Energy), and
(iii) to provide for the recovery of any costs or liabilities assumed by
Vermont Yankee under the APA and the TAPA and of Vermont Yankee's on-going
administrative expenses.
Vermont Yankee and the Purchaser have agreed to enter into this
Amendatory Agreement. Concurrently herewith each of the other Purchasers is
entering into an amendatory agreement which is identical hereto except for the
necessary changes in the names of the parties and, where appropriate, the
inclusion or exclusion of the obligation to purchase an aliquot share of the
Future Power.
2. Parties' Contractual Commitments.
---------------------------------
Vermont Yankee and the Purchaser each acknowledge that the other has
faithfully performed its obligations under the Power Contract. The Purchaser
hereby reconfirms its obligations under the Power Contract and the Additional
Power Contract to pay its entitlement percentage of Vermont Yankee's
unamortized costs and the decommissioning costs of the Unit as deferred
payment in connection with the capacity and net electrical output of the Unit
previously delivered by Vermont Yankee and agrees that the decision to sell
the Unit as described in Section 1 hereof did not give rise to any
cancellation right under Section 9 of the Power Contract or Section 10 of the
Additional Power Contract. Vermont Yankee and the Purchaser further
acknowledge that certain of the Purchasers, not including the Purchaser, shall
continue to be entitled and obligated to purchase their aliquot shares of the
Future Power produced by the Unit during the terms of the Initial Power
Contracts and Additional Power Contracts as modified by amendatory agreements
similar to that agreement and to pay a like percentage of Vermont Yankee's
costs therefor, and that Vermont Yankee shall continue to be obligated to sell
such Future Power to those Purchasers during such terms. Recognizing that the
APA, by transferring ownership and operating responsibility for the Unit,
changes the nature of the costs that Vermont Yankee will incur to obtain
Future Power from the Unit for resale to those Purchasers, Vermont Yankee and
the Purchaser further agree that this Amendatory Agreement sets forth the
necessary and appropriate provisions for the continuation of the foregoing
entitlements and obligations.
Except as expressly modified by this Amendatory Agreement, the provisions
of the Power Contract and the Additional Power Contract remain in full force
and effect.
3. Effective Date.
---------------
Subject to receipt of FERC approval, this Amendatory Agreement shall
become effective on the Closing Date under the APA (the "Effective Date").
<PAGE>4. Power Contract Amendments.
--------------------------
The Power Contract is hereby amended as follows:
(a)In recognition of the sale of the Unit being effected pursuant to the
APA and the intention of the parties to release Vermont Yankee from any
further obligations with respect to operation of the Unit, the text of each
of Sections 3, 4, 6, 8, 9 and 10 of the Power Contract is hereby deleted and,
in lieu thereof in each instance the words "Intentionally Deleted and This
Section Left Blank" shall be inserted; provided, however, that the
pre-existing text shall remain in effect for purposes of settling any accounts
between the parties for periods prior to the Effective Date.
(b)Section 5 is hereby deleted and a new Section 5A is hereby inserted to
read as follows:
"5A. Termination of Obligation.
All payments made pursuant to this Amendatory Agreement and pursuant to
the Power Purchase Agreement Cash-Out Election dated as of November 17, 1999
between AmerGen and Purchaser are made in termination of Purchaser's
obligations and entitlements under former Section 5 of this contract.
Purchaser's obligations and entitlements under former Section 5 of this
contract are hereby terminated.
(c)A new section 10A is hereby inserted immediately following Section 10
to read as follows:
"10A. Definitions.
------------
Unless the context otherwise specifies or requires, each term defined
below, when used in this contract, shall have the meaning indicated below:
"Adjusted Entitlement Percentage" means the percentage derived by dividing the
Purchaser's entitlement percentage by the aggregate entitlement percentages of
all Purchasers that have not exercised their Prepayment Options under Section
7A of their respective Power Contracts.
"AmerGen" means AmerGen Energy Company L.L.C., a Delaware limited liability
company.
"APA" means the Asset Purchase Agreement, dated as of November 17, 1999,
between Vermont Yankee and AmerGen.
"APA Obligations" means the obligations of Vermont Yankee to AmerGen under the
APA, a schedule of which is attached as Exhibit A hereto.
"Cash Out Option" means the Power Purchase Agreement Cash-Out Election as
defined in the APA.
"Closing" means the Closing as defined in the APA.
<PAGE>
"Credit Agreement" means the loan agreement entered into between Vermont
Yankee and the lending institutions named therein, to be dated on or before
the Effective Date and relating to the borrowing by Vermont Yankee of the
funds needed to prefund the Decommissioning Trust, prepay its outstanding
Bonds on the Effective Date and defray other costs in connection with the
Closing.
"Effective Date" means the Closing Date under the APA.
"Entitlement percentage" has the meaning provided in Section 1 hereof.
"End of License Term" means March 21, 2012.
"End of Term Date" means the earlier of the End of License Term
or the date on which the Unit is permanently removed from service.
"Net capacity" means for any period the actual level at which the Unit is
operated, less station service use and transformer losses.
"PPA" means the Power Purchase Agreement, dated November 17, 1999, between
Vermont Yankee, as buyer, and AmerGen, as seller, a complete copy of which is
attached hereto as Exhibit C.
"Prepayment Option" has the meaning set forth in Section 7A.
"Purchasers" means the sponsoring utilities named in Section 1 hereof or their
respective successors or assigns.
"TAPA" means the Transmission Asset Purchase Agreement, dated as of
November 17, 1999, between Vermont Yankee and Velco.
"TAPA Obligations: shall mean the maintenance and other support obligations
assumed by Vermont Yankee with respect to the transmission assets conveyed to
Velco pursuant to the TAPA, a schedule of which is attached as Exhibit B
hereto.
"Velco" means Vermont Electric Power Company, Inc.
(d) In recognition of the Purchaser's continuing obligation to reimburse
Vermont Yankee for its entitlement percentage of certain of Vermont Yankee's
costs as deferred payment for the capacity and net electrical output of the
Unit previously delivered by Vermont Yankee and to reflect the change in the
manner in which Vermont Yankee will incur costs to supply other Purchasers
with their entitlement percentages of the Future Power to be purchased
pursuant to the PPA by Vermont Yankee from AmerGen, the provisions of Sections
7 and 7A of the Power Contract are hereby deleted and new Sections 7 and 7A
are inserted in lieu thereof as follows:
"7. Reimbursed Costs
-----------------
With respect to each month during the balance of the term of this
contract, the Purchaser will pay Vermont Yankee (I) an amount equal to the
Purchaser's entitlement percentage (or the Purchaser's Adjusted Entitlement
Percentage, whichever is applicable, as provided in Section 7A hereof), of
each of (a) the portion of Vermont Yankee's Closing Net Unit Investment
allocable
<PAGE>
to such month, together with one-twelfth of the composite percentage for such
month of the net Unit investment as most recently determined in accordance
with this Section 7, and (b) Vermont Yankee's Total Decommissioning Obligation
for such month, and (ii) an amount equal to the Purchaser's entitlement
percentage of the sum of (c) Vermont Yankee's total operating expenses for
such month, plus (d) Vermont Yankee's APA Obligations, if any, for such month,
plus (e) Vermont Yankee's TAPA Obligations, if any, for such month, plus (f)
to the extent not duplicative of a payment made under clause (a) above or
clause (I) of Section 7A, the portion of Vermont Yankee's net Unit investment
represented by the Purchaser's entitlement percentage of the Equity investment
allocable to such month, together with an amount equal to one- twelfth of the
equity percentage for such month of the Purchaser's entitlement percentage of
the Equity investment, as most recently determined in accordance with this
Section 7; provided, however, for any month during the term of this contract
commencing on or after the date on which the Purchaser has exercised its
option under clause (I) of Section 7A, the Purchaser will no longer be
obligated to make further payments under clause (I) above.
"Composite percentage" shall be computed as of the Effective Date and as of
the last day of each month thereafter (the "computation date") and for any
month the composite percentage shall be that computed as of the most recent
computation date. "Composite percentage" as of a computation date shall be
the sum of (I) the equity percentage as of such date multiplied by the
percentage which equity investment as of such date is of the total capital as
of such date, plus (ii) the stated interest rate per annum of each principal
amount of indebtedness (other than the Decommissioning Borrowing) bearing a
particular rate of interest outstanding on such date for money borrowed from
persons other than Purchasers multiplied by the percentage which such
principal amount is of total capital as of such date.
"Equity percentage" as of any date shall be whatever percentage may be
authorized from time to time by FERC.
"Common stock equity investment" as of any date shall consist of equity
investment as of such date less the aggregate par value of all issues of
preferred stock outstanding on such date.
"Equity investment" as of any date shall consist of the sum of (I) all
amounts theretofore paid to Vermont Yankee for all capital stock theretofore
issued (taken at the total par value thereof plus the total of all amounts in
an excess of such par value paid thereon); plus all capital contributions,
loans and advances theretofore made to Vermont Yankee by its Purchasers, less
the sum of any amounts distributed by Vermont Yankee to its Purchasers or
stockholders in the form of stock repurchases or redemptions, return of
capital or repayments of loans and advances; plus (ii) any credit balance in
the capital surplus account (not included under (I)) and in earned surplus
account on the books of Vermont Yankee as of such date.
"Total capital" as of any date shall be the equity investment plus the total
of all indebtedness then outstanding for money borrowed from other than
Vermont Yankee's Purchasers, excluding Decommissioning Borrowing.
<PAGE>
"Uniform System" shall mean the Uniform System of Accounts prescribed by the
Federal Power Commission for Class A and Class B Public Utilities and
Licensees as in effect on the date of this contract and as said System may be
hereafter amended to take account of private ownership of special nuclear
material.
Vermont Yankee's "operating expenses" shall include all expenses incurred by
Vermont Yankee after the Effective Date (I) for administrative and general
expenses which would be properly chargeable by an operating electric utility,
less any applicable credits thereto, in accordance with the Uniform System and
(ii) for expenses resulting from the settlement of claims of dissenting
shareholders.
The "net Unit investment" shall consist, in each case with respect to the
Unit, of (I) the aggregate amount properly chargeable at the time in
accordance with the Uniform System of Vermont Yankee's electric plant accounts
(including construction work in progress but excluding the Decommissioning
Borrowing), less the sum of (x) the aggregate amount included in operating
expenses from the plant completion date to the date in question on account of
depreciation accruals (and amortization, if any, of property losses) reduced
by the aggregate of all amounts charged during such period against the
accumulated provision for depreciation plus (y) the amount of net available
cash; plus (ii) the aggregate amount properly chargeable at the time in
accordance with the Uniform System to accounts representing fuel assemblies
and components (including nuclear materials) and other materials and supplies,
less the balance, if any, at the time of the accumulated amortization thereof;
plus (iii) such reasonable allowances for prepaid items and cash working
capital as may from time to time be determined by Vermont Yankee; less (z) the
net proceeds received from the sale of any assets properly included in said
electric plant accounts. However, for purposes of this contract, the net
amount included at any date after the plant completion date in net Unit
investment under clause (I) of the immediately preceding sentence shall in no
event be less than the excess of:
(a) the amount properly chargeable at the plant completion date in accordance
with the Uniform System to electric plant accounts (including construction
work in progress) with respect to the Unit,
over
(b) the sum of (x) the aggregate minimum amount required by this Section 7 to
be included in operating expenses from the plant completion date to the date
in question on account of depreciation accruals (and amortization, if any, or
property losses) plus (y) the amount of net available cash.
The net Unit investment shall be determined as of the plant completion
date and thereafter as of the commencement of each calendar year, or, if
Vermont Yankee elects, at more frequent intervals.
The "Closing Net Unit Investment" means the amount of net Unit investment
determined as of the Effective Date, which amount shall be amortized in equal
monthly amounts during the period beginning on the Effective Date and ending
on the End of License Term.
<PAGE>
"Net available cash" means, at any date as of which the amount thereof is
to be determined, the excess of (a) the aggregate amount received by Vermont
Yankee after the plant completion date and prior to two years before the
determination date as insurance proceeds on account of loss or damage to the
Unit or as the proceeds of a sale or condemnation of a portion of the Unit,
over (b) the aggregate amount expended after the plant completion date and
prior to the determination date on account of rebuilding, repairs,
replacements and additions to the Unit, provided that insurance proceeds
received with respect to a particular loss shall be taken into account for
purposes of the foregoing computation only if the amount received with respect
to the loss exceeds $150,000.
"Total Decommissioning Obligation" for any month shall mean the sum of
(I) an amount equal to the principal payment, if any, of the Decommissioning
Borrowing due for such month plus (ii) the interest payment due for such month
on the Decommissioning Borrowing.
"Decommissioning Borrowing" means the balance outstanding from time to
time under (I) the Credit Agreement or (ii) any refinancing of any unpaid
balance of such borrowing.
Vermont Yankee will bill the Purchaser, as soon as practicable after the
end of each month, for all amounts payable by the Purchaser pursuant to this
Section 7 with respect to the particular month. Such bills will be rendered
in such detail as the Purchaser may reasonably request and may be rendered on
an estimated basis subject to corrective adjustments in subsequent billing
periods. All bills shall be paid in full within 10 days after receipt thereof
by the Purchaser.
7A. Prepayment Option
-----------------
The Purchaser is hereby granted an option to prepay (the "Prepayment
Option"), (i) in full but not in part, its entitlement percentage of Vermont
Yankee's Closing Net Unit Investment (excluding the portion thereof
represented by the Purchaser's equity investment in Vermont Yankee) and
Decommissioning Borrowing, together with any interest accrued but unpaid
thereon, and (ii) with Vermont Yankee's consent, in full but not in part, the
Purchaser's entitlement percentage of the Equity investment, together with an
amount equal to the equity percentage return accrued and unpaid thereon, all
determined as of the close of business on the day prior to the exercise date;
provided, however that (x) option under clause (ii) may only be exercised
concurrently with, or subsequent to, the exercise of the option under clause
(i) and (y) promptly after such exercise by Purchaser, Vermont Yankee shall
redeem the Purchaser's equity investment in Vermont Yankee. Such option or
options to be exercisable on the Effective Date or on the first day of any
calendar quarter thereafter during the term of this contract (an "exercise
date'). At least 30 days prior to the estimated Effective Date, Vermont
Yankee shall give written notice to the Purchaser providing its best estimate
of the amount subject to these options as of the Effective Date. Thereafter,
upon written request by the Purchaser at least 60 days prior to the next
exercise date, Vermont Yankee shall provide to the Purchaser its
<PAGE>
best estimate of the amounts subject to these options as of such exercise
date. Purchaser shall give Vermont Yankee at least 15 days prior written
notice of its intent to exercise one or both of these options, which notice
shall be binding and may not be withdrawn without the prior written consent of
Vermont Yankee. Within ten days after receipt of such notice, Vermont Yankee
shall provide the Purchaser with a calculation of the prepayment amount due
upon exercise. After making such prepayment and, if appropriate, delivering to
Vermont Yankee the certificates evidencing the Purchaser's equity investment
in Vermont Yankee together with duly endorsed stock powers, the Purchaser
shall no longer be responsible for paying any amounts under clause (I) of the
first paragraph of Section 7 with respect to the period following the exercise
of the Prepayment Option or, if the option under clause (ii) above has been
exercised, be a stockholder of Vermont Yankee. "After making the prepayment
due upon exercise of the option under clause (I) above, the Purchaser shall
only remain obligated to pay all other amounts due under this contract,
including, without limitation, amounts billed under clause (ii) of the first
paragraph 7, provided that after the option under clause (ii) above has been
exercised, Purchaser shall not be obligated for any further payments under
clause (ii)(f) of the first paragraph of Section 7."
In the event that any other Purchasers exercise their Prepayment Options
under any of the other Initial Power Contracts and the Purchaser has not
exercised its Prepayment Option, then from and after the exercise of each such
other Prepayment Option the Purchaser shall pay its Adjusted Entitlement
Percentage of amounts due under clause (I) of the first paragraph of Section 7
hereof."
(e) Section 14 of the Power Contract is hereby amended by adding the
following sentence at the end thereof:
"Notwithstanding the foregoing, (a) Purchaser (or its assigns) may assign its
interest in this contract only (I) to a third party that has a credit rating
equal to the higher of that of the assignor or of investment grade as
determined by a nationally rated service, or (ii) to a single purpose entity
whose obligations hereunder are guaranteed by a parent that has such a credit
rating, or (iii) in connection with a merger, consolidation or sale of
substantially all its assets to another party that has a credit rating at
least equal to that of the Purchaser (or its assigns), and (b) the Purchaser
hereby consents to an assignment by Vermont Yankee of its interest in this
contract to the special purpose entity described or referred to in Schedule
7.1(z) of the APA and agrees that Purchaser's obligations hereunder shall not
be affected by such assignment."
