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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 March 31, 2001
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Registrant; State of
Incorporation or I.R.S. Employer
Commission Organization; Address; Identification
File Number and Telephone Number Number
- ------------ ---------------------- ---------------
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. ( )
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
June 14, 2001 June 14, 2001
- ---------------------- -------------------------
New England $1,181,192 3,619,896($20 par value)
Power Company
Documents Incorporated by Reference
Part of Form 10-K into which
Description document is incorporated
- ---------------------------------- ----------------------------
Portions of New England Power Company Parts I and II
Annual Report to Stockholders for the
year ended March 31, 2001 as set
forth in Parts I and II
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS..........................................
FORWARD LOOKING INFORMATION................................
PART I
ITEM 1. BUSINESS............................................
THE COMPANY.................................................
Merger with National Grid .............................
Acquisition of EUA.....................................
Merger Agreement with Niagara Mohawk...................
Employees..............................................
ELECTRIC UTILITY OPERATIONS.................................
Transmission and Nuclear Generation Business...........
Description of Business.............................
Rates...............................................
Operating Revenues..................................
Electric Utility Properties............................
Transmission Properties.............................
Interconnection with Quebec ........................
Nuclear Generation Properties.......................
Nuclear Units.....................................
Purchased Power Transfer Agreement................
Regulatory and Environmental Matters...................
Regulation..........................................
Environmental Requirements..........................
Construction and Financing.............................
EXECUTIVE OFFICERS..........................................
ITEM 2. PROPERTIES..........................................
ITEM 3. LEGAL PROCEEDINGS...................................
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS................................................
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDER MATTERS........................
ITEM 6. SELECTED FINANCIAL DATA.............................
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS....................
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE....................
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT.............................................
ITEM 11. EXECUTIVE COMPENSATION............................
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT.........................................
PART IV
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K..................
INDEX TO FINANCIAL STATEMENTS...............................
GLOSSARY OF TERMS
Term Meaning
---- -------
AFDC allowance for funds used during
construction
CMS/MSS Congestion Management System and Multi-
Settlement System
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 National Grid Group plc
National Grid USA Successor to NEES and a wholly-owned
subsidiary of 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.
RTO Regional Transmission Organization
GLOSSARY OF TERMS
Term Meaning
---- -------
Seabrook 1 Seabrook Nuclear Generating Station
Unit 1
SEC Securities and Exchange Commission
Sellers NEP and Narragansett
Service Company National Grid USA Service Company, Inc.
spent nuclear fuel high level radioactive waste
stranded costs the amounts by which prudently
incurred costs 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
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 industry restructuring, as more fully set out under
Regulatory Environment below;
(b) the impact of general economic changes in New England;
(c) federal and state regulatory developments and changes in law which
may have a substantial adverse impact on the value of NEP?s assets;
(d) federal regulatory developments concerning regional transmission
organizations, as more fully set out under Transmission Properties below;
(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 __.
PART I
ITEM 1. BUSINESS
THE COMPANY
New England Power Company (NEP or 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. NEP is subject, for certain
purposes, to the jurisdiction of the regulatory commissions of all
these states (except Connecticut), 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,
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 Electricity Delivery Companies). NEP?s transmission
facilities are part of National Grid USA's transmission operations,
which are represented under the name National Grid Transmission
USA. Holders of common stock and 6% Cumulative Preferred Stock
have general voting rights. National Grid USA owns 99.60% of the
voting stock of NEP and the NEP 6% preferred holders own 0.40%.
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
- --------------- ------------ -------- ---------
Connecticut Yankee Atomic Conn. Ownership of 19.5%
Power Company Permanently
Shutdown
Nuclear Unit (a)
Maine Yankee Atomic Maine Ownership of 24.0%
Power Company Permanently
Shutdown
Nuclear Unit (a)
Vermont Yankee Nuclear Vermont Ownership of 22.5%
Power Corporation Operating
Nuclear Unit (a)
Yankee Atomic Electric Company Mass. Ownership of 34.5%
Permanently
Shutdown
Nuclear Unit (a)
(a) For information on NEP?s ownership interest in nuclear
generating units, see Nuclear Units, page __.
The facilities of NEP, together with the Electricity 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 __.
Merger with National Grid
On March 22, 2000, the merger of NEES and National Grid Group
plc (National Grid) was completed, with NEES (renamed National Grid
USA) becoming a wholly owned subsidiary of National Grid. NEP
maintained its existing name and remained a wholly owned subsidiary
of National Grid USA.
Acquisition of EUA
The acquisition of Eastern Utilities Associates (EUA) by
National Grid USA was completed on April 19, 2000. On May 1, 2000,
Montaup Electric Company (Montaup), formerly a subsidiary of EUA,
was merged into the Company.
Merger Agreement with Niagara Mohawk
On September 5, 2000, National Grid and Niagara Mohawk
Holdings, Inc., (NiMo) announced a merger agreement under which
National Grid will acquire NiMo through the formation of a new
National Grid holding company and the exchange of NiMo shares for a
combination of National Grid's American Depositary Shares (ADSs)
and cash. The terms of the agreement value the transaction at
approximately $3.0 billion.
The transaction is expected to be completed by late calendar
year 2001, and is subject to a number of conditions, including
regulatory and other governmental approvals and the sale of NiMo's
nuclear facilities or other satisfactory arrangements being
reached.
EMPLOYEES
At March 31, 2001, NEP had 114 employees, of which 15 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.
ACCOUNTING IMPLICATIONS
For a full discussion of Accounting Implications see the
Regulatory Environment and Accounting Implications section of the
2001 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 2001 NEP Annual
Report, incorporated herein by reference.
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 a minority interest in a joint owned nuclear
generating unit as well as minority equity interests in four
nuclear generating companies (see Nuclear Units, page __).
Regulatory Environment
Under 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 with which it has
settlement agreements through contract termination charges (CTC).
The Company's retail distribution affiliates recover CTC-related
costs through delivery charges to distribution customers. The
recovery of the Company's stranded costs (including the Montaup
share) is divided into several categories. The Company's
unrecovered costs associated with generating plants (nuclear and
nonnuclear) and most regulatory assets were fully recovered through
the CTC by the end of 2000 and earned a return on equity averaging
9.7 percent. The Montaup share of unrecovered costs associated with
generating plants and most regulatory assets will be fully
recovered through the CTC by the end of 2009. 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, 80 percent of the revenues and operating costs related
to the units will be allocated to customers through the CTC, with
shareholders being allocated the balance.
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. Similar to the
Company, Montaup also transferred its purchased power obligations
as part of the divestiture and in return agreed to make fixed
monthly payments. The aggregate fixed monthly payments, including
the Montaup share, average $11.3 million per month through December
2009 toward the above-market cost of those contracts. The liability
relating to purchased power obligations, which is also reflected in
regulatory assets, represents the net present value of these fixed
monthly payments. At March 31, 2001, the net present value is
approximately $786 million. 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 $453
million), which were separate from the $786 million figure referred
to above.
Prior to divesting substantially all of its nonnuclear
generation business in 1998, the Company was the wholesale supplier
of the electric energy requirements to its retail distribution
affiliates as well as unaffiliated customers. The Company's all-
requirements contracts with its affiliated distribution companies,
as well as with some unaffiliated customers, were generally
terminated pursuant to settlement agreements and tariff provisions
in 1998. However, the Company remains obligated to provide
transition power supply service to new customer load in Rhode
Island at the standard offer price, but does not have a regulatory
agreement that necessarily allows full recovery of the costs of
such standard offer power. Consequently, the Company is at risk for
the difference between the actual cost of serving this load and the
revenue received from this obligation. The standard offer rate that
the Company charges for continuing to meet this obligation
increased from 3.5 cents per kilowatthour (kWh) in 1999 to 3.8
cents per kWh effective January 1, 2000. The standard offer rate is
also subject to a rolling twelve-month fuel index adjustment
factor, which increased the rate by an additional 0.121 cents per
kWh beginning in April 2000 up to 2.404 cents per kWh by March
2001. The Company meets this obligation through a combination of
generation from some of its remaining generation sources, as well
as by periodically procuring power at market prices. Over time, the
Company cannot predict whether the resulting revenues will be
sufficient to cover the costs of procuring such power. For the year
ended March 31, 2001, the Company's losses from this obligation
were approximately $5 million.
In a December 15, 2000 Order, the Federal Energy Regulatory
Commission (FERC) rejected the Independent System Operator-New
England's (ISO New England's) proposed $0.17 per kW-month
Installed Capacity (ICAP) deficiency charge and reinstated an
administratively-determined deficiency charge of $8.75 per kW-
month, retroactive to August 1, 2000. Several parties, including
the Company, filed motions requesting rehearing and stay of the
FERC's order. On January 10, 2001, the FERC granted these
motions. On March 6, 2001, the FERC reversed its earlier order by
allowing ISO New England's previously proposed ICAP rate of $0.17
per kW-month to be effective from August 1, 2000 through March
31, 2001. Effective April 1, 2001, the FERC ordered an ICAP rate
of $8.75 per kW-month. On March 16, 2001, National Grid and
others filed a motion to stay the FERC Order with the United
States Court of Appeals for the First Circuit (First Circuit).
The First Circuit stayed the ICAP rate of $8.75 per kW-month on
March 30, 2001. On June 4, 2001, ISO New England made a filing to
comply with the March FERC order that proposed a maximum charge
of $4.87 per kW-month. On June 8, 2001, the First Circuit,
ruling on the merits of the appeal to the FERC's orders imposing
the $8.75 charge, remanded the case to the FERC for further
consideration. The First Circuit order allows the FERC to
reinstate its initial order on a prospective basis, but asks the
FERC to answer several questions to support its order. National
Grid and others have asked FERC to consider the June 4 ISO filing
while it is reconsidering its initial order on remand. At this
time, the Company cannot predict how ICAP charges will affect its
forward looking power supply costs.
OPERATING REVENUES
The following is the detail of kWh sales and deliveries,
electric sales and other operating revenue, and operating income
for the year ended March 31, 2001, the quarter ended March 31,
2000 and each of the years ended December 31, 1999, and 1998.
Sales and Deliveries of Electricity
(in thousands of kWh)
------------------------------------
Year Ended Quarter Ended Year Ended December 31,
March 31, 2001 March 31, 2000 1999 1998
-------------- -------------- ---- ----
Total Sales
and Deliveries 4,518,054 901,723 2,970,43318,214,193
========== ======= ========== ==========
Operating Revenues
(in thousands of dollars)
------------------------------------
Year Ended Quarter Ended Year Ended December 31,
March 31, 2001 March 31, 2000 1999 1998
-------------- -------------- ---- ----
Total Electric 168,057 32,048 90,639 631,943
Sales Revenue
Other Operating 488,215 102,515 505,702 586,397
Revenue
-------- --------- --------- -------
Total Operating
Revenue $656,272 $134,564 $596,341 $1,218,340
======== ========= ========== ==========
Operating Income $87,715 $ 16,685 $78,563 $157,362
======== ========= ========== ==========
Operating revenue for 1999 decreased $622 million compared
with 1998 due to the divestiture and reduced CTC charges.
ELECTRIC UTILITY PROPERTIES
Transmission Properties
NEP's integrated system consists of approximately 2,800
circuit miles of transmission lines, and approximately 116
substations.
The properties of National Grid USA subsidiaries also
include the ownership interests of New England Electric
Transmission Corporation (NEET),New England Hydro-Transmission
Electric Company, Inc. (Mass.Hydro), and New England Hydro-
Transmission Corporation (N.H.Hydro) in the Hydro-Quebec
Interconnection, and an integrated system of transmission lines,
substations, and distribution facilities.
NEP is a participant in ISO New England's Power Pool
(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. By Order issued June 28, 2000, FERC conditionally
approved a congestion management system and multi-settlement
system (CMS/MSS). The CMS/MSS includes a number of transitional
steps towards the establishment of a permanent congestion
management system which would include a Financial Congestion
Rights scheme, a transmission planning process, and locational
marginal pricing. On May 31, 2001, and June 4, 2001, ISO-NE and
NEPOOL, respectively filed proposals with FERC to implement a
revised standard market design (SMD) to implement CMS/MSS. The
SMD is based on the market system presently in place in the PJM
(Pennsylvania, New Jersey, Maryland) interconnection, and is
intended to bring greater consistency to power markets in the
Northeast. ISO-NE and NEPOOL have requested FERC action on SMD
later this year.
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. The Transmission sector accounts for 20 percent of the
NEPOOL vote and the National Grid USA Companies account for one-
seventh 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.
National Grid USA presented to the FERC in January 2001 a
joint proposal, with ISO-New England and other utilities in New
England, for a Regional Transmission Organization (RTO) in the
northeastern US. The RTO would consist of an ISO with
responsibility for administering a competitive wholesale market
in electricity and an Independent Transmission Company (ITC)
offering transmission services and undertaking transmission
network development and the provision of connections for new
generation. The proposal responds to the FERC's objective, set
out in its "Order 2000", of separating transmission operations
from market participation and would give the ITC, of which
National Grid USA would be a member, the opportunity to propose
financial incentives to deliver greater value for customers and
shareholders. The proposal is subject to FERC approval and the
ability of the utility group to reach agreement on a number of
additional issues.
Interconnection with Quebec
NEET owns and operates a portion of an international
transmission interconnection between the electric systems of
Hydro-Quebec and New England. Mass. Hydro and 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
57.47% of the voting stock of both 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 2,000 megawatts (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 22 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 March 31, 2001, NEP had
guaranteed approximately $18 million of project debt with terms
through 2015. 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. Also, as a result
of Montaup being merged into NEP, at March 31, 2001, NEP had
guaranteed an additional amount of approximately $4 million
originally guaranteed by Montaup. NEP remains an obligor under
the support agreements until 2020.