5. Additional Power Contract Amendments.
-------------------------------------
The Additional Power Contract is hereby amended as follows:
<PAGE>
(a) In recognition of the sale of the Unit being effected pursuant to the
APA and, the intention of the parties to release Vermont Yankee from any
further obligations with respect to operation of the Unit, the text of each of
Sections 3, 4, 6, 8, 9 and 10 of the Additional Power Contract is hereby
deleted and, in lieu thereof in each instance the words "Intentionally Deleted
and This Section Left Blank" shall be inserted.
(b) Section 5 is hereby deleted and a new Section 5A is hereby inserted to
read as follows:
"5A. Termination of Obligation.
All payments pursuant to this Amendatory Agreement and pursuant to the
Power Purchase Agreement Cash-Out Election dated as of November 17, 1999
between AmerGen and Purchaser are made in termination of Purchaser's
obligations and entitlements under former Section 5 of this contract.
Purchaser's obligations and entitlements under former Section 5 of this
contract are hereby terminated."
(c) A new section 10A is hereby inserted immediately following Section 10
to read as follows:
"10A. Definitions.
------------
Unless the context otherwise specifies or requires, each term defined
below, when used in this contract, shall have the meaning indicated below:
"Adjusted Entitlement Percentage" means the percentage derived by dividing the
Purchaser's entitlement percentage by the aggregate entitlement percentages of
all Purchasers that have not exercised their Prepayment Options under their
respective Power Contracts.
"AmerGen" means AmerGen Energy Company L.L.C., a Delaware limited liability
company.
"APA" means the Asset Purchase Agreement, dated as of November 17, 1999,
between Vermont Yankee and AmerGen.
"APA Obligations" means the obligations of Vermont Yankee to AmerGen, a
schedule of which is attached as Exhibit A hereto.
"Closing" means the Closing as defined in the APA.
"Credit Agreement" means the loan agreement entered into between
Vermont Yankee and the lending institutions named therein, to be dated on or
before the Effective Date and relating to the borrowing by Vermont Yankee of
the funds needed to prefund the Decommissioning Trust, prepay its outstanding
Bonds on the Effective Date and defray other costs in connection with the
Closing.
"Effective Date" means the Closing Date under the APA.
"End of License Term" means March 21, 2012.
<PAGE>
"End of Term Date" means the earlier of the End of License Term or the date on
which the Unit is permanently removed from service.
"Entitlement percentage" has the meaning provided in Section 1 hereof.
"Initial Power Contracts" means the several Power contracts, dated as of
February 1, 1968, as amended, between Vermont Yankee and each of the
Purchasers.
"Net capacity" means for any period the actual level at which the Unit is
operated, less station service use and transformer losses.
"Operative term" has the meaning provided in Section 2 hereof.
"PPA" means the Power Purchase Agreement, dated November 17, 1999 between
Vermont Yankee, as buyer, and AmerGen, as seller, a complete copy of which is
attached hereto as Exhibit C.
"Prepayment Option" means the option granted to each of the several Purchasers
pursuant to Section 7A of their respective Initial Power Contracts to prepay
their entitlement percentages of certain of Vermont Yankee's costs.
"Purchasers" means the sponsoring utilities named in Section 1 hereof or their
respective successors or assigns.
"TAPA" means the Transmission Asset Purchase Agreement, dated as of November
17, 1999, between Vermont Yankee and Velco.
"TAPA Obligations" shall mean the maintenance and other support obligation
assumed by Vermont Yankee with respect to the transmission assets conveyed to
Velco pursuant to the TAPA, a schedule of which is attached as Exhibit B
hereto.
"Velco" means Vermont Electric Power Company, Inc.
(d) Section 2 of the Additional Power Contract is hereby amended in full
to read as follows:
"The operative term of this contract shall commence on December 1, 2002
notwithstanding the fact that the Unit has been sold to AmerGen and shall
terminate 30 days after the date on which the last of the respective financial
obligations of Vermont Yankee and the Purchaser which constitute elements of
the reimbursed costs calculated pursuant to Section 7 hereof has been
extinguished."
<PAGE>
(e) In recognition of the Purchaser's continuing obligation to reimburse
Vermont Yankee for its entitlement percentage of certain of Vermont Yankee's
costs as deferred payment for the capacity and net electrical output of the
Unit previously delivered by Vermont Yankee and to reflect the change in the
manner in which Vermont Yankee will incur costs to supply certain Purchasers
with their aliquot shares of the Future Power to be purchased pursuant to the
PPA by Vermont Yankee from AmerGen, the provisions of Section 7 of the
Additional Power Contract are hereby deleted and a new Sections 7 and 7A are
inserted in lieu thereof as follows:
"7. Reimbursed Costs
----------------
With respect to each month during the operative term of this contract,
the Purchaser will pay Vermont Yankee (I) an amount equal to the Purchaser's
entitlement percentage (or the Purchaser's Adjusted Entitlement Percentage,
whichever is applicable, as provided below,) of each of (a) the portion of
Vermont Yankee's Closing Net Unit Investment applicable to such month,
together with one-twelfth of the composite percentage for such month of the
net Unit investment as most recently determined in accordance with this
Section 7, and (b) Vermont Yankee's Total Decommissioning Obligation for such
month, and (ii) an amount equal to the Purchaser's entitlement percentage of
the sum of (c) Vermont Yankee's total operating expenses for such month, plus
(d) Vermont Yankee's APA Obligations, if any, for such month, plus (e) Vermont
Yankee's TAPA Obligations, if any, for such month, plus (f) to the extent not
duplicative of a payment made under clause (a) above or clause (I) of Section
7A, the portion of Vermont Yankee's net Unit investment represented by the
Purchaser's entitlement percentage of the Equity investment allocable to such
month, together with an amount equal to one-twelfth of the equity percentage
for such month of the Purchaser's entitlement percentage of the Equity
investment, as most recently determined in accordance with this Section 7;
provided, however, for any month during the term of this contract commencing
on or after the date on which the Purchaser has exercised its option under
clause (I) of Section 7A, then for each month thereafter the Purchaser's
Adjusted Entitlement Percentage shall be applicable to the payment required by
clauses (a) and (b) hereof.
"Composite percentage" shall be computed as of the Effective Date and as of
the last day of each month thereafter (the "computation date") and for any
month the composite percentage shall be that computed as of the most recent
computation date. "Composite percentage" as of a computation date shall be
the sum of (I) the equity percentage as of such date multiplied by the
percentage which equity investment as of such date is of the total capital as
of such date, plus (ii) the stated interest rate per annum of each principal
amount of indebtedness (other than the Decommissioning Borrowing) bearing a
particular rate of interest outstanding on such date for money borrowed from
persons other than Purchasers multiplied by the percentage which such
principal amount is of total capital as of such date.
<PAGE>
"Equity percentage" as of any date shall be whatever percentage may be
authorized from time to time by FERC.
"Common stock equity investment" as of any date shall consist of equity
investment as of such date less the aggregate par value of all issues of
preferred stock outstanding on such date.
"Equity investment" as of any date shall consist of the sum of (I) all
amounts theretofore paid to Vermont Yankee for all capital stock theretofore
issued (taken at the total par value thereof plus the total of all amounts in
an excess of such par value paid thereon); plus all capital contributions,
loans and advances theretofore made to Vermont Yankee by its Purchasers, less
the sum of any amounts distributed by Vermont Yankee to its Purchasers or
stockholders in the form of stock repurchases or redemptions, return of
capital or repayments of loans and advances; plus (ii) any credit balance in
the capital surplus account (not included under (I)) and in earned surplus
account on the books of Vermont Yankee as of such date.
"Total capital" as of any date shall be the equity investment plus the total
of all indebtedness then outstanding for money borrowed from other than
Vermont Yankee's Purchasers, excluding Decommissioning Borrowing.
"Uniform System" shall mean the Uniform System of Accounts prescribed by the
Federal Power Commission for Class A and Class B Public Utilities and
Licensees as in effect on the date of this contract and as said System may be
hereafter amended to take account of private ownership of special nuclear
material.
Vermont Yankee's "operating expenses" shall include all ordinary and necessary
expenses incurred by Vermont Yankee during the operative term of this contract
for administrative and general expenses which would be properly chargeable to
Administrative and General Expenses by an operating electric utility, less any
applicable credits thereto, in accordance with the Uniform System and (ii) for
expenses resulting from the settlement of claims of dissenting shareholders.
The "net Unit investment" shall consist, in each case with respect to the
Unit, of (I) the aggregate amount properly chargeable at the time in
accordance with the Uniform System of Vermont Yankee's electric plant accounts
(including construction work in progress but excluding the Decommissioning
Borrowing), less the sum of (x) the aggregate amount included in operating
expenses from the plant completion date to the date in question on account of
depreciation accruals (and amortization, if any, of property losses) reduced
by the aggregate of all amounts charged during such period against the
accumulated provision for depreciation plus (y) the amount of net available
cash; plus (ii) the aggregate amount properly chargeable at the time in
accordance with the Uniform System to accounts representing fuel assemblies
and components (including nuclear materials) and other materials and supplies,
less the balance, if any, at the time of the accumulated amortization thereof;
plus (iii) such reasonable allowances for prepaid items and cash working
capital as may from time to time be determined by Vermont Yankee; less (z) the
net proceeds received from the sale of any assets properly included in said
electric plant accounts.
<PAGE>
However, for purposes of this contract, the net amount included at any date
after the plant completion date in net Unit investment under clause (I) of the
immediately preceding sentence shall in no event be less than the excess of:
(a) the amount properly chargeable at the plant completion date in accordance
with the Uniform System to electric plant accounts (including construction
work in progress) with respect to the Unit,
over
(b) the sum of (x) the aggregate minimum amount required by this Section 7 to
be included in operating expenses from the plant completion date to the date
in question on account of depreciation accruals (and amortization, if any, or
property losses) plus (y) the amount of net available cash.
The net Unit investment shall be determined as of the plant completion
date and thereafter as of the commencement of each calendar year, or, if
Vermont Yankee elects, at more frequent intervals.
The "Closing Net Unit Investment" means the amount of net Unit investment
determined as of the Effective Date, which amount shall be amortized in equal
monthly amounts during the period commencing on the Effective Date and ending
on the End of License Date.
"Net available cash" means, at any date as of which the amount thereof is
to be determined, the excess of (a) the aggregate amount received by Vermont
Yankee after the plant completion date and prior to two years before the
determination date as insurance proceeds on account of loss or damage to the
Unit or as the proceeds of a sale or condemnation of a portion of the Unit,
over (b) the aggregate amount expended after the plant completion date and
prior to the determination date on account of rebuilding, repairs,
replacements and additions to the Unit, provided that insurance proceeds
received with respect to a particular loss shall be taken into account for
purposes of the foregoing computation only if the amount received with respect
to the loss exceeds $150,000.
"Total Decommissioning Obligation" for any month shall mean the sum of
(I) an amount equal to the principal payment, if any, of the Decommissioning
Borrowing due for such month plus (ii) the interest payment due for such month
on the Decommissioning Borrowing.
"Decommissioning Borrowing" means the balance outstanding from time to
time under (I) the Credit Agreement or (ii) any refinancing of any unpaid
balance of such borrowing.
Vermont Yankee will bill the Purchaser, as soon as practicable after the
end of each month, for all amounts payable by the Purchaser pursuant to this
Section 7 with respect to the particular month. Such bills will be rendered
in such detail as the Purchaser may reasonably request and may be rendered on
an estimated basis subject to corrective adjustments in subsequent billing
periods. All bills shall be paid in full within 10 days after receipt thereof
by the Purchaser.
<PAGE> 7A. Prepayment Option
-----------------
The Purchaser is hereby granted an option to prepay (the "Prepayment
Option"), (I) in full but not in part, its entitlement percentage of Vermont
Yankee's Closing Net Unit Investment (excluding the portion thereof
represented by the Purchaser's equity investment in Vermont Yankee) and
Decommissioning Borrowing, together with any interest accrued but unpaid
thereon, and (ii) with Vermont Yankee's consent, in full but not in part, the
Purchaser's entitlement percentage of the Equity investment, portion of
Vermont Yankee's Closing Net Unit Investment represented by the Purchaser's
equity investment in Vermont Yankee, together with an amount equal to the
equity percentage return accrued and unpaid thereon, all determined as of the
close of business on the day prior to the exercise date; provided, however
that (x) option under clause (ii) may only be exercised concurrently with, or
subsequent to, the exercise of the option under clause (I) and (y) promptly
after such exercise by Purchaser, Vermont Yankee shall redeem the Purchaser's
equity investment in Vermont Yankee. Such option or options to be exercisable
on the Effective Date or on the first day of any calendar quarter thereafter
during the term of this contract (an "exercise date"). At least 30 days prior
to the estimated Effective Date, Vermont Yankee shall give written notice to
the Purchaser providing its best estimate of the amount subject to these
options as of the Effective Date. Thereafter, upon written request by the
Purchaser at least 60 days prior to the next exercise date, Vermont Yankee
shall provide to the Purchaser its best estimate of the amounts subject to
these options as of such exercise date. Purchaser shall give Vermont Yankee
at least 15 days prior written notice of its intent to exercise one or both of
these options, which notice shall be binding and may not be withdrawn without
the prior written consent of Vermont Yankee. Within ten days after receipt of
such notice, Vermont Yankee shall provide the Purchaser with a calculation of
the prepayment amount due upon exercise. After making such prepayment and, if
appropriate, delivering to Vermont Yankee the certificates evidencing the
Purchaser's equity investment in Vermont Yankee together with duly endorsed
stock powers, the Purchaser shall no longer be responsible for paying any
amounts under clause (I) of the first paragraph of Section 7 with respect to
the period following the exercise of the Prepayment Option or, if the option
under clause (ii) above has been exercised, be a stockholder of Vermont
Yankee. "After making the prepayment due upon exercise of the option under
clause (I) above, the Purchaser shall only remain obligated to pay all other
amounts due under this contract, including, without limitation, amounts billed
under clause (ii) of the first paragraph 7, provided that after the option
under clause (ii) above has been exercised, Purchaser shall not be obligated
for any further payments under clause (ii)(f) of the first paragraph of
Section 7."
In the event that any other Purchasers exercise their Prepayment Options
under any of the other Initial Power Contracts and the Purchaser has not
exercised its Prepayment Option, then from and after the exercise of each such
other Prepayment Option the Purchaser shall pay its Adjusted Entitlement
Percentage of amounts due under clause (I) of the first paragraph of Section 7
hereof."
<PAGE>
(f) Section 15 of the Additional Power Contract is hereby amended by
adding the following sentence at the end thereof:
"Notwithstanding the foregoing, (a) Purchaser (or its assigns) may assign its
interest in this contract only (I) to a third party that has a credit rating
equal to the higher of that of the assignor or of investment grade as
determined by a nationally rated service, or (ii) to a single purpose entity
whose obligations hereunder are guaranteed by a parent that has such a credit
rating, or (iii) in connection with a merger, consolidation or sale of
substantially all its assets to another party that has a credit rating at
least equal to that of the Purchaser (or its assigns) and (b) the Purchaser
hereby consents to an assignment by Vermont Yankee of its interest in this
contract to the special purpose entity described or referred to in Schedule
7.1(z) of the APA and agrees that Purchaser's obligations hereunder shall not
be affected by such assignment."
6. Government Regulation.
---------------------
This Amendatory Agreement and all rights and obligations of the Parties
hereunder are subject to all applicable federal, state and local laws and all
duly promulgated orders and duly authorized actions of governmental
authorities having proper and valid jurisdiction over the terms of this
Amendatory Agreement. Purchaser will be obligated to make all payments to
Vermont Yankee for purchases at wholesale of capacity, energy and ancillary
products hereunder regardless of whether or not the Purchaser is permitted to
pass along or recover those payments from its customers. Each of Vermont
Yankee and Purchaser shall not propose, advance or support, and shall
vigorously oppose and defend against, any action by any legislature, agency,
commission, (including the Federal Energy Regulatory Commission), entity or
court that would adversely affect the Parties' rights and benefits hereunder
and each of Vermont Yankee and the Purchaser will vigorously pursue all
actions and remedies to overturn or cure any such action. In addition, the
rates, terms, and conditions contained in this Amendatory Agreement are not
subject to change under Sections 205 or 206 of the Federal Power Act, as
either section may be amended or superseded, absent the mutual written
agreement of the Parties or a finding by the Federal Energy Regulatory
Commission, that this Amendatory Agreement is not in the public interest.
7. Confidentiality.
----------------
Except as otherwise required by law or for implementation of this
Amendatory Agreement, the Parties must keep confidential the transactions
undertaken pursuant hereto; provided, however, that the Purchaser may disclose
such information on a confidential basis to third parties in connection with
good faith negotiation for the assignment of Purchaser's interests hereunder.
Nothing herein shall preclude the Purchaser from disclosing the substance of
this Amendatory Agreement to third parties on a confidential basis in connection
with the negotiation of the assignment of any of its interests herein. Any
information provided by either Party to the other Party pursuant to this
Amendatory Agreement and labeled "CONFIDENTIAL" will be used by the receiving
Party solely in connection with the purposes of this Amendatory Agreement and
will not be disclosed by the receiving Party to any third party, except with
the providing Party's consent. This Section 7 of this Amendatory
<PAGE>
Agreement will not prevent either Party from providing any confidential
information received from the other Party to any court or in accordance with a
proper discovery request or in response to the reasonable request of any
governmental agency with jurisdiction to regulate or investigate the
disclosing Party's affairs, provided that, if feasible, the disclosing Party
will give prior notice to the other Party of such disclosure and, if so
requested by such other Party, will have used all reasonable efforts to oppose
or resist the requested disclosure, as appropriate under the circumstances, or
to otherwise make such disclosure pursuant to a protective order or other
similar arrangement for confidentiality.
8. Miscellaneous.
-------------
(a) Mitigation of Damages. In the event of any default by Purchaser,
Vermont Yankee shall have the right to sell the Purchaser's entitlement
percentage of any energy and ancillary products and apply the proceeds thereof
against the amounts owing from the Purchaser.
(b) Counterparts. This Agreement may be executed in two or more
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
IN WITNESS WHEREOF, the parties have executed this Amendment by their
respective officers hereto duly authorized, as of the date first above
written.
VERMONT YANKEE NUCLEAR POWER
CORPORATION
By_______________________________________
Its President and Chief Executive Officer
Title
Address: Box 169, Ferry Road
Brattleboro, VT 05301
[PURCHASER]
By______________________________________
Its ____________________________________
Title
Address:
<PAGE>Exhibit A
to
1999 Amendatory Agreement
APA Obligations
Section 2.4 Excluded Liabilities
Section 6.13(b) One-time fee due to DOE under the DOE Standard Contract
Section 6.13(c)Operational phase spend fuel storage facility costs up to 70%
of $20.7 million (1999 dollars).
Section 6.14 DOE Decontamination and Decommissioning fees
Section 8.1(b) Indemnification obligations
<PAGE>Exhibit B
to
1999 Amendatory Agreement
TAPA Obligations:
Section 5.6(a),(b) and (c) Operating and Capital Costs
Sections 7.1(b) and 7.2 Indemnities
<PAGE>Exhibit C
to
1999 Amendatory Agreement
[Attach copy of PPA]
<PAGE>
Amendment to
New England Electric Companies'
Deferred Compensation Plan
Pursuant to the provisions of the New England Electric Companies'
Deferred Compensation Plan, said Plan is hereby amended effective as of March
1, 1999, as follows:
Amend the first paragraph of Section 2.39 to read as follows:
2.39 Share Price for purchases shall be determined using as a proxy the
price of Shares being acquired by the New England Electric System Dividend
Reinvestment Plan during the time period when the Shares for this Plan would
be acquired were this Plan a participant in that plan. The Share Price for
Shares being liquidated shall be determined (i) by using as a proxy the price
received for those Shares sold by the Dividend Reinvestment Plan next
following the date of determination or (ii) if in connection with a Cash for
Shares merger, by using the price actually received by the Rabbi Trust
established as of the first day of January 1994, by and between New England
Power Service Company and State Street Bank and Trust Company, as amended from
time to time, on a conversion of Shares related hereto.
Insert the following language at the end of Section 4.03:
Upon the occurrence of a merger of New England Electric System into or
with another entity, if the merger is a Cash for Shares transaction, any Share
Account shall be converted to a Cash Account. The Share values for the
conversion are to be determined by the price per Share received by
nondissenting shareholders in the transaction.
Amend the second paragraph of Section 4.04(F) to read as follows:
In the event of a Major Transaction or a Change in Control, any
Participant, whether terminated or active, may elect at any time during the
Election Period to receive, in lieu of any future benefits hereunder, a lump
sum payment equal to the balance of his Cash and Share Accounts and the
Actuarial Value of the maximum value of future benefits from Deferral Units,
all less 10%. Said lump sum is to be paid to the Participant no later than 30
days after the receipt by New England Electric System of the Participant's
election. The Employer of each Participant at the time (or at termination, if
applicable) shall, as soon as practicable after a Major Transaction or a
Change in Control advise the Participant of his rights under this paragraph.
Amend Section 5.01 to read as follows:
5.01 Right to Amend or Terminate. The Compensation Committee may amend
or terminate this Plan at any time; provided, however, that no such action
shall affect any right or obligation with respect to any Compensation
previously earned; provided, further, that, if the Compensation Committee, in
its sole discretion, determines that (a) changes in Federal income tax
statutes, rules, or regulations applicable to the Plan, (b) changes in the
Federal tax rate paid by the Employers, or (c) the application or potential
application to the Plan of Section 406 of Title I of the Employee Retirement
Income Security Act of 1974 make it advisable, existing Deferral Units may be
modified or canceled;
<PAGE>
and provided further, no amendment or discontinuance in any manner adverse to
a Participant with respect to benefit formula or optional form of payment may
be made for three years following a Change in Control or a Major Transaction.
No such modification or cancellation shall affect any Participant's Cash or
Share Account Balance. No such modification may reduce the then established
retirement income or death benefit of a Participant who has had a Termination
of Service, but it may reduce or eliminate any subsequent increases in either
or both.
s/ George M. Sage
________________________________________
Chairman
Pursuant to Vote of February 23, 1999, of
the Compensation Committee
<PAGE>AMENDMENT
TO
NEW ENGLAND ELECTRIC SYSTEM COMPANIES
RETIREMENT SUPPLEMENT PLAN
Pursuant to the provisions of the New England Electric System Companies
Retirement Supplement Plan, said Plan is hereby amended effective as of March
1, 1999, as follows:
Insert the following new language at the beginning of the section entitled
"Lump Sum Payments":
In the event of the dissolution, liquidation, or winding up of the
business of the Company or the New England Electric System, whether voluntary
or involuntary, the Participant shall receive, at the time of such event, a
lump sum payment equal to the full amount of the current Actuarial Value of
the Participant's benefits under this Plan, unless the New England Electric
System, or its successor, has assumed all the rights, duties, and obligations
of the Company or New England Electric System hereunder.
Amend the third paragraph under the section entitled "Lump Sum Payments" to
read as follows:
At any time following a Change in Control or a Major Transaction, any
Participant who has had a Termination of Employment, whether before or after
the Change in Control or Major Transaction, may elect to receive, in lieu of
any future benefits hereunder, a lump sum payment equal to the Actuarial Value
of the maximum value of said future benefits, less 10%. Said lump sum is to
be paid to the Participant no later than 30 days after the receipt by New
England Electric System of the Participant's election.
Insert a new section as follows:
Effectuation of Interest
------------------------
In the event it should become impossible for the Company, the Benefits
Committee, or other committee to perform any act required by the Plan, the
Company, the Benefits Committee, or other committee may perform such other act
as it in good faith determines will most nearly carry out the intent and
purpose of the Plan.
Amend the section entitled "Amendment or Discontinuance" to read as follows:
Amendment or Discontinuance
---------------------------
The Committee may amend or discontinue the Plan at any time; provided, no
modification shall reduce a benefit which, at the time of such amendment or
discontinuance, a Participant would be eligible to receive upon Retirement
under the Plan; and provided further, no amendment or discontinuance in any
manner adverse to a Participant with respect to benefit formula or optional
form of payment may be made for three years following a Change in Control or a
Major Transaction.
<PAGE>
s/ George M. Sage
__________________________________
Chairman
Pursuant to Vote of February 23, 1999,
of the Compensation Committee
<PAGE>AMENDMENT
TO
NEW ENGLAND ELECTRIC COMPANIES'
EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN
Pursuant to the provisions of the New England Electric Companies'
Executive Supplemental Retirement Plan, said Plan is hereby amended effective
as of March 1, 1999, as follows:
Amend the third paragraph of the section entitled "Lump Sum Payments" as
follows:
At any time following a Change in Control or Major Transaction, any
Participant who has had a Termination of Employment, whether before or after
the Change in Control or Major Transaction, may elect to receive, in lieu of
any future benefits hereunder, a lump sum payment equal to the Actuarial Value
of the maximum value of said future benefits, less 10%. Said lump sum is to
be paid to the Participant no later than 30 days after the receipt by New
England Electric System of the Participant's election.
Amend the section entitled "Amendment or Discontinuance" to read as follows:
Amendment or Discontinuance
---------------------------
The Committee may amend or discontinue the Supplemental Plan at any time;
provided, no modification shall reduce a benefit which, at the time of such
amendment or discontinuance, a Participant would be eligible to receive upon
Retirement under the Supplemental Plan; and provided further, no amendment or
discontinuance in any manner adverse to a Participant with respect to benefit
formula or optional form of payment may be made for three years following a
Change in Control or a Major Transaction.
s/ George M. Sage
__________________________________
Chairman
Pursuant to Vote of February 23, 1999, of the Compensation
Committee
<PAGE>AMENDMENT
TO
NEW ENGLAND ELECTRIC COMPANIES'
INCENTIVE SHARE PLAN
Pursuant to the provisions of Article III of the New England Electric
Companies' Incentive Share Plan, said Plan is hereby amended effective as of
March 1, 1999, as follows:
Section 4.05 is hereby amended to read as follows:
4.05 Change in Control. In the event of a Change in Control or of a
Major Transaction, each Participant will receive, within 30 days of the
consummation of the Change in Control or of the transaction approved by the
Major Transaction, a payment calculated in accordance with Section 4.01. If
the consummation of the Change in Control or of the transaction approved by
the Major Transaction occurs prior to the determination and payment of the
Participant's Cash Bonus for the Prior Year, the Participant will also receive
within 30 days of the consummation of the Change in Control or of the
transaction approved by the Major Transaction a payment calculated in
accordance with Section 4.01 for that year. No further benefits in either
Shares or cash will be payable for this Plan.
If the Change of Control or Major Transaction is on a share for shares
basis, the payment shall be made by a share distribution. If the Change of
Control or Major Transaction is a cash for shares transaction, the payment
will be a cash payment.
Section 5.01 is repealed.
Section 5.01(A) is repealed.
Add a new Section 6.06 as follows:
6.06 Effectuation of Interest
------------------------
In the event it should become impossible for the Company, the Benefits
Committee, or other committee to perform any act required by the Plan, the
Company, the Benefits Committee, or other committee may perform such other act
as it in good faith determines will most nearly carry out the intent and
purpose of the Plan.
s/ George M. Sage
__________________________________
Chairman
Pursuant to Vote of February 23, 1999,
of the Compensation Committee
<PAGE>Amendment to
New England Electric Companies'
Long-Term Performance Share Award Plan
Pursuant to the provisions of Article III of the New England Electric
Companies' Long-Term Performance Share Award Plan, said Plan is hereby amended
effective as of March 1, 1999, as follows:
Add a new Section 2.04A as follows:
2.04A Cash Out Merger shall have occurred if New England Electric
System is merged into or with another entity and as a result thereof all of
the then outstanding publicly held Shares of New England Electric System are
converted into a right to receive cash.
Add a new Section 3.01A as follows:
3.01A Effectuation of Interest. In the event it should become
impossible for the Employers or the Committee to perform any act required by
the Plan, the Employers or the Committee may perform such other act as they in
good faith determines will most nearly carry out the intent and purpose of the
Plan.
In the event of a Cash Out Merger, Share values shall be converted to a
dollar value to be determined by the price per Share received by nondissenting
shareholders in the transaction.
Add a new Section 4.07 as follows:
4.07 The Employer shall acquire any Shares necessary to satisfy its
obligations hereunder by purchases in the open market or by purchases of
Shares (either newly issued or treasury shares) from New England Electric
System. The price to be paid to New England Electric System for Shares
acquired from it shall be the average of the high and low prices of Shares on
the New York Stock Exchange - Composite Transactions as reported in The Wall
Street Journal for five consecutive trading days prior to the date of
acquisition from New England Electric System.
s/ George M. Sage
___________________________________
Chairman
Pursuant to Vote of February 23, 1999,
of the Compensation Committee
<PAGE>AMENDMENT No. 1
TO
ASSET PURCHASE AGREEMENT
Amendment No. 1, dated as of September 25, 1997, to the Asset
Purchase Agreement, dated as of August 5, 1997 (the "APA"), by and among New
England Power Company, a Massachusetts corporation ("NEP"), The Narragansett
Electric Company, a Rhode Island corporation ("Narragansett"), and USGen New
England, Inc. (formerly named USGen Acquisition Corporation), a Delaware
corporation (the "Buyer").
Whereas, NEP, Narragansett and the Buyer are parties to the APA.
Whereas, NEP, Narragansett and the Buyer desire to amend the APA in
certain respects.
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. Section 11.2 of the APA is hereby amended to delete "Subject
to Section 11.3, in" from the first line and insert in its place, "In".
Section 2. Section 12.3 of the APA is hereby also amended to delete
"Sections 11.2 and 11.3" from the second line and insert in its place,
"Section 11.2".
Section 3. Section 3.1 of the APA is hereby also amended to delete
"Sections 7.4(f)" from the seventh line and insert in its place, "Section
7.4(e)".
IN WITNESS WHEREOF, the undersigned parties hereto have executed this
Amendment No. 1 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ Michael E. Jesanis
___________________________
Name: Michael E. Jesanis
Title: Treasurer
NARRAGANSETT ELECTRIC COMPANY
By: s/ Alfred D. Houston
_______________________________
Name: Alfred D. Houston
Title: Vice President and Treasurer
USGEN NEW ENGLAND, INC.
By: s/ M. Richard Smith
_________________________________
Name: M. Richard Smith
Title: Vice President
<PAGE>AMENDMENT No. 2
TO
ASSET PURCHASE AGREEMENT
Amendment No. 2, dated as of October 29, 1997, to the Asset Purchase
Agreement, dated as of August 5, 1997 (the "APA"), by and among New England
Power Company, a Massachusetts corporation ("NEP"), The Narragansett Electric
Company, a Rhode Island corporation ("Narragansett"), and USGen New England,
Inc. (formerly named USGen Acquisition Corporation), a Delaware corporation
(the "Buyer").
Whereas, NEP, Narragansett and the Buyer are parties to the APA.
Whereas, NEP, Narragansett and the Buyer desire to amend the APA in
certain respects.
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. Section 1.1(a)(54) is replaced in its entirety with: ""PPA
Transfer Agreement" means the Amended and Restated PPA Transfer Agreement,
dated as of October 29, 1997, between NEP and USGen New England, Inc.
(formerly known as USGen Acquisition Corporation) and the OSP PPA Transfer
Agreement, dated as of October 29, 1997, between NEP and USGen New England,
Inc. (formerly known as USGen Acquisition Corporation)."
Section 2. Section 1.1(a)(72) is replaced in its entirety with:
""Transition Agreements" means the Amended and Restated Wholesale Standard
Offer Service Agreements, the NECO Wholesale Standard Offer Service Agreement
II and the MECO Wholesale Standard Offer Service Agreement II, dated as of
October 29, 1997, between USGen New England, Inc. (formerly known as USGen
Acquisition Corporation) on the one hand and The Narragansett Electric
Company, or Massachusetts Electric Company and Nantucket Electric Company on
the other hand."
IN WITNESS WHEREOF, the undersigned parties hereto have executed
this Amendment No. 2 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ Michael E. Jesanis
______________________________
Name: Michael E. Jesanis
Title: Treasurer
NARRAGANSETT ELECTRIC COMPANY
By: s/ John G. Cochrane
________________________________
Name: John G. Cochrane
Title: Assistant Treasurer
USGEN NEW ENGLAND, INC.
By: s/ M. Richard Smith
________________________________
Name: M. Richard Smith
Title: Vice President
<PAGE>AMENDMENT No. 3
TO
ASSET PURCHASE AGREEMENT
Amendment No. 3, dated as of May 29, 1998, to the Asset Purchase
Agreement, dated as of August 5, 1997 (the "APA"), by and among New England
Power Company, a Massachusetts corporation ("NEP"), The Narragansett Electric
Company, a Rhode Island corporation ("Narragansett"), and USGen New England,
Inc. (formerly named USGen Acquisition Corporation), a Delaware corporation
(the "Buyer").