Nuclear Units
General
NEP has interests in five nuclear units. Three of the units
have been permanently shut down. The remaining two 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 of the 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 Seabrook Nuclear
Generating Station Unit 1 (Seabrook 1) in New Hampshire. Seabrook
1 is operated by subsidiaries of Northeast Utilities (NU). NEP
pays its proportionate share of costs and receives its
proportionate share of output from 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 interest in the two operating
nuclear generating units.
Nuclear Units Permanently Shut Down
Three of the Yankee Nuclear Power 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
The Company's Estimated
Investment Billings to
as of 3/31/01 Date the Company
Unit % $(millions) Retired $(millions)
- -----------------------------------------------------------------
Yankee Atomic 34.5 2 Feb 1992 0
Connecticut Yankee 19.5 15 Dec 1996 50
Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a
liability and a 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 and Connecticut
Yankee recover their costs, including a return, in accordance with
settlement agreements approved by the FERC in May 1999 and July
2000, respectively. Prospectively, under the FERC settlement
agreement, Connecticut Yankee agreed to reduce annual collections
for decommissioning through the use of its pre-1983 spent fuel
trust funds and to limit its return on equity to 6 percent. In
addition, Connecticut Yankee, Yankee Atomic, and Maine Yankee
continue to pursue litigation against the Department of Energy
(DOE) to assume financial responsibility for storage of spent
nuclear fuel. Under rate provisions approved by the FERC for
Connecticut Yankee and Yankee Atomic, any recovery from the DOE
proceedings after litigation expenses and taxes will be returned to
customers.
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.
Maine Yankee had hired Stone & Webster, Inc. (S&W), an
engineering, construction, and consulting company, as the principal
contractor to decommission the unit. In May 2000, Maine Yankee
terminated its long-term contract with S&W and negotiated an
arrangement with S&W to continue work through June 2000. In June
2000, S&W filed for Chapter 11 bankruptcy protection. Subsequently,
Maine Yankee decided to self-manage the unit's decommissioning
process. In June 2000, Federal Insurance Company (Federal) filed a
complaint in S&W's bankruptcy proceeding which alleges that Maine
Yankee improperly terminated its contract with S&W. If the court
were to make such a finding, Federal would be excused from a $37
million performance bond liability to Maine Yankee. Federal's
complaint has been removed to the US Federal District Court in
Maine for jury trial. In August 2000, Maine Yankee filed a $78.2
million (later increased to approximately $86 million) damage claim
against S&W in the bankruptcy proceeding. At this time, the Company
is unable to determine the potential impact, if any, of these
developments.
Under the provisions of the Company's industry restructuring
settlement agreements approved by state and federal regulators in
1998, 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 currently has minority interests in two operating
nuclear generating units which the Company is engaged in efforts to
divest: Vermont Yankee and Seabrook 1. In addition the Company sold
its 16.2 percent interest in Millstone 3 to Dominion Resources,
Inc. (Dominion) on March 31, 2001. Until such time as the Company
divests its operating nuclear interests, 80 percent of the revenues
and operating costs related to the Company's interest in these
units will be allocated to customers through the CTC, with
shareholders being allocated the balance.
Vermont Yankee
The following table summarizes the Company's interest in the
Vermont Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest
(millions of dollars)
---------------------------------------------------
Net Decommissioning
Equity Plant Estimated Fund License
Ownership Equity Assets Decommissioning Balance Expiration
Interest (%) Investments Cost (in 2000 $)
------------- --------------------------------------------------------------------
22.5 $12 $36 $102 $57 2012
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. Several other parties, including Entergy
Corporation (Entergy), indicated to the Vermont Public Service
Board (VPSB) that they were prepared to make an offer for Vermont
Yankee.
On February 14, 2001, the VPSB rejected Vermont Yankee's sale
agreement with AmerGen and formally terminated the AmerGen
proceeding on March 15, 2001. The VPSB also required Entergy to
post a $26 million bond payable in the event that Entergy withdraws
its offer. In addition, the VPSB stated that if the Entergy bond
were redeemed, the proceeds would go exclusively to Vermont
customers. The Vermont Yankee Board of Directors is presently
considering its options with respect to that part of the order.
On March 15, 2001, Vermont Yankee terminated its agreement
with AmerGen. After considering the pros and cons of shutting the
plant down, continuing to operate it, or sell it, Vermont Yankee
decided to proceed with a formal auction of the plant. The auction
was officially launched on April 16, 2001. The Company expects that
the winning bidder of the plant will be named in the fall of 2001.
Any sale of the plant is contingent upon the receipt of regulatory
approvals by the SEC, under the 1935 Act, the FERC, the NRC, the
VPSB, and other state regulatory commissions with jurisdiction over
other equity owners of Vermont Yankee.
Under the terms of the original AmerGen agreement, the
existing power purchasers (including the Company) were required 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 would be recovered through the Company's CTC. At that time,
the Company recorded a 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. With
Vermont Yankee's termination of the agreement with AmerGen in March
2001, the Company was relieved of this obligation and accordingly
reversed the liability and offsetting regulatory asset of $80
million. To date, the Company has not determined if it will enter
into a purchased power agreement with a proposed new owner of
Vermont Yankee.
Seabrook 1
The table below lists information on the Seabrook nuclear plant in
which the Company is a joint owner.
Company's share of (millions of dollars)
--------------------------------------------
Decommissioning
The Company's Net Estimated Fund
Ownership Plant Assets Decommissioning Balances* License
Interest (%) (at 3/31/01) Cost (in 2000 $) (at 3/31/01) Expiration
- -------------------------------------------------------------------------------------------
10 $17** $61 $16 2026
*Certain additional amounts are anticipated to be available through tax
deductions.
**Represents post-December 1995 spending including nuclear fuel.
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), committed
to seek New Hampshire Public Utilities Commission (NHPUC) approval
of a definitive plan to sell, via public auction administered by
the NHPUC, its share of Seabrook 1, with such sale to occur no
later than December 31, 2003. NAEC owns the largest percentage of
the plant with a 35.98 percent interest, and its affiliate, North
Atlantic Energy Service Corporation, is the plant operator. As part
of its settlement, PSNH has also agreed to make all reasonable
efforts to bundle its interests with those of other owners
(including the Company) seeking to sell their interests so that a
controlling interest may be offered in the auction.
In December 2000, NU filed its divestiture plan before the
NHPUC, requesting an expeditious process in order to permit a
prompt sale of the plant. Under the terms of the PSNH Settlement
and enabling legislation, the NHPUC will administer the sale of the
plant with the assistance of an asset sale specialist.
On April 12, 2001, the Company filed a Seabrook Divestiture
Plan with the NHPUC as directed by its 1998 restructuring
settlement agreement. Under the Divestiture Plan, the Company has
indicated its interest in selling its share of Seabrook 1 and has
requested that the NHPUC administer an auction on the Company's
behalf under certain guidelines and conditions.