Whereas, NEP, Narragansett and the Buyer are parties to the APA.
Whereas, NEP, Narragansett and the Buyer desire to amend the APA in
certain respects.
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. Section 1.1(a)(54) is replaced in its entirety with: ""PPA
Transfer Agreement" means the Amended and Restated PPA Transfer Agreement,
dated as of October 29, 1997, between NEP and USGen New England, Inc.
(formerly known as USGen Acquisition Corporation) the OSP PPA Transfer
Agreement, dated as of October 29, 1997, between NEP and USGen New England,
Inc. (formerly known as USGen Acquisition Corporation), the PPA Transfer
Implementation Agreement - Ogden Haverhill Associates, dated as of May 29,
1998, between NEP and USGen New England, Inc. (formerly known as USGen
Acquisition Corporation), and any validly executed future PPA Transfer
Implementation Agreement between NEP and USGen New England, Inc."
IN WITNESS WHEREOF, the undersigned parties hereto have executed
this Amendment No. 3 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ John G. Cochrane
______________________________
Name: John G. Cochrane
Title: Treasurer
NARRAGANSETT ELECTRIC COMPANY
By: s/ John G. Cochrane
________________________________
Name: John G. Cochrane
Title: Treasurer
USGEN NEW ENGLAND, INC.
By: s/ M. Richard Smith
________________________________
Name: M. Richard Smith
Title: Vice President
<PAGE>AMENDMENT No. 4
TO
ASSET PURCHASE AGREEMENT
Amendment No. 4, dated as of September 1, 1998, to the Asset
Purchase Agreement, dated as of August 5, 1997 (the "APA"), by and among New
England Power Company, a Massachusetts corporation ("NEP"), The Narragansett
Electric Company, a Rhode Island corporation ("Narragansett"), and USGen New
England, Inc. (formerly named USGen Acquisition Corporation), a Delaware
corporation (the "Buyer").
Whereas, NEP, Narragansett and the Buyer are parties to the APA;
Whereas, NEP, Narragansett and the Buyer desire to amend the APA in
certain respects;
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. Section 1.1(a)(15) of the APA is hereby replaced in its
entirety with: ""Continuing Site Agreement" means the Amended and Restated
Continuing Site/Interconnection Agreement By and Between New England Power
Company and USGen New England, Inc., dated September 1, 1998."
Section 2. Section 5.1(b) of the APA is replaced in its entirety with:
(b) The authorized capital stock of NERC consists of eight thousand
(8,000) shares of common stock, par value $1.00 per share, twenty-five shares
of which are issued and outstanding (the "Share"). Such shares of NERC Stock
have been duly authorized and validly issued, are fully paid and
non-assessable, and have not been issued in violation of the preemptive rights
of any stockholder of NERC. At the Closing, NEP will be the record and
beneficial owner of full right and title to such shares of NERC Stock, free
and clear of all Encumbrances, options, warrants, rights, calls, pledges,
trusts, voting trusts and other stockholder agreements, assess- ments,
covenants, restrictions, reservations, commitments, obligations, liabilities,
and other burdens. Assuming issuance by the SEC of an appropriate order under
the Holding Company Act, as of the Closing NEP will have the absolute and
unrestricted right, power, authority and capacity to sell the NERC Stock to
the Buyer.
Section 3. Section 9.2(d) of the APA is hereby amended to delete
"8.2(a), (b) and (c)" from the last line and insert in its place, "9.2(a), (b)
and (c)".
Section 4. Section 9.2 of the APA is hereby amended to insert Section
9.2(h), which is as follows:
(h) The Buyer shall be reasonably satisfied that all material
Environmental Permits and material Permits will be transferred to the Buyer or
obtained by the Buyer on or before the Closing Date.
<PAGE>
Section 5. Section 12.3 of the APA is hereby amended to (i) add "3.3,
3.4, 3.5," to the third line after "3.2", (ii) add "7.2(c), 7.2(f)" to the
third line after "7.2(b)", (iii) delete "Articles X and XI" from the fifth and
sixth line and insert in its place, "Articles X, XI and XII" and (iv) delete
"Sections 5.1, 5.2 and 5.3" from the eighth line and insert in its place,
"Sections 5.1, 5.2, 5.3, 6.1, 6.2 and 6.3".
IN WITNESS WHEREOF, the undersigned parties hereto have executed
this Amendment No. 4 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ Michael E. Jesanis
___________________________________
Name: Michael E. Jesanis
Title: Vice President
NARRAGANSETT ELECTRIC COMPANY
By: s/ Michael E. Jesanis
___________________________________
Name: Michael E. Jesanis
Title: Vice President
USGEN NEW ENGLAND, INC.
By: /s/ James V. Mahoney
___________________________________
Name: James V. Mahoney
Title: Senior Vice President
<PAGE>AMENDMENT No. 1
TO
WHOLESALE SALES AGREEMENT
Amendment No. 1, dated as of September 25, 1997, to the Wholesale
Sales Agreement, dated as of August 5, 1997 (the "Agreement"), by and among
New England Power Company, a Massachusetts corporation ("NEP") and USGen New
England, Inc. (formerly named USGen Acquisition Corporation), a Delaware
corporation (the "Buyer").
Whereas, NEP and the Buyer are parties to the Agreement.
Whereas, NEP and the Buyer desire to amend the Agreement in certain
respects.
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. Section 5.1 of the Agreement is hereby amended by adding the
following text at the end of Section 5.1 following the table and immediately
prior to the beginning of Section 5.2:
"For purposes of this paragraph, "average Energy Price" shall be the value
obtained by dividing (i) the amount determined in accordance with paragraph
5.1(a)(2) above and (ii) the total number of megawatt- hours delivered by NEP
from the Purchased Quantity during the month.
The amount of the credit, if any, shall be the product of (i) the difference
between (a) the average Energy Price (as expressed in dollars per
megawatt-hour) and (b) the applicable value from the above table (expressed in
dollars per megawatt-hour) and (ii) the lesser of (a) the number of
megawatt-hours delivered under the Wholesale Standard Offer Service Agreements
during the month or (b) the total number of megawatt-hours delivered by NEP
from the Purchased Quantity for the month."
IN WITNESS WHEREOF, the undersigned parties hereto have executed
this Amendment No. 1 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ Michael E. Jesanis
_________________________
Name: Michael E. Jesanis
Title: Treasurer
USGEN NEW ENGLAND, INC.
By: s/ M. Richard Smith
_________________________
Name: M. Richard Smith
Title: Vice President
<PAGE>AMENDMENT No. 2
TO
WHOLESALE SALES AGREEMENT
Amendment No. 2, dated as of September 1, 1998, to the Wholesale
Sales Agreement, dated as of August 5, 1997 and amended as of September 25,
1997 (the Agreement"), by and among New England Power Company, a Massachusetts
corporation ("NEP") and USGen New England, Inc. (formerly named USGen
Acquisition Corporation), a Delaware corporation (the "Buyer").
Whereas, NEP and the Buyer are parties to the Agreement.
Whereas, NEP and the Buyer desire to further amend the Agreement in
certain respects.
Now, therefore, in consideration of the premises and the
representations and warranties, covenants and other agreements hereinafter set
forth, the parties hereto, intending to be legally bound hereby, agree as
follows:
Section 1. ARTICLE 2 of the Agreement is hereby amended to replace the
definition of Wholesale Nuclear Entitlement with:
"NEP'S generation and delivery to Buyer at any location on the NEPOOL PTF
system of electric energy, capacity, and any other associated electric product
produced by NEP's Nuclear Interests (other than electric energy, capacity and
any other associated electric product committed to Banhor Hydro-Electric
Company under an agreement dated September 30, 1994 and that committed to
Unitil Power Corporation under agreements dated July 30, 1992 and dated
December 30, 1997) in the quantities determined in accordance with ARTICLE 4,
SECTION 4.2."
Section 2. ARTICLE 4, SECTION 4.1 of the Agreement is hereby
amended to delete "Wholesale Nuclear Energy" from the second line and insert
in its place, "Wholesale Nuclear Entitlement."
Section 3. ARTICLE 4, SECTION 4.2, of the Agreement is hereby
amended to delete the last sentence of the first paragraph and replace it with
the following:
"During each month of the Contract Period, NEP shall sell and deliver and
Buyer shall purchase the quantity of Wholesale Nuclear Entitlement nominated
by the Buyer with respect to the month."
Section 4. ARTICLE 5, SECTION 5.1 of the Agreement is hereby
amended by adding the following text at the end of Section 5.1 (a)(2) and
immediately prior to the beginning of Section 5.1(a)(3):
"In the event no NEPOOL Energy Clearing Price has been established for any
portion of any month, the parties will utilize the prices set forth in the
"Prices of Spot Electricity" table published in The McGraw-Hill Companies'
Power Markets Week publication )"PMW"), using the prices in the New England
Line in the Northeastern Markets section under the column Weekly Index (on-
peak)("PMW Index"). Buyer shall pay each day the PMW Index for the week of
PMW which contains the day of delivered megawatt-hours, multiplied by 0.85
("the Price") (expressed in dollars per megawatt-hour) times the megawatt-
hous delivered by NEP from the Purchased Quantity; plus
<PAGE>
In the event that the PMW Index is not published, fails to publish the
information necessary for determining the Price, or is otherwise not available
for any reason, the parties will utilize the prices set forth in the "Megawatt
Daily Price Survey" table published in the Pasha Publications, Inc.'s Megawatt
Daily publication, using the prices in the NEPOOL line in the Peak section
under the column Weighted Average Index ("MW Index"). For any energy
delivered during a Week by NEP from the Purchased Quantity, a Week to be
defined as Monday through Sunday, Buyer shall pay the simple average of Monday
through Friday's five days of MW Indices multiplied by 0.85 (expressed in
dollars per megawatt-hour) times the megawatt hours delivered by NEP from the
Purchased Quantity during the applicable Week; plus"
Section 5. ARTICLE 5, SECTION 5.1 of the Agreement is hereby amended by
adding the following text as Section 5.1(c), which is to be added after
Section 5.1(b) and immediately prior to the beginning of Section 5.2:
"In the event any pricing component is unavailable at the time of billing, NEP
will base the current month's bill on the most recently available data for
such component ("the estimated component") and make any necessary adjustments
in the next monthly bill after such component becomes known. Interest shall
accrue from the date of such bill based on the difference between the
estimated component and the actual component value at a rate per annum equal
to the Prime Rate in effect on the date the component value becomes known."
IN WITNESS WHEREOF, the undersigned parties hereto have executed
this Amendment No. 2 as of the date first written above.
NEW ENGLAND POWER COMPANY
By: s/ Michael E. Jesanis
_________________________
Name: Michael E. Jesanis
Title: Treasurer
USGEN NEW ENGLAND, INC.
By: s/ James V. Mahoney
_________________________
Name: James V. Mahoney
Title: Senior Vice President
<PAGE>
Annual Report 1999
New England Power Company
(logo) National Grid
<PAGE>New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of March 22, 2000)
Cynthia A. Arcate
Vice President of the Company
L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission
Peter G. Flynn
President of the Company
Alfred D. Houston
Chairman of the Company and Former Chairman of
New England Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice President,
General Counsel, and Secretary of National Grid USA
Richard P. Sergel
President and Chief Executive Officer of National Grid USA
Philip R. Sharp
Lecturer, Harvard University, John F. Kennedy School of Government
Officers
(As of March 22, 2000)
Alfred D. Houston
Chairman of the Company and Former Chairman of New England Electric System
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief Financial
Officer of National Grid USA
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice President,
General Counsel, and Secretary of National Grid USA
Cynthia A. Arcate
Vice President of the Company
John F. Malley
Vice President of the Company
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
James S. Robinson
Vice President of the Company
<PAGE>Gregory A. Hale
Clerk of the Company and of certain affiliates, Assistant Secretary or
Assistant Clerk of certain affiliates and Secretary of an affiliate
John G. Cochrane
Treasurer of the Company and of certain affiliates, Vice President of an
affiliate, Assistant Treasurer of an affiliate and Vice President and
Treasurer of National Grid USA
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates, Secretary or Clerk
of certain affiliates and Assistant Secretary of an affiliate
Kwong O. Nuey
Controller of the Company and of certain affiliates
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock,
BankBoston, N.A., Boston, Massachusetts
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
<PAGE>New England Power Company
New England Power Company, (the Company) a wholly owned subsidiary of
National Grid USA (formerly New England Electric System), is a Massachusetts
corporation qualified to do business in Massachusetts, New Hampshire, Rhode
Island, Connecticut, Maine, and Vermont. The Company is subject, for certain
purposes, to the jurisdiction of the regulatory commissions of these six
states, the Securities and Exchange Commission, under the Public Utility
Holding Company Act of 1935, the Federal Energy Regulatory Commission, and the
Nuclear Regulatory Commission. The Company's business is primarily the
transmission of electric energy in wholesale quantities to other electric
utilities, principally its distribution affiliates Granite State Electric
Company, Massachusetts Electric Company, Nantucket Electric Company, and The
Narragansett Electric Company. The Company's transmission business will also
do business under the name of National Grid Transmission USA.
<PAGE>Report of Independent Accountants
New England Power Company, Westborough, Massachusetts:
In our opinion, the accompanying balance sheets and the related
statements of income, of retained earnings, and cash flows present fairly, in
all material respects, the financial position of New England Power Company
(the Company), a wholly owned subsidiary of National Grid USA (formerly New
England Electric System), at December 31, 1999 and 1998, and the results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1999 in conformity with accounting principles generally
accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
March 6, 2000, except for Note B,
as to which the date is March 22, 2000
<PAGE>New England Power Company
Financial Review
Merger Agreement with National Grid
On March 22, 2000, the merger of New England Electric System (NEES) and
The National Grid Group plc (National Grid) was completed, with NEES (renamed
National Grid USA) becoming a wholly owned subsidiary of National Grid. New
England Power Company (the Company) will maintain its existing name and will
remain a wholly owned subsidiary of National Grid USA. The merger is being
accounted for by the purchase method, the application of which, including the
recognition of goodwill, is being pushed down and reflected on the books of
the National Grid USA subsidiaries, including the Company.
Merger Agreement with EUA
In February 1999, NEES, Eastern Utilities Associates (EUA), and Research
Drive LLC (Research Drive), a wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA Agreement,
Research Drive will merge with and into EUA, with EUA becoming a wholly owned
subsidiary of National Grid USA.
The acquisition of EUA has received approval or support from EUA
shareholders, the Federal Trade Commission (FTC), the Federal Energy
Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC), the
Connecticut Department of Public Utility Control, the Rhode Island Public
Utilities Commission, the Massachusetts Department of Telecommunications and
Energy (MDTE), and the Vermont Public Service Board (VPSB). An application has
also been filed for approval with the Securities and Exchange Commission
(SEC), under the Public Utility Holding Company Act of 1935 (1935 Act). The
acquisition of EUA, including the consolidation of Montaup Electric Company
(Montaup Electric), a wholly owned subsidiary of EUA, into the Company, is
expected to be completed following the receipt of an SEC order approving the
acquisition, which could come at any time. If the SEC order is not received in
time to close the transaction by April 28, 2000, the approval by the FTC,
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
expires and will have to be renewed prior to completion of the acquisition.
Industry Restructuring
Pursuant to legislation enacted in Massachusetts, Rhode Island, and New
Hampshire, and settlement agreements approved by state and federal regulators
(the Settlement Agreements), customers were granted choice of power supplier
in 1998. To facilitate the implementation of customer choice, the Settlement
Agreements provided for the termination of the Company's all-requirements
contracts with its affiliated distribution companies. The Company's all-
requirements contracts with unaffiliated customers were also generally
terminated pursuant to settlement agreements or tariff provisions. However,
the Company remains obligated to provide transition power supply service at
fixed rates to new customer load in Rhode Island. In addition, as a result of
the Settlement Agreements, the Company and its affiliate, The Narragansett
Electric Company, sold substantially all of their nonnuclear generating
business (divestiture) in September 1998. As part of the divestiture plan, New
England Energy Incorporated sold its oil and gas properties in 1998, resulting
in a loss of approximately $120 million, before tax, which was reimbursed by
the Company. The Company also agreed to endeavor to sell its minority interest
in three nuclear power plants and a 60 megawatt interest in a fossil-fueled
generating station in Maine.
<PAGE>
In conjunction with the divestiture, the Company transferred to the buyer
of its nonnuclear generating business (the buyer) its entitlement to power
procured under several long-term contracts in exchange for monthly fixed
payments by the Company averaging $9.5 million per month through January 2008
(having a net present value at December 31, 1999 of approximately $704
million) toward the above-market cost of those contracts. For certain
contracts which have been formally assigned to the buyer, the Company has made
lump sum payments equivalent to the present value of the monthly fixed payment
obligations of those contracts (approximately $345 million), which were
separate from the $704 million figure referred to above.
Under the Settlement Agreements, the Company is permitted to recover
costs associated with its former generating investments and related
contractual commitments that were not recovered through the sale of those
investments ("stranded costs"). These costs are recovered from the Company's
wholesale customers through contract termination charges (CTC) which the
affiliated wholesale customers recover through delivery charges to
distribution customers. The recovery of the Company's stranded costs is
divided into several categories. Unrecovered costs associated with generating
plants (nuclear and nonnuclear) and most regulatory assets will be fully
recovered through the CTC by the end of 2000 and earn a return on equity
averaging 9.7 percent. The Company's obligation related to the above-market
cost of purchased power contracts and nuclear decommissioning costs are
recovered through the CTC as such costs are actually incurred. As the CTC rate
declines, the Company, under certain of the Settlement Agreements, earns
incentives based on successful mitigation of its stranded costs. These
incentives supplement the Company's return on equity. Until such time as the
Company divests its operating nuclear interests, the Company will share with
customers, through the CTC, 80 percent of the revenues and operating costs
related to the units, with shareholders retaining the balance. For further
information on the potential sale of the Vermont Yankee and Millstone 3
nuclear generating units, refer to the "Nuclear Units" section below.
Accounting Implications
Because electric utility rates have historically been based on a
utility's costs, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in general.
The Company applies the provisions of Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), which requires regulated entities, in appropriate circumstances, to
establish regulatory assets, and thereby defer the income statement impact of
certain charges or revenues because they are expected to be collected or
refunded through future customer billings. In 1997, the Emerging Issues Task
Force of the Financial Accounting Standards Board concluded that a utility
that had received approval to recover stranded costs through regulated rates
would be permitted to continue to apply FAS 71 to the recovery of stranded
costs.
As discussed above, the Company received authorization from the FERC to
recover through CTCs substantially all of the costs associated with its
former generating business not recovered through the divestiture.
Additionally, FERC Order No. 888 enables transmission companies to recover
their specific costs of providing transmission service. Therefore,
substantially all of the Company's business, including the recovery of its
stranded costs, remains under cost-based rate regulation. Because of the
nuclear cost-sharing provisions related to the Company's CTC, the Company
ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear
operations, the impact of which is immaterial.
<PAGE>
As a result of applying FAS 71, the Company has recorded a regulatory
asset for the costs that are recoverable from customers through the CTC. At
December 31, 1999, this amounted to approximately $1.3 billion, including $1.0
billion related to the above-market costs of purchased power contracts, $0.3
billion related to accrued Yankee nuclear plant costs, and a smaller amount of
other net CTC-related regulatory assets.
In 1998, the Company concluded that its interests in the Millstone 3 and
Seabrook 1 nuclear generating units had little, if any, market value, based,
in part, on the fact that proposed sales of nuclear units by other utilities
have required the seller to set aside amounts for decommissioning in excess of
the proceeds from the sale of the units. As a result, the Company recorded an
impairment write-down in its reserve for depreciation of approximately $390
million, representing the book value of Millstone 3 and Seabrook 1 at December
31, 1995, less applicable depreciation subsequent to that date.
Impact of Mergers on Transmission and CTC Rates
In March 2000, the MDTE approved the merger of Montaup Electric into the
Company, which is contingent upon the approval of the pending acquisition of
EUA. Under a rate consolidation plan accepted by the FERC in September 1999,
upon National Grid USA's acquisition of EUA, Montaup Electric's open access
transmission tariffs will adopt the same terms and conditions for service as
those contained in the Company's tariffs. Upon the merger of Montaup Electric
into the Company, the combined company will charge a single system
transmission tariff based upon its total transmission costs. The CTC rates for
the companies will not initially be combined.
Overview of Financial Results
Net income for 1999 decreased $52 million compared with 1998 as a result
of the continuing impacts of the divestiture and the restructuring of the
utility business. Partially offsetting the decrease is the recovery of
stranded cost mitigation incentives of approximately $25 million in 1999
compared with $10 million in 1998, as well as increased transmission revenues
of approximately $13 million due to the elimination of certain liabilities
related to open access transmission tariffs.
Net income for 1998 decreased $22 million compared with 1997. This
decrease was also primarily due to the divestiture and reduced revenues as a
result of industry restructuring.
Operating Revenue
Operating revenue for 1999 decreased $622 million compared with 1998 due
to the divestiture and reduced CTC charges. Partially offsetting these
decreases is an increase in transmission revenues associated with the
elimination of certain liabilities related to open access transmission tariffs
discussed above.
Operating revenue for 1998 decreased $460 million compared with 1997.
This decrease was also the result of the divestiture and reduced revenues due
to industry restructuring, partially offset by the recovery of stranded
investments and increased transmission billings.
<PAGE>
Operating Expenses
Operating expenses for 1999 decreased $543 million compared with 1998.
The divestiture reduced all categories of operating expenses in 1999, with the
exception of depreciation and amortization expenses.
The decrease in fuel expense and purchased power costs reflects the
divestiture and the assumption of the Company's obligations under most of its
previously existing purchased power contracts by the buyer of its nonnuclear
generating business. The Company remains obligated to pay predetermined
amounts to the buyer related to the above-market cost of those contracts. In
addition, the Company also remains obligated under purchased power contracts
with the four Yankee nuclear power companies, the costs of which decreased $8
million in 1999, reflecting reduced costs from Maine Yankee and Connecticut
Yankee, net of increased costs of a 1999 refueling outage at Vermont Yankee.
In addition to the impact of the divestiture, which reduced nonnuclear
generation operation and maintenance expenses by $71 million, the decrease in
other operation and maintenance expenses reflects reduced general and
administrative costs due primarily to workforce reductions and reduced charges
from New England Power Service Company following the divestiture. In addition,
transmission costs decreased $16 million in 1999 due to the assumption of
transmission support agreements by the buyer and reduced Independent System
Operator-New England start-up costs. These decreases were partially offset by
increased costs of $3 million associated with the partially owned Millstone 3
and Seabrook 1 nuclear generating facilities which experienced refueling
outages in the second quarter of 1999.
Operating expenses for 1998 decreased $426 million compared with 1997 as
a result of the divestiture, reduced charges of $22 million from Maine Yankee,
which was closed in mid-1997, and reduced charges of $3 million and $12
million from the partially owned Seabrook 1 and Millstone 3 nuclear generating
facilities, respectively. Operating expenses also decreased due to lower
charges related to postretirement benefits other than pensions (PBOPs),
reflecting the completion of the accelerated amortization of the Company's
deferred PBOP costs in 1997 under the terms of a 1995 rate agreement.
Depreciation and amortization expenses increased $3 million and $2
million in 1999 and 1998, respectively, due to the recovery and amortization
of generation-related stranded costs in those years being greater than the
depreciation and amortization of generation-related plant in the prior years.
The increase is also due to new transmission plant expenditures.
Interest Expense and Other Income
The decrease in interest expense in 1999 and 1998 was principally due to
reduced long-term and short-term debt as a result of the divestiture.
The increase in other income in 1999 and 1998 was due primarily to
increased interest income resulting from the reinvestment of the proceeds from
the divestiture. In 1999, this is partially offset by reduced equity income
from nuclear power companies as a result of reductions in the rates of return
for two of these companies.
<PAGE>
Nuclear Units
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the Company has a
minority interest own nuclear generating units that have been permanently shut
down. These three units are as follows:
<TABLE>
<CAPTION>
Future
Estimated
The Company's Billings to
Investment Date the Company
Unit % $ (millions) Retired $(millions)
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Yankee Atomic 30 5 Feb 1992 7
Connecticut Yankee 15 16 Dec 1996 63
Maine Yankee 20 15 Aug 1997 128
</TABLE>
In the case of each of these units, the Company has recorded a liability
and an offsetting regulatory asset reflecting the estimated future billings
from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to
recover its undepreciated investment in the plant, including a return on that
investment, as well as unfunded nuclear decommissioning costs and other
costs. Maine Yankee recovers its costs, including a return, in accordance
with settlement agreements approved by the FERC in May 1999. Connecticut
Yankee filed a similar request with the FERC, to which several parties
intervened in opposition. In August 1998, a FERC Administrative Law Judge
(ALJ) issued an initial decision which would allow for full recovery of
Connecticut Yankee's unrecovered investment, but precluded a return on that
investment. Connecticut Yankee, the Company, and other parties filed with the
FERC exceptions to the ALJ's decision. Should the FERC uphold the ALJ's
initial decision in its current form, the Company's share of the loss of the
return component would total approximately $12 million to $15 million before
taxes for the entire recovery period.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally liable
for the shortfall.
Under the provisions of the Settlement Agreements, the Company recovers
all costs, including shutdown costs, that the FERC allows these Yankee
companies to bill to the Company.
Operating Nuclear Units
The Company has minority interests in three operating nuclear generating
units which the Company is engaged in efforts to divest: Vermont Yankee,
Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear
generating stations, particularly older units, such as Vermont Yankee, have
increased in recent years and could adversely affect their service lives,
availability, and costs. These uncertainties stem from a combination of
factors, including the acceleration of competitive pressures in the power
generation industry and increased NRC scrutiny. The Company performs periodic
economic viability reviews of operating nuclear units in which it holds
ownership interests.
<PAGE> Vermont Yankee
The following table summarizes the Company's interests in the
Vermont Yankee Nuclear Power Corporation:
<TABLE>
<CAPTION>
(millions of dollars)
----------------------------------------------
Equity Net Estimated
Decommissioning
Ownership Equity Plant Decommissioning
Fund License
Interest(%) Investment Assets Cost (in
1999$) Balance Expiration
- ----------- ---------- ------
- --------------- ------- ----------
<S> <C> <C> <C>
<C> <C>
20 11 34 86 42
2012
</TABLE>
In November 1999, the Vermont Yankee Nuclear Power Corporation entered
into an agreement with AmerGen Energy Company (AmerGen), a joint venture
between PECO Energy and British Energy, to sell the assets of Vermont Yankee.
Under the terms of the agreement, after a Vermont Yankee contribution toward
the plant's decommissioning trust fund, AmerGen will take over the fund and
assume responsibility for the actual cost of decommissioning the plant. The
agreement also requires the existing power purchasers (including the Company)
to continue to purchase the output of the plant or to buy out of the purchased
power obligation. In November 1999, the Company signed an agreement to buy out
of its obligation, requiring future payments which will be recovered through
the Company's CTC. The Company has recorded an accrued liability and
offsetting regulatory asset of $80 million for its share of future liabilities
related to Vermont Yankee, including the purchased power contract termination
payment obligation, but excluding interest and a return allowance. The
proposed sale is contingent upon regulatory approvals by the NRC, the SEC,
under the 1935 Act, and the VPSB, among others.
Millstone 3
In July 1998, Millstone 3, which is operated by a subsidiary of Northeast
Utilities (NU), returned to full operation after being shut down for more than
two years.
In August 1997, the Company sued NU in Massachusetts Superior Court for
damages resulting from the tortious conduct of NU that caused the shutdown of
Millstone 3. The Company's claim for damages included the costs of replacement
power during the outage, costs necessary to return Millstone 3 to safe
operation, and other additional costs. Most of the Company's incremental
replacement power costs have been recovered from customers, either through
fuel adjustment clauses or through provisions in the Settlement Agreements.
In August 1997, the Company also sent a demand for arbitration to
Connecticut Light & Power Company and Western Massachusetts Electric Company,
both subsidiaries of NU (subsidiaries), seeking damages resulting from their
breach of obligations under an agreement with the Company and others regarding
the operation and ownership of Millstone 3.
<PAGE>
In November 1999, the Company, NU, and the subsidiaries executed an
agreement which settled the litigation and arbitration described above. Under
the settlement, NU paid the Company approximately $24 million. In addition, NU
also agreed to include the Company's Millstone 3 interest when NU sells its
Millstone 3 interest at auction. Amounts received pursuant to a sale will,
after reimbursement of the Company's transaction costs and net investment in
Millstone 3, be credited to customers.
Year 2000 Disclosure
In 1999, the NEES companies completed their remediation of the
information systems (computer) problem resulting from the fact that many
software applications and operational programs written in the past might not
have recognized calendar dates associated with the year 2000 (Y2K). As a
result of their remediation efforts, the NEES companies have experienced no
significant disruptions in any of their enterprise or operational computer
systems.
The NEES companies' costs of making the necessary Y2K modifications were
approximately $28 million. In addition, the NEES companies spent approximately
$9 million (of which approximately $7 million has been capitalized) related to
the replacement of the human resources and payroll system, in part due to the
Y2K issue.
Risk Management
The Company's major financial market risk exposure is changing interest
rates. Changing interest rates will affect interest paid on variable rate
debt. At December 31, 1999, the Company's variable rate long-term debt had a
carrying value and fair value of approximately $372 million, a weighted
average interest rate of 3.73 percent, and maturity dates of greater than five
years.
As discussed in the "Industry Restructuring" section, the Company remains
obligated to provide transition power supply service at fixed rates to new
customer load in Rhode Island. The Company meets these obligations by
periodically procuring the necessary power supply at market prices. The
Company cannot predict whether the resulting revenues will be sufficient to
cover the costs to procure such power.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $57 million in 1999 and were
primarily transmission-related. The funds necessary for utility plant
expenditures during the period were primarily provided by internal funds. Cash
expenditures for 2000 are estimated to be approximately $45 million,
principally related to transmission functions. Internally generated funds are
expected to fully cover the Company's capital expenditures in 2000.
On February 8, 1999, the Company repurchased 130,000 shares of its common
stock from NEES for $18 million. Approximately $7 million of the repurchase
price was charged to retained earnings.
On November 30, 1999, the Company declared a dividend of approximately
$232 million, payable on September 30, 2000, to the shareholders of record on
September 29, 2000.
<PAGE>
In 1999, the Company increased its short-term debt outstanding by $39
million. The Company has regulatory approval from the SEC, under the 1935 Act,
to issue up to $375 million of short-term debt. The Company plans to seek the
necessary regulatory approvals in 2000 which would allow the $39 million of
variable rate debt to remain outstanding through 2015. This would result in
classifying the debt as long-term rather than short-term.
At December 31, 1999, the Company had lines of credit and standby bond
purchase facilities with banks totaling $460 million which are available to
provide liquidity support for $410 million of the Company's short-term and
long- term bonds in tax-exempt commercial paper mode (including the $39
million discussed above), and for other corporate purposes. There were no
borrowings under these lines of credit at December 31, 1999.