On May 22, 2001, legislation was enacted in New Hampshire to
provide New Hampshire residents additional protections against the
restructuring problems encountered in California. Although the
legislation includes provisions to delay the sale of PSNH fossil
and hydro generation assets, it directs the NHPUC to expedite the
auction of the Seabrook Station in a manner that benefits customers
of all New Hampshire utilities, including the Company.
Millstone 3
In November 1999, the Company entered into an agreement with
NU and certain of NU's subsidiaries to settle claims made by the
Company relative to the operation of Millstone 3. Among other
things, the settlement provided for NU to include the Company's
share of Millstone 3 in an auction of NU's share of the unit. Upon
the closing of the sale, NU would pay the Company a total of $25
million, regardless of the actual sale price, with adjustments for
certain capital and fuel procurement expenditures. The settlement
also required NU to indemnify the Company and assume any residual
liabilities resulting from the sale, including any requirements
that the sellers continue to purchase output from the unit.
In August 2000, Dominion agreed to purchase the Millstone
units, including the Company's 16.2 percent interest in Millstone
3, for $1.3 billion in cash.
In November 2000, the Rhode Island Attorney General and the
Rhode Island Division of Public Utilities and Carriers filed a
protest at the FERC contending that the payment the Company would
receive from the sale of Millstone 3, as established by its
agreement with NU, was insufficient. In December 2000, the Company
and other parties to the Millstone sale submitted answers opposing
Rhode Island's position and arguing, among other things, that Rhode
Island's contention was well beyond the scope of the FERC
proceeding. The Company further stated that concerns over the
customer rate impact of the Company's agreement with NU would be
more appropriately addressed under the terms of its restructuring
settlements. On January 25, 2001, the FERC found that Rhode
Island's objection was beyond the scope of the proceeding and
approved the sale.
On March 31, 2001, the Company completed the sale of its 16.2
percent interest in Millstone 3 for approximately $27.9 million. In
addition, the Company paid approximately $5.8 million to increase
the decommissioning trust fund to the level prescribed in its
settlement agreement with NU. The amounts received pursuant to the
sale will, after reimbursement of the Company's transaction costs
and net investment in Millstone 3, be credited to customers. The
Company cannot predict whether the Rhode Island regulators will
reassert their claims in connection with the recovery of stranded
costs.
Nuclear Decommissioning
The Company is liable for its share of decommissioning costs
for 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 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 Seabrook 1 through depreciation expense.
In addition, the Company is paying its portion of projected
decommissioning costs for Connecticut Yankee and Maine Yankee. The
Company has completed its projected decommissioning obligation for
Yankee Atomic. 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, there is a
single owner of an approximate 15 percent share of Seabrook 1 that
is subject to the legislation. The impact of this legislation to
the Company is not considered material to its financial position or
results of operation.
The Company has been working to amend the current nuclear
decommissioning statute to become effective upon the sale of
Seabrook. Decommissioning legislation has passed in the New
Hampshire legislature. This bill, initiated and supported by
Seabrook's joint owners, including the Company and members of the
New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC),
modifies New Hampshire's current decommissioning law and removes
utility owners from the role of proportional guarantor for non-
utility owners. The new legislation also seeks to protect customers
from future decommissioning risks by requiring a buyer to provide
funding assurance even in the event of a premature shutdown at the
plant. The bill also enhances the potential sale price of Seabrook
by allowing the buyer to retain any decommissioning funds in excess
of those contributed by customers of the present utility owners and
by reducing the standard set by the NHNDFC for non-radiological
decommissioning.
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 the
Company to pay a fee based on its share of the net generation from
the Seabrook 1 nuclear generating unit. Prior to 1998, the Company
recovered this fee through its fuel clause. Under 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 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 filed claims for money damages in the U.S.
Court of Federal Claims for the costs associated with the DOE's
failure to begin to take fuel in 1998. As an interim measure until
the DOE meets its contractual obligations to dispose of their spent
fuel, those companies are proceeding with construction of
independent spent fuel storage installations on the plant sites.
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. There is no assurance that decommissioning
costs actually incurred by Seabrook 1 or the Yankees 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, the funds collected for decommissioning to that
point may be insufficient. Under 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
and Seabrook 1 would subject the Company to a $28.6 million maximum
assessment per incident. The Company's payment of any such
assessment would be limited to a maximum of $3.2 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.
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 $3.0 million with respect to the current policy
period.
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.
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 Regulatory
Environment and Accounting Implications section of the 2001 NEP
Annual Report.
Wyman 4
NEP is a 9 percent owner of the Wyman 4 generating unit, a
600 MW oil fired generating unit located in Yarmouth, ME. For
more information, see Legal Proceedings.
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 the Regulatory Environment and
Accounting Implications section of the 2001 NEP Annual Report,
Nuclear Units, page__ and Environmental Requirements, below.
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 Regulatory
Environment and Accounting Implications section of the 2001 NEP
Annual Report.
ISO 14001
In June 2001, the Company announced that its transmission
business achieved ISO (International Organization of
Standardization) 14001 registration of its Environmental
Management System, the first linear electric utility system in
the country to achieve such designation. This also marks the
first ISO 14001 registration of a high-voltage direct current
(HVDC) transmission system in the U.S. The registration
certifies that all activities, products, and services required to
operate, maintain, and construct transmission lines, rights-of-
way, HVDC converter terminals, and vegetation management
activities meet the requirements of the internationally accepted
ISO 14001 environmental standard.
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. These
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.
Environmental Protection Facilities Expenditures
NEP estimates that capital expenditures for environmental
protection facilities in 2001 and 2002 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 a potentially responsible party,
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 2001 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 __.
CONSTRUCTION AND FINANCING
NEP?s estimated construction expenditures (including nuclear
fuel) are shown below for the fiscal years ended March 2002
through 2004.
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.
Estimated Construction Expenditures
for the years ended March
-----------------------------------
2002 2003 2004 Total
- ---- ---- ---- -----
($ in Millions - excluding AFDC)
Nuclear Generation (1) 10 10 10 30
Transmission 40 60 50 150
---- ---- ---- ----
Total NEP 50 70 60 180
---- ---- ---- ----
(1) Includes nuclear fuel.
Financing
All of NEP?s construction expenditures during the fiscal
years ended March 2002 through March 2004 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 NHPUC. The following table summarizes the
short-term debt amounts for which regulatory approval has been
granted at March 31, 2001, and the amount of outstanding
short-term debt and lines of credit and standby bond facilities
at such date.
($ millions)
Lines of Credit/
Regulatory Standby Bond
Limit Outstanding Facilities
- ---------- ----------- ----------------
NEP 375 0 456
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 March
31, 2001, NEP had no moneypool borrowings outstanding.
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. The list below is as of March 31, 2001.
Peter G. Flynn - Age: 47 - Elected President in 1999 -
National Grid USA Vice President since 2000 - Vice President
and Director of Rates for the Service Company from 1996 to
1999.