<PAGE>New England Power Company
Statements of Income
<TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenue, principally
from affiliates $ 596,341 $1,218,340 $1,677,903
Operating expenses:
Fuel for generation 12,803 223,828 372,734
Purchased electric energy:
Contract termination and nuclear
unit shutdown charges 187,777 97,469 43,876
Other 56,731 302,367 483,771
Other operation 70,936 155,065 241,506
Maintenance 28,536 60,239 89,820
Depreciation and amortization 103,080 99,924 98,024
Taxes, other than income taxes 20,282 48,492 67,311
Income taxes 37,633 73,594 90,009
--------- ---------- ----------
Total operating expenses 517,778 1,060,978 1,487,051
--------- ---------- ----------
Operating income 78,563 157,362 190,852
Other income:
Allowance for equity funds
used during construction 1,958 633 -
Equity in income of nuclear
power companies 2,939 5,284 5,189
Other income (expense), net 2,087 118 (3,404)
--------- ---------- ----------
Operating and other income 85,547 163,397 192,637
--------- ---------- ----------
Interest:
Interest on long-term debt 14,052 30,775 42,277
Other interest 1,003 10,688 7,055
Allowance for borrowed funds used
during construction (522) (961) (1,238)
--------- ---------- ----------
Total interest 14,533 40,502 48,094
--------- ---------- ----------
Net income $ 71,014 $ 122,895 $ 144,543
========= ========== ==========
Statements of Retained Earnings
Year ended December 31, (In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
Retained earnings at beginning
of year $ 204,603 $ 407,630 $ 400,610
Net income 71,014 122,895 144,543
Dividends declared on cumulative
preferred stock (94) (1,230) (2,075)
Dividends declared on common stock,
$37.43, $20.25, and $21.00
per share, respectively (241,415) (130,610) (135,448)
Premium on redemption of
preferred stock 264 (264) -
Repurchase of common stock (7,085) (193,818) -
--------- ---------- ----------
Retained earnings at end of year $ 27,287 $ 204,603 $ 407,630
========= ========== ==========
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<PAGE>New England Power Company
Balance Sheets
<TABLE>
<CAPTION>
At December 31, (In thousands) 1999 1998
- -----------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility plant, at original cost $1,312,384 $1,262,461
Less accumulated provisions
for depreciation and amortization 849,694 837,637
---------- ----------
462,690 424,824
Construction work in progress 30,063 33,289
---------- ----------
Net utility plant 492,753 458,113
---------- ----------
Investments:
Nuclear power companies, at equity (Note D-1) 46,233 48,538
Decommissioning trust funds (Note D-2) 36,279 31,281
Nonutility property and other investments 7,248 8,302
---------- ----------
Total investments 89,760 88,121
---------- ----------
Current assets:
Cash and temporary cash investments (including
$59,039 and $109,911 with affiliates) 204,344 179,413
Accounts receivable:
Affiliated companies 73,444 107,878
Others 44,301 32,573
Fuel, materials, and supplies, at average cost 9,471 9,220
Prepaid and other current assets 39,315 21,569
---------- ----------
Total current assets 370,875 350,653
---------- ----------
Regulatory assets (Note C) 1,345,832 1,512,562
Deferred charges and other assets 3,445 5,339
---------- ----------
$2,302,665 $2,414,788
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized - 6,449,896 shares
Outstanding - 3,619,896 and 3,749,896 shares $ 72,398 $
74,998
Premium on capital stock 48,623 50,371
Other paid-in capital 183,937 190,852
Retained earnings 27,287 204,603
Unrealized gain on securities, net 91 72
---------- ----------
Total common equity 332,336 520,896
Cumulative preferred stock, par value
$100 per share (Note H) 1,567 1,567
Long-term debt 371,771 371,765
---------- ----------
Total capitalization 705,674 894,228
---------- ----------
Current liabilities:
Short-term debt 38,500 -
Accounts payable (including $25,620
and $119,657 to affiliates) 63,212 162,360
Accrued liabilities:
Taxes 3,889 15,009
Interest 3,378 2,440
Other accrued expenses (Note G) 15,693 20,086
Dividends payable 232,365 24
---------- ----------
Total current liabilities 357,037 199,919
---------- ----------
Deferred federal and state income taxes 179,686 165,115
Unamortized investment tax credits 19,060 30,870
Accrued Yankee nuclear plant costs (Note D-2) 277,932 242,138
Purchased power obligations 703,737 832,668
Other reserves and deferred credits 59,539 49,850
Commitments and contingencies (Note D)
---------- ----------
$2,302,665 $2,414,788
========== ==========
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>New England Power Company
Statements of Cash Flows
<TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating activities:
Net income $ 71,014 $ 122,895 $ 144,543
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 108,789 104,331 101,186
Deferred income taxes and
investment tax credits, net 14,111 (226,722) (12,728)
Allowance for funds used
during construction (2,480) (1,594) (1,238)
Reimbursement to New England Energy
Incorporated of loss on sale of oil
and gas properties - (120,900) -
Buyout of purchased power contracts (3,472) (326,590) -
Decrease (increase) in
accounts receivable 22,706 130,914 (25,128)
Decrease (increase) in fuel,
materials, and supplies (251) (10,270) 11,217
Decrease (increase) in prepaid
and other current assets (17,746) (8,778) 7,213
Increase (decrease) in accounts payable (99,148)
(31,761) (18,105)
Increase (decrease) in other
current liabilities (14,575) 5,037 (1,905)
Other, net (3,995) (49,611) 19,919
-------- ----------- ---------
Net cash provided by (used in)
operating activities $ 74,953 $ (413,049) $
224,974
-------- ----------- ---------
Investing activities:
Proceeds from sale of generating assets $ - $ 1,688,863
$ -
Plant expenditures, excluding allowance
for funds used during construction (56,887) (64,446)
(69,863)
Other investing activities (4,411) (5,474) (4,040)
-------- ----------- ---------
Net cash provided by (used in)
investing activities $(61,298) $ 1,618,943 $
(73,903)
-------- ----------- ---------
Financing activities:
Capital contribution from parent $ - $ 34,881 $ -
Dividends paid on common stock (9,050) (166,084) (127,386)
Dividends paid on preferred stock (118) (1,206) (2,075)
Changes in short-term debt 38,500 (111,250) 17,650
Long-term debt - retirements - (328,000) (38,500)
Repurchase of common shares (18,056) (417,960) -
Preferred stock - retirements - (38,505) -
Premium on reacquisition of long-term debt - - (2,163)
-------- ----------- ---------
Net cash provided by (used in)
financing activities $ 11,276 $(1,028,124)
$(152,474)
-------- ----------- ---------
Net increase (decrease) in
cash and cash equivalents $ 24,931 $ 177,770 $ (1,403)
Cash and cash equivalents
at beginning of year 179,413 1,643 3,046
-------- ----------- ---------
Cash and cash equivalents at end of year $204,344 $ 179,413 $
1,643
======== =========== =========
Supplementary Information:
Interest paid less amounts capitalized $ 11,849 $ 43,419 $
46,033
-------- ----------- ---------
Federal and state income taxes paid $ 55,134 $ 282,076 $ 109,109
-------- ----------- ---------
Dividends received from
investments at equity $ 5,243 $ 6,571 $ 3,267
-------- ----------- ---------
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
New England Power Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of operations:
New England Power Company (the Company), a wholly owned subsidiary of
National Grid USA (formerly New England Electric System (NEES)), is a
Massachusetts corporation qualified to do business in Massachusetts, New
Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is
subject, for certain purposes, to the jurisdiction of the regulatory
commissions of these six states, the Securities and Exchange Commission (SEC),
under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal
Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission
(NRC). The Company's business is primarily the transmission of electric energy
in wholesale quantities to other electric utilities, principally its
distribution affiliates Granite State Electric Company, Massachusetts Electric
Company, Nantucket Electric Company, and The Narragansett Electric Company
(Narragansett Electric). In addition, the Company also owns minority interests
in two joint owned nuclear generating units as well as minority equity
interests in four nuclear generating companies (Yankees), three of which own
generating facilities that are permanently shut down. The output from these
generating facilities is sold to third parties.
2. System of accounts:
The accounts of the Company are maintained in accordance with the Uniform
System of Accounts prescribed by regulatory bodies having jurisdiction.
In preparing the financial statements, management is required to make
estimates that affect the reported amounts of assets and liabilities and
disclosures of asset recovery and contingent liabilities as of the date of the
balance sheets, and revenues and expenses for the period. These estimates may
differ from actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates. In addition, certain
presentation adjustments have been made to conform prior years with the 1999
presentation.
3. Allowance for funds used during construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC
represents the composite interest and equity costs of capital funds used to
finance that portion of construction costs not yet eligible for inclusion in
rate base. AFDC is capitalized in "Utility plant" with offsetting noncash
credits to "Other income" and "Interest." This method is in accordance with an
established rate-making practice under which a utility is permitted a return
on, and the recovery of, prudently incurred capital costs through their
ultimate inclusion in rate base and in the provision for depreciation. The
composite AFDC rates were 7.6 percent, 6.1 percent, and 5.9 percent in 1999,
1998, and 1997, respectively.
4. Depreciation and amortization:
The depreciation and amortization expense included in the statements of
income is composed of the following:
<TABLE>
<CAPTION>
Year ended December 31
(In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Depreciation - transmission related $ 13,222 $12,553 $11,828
Depreciation - all other 1,286 46,256 68,432
Nuclear decommissioning costs (Note D-2) 3,637 2,719 2,638
Amortization:
Seabrook 2 property losses - - 113
Millstone 3 additional amortization,
pursuant to 1995 rate settlement - 22,040 15,013
Regulatory assets covered by contract
termination charges (See Note C) 84,935 16,356 -
-------- ------- -------
Total depreciation and
amortization expense $103,080 $99,924 $98,024
======== ======= =======
</TABLE>
<PAGE>
Depreciation is provided annually on a straight-line basis. The provision
for depreciation as a percentage of weighted average depreciable transmission
property was 2.3 percent in 1999, 1998, and 1997. Amortization of Seabrook and
Millstone 3 investments above normal depreciation accruals and amortization of
regulatory assets covered by contract termination charges (CTC) was in
accordance with rate settlement agreements.
5. Cash:
The Company classifies short-term investments with a maturity of 90 days
or less as cash.
Note B - Merger Agreements with National Grid and EUA
Merger Agreement with National Grid
On March 22, 2000, the merger of NEES and The National Grid Group plc
(National Grid) was completed, with NEES (renamed National Grid USA) becoming
a wholly owned subsidiary of National Grid. The Company will maintain its
existing name and will remain a wholly owned subsidiary of National Grid USA.
The merger is being accounted for by the purchase method, the application of
which, including the recognition of goodwill, is being pushed down and
reflected on the books of the National Grid USA subsidiaries, including the
Company.
Merger Agreement with EUA
In February 1999, NEES, Eastern Utilities Associates (EUA), and Research
Drive LLC (Research Drive), a wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA Agreement,
Research Drive will merge with and into EUA, with EUA becoming a wholly owned
subsidiary of National Grid USA.
The acquisition of EUA has received approval or support from EUA
shareholders, the Federal Trade Commission (FTC), the FERC, the NRC, the
Connecticut Department of Public Utility Control, the Rhode Island Public
Utilities Commission, the Massachusetts Department of Telecommunications and
Energy, and the Vermont Public Service Board (VPSB). An application has also
been filed for approval with the SEC, under the 1935 Act. The acquisition of
EUA, including the consolidation of Montaup Electric Company, a wholly owned
subsidiary of EUA, into the Company, is expected to be completed following the
receipt of an SEC order approving the acquisition, which could come at any
time. If the SEC order is not received in time to close the transaction by
April 28, 2000, the approval by the FTC, under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, as amended, expires and will have to be renewed
prior to completion of the acquisition.
Note C - Industry Restructuring
Pursuant to legislation enacted in Massachusetts, Rhode Island, and New
Hampshire, and settlement agreements approved by state and federal regulators
(the Settlement Agreements), customers were granted choice of power supplier
in 1998. To facilitate the implementation of customer choice, the Settlement
Agreements provided for the termination of the Company's all-requirements
contracts with its affiliated distribution companies. The Company's all-
requirements contracts with unaffiliated customers were also generally
terminated pursuant to settlement agreements or tariff provisions. However,
the Company remains obligated to provide transition power supply service at
fixed rates to new customer load in Rhode Island. In addition, as a result of
the Settlement Agreements, the Company and its affiliate, Narragansett
Electric, sold substantially all of their nonnuclear generating business
(divestiture) in September 1998. As part of the divestiture plan, New England
Energy Incorporated sold its oil and gas properties in 1998, resulting in a
loss of approximately $120 million, before tax, which was reimbursed by the
Company. The Company also agreed to endeavor to sell its minority interest in
three nuclear power plants and a 60 megawatt interest in a fossil-fueled
generating station in Maine.
<PAGE>
In conjunction with the divestiture, the Company transferred to the buyer
of its nonnuclear generating business (the buyer) its entitlement to power
procured under several long-term contracts in exchange for monthly fixed
payments by the Company averaging $9.5 million per month through January 2008
(having a net present value at December 31, 1999 of approximately $704
million) toward the above-market cost of those contracts. For certain
contracts which have been formally assigned to the buyer, the Company has made
lump sum payments equivalent to the present value of the monthly fixed payment
obligations of those contracts (approximately $345 million), which were
separate from the $704 million figure referred to above.
Under the Settlement Agreements, the Company is permitted to recover
costs associated with its former generating investments and related
contractual commitments that were not recovered through the sale of those
investments ("stranded costs"). These costs are recovered from the Company's
wholesale customers through CTCs which the affiliated wholesale customers
recover through delivery charges to distribution customers. The recovery of
the Company's stranded costs is divided into several categories. Unrecovered
costs associated with generating plants (nuclear and nonnuclear) and most
regulatory assets will be fully recovered through the CTC by the end of 2000
and earn a return on equity averaging 9.7 percent. The Company's obligation
related to the above-market cost of purchased power contracts and nuclear
decommissioning costs are recovered through the CTC as such costs are actually
incurred. As the CTC rate declines, the Company, under certain of the
Settlement Agreements, earns incentives based on successful mitigation of its
stranded costs. These incentives supplement the Company's return on equity.
Until such time as the Company divests its operating nuclear interests, the
Company will share with customers, through the CTC, 80 percent of the revenues
and operating costs related to the units, with shareholders retaining the
balance. For further information on the potential sale of the Vermont Yankee
and Millstone 3 nuclear generating units, refer to the "Nuclear Units" section
below.
Accounting Implications
Because electric utility rates have historically been based on a
utility's costs, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in general.
The Company applies the provisions of Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), which requires regulated entities, in appropriate circumstances, to
establish regulatory assets, and thereby defer the income statement impact of
certain charges or revenues because they are expected to be collected or
refunded through future customer billings. In 1997, the Emerging Issues Task
Force of the Financial Accounting Standards Board concluded that a utility
that had received approval to recover stranded costs through regulated rates
would be permitted to continue to apply FAS 71 to the recovery of stranded
costs.
As discussed above, the Company received authorization from the FERC to
recover through CTCs substantially all of the costs associated with its
former generating business not recovered through the divestiture.
Additionally, FERC Order No. 888 enables transmission companies to recover
their specific costs of providing transmission service. Therefore,
substantially all of the Company's business, including the recovery of its
stranded costs, remains under cost-based rate regulation. Because of the
nuclear cost-sharing provisions related to the Company's CTC, the Company
ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear
operations, the impact of which is immaterial.
As a result of applying FAS 71, the Company has recorded a regulatory
asset for the costs that are recoverable from customers through the CTC. At
December 31, 1999, this amounted to approximately $1.3 billion, including $1.0
billion related to the above-market costs of purchased power contracts, $0.3
billion related to accrued Yankee nuclear plant costs, and a smaller amount of
other net CTC-related regulatory assets.
<PAGE>
In 1998, the Company concluded that its interests in the Millstone 3 and
Seabrook 1 nuclear generating units had little, if any, market value, based,
in part, on the fact that proposed sales of nuclear units by other utilities
have required the seller to set aside amounts for decommissioning in excess of
the proceeds from the sale of the units. As a result, the Company recorded an
impairment write-down in its reserve for depreciation of approximately $390
million, representing the book value of Millstone 3 and Seabrook 1 at December
31, 1995, less applicable depreciation subsequent to that date.
Note D - Commitments and Contingencies
1. Yankee Nuclear Power Companies
The Company has minority interests in four Yankee Nuclear Power
Companies. These ownership interests are accounted for on the equity method.
The Company's share of the expenses of the Yankees is accounted for in
"Purchased electric energy" on the income statement. A summary of combined
results of operations, assets, and liabilities of the four Yankees is as
follows:
<TABLE>
<CAPTION>
(In thousands) 1999 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenue $ 377,039 $ 439,046 $ 660,742
=========== =========== ===========
Net income $ 13,890 $ 23,218 $ 29,959
=========== =========== ===========
Company's equity in net income $ 2,939 $ 5,284 $ 5,189
=========== =========== ===========
Net plant 172,100 171,582 204,689
Other assets 2,631,750 2,810,613 3,100,589
Liabilities and debt (2,554,261) (2,723,454) (3,036,845)
----------- ----------- -----------
Net assets $ 249,589 $ 258,741 $ 268,433
=========== =========== ===========
Company's equity in net assets $ 46,233 $ 48,538 $ 49,825
=========== =========== ===========
Company's purchased electric energy:
Vermont Yankee $ 37,551 $ 35,108 $ 31,240
All other Yankees $ 37,765 $ 48,543 $ 75,900
=========== =========== ===========
</TABLE>
At December 31, 1999, $12 million of undistributed earnings of the
nuclear power companies were included in the Company's retained earnings.
2. Nuclear Units
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the Company has a
minority interest own nuclear generating units that have been permanently shut
down. These three units are as follows:
Future
Estimated
The Company's Billings to
Investment Date the Company
Unit % $ (millions) Retired $(millions)
- ----------------------------------------------------------------------------
Yankee Atomic 30 5 Feb 1992 7
Connecticut Yankee 15 16 Dec 1996 63
Maine Yankee 20 15 Aug 1997 128
<PAGE>
In the case of each of these units, the Company has recorded a liability
and an offsetting regulatory asset reflecting the estimated future billings
from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to
recover its undepreciated investment in the plant, including a return on that
investment, as well as unfunded nuclear decommissioning costs and other
costs. Maine Yankee recovers its costs, including a return, in accordance
with settlement agreements approved by the FERC in May 1999. Connecticut
Yankee filed a similar request with the FERC, to which several parties
intervened in opposition. In August 1998, a FERC Administrative Law Judge
(ALJ) issued an initial decision which would allow for full recovery of
Connecticut Yankee's unrecovered investment, but precluded a return on that
investment. Connecticut Yankee, the Company, and other parties filed with the
FERC exceptions to the ALJ's decision. Should the FERC uphold the ALJ's
initial decision in its current form, the Company's share of the loss of the
return component would total approximately $12 million to $15 million before
taxes for the entire recovery period.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally liable
for the shortfall.
Under the provisions of the Settlement Agreements, the Company recovers
all costs, including shutdown costs, that the FERC allows these Yankee
companies to bill to the Company.
Operating Nuclear Units
The Company has minority interests in three operating nuclear generating
units which the Company is engaged in efforts to divest: Vermont Yankee,
Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear
generating stations, particularly older units, such as Vermont Yankee, have
increased in recent years and could adversely affect their service lives,
availability, and costs. These uncertainties stem from a combination of
factors, including the acceleration of competitive pressures in the power
generation industry and increased NRC scrutiny. The Company performs periodic
economic viability reviews of operating nuclear units in which it holds
ownership interests.
Vermont Yankee
The following table summarizes the Company's interests in the
Vermont Yankee Nuclear Power Corporation:
<TABLE>
<CAPTION>
(millions of dollars)
-----------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning
Fund License
Interest (%) Investment Assets Cost (in 1999$)
Balance Expiration
- ------------ ---------- ------ ---------------
- ------- ----------
20 11 34 86 42
2012
</TABLE>
In November 1999, the Vermont Yankee Nuclear Power Corporation entered
into an agreement with AmerGen Energy Company (AmerGen), a joint venture
between PECO Energy and British Energy, to sell the assets of Vermont Yankee.
Under the terms of the agreement, after a Vermont Yankee contribution toward
the plant's decommissioning trust fund, AmerGen will take over the fund and
assume responsibility for the actual cost of decommissioning the plant. The
agreement also requires the existing power purchasers (including the Company)
to continue to purchase the output of the plant or to buy out of the purchased
power obligation. In November 1999, the Company signed an agreement to buy out
of its obligation, requiring future payments which will be recovered through
the Company's CTC. The Company has recorded an accrued liability and
offsetting
<PAGE>
regulatory asset of $80 million for its share of future liabilities related to
Vermont Yankee, including the purchased power contract termination payment
obligation, but excluding interest and a return allowance. The proposed sale
is contingent upon regulatory approvals by the NRC, the SEC, under the 1935
Act, and the VPSB, among others.
Millstone 3
In July 1998, Millstone 3, which is operated by a subsidiary of Northeast
Utilities (NU), returned to full operation after being shut down for more than
two years.
In August 1997, the Company sued NU in Massachusetts Superior Court for
damages resulting from the tortious conduct of NU that caused the shutdown of
Millstone 3. The Company's claim for damages included the costs of replacement
power during the outage, costs necessary to return Millstone 3 to safe
operation, and other additional costs. Most of the Company's incremental
replacement power costs have been recovered from customers, either through
fuel adjustment clauses or through provisions in the Settlement Agreements.
In August 1997, the Company also sent a demand for arbitration to
Connecticut Light & Power Company and Western Massachusetts Electric Company,
both subsidiaries of NU (subsidiaries), seeking damages resulting from their
breach of obligations under an agreement with the Company and others regarding
the operation and ownership of Millstone 3.
In November 1999, the Company, NU, and the subsidiaries executed an
agreement which settled the litigation and arbitration described above. Under
the settlement, NU paid the Company approximately $24 million. In addition, NU
also agreed to include the Company's Millstone 3 interest when NU sells its
Millstone 3 interest at auction. Amounts received pursuant to a sale will,
after reimbursement of the Company's transaction costs and net investment in
Millstone 3, be credited to customers.
Nuclear Decommissioning
The Company is liable for its share of decommissioning costs for
Millstone 3, Seabrook 1, and all of the Yankees. Decommissioning costs include
not only estimated costs to decontaminate the units as required by the NRC,
but also costs to dismantle the uncontaminated portion of the units. The
Company records decommissioning costs on its books consistent with its rate
recovery. The Company is recovering its share of projected decommissioning
costs for Millstone 3 and Seabrook 1 through depreciation expense. In
addition, the Company is paying its portion of projected decommissioning costs
for all of the Yankees through purchased power expense. Such costs reflect
estimates of total decommissioning costs approved by the FERC.
In New Hampshire, legislation was enacted in 1998 which makes owners of
Seabrook 1, in which the Company owns a 10 percent interest, proportional
guarantors for decommissioning costs in the event that an owner without a
franchise service territory fails to fund its share of decommissioning costs.
Currently, a single owner of an approximate 12 percent share of Seabrook 1 has
no franchise service territory. The impact of this legislation to the Company
is not considered material to its financial position or results of operation.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government (through the Department of Energy (DOE)) is responsible for the
disposal of spent nuclear fuel. The federal government requires the Company to
pay a fee based on its share of the net generation from the Millstone 3 and
Seabrook 1 nuclear generating units. Prior to 1998, the Company recovered this
fee through its fuel clause. Under the Settlement Agreements, substantially
all of these costs are recovered through CTCs. Similar costs are billed to the
Company by Vermont Yankee and are also recovered from customers through CTCs.
In 1997, ruling on a lawsuit brought against the DOE by numerous utilities and
state regulatory commissions, the U.S. Court of Appeals for the District of
Columbia held that the DOE was obligated to begin disposing of utilities'
spent nuclear
<PAGE>
fuel by January 1998. The DOE failed to meet this deadline and is not expected
to have a temporary or permanent repository for spent nuclear fuel before
2010, at the earliest. Many utilities, including Yankee Atomic, Connecticut
Yankee, and Maine Yankee, are plaintiffs in on-going litigation related to the
DOE's failure to accept spent nuclear fuel.
Decommissioning Trust Funds
Each nuclear unit in which the Company has an ownership interest has
established a decommissioning trust fund or escrow fund into which payments
are being made to meet the projected costs of decommissioning. The table below
lists information on the two operating nuclear plants in which the Company is
a joint owner.
<TABLE>
<CAPTION>
The Company's share of (millions of dollars)
-----------
- -------------------------------------------
The Company's Estimated Decommissioning
Ownership Net Decommissioning Fund License
Unit Interest (%) Plant Assets Cost (in 1999 $) Balances*
Expiration
- --------------------------------------------------------------------------------
- ---------
<S> <C> <C> <C> <C> <C>
Millstone 3 12 12** 76 23 2025
Seabrook 1 10 14** 56 13 2026
<FN>
*Certain additional amounts are anticipated to be available through tax
deductions.
**Represents post-December 1995 spending including nuclear fuel. For further
information,
refer to Note C.
</FN>
</TABLE>
There is no assurance that decommissioning costs actually incurred by
Millstone 3, Seabrook 1, or Vermont Yankee, as previously mentioned, will not
substantially exceed the estimated amounts. For example, decommissioning cost
estimates assume the availability of permanent repositories for both low-level
and high-level nuclear waste; those repositories do not currently exist. The
temporary low-level repository located in Barnwell, South Carolina may become
unavailable, which could increase the cost of decommissioning the Yankee
Atomic, Connecticut Yankee, and Maine Yankee plants. If any of the operating
units were shut down prior to the end of their operating licenses, which the
Company believes is likely, the funds collected for decommissioning to that
point would be insufficient. Under the Settlement Agreements, the Company will
recover decommissioning costs through CTCs.
Nuclear Insurance
The Price-Anderson Act limits the amount of liability claims that would
have to be paid in the event of a single incident at a nuclear plant to $9.5
billion (based upon 106 licensed reactors). The maximum amount of commercially
available insurance coverage to pay such claims is $200 million. The remaining
$9.3 billion would be provided by an assessment of up to $88.1 million per
incident levied on each of the participating nuclear units in the United
States, subject to a maximum assessment of $10 million per incident per
nuclear unit in any year. The maximum assessment, which was most recently
adjusted in 1998, is adjusted for inflation at least every five years. The
Company's current interest in Vermont Yankee, Millstone 3, and Seabrook 1
would subject the Company to a $35.4 million maximum assessment per incident.
The Company's payment of any such assessment would be limited to a maximum of
$4.0 million per year. As a result of the permanent cessation of power
operation of the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants,
these units have received from the NRC an exemption from participating in the
secondary financial protection system under the Price-Anderson Act. However,
these plants must continue to maintain $100 million of commercially available
nuclear liability insurance coverage.
<PAGE>
Each of the nuclear units in which the Company has either an ownership or
purchased power interest also carries nuclear property insurance to cover the
costs of property damage, decontamination, and premature decommissioning
resulting from a nuclear incident. These policies may require additional
premium assessments if losses relating to nuclear incidents at units covered
by this insurance occur in a prior six-year period. The Company's maximum
potential exposure for these assessments, either directly or indirectly, is
approximately $4.6 million with respect to the current policy period.
3. Plant expenditures
The Company's utility plant expenditures are estimated to be
approximately $45 million in 2000. At December 31, 1999, substantial
commitments had been made relative to future planned expenditures.
4. Hydro-Quebec Interconnection
Three affiliates of the Company were created to construct and operate
transmission facilities to transmit power from Hydro- Quebec to New England.
Under support agreements entered into at the time these facilities were
constructed, the Company agreed to guarantee a portion of the project debt.
That portion at December 31, 1999 amounted to $21 million.
5. Hazardous waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. The
Company currently has in place an internal environmental audit program and an
external waste disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the United States Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for several sites at which hazardous
waste is alleged to have been disposed. Private parties have also contacted or
initiated legal proceedings against the Company regarding hazardous waste
cleanup. The Company is currently aware of other possible hazardous waste
sites, and may in the future become aware of additional sites, that it may be
held responsible for remediating.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. The Company has recovered amounts from certain insurers, and,
where appropriate, intend to seek recovery from other insurers and from other
PRPs, but it is uncertain whether, and to what extent, such efforts will be
successful. The Company believes that hazardous waste liabilities for all
sites of which it is aware are not material to its financial position.
6. Town of Norwood dispute
From 1983 until 1998, the Company was the wholesale power supplier for
the Town of Norwood, Massachusetts (Norwood). In April 1998, Norwood began
taking power from another supplier. Pursuant to a tariff amendment approved by
the FERC in May 1998, the Company has been assessing Norwood a CTC. Through
December 1999, the charges assessed Norwood amount to approximately $15
million, all of which remain unpaid. The Company is pursuing a collection
action in Massachusetts Superior Court.
<PAGE>
Separately, Norwood filed suit in Federal District Court (District Court)
in April 1997 alleging that the divestiture violated the terms of the 1983
power contract and contravened antitrust laws. The District Court dismissed
the lawsuit. On appeal, the First Circuit Court of Appeals (First Circuit)
also consolidated appeals Norwood made from FERC's orders approving the
divestiture, the wholesale rate settlement between the Company and its
distribution affiliates, and the CTC tariff amendment. On February 2, 2000,
the First Circuit dismissed Norwood's appeal from the FERC orders and
dismissed its appeal from all but one of Norwood's District Court claims,
which relates to the creation of generation market power. On February 28, 2000
and March 3, 2000, respectively, the First Circuit denied Norwood's petition
for further review of its District Court claims decision and its decision on
the FERC orders.
Norwood has also appealed a 1999 FERC decision that rejected Norwood's
challenge to the calculation of the CTC based on the term of the 1983 power
contract.
Note E - Employee Benefits
1. Pension Plans:
The Company participates with other subsidiaries of National Grid USA in
noncontributory, defined-benefit plans covering substantially all employees of
the Company. The plans provide pension benefits based on the employee's
compensation during the five years prior to retirement. Absent unusual
circumstances, the Company's funding policy is to contribute each year the net
periodic pension cost for that year. However, the contribution for any year
will not be less than the minimum contribution required by federal law or
greater than the maximum tax deductible amount.
Net pension cost for 1999, 1998, and 1997 included the following
components:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
- ---------
Year ended December 31 (thousands of dollars) 1999 1998
1997
- --------------------------------------------------------------------------------
- ---------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 527 $
2,430 $ 2,887
Plus (less):
Interest cost on projected benefit obligation 7,044
7,435 7,003
Return on plan assets at expected long-term rate (8,090)
(8,675) (7,842)
Amortization of transition obligation (170) (184)
(175)
Amortization of prior service cost 115 161 171
Amortization of net (gain)/loss 36 159 65
Curtailment (gain)/loss - (5,680) -
- --------------------------------------------------------------------------------
- ---------
Benefit cost $ (538) $(4,354) $ 2,109
- --------------------------------------------------------------------------------
- ---------
Special termination benefits not included above $ -
$10,911 $ -
- --------------------------------------------------------------------------------
- ---------
</TABLE>
The funded status of the plans cannot be presented separately for the
Company as the Company participates in the plans with other National Grid USA
subsidiaries. The following table sets forth the funded status of the National
Grid USA companies' plans at December 31:
<PAGE><TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
(millions of dollars) 1999 1998
- ---------------------------------------------------------------------------
<S> <C> <C>
Benefit obligation $789 $843
Unrecognized prior service costs (5) (6)
Transition liability not yet recognized (amortized) (2) (2)
Additional minimum liability 6 7
- ---------------------------------------------------------------------------
788 842
- ---------------------------------------------------------------------------
Plan assets at fair value 947 837
Transition asset not yet recognized (amortized) (5) (6)
Net (gain)/loss not yet recognized (amortized) (206) (92)
- ---------------------------------------------------------------------------
736 739
- ---------------------------------------------------------------------------
Accrued (prepaid) pension benefits
recorded on books $ 52 $103
- ---------------------------------------------------------------------------
</TABLE>
The following provides a reconciliation of benefit obligations and plan
assets:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
(millions of dollars) 1999 1998
- ---------------------------------------------------------------------------
<S> <C> <C>
Changes in benefit obligation:
Benefit obligation at January 1 $843 $819
Service cost 11 14
Interest cost 56 55
Actuarial (gain)/loss (55) (5)
Benefits paid (66) (94)
Special termination benefits - 64
Curtailment - (11)
Plan amendments - 1
- ---------------------------------------------------------------------------
Benefit obligation at December 31 $789 $843
- ---------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $837 $834
Actual return on plan assets during year 117 93
Company contributions 59 4
Benefits paid from plan assets (66) (94)
- ---------------------------------------------------------------------------
Fair value of plan assets at December 31 $947 $837
- ---------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year ended December 31 2000 1999 1998 1997
- ----------------------------------------------------------------------
<S> <C> <C> <C> <C>
Assumptions used to determine pension cost:
Discount rate 7.75% 6.75% 6.75% 7.25%
Average rate of increase in
future compensation level 5.10% 4.13% 4.13% 4.13%
Expected long-term rate of
return on assets 8.50% 8.50% 8.50% 8.50%
</TABLE>
<PAGE>
The plans' funded status at December 31, 1999 and 1998 were calculated
using the assumed rates from 2000 and 1999, respectively, and the 1983 Group
Annuity Mortality table.
Plan assets are composed primarily of equity and fixed income securities.
2. Postretirement Benefit Plans Other than Pensions (PBOPs):
The Company provides health care and life insurance coverage to eligible
retired employees. Eligibility is based on certain age and length of service
requirements and in some cases retirees must contribute to the cost of their
coverage.