Michael E. Jesanis - Age: 44 - Vice President since 1998 -
National Grid USA Executive Vice President since 1/1/01 -
NEES Senior Vice President and Chief Financial Officer from
1998 - 2000 - 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.
Marc F. Mahoney - Age: 47- Elected Vice President in 2000 -
Vice President, Field Operations for EUA from 1997 to 2000 -
Director, Transmission and Distribution for EUA from 1995 to
1997.
John F. Malley - Age: 52 - Vice President since 1992.
Lawrence J. Reilly - Age: 45 - Vice President since 1/1/01 -
National Grid USA Senior Vice President since 2000 -
National Grid USA Secretary and General Counsel since 1/1/01
- - President of Mass. Electric, Narragansett, Nantucket, and
Granite State from 1996 to 2000.
James S. Robinson - Age: 47 - Vice President since 1998 -
Director of Nuclear Investments from 1997 to 1998 - Manager,
Wholesale Business Administration from 1993 to 1997.
Masheed H. Rosenqvist - Age: 46 - Vice President since 1998
- - Manager, Transmission Tariffs and Contracts for NEP or
Service Company since 1997.
Terry L. Schwennesen - Age: 45 - Elected Vice President in
2000 - Associate General Counsel of Mass. Electric from 1999
to 2000 - Director of Rates for Service Company from 1998 to
1999 - Manager of Rates during 1998 - Manager of Wholesale
Rates until 1998.
John G. Cochrane - Age: 43 - Treasurer since 1998 - National
Grid USA Chief Financial Officer since 1/1/01 - NEES Vice
President since 1999 - NEES and Service Company Treasurer
since 1998 - Vice President of the Service Company since
1993 - Treasurer of Mass. Electric Company from 1998 to 2000
- - Treasurer of Narragansett from 1993 to 2000.
Kwong O. Nuey - Age: 52 - 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 __ and
Nuclear Generation Properties, page __.
ITEM 3. LEGAL PROCEEDINGS
See Item 1. Business - TRANSMISSION AND NUCLEAR GENERATION
BUSINESS - Regulatory Environment, Page __ and ELECTRIC UTILITY
PROPERTIES - Nuclear Units, Page ___
Norwood
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 March 2001, the charges
assessed Norwood amount to approximately $29 million, all of which
remain unpaid. The Company filed a collection action in
Massachusetts Superior Court (Superior Court). The Superior Court
deferred action until the various appeals described below were
decided. On March 14, 2001, the Superior Court ordered Norwood to
pay the Company $27 million including interest. Norwood was ordered
to pay the judgement in monthly installments of $600,000. Norwood
has also entered a consent order to establish a segregated account
for the benefit of the Company in the amount of $14 million and to
make regular additions to the account.
Separately, Norwood filed suit in Federal District Court
(District Court) in April 1997 alleging that the divestiture of the
Company's nonnuclear generating business (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 consolidated appeals Norwood made from the FERC's
orders approving the Company's divestiture, the wholesale rate
settlement between the Company and its distribution affiliates, and
the CTC tariff amendment. In February 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 alleged generation market power. In February and March
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. In May 2000, Norwood petitioned the US
Supreme Court for review of the First Circuit decisions. In October
2000, the US Supreme Court refused Norwood's petitions to review
the First Circuit decisions affirming (a) the FERC's approval of
the CTC, the divestiture, and the settlement agreements regarding
termination of the Company's power sales agreements with its
affiliates, and (b) the District Court's dismissal of Norwood's
antitrust and breach of contract claims.
In the District Court action, in April 2000, the Company
renewed its motion to dismiss Norwood's remaining claim. Norwood
amended its complaint to reassert a request for rescission of the
divestiture, which it had earlier dropped. A hearing took place
before the District Court in July 2000.
Norwood has also appealed a June 1999 FERC decision that
rejected Norwood's challenge to the calculation of the CTC based on
the terms of the 1983 power contract, which Norwood contended ended
in October 1998, not October 2008. In June 2000, the First Circuit
rejected Norwood's appeal. Norwood filed a petition for certiorari
to the US Supreme Court for review of the First Circuit's decision.
On April 24, 2001, the US Supreme Court denied Norwood's petition.
NSTAR Settlement
On March 30, 2001, the Company reached a settlement in
principal with NSTAR, formerly known as Boston Edison Company
(BECO), resolving issues surrounding a $3 million refund to
Montaup ordered by the FERC in January 2000. The order stemmed
from an earlier proceeding initiated by the FERC where it
required BECO to reduce its ROE under a life of unit purchased
power agreement (PPA) with Montaup for 11 percent of the output
from the Pilgrim plant. BECO subsequently divested its ownership
in the Pilgrim plant in July 1999, and Montaup terminated its
life of unit PPA in favor of a PPA that expires in 2004. BECO
appealed the FERC Order to the First Circuit which, in turn, has
remanded the case to the FERC for further proceedings. Proceeds
from the refund have already been credited to customers through
Montaup's CTC reconciliation mechanism. Under the terms of the
settlement, the Company will return to BECO 75 percent of the
refund amount, plus interest through March 31, 2001. The
settlement is conditioned on consent from the parties to
Montaup's restructuring settlement to recover this amount from
customers through the CTC.
Wyman 4 Settlement
On April 23, 2001, Central Maine Power (CMP) and the Wyman 4
minority owners reached a settlement under which CMP will pay a
total of $12 million to the minority owners. NEP's pro rata share
of the settlement proceeds will be $2.9 million. The proceeds of
the settlement, less legal costs, will be returned to customers via
the CTC mechanism. The settlement is the result of arbitration
brought by NEP and others against CMP regarding the sharing of
CMP's proceeds from its sale of the Wyman 4 unit and site in
Yarmouth, Maine in 1999. NEP is a 9 percent minority owner of the
Wyman 4 generating unit.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to the shareholders for vote
during the fourth quarter of the fiscal year.
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 2001 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
2001 Annual Report.
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 2001
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 2001
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 2001 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.
The list below is as of March 31, 2001
L. Joseph Callan - Age: 53 - 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.
Michael E. Jesanis* - Elected Director in 2000 -
Directorships of National Grid USA Companies: EUA Bioten,
Inc., EUA Energy Investment Corporation, Granite State
Electric Company, Massachusetts Electric Company, Nantucket
Electric Company, National Grid USA, National Grid USA
Service Company, Inc., NEES Communications, 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 Company, and The Narragansett Electric
Company.
Robert G. Powderly - Age: 54 - Elected Director in 2000 -
Executive Vice President of EUA until 2000 - Directorships
of National Grid USA Companies: EUA Bioten, Inc., EUA Energy
Investment Corporation, National Grid USA, National Grid USA
Service Company, Inc., and New England Power Company.
Lawrence J. Reilly* - Director since 2001. Directorships of
National Grid USA companies: AllEnergy Fuels Corp., EUA
Bioten, Inc., EUA Energy Investment Corporation, Granite
State Electric Company, Massachusetts Electric Company,
Nantucket Electric Company, National Grid Transmission
Services Corporation, National Grid USA, National Grid USA
Service Company, Inc., NEES Communications, Inc., NEES
Energy, Inc., NEES Telecommunications Corp., 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
Company, NEWHC, Inc., New England Wholesale Electric
Company, The Narragansett Electric Company and Wayfinder
Group, Inc.
Terry L. Schwewnnesen* - Elected Director in 2000.
Richard P. Sergel - Age: 52 - Director since 1998.
Director of National Grid Group plc. Directorships of
National Grid USA companies: EUA Bioten, Inc., EUA Energy
Investment Corporation, Granite State Electric Company,
Massachusetts Electric Company, Nantucket Electric Company,
National Grid Transmission Services Corporation, National
Grid USA, National Grid USA Service Company, Inc., NEES
Communications, Inc., NEES Energy, Inc., NEES
Telecommunications Corp., 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 Company, NEWHC, Inc., The
Narragansett Electric Company, and Wayfinder Group, Inc.
Philip R. Sharp - Age: 58 - 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.
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 fiscal year 2001, all filing requirements
applicable to its officers, directors, and 10 percent beneficial
owners were complied with, with the exception that, due to
Company error, a Form 3 for each of Marc Mahoney, Lawrence
Reilly, and Terry Schwennesen was filed late.
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
fiscal year ending March 31, 2001, the first calendar quarter of
2000, and calendar years 1999 and 1998 to or for the benefit of
the Chief Executive Officer and the four other most highly
compensated executive officers.
NEP
SUMMARY COMPENSATION TABLE
Long-Term
Annual Compensation (b) Compensation
-------------------------- -------------------
Other Restricted Securities
Name and Annual & Deferred Under All Other
Principal Compensa- Share Lying LTIP Compensa-
Position Year Salary Bonus tion Awards Options Payouts tion
(a) ($) ($)(c) ($)(d) (#) ($) ($)(f)
- ---------- ---- ------- ------ --------- ---------- -------- ------- ------
Peter G. 2001(g) 177,211 30,270 12,175 0 0 0 432
Flynn (i) 2000(h) 40,997 107,889 2,050 0 36,473 118,615 90
President 1999 154,707 74,812 3,616 30,220 46,464 359
1998 57,838 29,383 1,151 12,176 0 6,864 75
Marc F. 2001(g) 118,010 78,428 11,352 0 35,886 0 280
Mahoney(j)
Vice
President
Masheed H. 2001(g) 146,112 17,892 18,452 0 0 0 539
Rosenqvist 2000(h) 32,745 63,412 1,637 0 16,023 54,855 103
Vice 1999 124,740 45,569 2,538 17,671 0 412
President 1998 113,697 44,654 2,285 17,618 0 366
James S. 2001(g) 130,137 39,862 18,649 0 0 0 204
Robinson 2000(h) 31,811 62,966 1,625 0 14,458 53,878 42
Vice 1999 115,920 42,415 2,693 16,405 22,018 167
President 1998 108,205 39,143 2,510 17,734 13,641 149
Terry L. 2001(g) 124,951 15,992 16,787 0 0 0 168
Schwennesen (j)
Vice
President
(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. 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 (1998 - 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.
(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.
(g) Information is for fiscal year ending March 31, 2001.
(h) Information is for the first calendar quarter of 2000 only.
(i) Elected January 1999.
(j) Elected May 2000.
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.
The Chairman of the Nuclear Committee, Mr. Callan, receives $1,500
for each committee meeting he chairs.
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
2001.
PENSION TABLE
Five-Year
Average 15 Years 20 Years 25 Years 30 Years 35 Years
Compensa- of of of of of
tion Service Service Service Service Service
- --------- -------- -------- -------- -------- --------
$100,000 $28,093 $36,790 $45,238 $53,685 $59,133
$150,000 $44,093 $57,790 $71,113 $84,435 $93,258
$200,000 $60,093 $78,790 $96,988 $115,185 $127,383
$250,000 $76,093 $99,790 $122,863 $145,935 $161,508
$300,000 $92,093 $120,790 $148,738 $176,685 $195,633
$350,000 $108,093 $141,790 $174,613 $207,435 $229,758
$400,000 $124,093 $162,790 $200,488 $238,185 $263,883
$450,000 $140,093 $183,790 $226,363 $268,935 $298,008
$500,000 $156,093 $204,790 $252,238 $299,685 $332,133
For purposes of the retirement plans, Mr. Flynn, Mr. Mahoney,
Ms. Rosenqvist, Mr. Robinson, and Ms. Schwennesen currently have
19, 25, 19, 13, and 16 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. 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.
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 a Change in Control Agreement
with Mr. Flynn dated November 1, 1998 which remains in effect for
36 months beyond the month in which a (1) Change in Control of NEES
(as defined in the Change in Control Agreement) or (2) Major
Transaction (as defined in the Change in Control Agreement) occurs.
In accordance with the terms of the Change in Control Agreement, if
Mr. Flynn's employment is terminated without cause by the Company
or for Good Reason (as defined in the Change in Control Agreement)
by Mr. Flynn within 36 months following the event described in
clause (1) or (2) National Grid USA will provide Mr. Flynn with the
severance payments and benefits described below.
The shareholder approval of the merger agreement with National
Grid Group plc (May 1999) constituted a Major Transaction and the
merger with National Grid Group plc on March 22, 2000 constituted a
Change in Control. Accordingly, in the event Mr. Flynn's
employment is terminated without cause by the Company or for Good
Reason by Mr. Flynn within 36 months following the month in which
the Major Transaction or Change in Control occurred, Mr. Flynn will
be entitled to receive (in addition to any normal post-term
compensation and benefits as they become due), (1) in lieu of any
other salary payments: a lump sum cash payment equal to two times
the sum of (a) the higher of (i) his annual base salary in effect
at the time of termination and (ii) his 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 him under the New England Electric System Companies?
Senior Incentive Compensation Plan, New England Electric System
Companies? Incentive Compensation Plan I, II or III and the
Incentive Share Plan or successors of any such plans (collectively,
the Incentive Plans) for the three performance years preceding the
year in which his Date of Termination (as defined in the Change in
Control Agreement) occurs or (ii) the average of the annual bonuses
awarded him pursuant to the Incentive Plans for the three
performance years preceding the year in which the Change in Control
or Major Transaction occurs; (2)in addition to the retirement
benefits to which Mr. Flynn is entitled, a lump sum cash payment
equal to the excess of (a) the actuarial equivalent of the
retirement pension which he would have accrued under the terms of
each Pension Plan (as defined in the Change in Control Agreement)
of National Grid USA (determined as if he (i) were fully vested
thereunder and had accumulated 24 additional months of service
credit thereunder and (ii) had been credited under each Pension
Plan during such 24 month period with compensation at the higher of
(A) his compensation during the 12 months immediately preceding his
Date of Termination or (B) his compensation during the 12 months
immediately preceding the Change in Control or Major Transaction)
over (b) the actuarial equivalent of the retirement pension which
he had actually accrued pursuant to the provisions of each pension
plan as of the Date of Termination; (3) the continuation of life,
disability, accident and health insurance benefits substantially
similar to those which he had received prior to his Date of
Termination for 24 months following the Date of Termination,
reduced to the extent he receives such benefits or such benefits
are made available to him from a subsequent employer, without cost
to him; (4) if he would have otherwise been entitled to post-
retirement health care or life insurance had his employment
terminated at any time during the 24 months following his Date of
Termination 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 him 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 him
in disputing in good faith, any issue relating to the termination
of his employment. Notwithstanding the above, the payments and
benefits to be provided to Mr. Flynn will be reduced to the extent
necessary to avoid imposition of the Excise Tax (as defined in the
Change in Control Agreement) pursuant to Section 4999 of the Code;
provided that such reduction would yield a greater result to Mr.
Flynn than actual payment by Mr. Flynn of the Excise Tax.
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.
NEES' bonus plans, including the Incentive 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. These payments were triggered upon the merger with
National Grid and are reflected in the Summary Compensation Table
in the bonus column for 2000. 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. This payment was triggered upon the merger with
National Grid and is reflected in the Summary Compensation Table in
the LTIP Payouts column for 2000. 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 cash bonus program is is a broad-based, all-
employee bonus program, which focuses employees on both the
financial performance of the Company and operational performance
in key categories such as reliability, customer satisfaction and
safety. Payout levels vary depending on both financial
performance and the number of goals achieved in each work
location and function. Assuming the minimum financial goal is
met, and depending upon the number of other goals attained, an
employee may earn a cash bonus of between 0.8% and 4.5% of their
eligible pay.
Incentive Thrift Plan
The Incentive Thrift Plan permits eligible employees to
contribute up to 20% of their pay on a on a pre-tax basis into the
plan (subject to legal limits), and to receive a Company matching
contribution of up to 5% of their base pay provided the employee
contributes at least 6% of her or his base pay into the plan.
Under Internal Revenue Code rules, annual salary deferrals could
not exceed $10,500 during calendar years 2000 or 2001, and
compensation taken into account for determining deferrals could not
exceed $170,000. Consequently, matching contributions were capped
at $8,500. Matching contributions are shown under Other Annual
Compensation in the Summary Compensation Table.
Deferred Compensation Plan
The Deferred Compensation Plan offers executives the
opportunity to defer bonuses and/or a portion of base pay
until a later elected date. The plan offers returns on
deferrals based upon either the prime rate, the S&P 500 Index,
or parent company securities. In addition, the Company
credits executives under the Deferred Compensation Plan with
the amount of matching contribution that the executive was
unable to contribute under the Incentive Thrift Plan due to
the $170,000 compensation limit, determined by presuming a
maximum executive deferral of $10,500. For calendar years
2000 and 2001 the maximum make-up contribution was
approximately $250.
Life Insurance
Executives are offered life insurance funded by individual
policies with death benefits of either two or three times the
participant's annual salary depending upon the executive's level.
These policies are structured in a manner that the employing
company will recoup the premiums it has made into the policies at
a later date. This program is under review due to a recently
released Internal Revenue Service Notice on the subject matter.
Incentive Compensation Plan
There are two bonus plans applicable to executives, the
Incentive Compensation Plan and the Incentive Share Plan. The
former awards cash bonuses tied to the achievement of financial
results and which are closely aligned with the company's
strategic objectives. Annual financial targets and individual
goals are established each year. In addition, depending upon the
level of bonus awarded under the Incentive Compensation Plan,
executives receive an award in the form of parent company
securities under the Incentive Share Plan. If no cash bonus is
paid, no Incentive Share Plan bonus is paid. For 2000, executives
received incentive compensation bonuses under Change in Control
provisions under the plans.
Financial Counseling
NEP pays for personal financial counseling for certain senior
executives. As required by the Internal Revenue Service, a portion
of the value of services is reported as taxable income to the
executive.
Stock Option Plan
For description, please see the Option Grant and Fiscal
Year-End Option Values tables.
OPTION GRANTS IN LAST FISCAL YEAR
- ----------------------------------
Potential Realizable
Value At Assumed
Annual Rates of Stock
Individual Grants Price Appreciation
For Option Term
- ---------------------------------------------------------------------------------
Percent Of
Number of Options
Securities Granted
Underlying To Exercise
Option Employees Of Base Expi-
Granted In Fiscal Price ration
(#) Year ($/Sh) Date 5%($) 10 % ($)
- ---------------------------------------------------------------------------------
Marc F. Mahoney 35,886 20% 7.80 July 2010 176,047 446,139
In July 2000, National Grid granted stock options to Mr.
Mahoney. The exercise price is 7.80 dollars (the mid market price
on the day before the grant of the options) per share of National
Grid stock. The options are for National Grid shares listed on the
London Stock Exchange - not National Grid ADRs, each ADR being
equal to 5 shares. The exercise price is 5.26 GBP and was
converted to dollars for this table using a conversion of 1 GBP to
1.483 dollars. The options are not vested for 3 years and lapse
after 10 years. The number of stock options granted was a multiple
of base pay ranging from 1 to 3 times base pay. None of the
options may be exercised if National Grid earnings per share growth
does not exceed inflation on a rolling three year basis (EPS
Exceeds Inflation) by 5.99%. Fifty percent of the options may be
exercised if EPS Exceeds Inflation by 6% to 8.99% and 100% may be
exercised if EPS Exceeds Inflation by 9% or more.
FISCAL YEAR-END OPTION VALUES
--------------------------------------
Number of Value of
Securities Unexercised
Underlying In-the-Money
Unexercised Options at
Options at 3/31/01 ($)(a)(b)
Name 3/31/01 (#)(a)
- ------------------------------------------------------------------------------------
Peter G. Flynn 36,473(C) 0
Marc F. Mahoney 35,886 $9,579
Masheed H. Rosenqvist 16,023 0
James S. Robinson 14,458 0
Terry L. Schwennesen 14,315 0
(a) All of these options are unexercisable as
they do not vest until 2003.
(b) The dollar value for Mr. Mahoney was
calculated as the difference between the
exercise price (5.26 GBP) and the share price
at fiscal year end (5.44 GBP) multiplied by
the number of options and then converted to
dollars using the ratio of 1 GBP to 1.483
dollars. The exercise price for the options
of the other executives is 5.665 GBP and were
not in-the-money.
(c) Mr. Flynn holds a total of 38,900 options, however
only 36,473 were allocated as compensation paid by
NEP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
National Grid USA owns 99.6 percent of the voting securities
of NEP.
The following table lists the holdings of National Grid
American Depositary Receipts (ADRs) as of June 1, 2001 by the
directors, the executive officers named in the Summary
Compensation Table, and all directors and executive officers of
the Company, as a group. All of the ADRs are held through the
Incentive Thrift Plan described above.
Name ADRs Beneficially Owned
L. Joseph Callan 0
Peter G. Flynn 2,990
Michael E. Jesanis 351
Marc F. Mahoney 178
Robert G. Powderly 235
Lawrence J. Reilly 291
James S. Robinson 409
Masheed H. Rosenqvist 216
Terry L. Schwennesen 198
Richard P. Sergel 276
Philip R. Sharp 0
All directors and
executive officers,
as a group (14 persons) 5,682
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.
(3) (a) Articles of Organization as amended through June 25,
1987 (Exhibit 3(a) to 1988 Form 10-K, File No. 0-1229).
Articles of Amendment dated January 27, 1998 (Exhibit
B.18.a to National Grid USA 1999 Form U-5-S, File No.
30-33); Articles of Amendment dated February 25, 2000
(Exhibit 3(a) to 2000 Form 10-K, File No. 1-6564);
Articles of Merger dated May 1, 2000 (Filed herewith).
(b) By-laws of the Company as amended April 19, 2000
(Exhibit 3(b) to 2000 Form 10-K, File No. 1-6564).
(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) 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).
(c) 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).
(d) 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).
(e) 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).
(f) 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 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 (Exhibit 10(i)
to 1999 Form 10-K, File No. 1-6564); Restated New
England Power Pool Agreement as amended through the
Sixty-sixth Agreement amending New England Power Pool
Agreement (Filed herewith).
(g) National Grid USA Service Company, Inc. and the
Company: Specimen of Service Contract (filed
herewith).
(h) 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).
(i) 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).
(j) 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).
(k) 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).
(l) 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).
*(m) 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 (Exhibit 10(p) to 1999 Form 10-K,
File No. 1-6564).
*(n) 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 (Exhibit 10(q) to 1999 Form 10-K, File No. 1-6564).
*(o) 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 (Exhibit 10(r) to 1999 Form
10-K, File No. 1-6564).
*(p) 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).
*(q) 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).
*(r) 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).
*(s) 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).
*(t) 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).
*(u) 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).
*(v) 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 Exhibit 10(y) to 1999 Form
10-K, File No. 1-6564).
*(w) 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).
(x) 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).
(y) 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).
(z) 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).
(aa) 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 (Exhibit
10(ee)(i) to 1999 Form 10-K, File No. 1-
6564).
(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 (Exhibit 10(ee)(ii) to 1999 Form 10-K,
File No. 1-6564); Amendment No. 3 dated as
of December 23, 1999 (Filed herewith).
(iii) Amended and Restated PPA Transfer Agreement
between the Company and USGen New England,
Inc. dated as of October 29, 1997 (Filed
herewith).
(iv) Form of PSA Performance Support Agreement
between the Company, USGen New England,
Inc., and each of the following; Unitil
Power Corp. (Ocean State), Braintree
Electric Light Department, Littleton
Electric Light Department, Massachusetts
Government Land Bank, Shrewsbury Electric
Light Plant, and Taunton Municipal Light
Plant, dated as of August 5, 1997 (Exhibit
10(gg)(iv) to 1997 Form 10-K, File No. 1-
6564).
(v) Quebec Interconnection Transfer Agreement
between the Company, The Narragansett
Electric Company, and USGen New England,
Inc. dated as of September 1, 1998 (Exhibit
10(ee)(v) to 1999 Form 10-K, File No. 1-
6564).
(bb) Montaup (now New England Power Company)
(i) Equity Funding Agreement for New England
Hydro-Transmission Corporation dated as of
June 1, 1985, between New England Hydro-
Transmission Corporation and several New
England electric utilities, including
Montaup (now New England Power Company) as
amended as of May 1, 1986 and September 1,
1987 (Exhibits 10-96 and 10-97, Form 10-K
of EUA for 1986, File No. 1-5366; Exhibit
10-116, Form 10-K of EUA for 1987, File No.
1-5366).
(ii) Equity Funding Agreement for New England
Hydro-Transmission Electric Company, Inc.
dated as of June 1, 1985, between New
England Hydro-Transmission Electric
Company, Inc. and several New England
electric utilities, including Montaup (now
New England Power Company) as amended as of
May 1, 1986 and September 1, 1987 (Exhibits
10-98 and 10-99, Form 10-K of EUA for 1986,
File No. 1-5366; Exhibit 10-117, Form 10-K
of EUA for 1987, File No. 1-5366).
(iii) Unit Power Agreement for the Sale of Unit
Capacity and Energy from Ocean State Power
Project to Montaup Electric Company (now
New England Power Company) dated as of May
14, 1986 as amended as of August 27, 1986,
September 27, 1988, October 21, 1988, July
21, 1989, February 7, 1990, December 21,
1990, and February 12, 1996 (Exhibits 10-
101 and 10-102, Form 10-K of EUA for 1986,
File No. 1-5366; Exhibits 10-106 and 10-
107, Form 10-K of EUA for 1988, File No. 1-
5366; Exhibit 10-106, Form 10-K of EUA for
1989, File No. 1-5366; Exhibits 10-86 and
10-87, Form 10-K of Eastern Edison for
1990, File No. 0-8480; Exhibit 10-39.05 and
10-40.05, Form 10-K of EUA for 1996, File
No. 1-5366).
(iv) Power Purchase Agreement dated as of
October 17, 1986, between Northeast Energy
Associates and Montaup (now New England
Power Company) as amended as of June 28,
1989 (Exhibit 10-103, Form 10-K of EUA for
1986, File No. 1-5366; Exhibit 10-103, Form
10-K of EUA for 1989, File No. 1-5366).
(v) Unit Power Agreement for the Sale of Second
Unit Capacity and Energy from Ocean State
Power Project to Montaup Electric Company
(now New England Power Company) dated as of
September 28, 1988 as amended as of July
21, 1989, February 7, 1990, and February
12, 1996 and a Supplemental Agreement dated
July 21, 1989 (Exhibit 10-104, Form 10-K of
EUA for 1989, File No. 1-5366; Exhibits 10-
41.05 and 10-42.05, Form 10-K of EUA for
1996, File No. 1-5366; Exhibit No. 10-88,
Form 10-K of Eastern Edison for 1990, File
No. 0-8480).
(vi) Amended and Restated Power Sales Contract
by and between Southern Energy Canal L.L.C.
(as assignee of Canal Electric Company) and
Montaup Electric Company (now New England
Power Company), dated December 18, 1988 and
effective on December 30, 1998 (Filed
herewith).
(vii) Power Purchase Agreement between Entergy
Nuclear Generation Company and Montaup
Electric Company (now New England Power
Company), dated November 18, 1998 (Filed
herewith).
(viii) Power Purchase and Sale Agreement between
Montaup Electric Company (now New England
Power Company) and Constellation Power
Source, Inc., dated December 21, 1998
(Filed herewith).
(ix) PPA