The Company's total cost of PBOPs for 1999, 1998, and 1997 included the
following components:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
- ---------
Year ended December 31 (thousands of dollars) 1999 1998
1997
- --------------------------------------------------------------------------------
- ---------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 193 $
1,109 $ 1,363
Plus (less):
Interest cost on projected benefit obligation 2,816
3,244 3,545
Return on plan assets at expected long-term rate (2,896)
(2,656) (2,343)
Amortization of transition obligation 85 1,732
2,556
Amortization of prior service cost - 5 8
Amortization of net (gain)/loss (1,252)
(1,138) (983)
Curtailment (gain)/loss - 27,149 -
- --------------------------------------------------------------------------------
- ---------
Benefit cost $(1,054) $29,445 $ 4,146
- --------------------------------------------------------------------------------
- ---------
Special termination benefits not included above $ - $
439 $ -
- --------------------------------------------------------------------------------
- ---------
</TABLE>
The following table sets forth the Company's benefits earned and the
plans' funded status:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
At December 31 (millions of dollars) 1999 1998
- -----------------------------------------------------------------------------
<S> <C> <C>
Benefit obligation $ 42 $ 41
Unrecognized prior service costs - -
Transition liability not yet recognized (amortized) (1) (1)
- -----------------------------------------------------------------------------
41 40
- -----------------------------------------------------------------------------
Plan assets at fair value 39 36
Net (gain)/loss not yet recognized (amortized) (25) (26)
- -----------------------------------------------------------------------------
14 10
- -----------------------------------------------------------------------------
Accrued (prepaid) PBOPs recorded on books $ 27 $ 30
- -----------------------------------------------------------------------------
</TABLE>
<PAGE>
The following provides a reconciliation of benefit obligations and plan
assets:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(millions of dollars) 1999 1998
- -----------------------------------------------------------------------------
<S> <C> <C>
Changes in benefit obligation:
Benefit obligation at January 1 $41 $ 51
Service cost - 1
Interest cost 3 3
Actuarial (gain)/loss - 2
Benefits paid (2) (2)
Special termination benefits - -
Curtailment - (14)
- -----------------------------------------------------------------------------
Benefit obligation at December 31 $42 $ 41
- -----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $36 $ 34
Actual return on plan assets during year 4 4
Company contributions 1 -
Benefits paid from plan assets (2) (2)
- -----------------------------------------------------------------------------
Fair value of plan assets at December 31 $39 $ 36
- -----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year ended December 31 2000 1999 1998 1997
- ----------------------------------------------------------------------
<S> <C> <C> <C> <C>
Assumptions used to determine postretirement benefit cost:
Discount rate 7.75% 6.75% 6.75% 7.25%
Expected long-term rate of
return on assets 8.42% 8.35% 8.27% 8.21%
Health care cost rates:
1997 to 1999 5.25% 5.25% 8.00%
2000 8.25% 5.25% 5.25% 6.25%
2001 6.75% 5.25% 5.25% 6.25%
2002 to 2004 5.25% 5.25% 5.25% 6.25%
2005 and beyond 5.25% 5.25% 5.25% 5.25%
</TABLE>
The plans' funded status at December 31, 1999 and 1998 were calculated
using the assumed rates in effect for 2000 and 1999, respectively.
The assumptions used in the health care cost trends have a significant
effect on the amounts reported. A one percentage point change in the assumed
rates would increase the accumulated postretirement benefit obligation (APBO)
as of December 31, 1999 by approximately $5 million or decrease the APBO by
approximately $4 million, and change the net periodic cost for 1999 by
approximately $350,000.
The Company generally funds the annual tax-deductible contributions. Plan
assets are invested in equity and fixed income securities and cash
equivalents.
3. Early Retirement and Special Severance Programs:
<PAGE>
In 1998, the Company offered a voluntary early retirement program to all
employees who were at least 55 years old with 10 years of service. This
program was part of an organizational review with the goal of streamlining
operations and reducing the work force to reflect industry restructuring. The
early retirement offer was accepted by 104 employees. A special severance
program was also utilized in 1998 for employees affected by the organizational
restructuring, but who were not eligible for, or did not accept, the early
retirement offer. The cost of these programs was in part reimbursed by the
buyer at the closing of the divestiture and will be recovered in part from
customers as a component of stranded cost recovery.
Note F - Income Taxes
The Company and other subsidiaries participate with National Grid USA in
filing consolidated federal income tax returns. The Company's income tax
provision is calculated on a separate return basis. Federal income tax returns
have been examined and reported on by the Internal Revenue Service through
1993.
Total income taxes in the statements of income are as follows:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- ----------------------------------------------------------------
<S> <C> <C> <C>
Income taxes charged to operations $37,633 $73,594 $90,009
Income taxes charged (credited) to
"Other income" 1,985 (19,582) (373)
------- ------- -------
Total income taxes $39,618 $54,012 $89,636
======= ======= =======
</TABLE>
Total income taxes, as shown above, consist of the following components:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- ----------------------------------------------------------------
<S> <C> <C> <C>
Current income taxes $25,507 $280,734 $102,364
Deferred income taxes 25,921 (204,129) (10,705)
Investment tax credits, net (11,810) (22,593) (2,023)
------- -------- --------
Total income taxes $39,618 $ 54,012 $ 89,636
======= ======== ========
</TABLE>
Investment tax credits (ITC) have been deferred and amortized over the
estimated lives of the property giving rise to the credits. ITC amortization
in 1999 reflects the accelerated amortization of the property giving rise to
the credits, while the increase in amortization of ITC in 1998 compared with
1997 results from the recognition in income of unamortized ITC related to the
generating assets divested during 1998.
Total income taxes, as shown above, consist of federal and state
components as follows:
<PAGE><TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- ----------------------------------------------------------------
<S> <C> <C> <C>
Federal income taxes $33,746 $41,255 $73,077
State income taxes 5,872 12,757 16,559
------- ------- -------
Total income taxes $39,618 $54,012 $89,636
======= ======= =======
</TABLE>
With regulatory approval from the FERC, the Company has adopted
comprehensive interperiod tax allocation (normalization) for temporary
book/tax differences.
Total income taxes differ from the amounts computed by applying the
federal statutory tax rates to income before taxes. The reasons for the
differences are as follows:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- ----------------------------------------------------------------
<S> <C> <C> <C>
Computed tax at statutory rate $38,721 $ 61,917 $81,963
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (7,677) (15,157) (2,023)
State income taxes, net of
federal income tax benefit 3,817 8,292 10,763
Rate recovery of deficiency
in deferred tax reserves 8,207 - -
Prior year tax adjustment (2,028) (188) (313)
All other differences (1,422) (852) (754)
------- -------- -------
Total income taxes $39,618 $ 54,012 $89,636
======= ======== =======
</TABLE>
The following table identifies the major components of total deferred
income taxes:
<TABLE>
<CAPTION>
At December 31, (In millions) 1999 1998
- ----------------------------------------------------------------
<S> <C> <C>
Deferred tax asset:
Plant related $ 67 $ 76
Investment tax credits 8 13
All other 2 24
----- -----
77 113
----- -----
Deferred tax liability:
Plant related (157) (53)
All other, principally regulatory
assets (100) (225)
----- -----
(257) (278)
----- -----
Net deferred tax liability $(180) $(165)
===== =====
</TABLE>
<PAGE>Note G - Short-term Borrowings and Other Accrued Expenses
At December 31, 1999, the Company had $39 million of short-term debt
outstanding. The Company has regulatory approval from the SEC, under the 1935
Act, to issue up to $375 million of short-term debt. The Company plans to seek
the necessary regulatory approvals in 2000 which would allow the $39 million
of variable rate debt to remain outstanding through 2015. This would result in
classifying the debt as long-term rather than short-term. National Grid USA
and certain subsidiaries, including the Company, with regulatory approval,
operate a money pool to more effectively utilize cash resources and to reduce
outside short-term borrowings. Short-term borrowing needs are met first by
available funds of the money pool participants. Borrowing companies pay
interest at a rate designed to approximate the cost of outside short-term
borrowings. Companies which invest in the pool share the interest earned on a
basis proportionate to their average monthly investment in the money pool.
Funds may be withdrawn from or repaid to the pool at any time without prior
notice.
At December 31, 1999, the Company had lines of credit and standby bond
purchase facilities with banks totaling $460 million which are available to
provide liquidity support for $410 million of the Company's short-term and
long- term bonds in tax-exempt commercial paper mode (including the $39
million discussed above) and for other corporate purposes. There were no
borrowings under these lines of credit at December 31, 1999. Fees are paid on
the lines and facilities in lieu of compensating balances.
The components of other accrued expenses are as follows:
<TABLE>
<CAPTION>
At December 31, (In thousands) 1999 1998
- ----------------------------------------------------------------
<S> <C> <C>
Accrued wages and benefits $ 1,063 $ 3,059
Rate adjustment mechanisms 14,550 16,781
Other 80 246
------- -------
$15,693 $20,086
------- -------
</TABLE>
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1999 and 1998 is
as follows (in thousands of dollars except for share data):
<TABLE>
<CAPTION>
Shares Dividends Call
Outstanding Amount Declared Price
- ------------------------------------------------------------------------------
1999 1998 1999 1998 1999 1998
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
$100 par value
6.00% Series 15,672 15,672 $1,567 $1,567 $94 $
277 (a)
4.56% Series - - - - - 247
4.60% Series - - - - - 236
4.64% Series - - - - - 98
6.08% Series - - - - - 372
- ------------------------------------------------------------------------------
Total 15,672 15,672 $1,567 $1,567 $94 $1,230
<FN>
(a) Noncallable.
</FN>
</TABLE>
<PAGE>
The annual dividend requirement for cumulative preferred stock was
$94,000 at the end of 1999 and 1998. In 1998, the Company repurchased or
redeemed preferred stock with an aggregate par value of $38 million.
There are no mandatory redemption provisions on the Company's cumulative
preferred stock.
Note I - Long-term Debt
A summary of long-term debt is as follows:
<TABLE>
<CAPTION>
At December 31, (In thousands)
Series Rate % Maturity 1999 1998
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Pollution Control Revenue Bonds:
MIFA 1 (a) variable March 1, 2018 $ 79,250 $ 79,250
BFA 1 (b) variable November 1, 2020 135,850 135,850
BFA 2 (b) variable November 1, 2020 50,600 50,600
MIFA 2 (a) variable October 1, 2022 106,150 106,150
Unamortized discounts (79) (85)
-------- --------
Total long-term debt $371,771 $371,765
======== ========
<FN>
(a)MIFA = Massachusetts Industrial Finance Authority
(b)BFA = Business Finance Authority of the State of New Hampshire
</FN>
</TABLE>
At December 31, 1999, interest rates on the Company's variable rate long-
term bonds ranged from 3.55 percent to 3.90 percent.
At December 31, 1999, the Company's long-term debt had a carrying value
and fair value of approximately $372,000,000. The fair value of debt that
reprices frequently at market rates approximates carrying value.
Note J - Common Stock
The Company repurchased shares of its common stock in 1999 and 1998 as
follows (dollar amounts expressed in thousands):
<TABLE>
<CAPTION>
Reductions to:
-----------------------------------------
Common stock
Number of Cash and related Other paid- Retained
Year Shares Paid premium in capital earnings
- --------------------------------------------------------------------------------
- ----
<S> <C> <C> <C> <C> <C>
1999 130,000 $ 18,056 $ 4,348 $ 6,623 $ 7,085
1998 2,700,000 $417,960 $90,266 $133,876 $193,818
</TABLE>
Note K - Supplementary Income Statement Information
Advertising expenses, expenditures for research and development, and
rents were not material and there were no royalties paid in 1999, 1998, or
1997. Taxes, other than income taxes, charged to operating expenses are set
forth by classes as follows:
<PAGE><TABLE>
<CAPTION>
Year ended December 31, (In thousands) 1999 1998 1997
- ----------------------------------------------------------------
<S> <C> <C> <C>
Municipal property taxes $17,640 $42,080 $59,102
Federal and state payroll
and other taxes 2,642 6,412 8,209
------- ------- -------
$20,282 $48,492 $67,311
======= ======= =======
</TABLE>
New England Power Service Company, an affiliated service company
operating pursuant to the provisions of Section 13 of the 1935 Act, furnished
services to the Company at the cost of such services. These costs amounted to
$43,584,000, $74,203,000, and $91,985,000, including capitalized construction
costs of $17,229,000, $21,281,000, and $24,347,000, in 1999, 1998, and 1997,
respectively.
<TABLE>
<CAPTION>
New England Power Company
Selected Financial Information
Year ended December 31,
(In millions) 1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue $ 596 $1,218 $1,678 $1,600
$1,571
Net income $ 71 $ 123 $ 145 $ 152 $ 151
Total assets $2,303 $2,415 $2,763 $2,648 $2,648
Capitalization:
Common equity $ 332 $ 521 $ 913 $ 906
$ 889
Cumulative preferred stock 2 1 40 40 61
Long-term debt 372 372 648 733 735
------ ------ ------ ------ ------
Total capitalization $ 706 $ 894 $1,601
$1,679 $1,685
Preferred dividends declared $ - $ 1 $ 2 $
3 $ 3
Common dividends declared $ 241 $ 131 $ 135 $
134 $ 135
------ ------ ------ ------ ------
</TABLE>
Selected Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>
First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
<S> <C> <C> <C> <C>
1999
Operating revenue $167,177 $139,620
$142,066 $147,478
Operating income $ 22,058 $ 13,796 $
18,782 $ 23,927
Net income $ 20,345 $ 14,254 $ 17,669 $
18,746
1998
Operating revenue $401,147 $358,320
$321,569 $137,304
Operating income $ 48,740 $ 32,523 $
54,647 $ 21,452
Net income $ 35,950 $ 20,425 $ 47,956 $
18,564
</TABLE>
Per share data is not relevant because the Company's common stock is
wholly owned by National Grid USA, a wholly owned subsidiary of The National
Grid Group plc.
<PAGE>
<TABLE> EXHIBIT (21)
Subsidiaries of New England Power Company
-----------------------------------------
<CAPTION>
State of Incorporation or
Name of Company Organization
- --------------- -------------------------
<S> <C>
Connecticut Yankee Atomic Connecticut
Power Company
Maine Yankee Atomic Maine
Power Company
Vermont Yankee Nuclear Vermont
Power Corporation
Yankee Atomic Electric Company Massachusetts
</TABLE>
<PAGE>
EXHIBIT (24)
POWER OF ATTORNEY
-----------------
Each of the undersigned directors of New England Power Company
(the "Company"), individually as a director of the Company, hereby
constitutes and appoints John G. Cochrane, Gregory A. Hale, and
Geraldine M. Zipser, individually, as attorney-in-fact to execute
on behalf of the undersigned the Company's annual report on Form
10-K for the year ended December 31, 1999 to be filed with the
Securities and Exchange Commission, and to execute any appropriate
amendment or amendments thereto as may be required by law.
Dated this 20th day of March, 2000.
s/Cynthia A. Arcate s/Cheryl A. LaFleur
_________________________ _________________________
Cynthia A. Arcate Cheryl A. LaFleur
s/L. Joseph Callan s/Richard P. Sergel
_________________________ _________________________
L. Joseph Callan Richard P. Sergel
s/Peter G. Flynn s/Philip R. Sharp
_________________________ _________________________
Peter G. Flynn Philip R. Sharp
s/Alfred D. Houston
_________________________
Alfred D. Houston
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND> THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
THE BALANCE SHEET AND RELATED STATEMENTS OF INCOME, RETAINED
EARNINGS AND CASH FLOWS OF NEW ENGLAND POWER COMPANY, AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<PERIOD-TYPE> 12-MOS
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 492,753
<OTHER-PROPERTY-AND-INVEST> 89,760
<TOTAL-CURRENT-ASSETS> 370,875
<TOTAL-DEFERRED-CHARGES> 1,349,277 <F1>
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,302,665
<COMMON> 72,398
<CAPITAL-SURPLUS-PAID-IN> 232,560
<RETAINED-EARNINGS> 27,287
<TOTAL-COMMON-STOCKHOLDERS-EQ> 332,336 <F2>
0
1,567
<LONG-TERM-DEBT-NET> 371,771
<SHORT-TERM-NOTES> 38,500
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,558,491
<TOT-CAPITALIZATION-AND-LIAB> 2,302,665
<GROSS-OPERATING-REVENUE> 596,341
<INCOME-TAX-EXPENSE> 37,633
<OTHER-OPERATING-EXPENSES> 480,145
<TOTAL-OPERATING-EXPENSES> 517,778
<OPERATING-INCOME-LOSS> 78,563
<OTHER-INCOME-NET> 6,984
<INCOME-BEFORE-INTEREST-EXPEN> 85,547
<TOTAL-INTEREST-EXPENSE> 14,533
<NET-INCOME> 71,014
94
<EARNINGS-AVAILABLE-FOR-COMM> 71,184 <F3>
<COMMON-STOCK-DIVIDENDS> 241,415
<TOTAL-INTEREST-ON-BONDS> 14,052
<CASH-FLOW-OPERATIONS> 74,953
<EPS-BASIC> 0 <F4>
<EPS-DILUTED> 0 <F4>
<FN>
<F1> Total deferred charges includes other regulatory assets and other assets.
<F2> Total common stockholders equity includes the unrealized gain on
securities, net.
<F3> Earnings available for common includes preferred stock dividends and
premium on redemption of preferred stock.
<F4> Per share data is not relevant because the Company's common stock is
wholly-owned by New England Electric System.
</FN>
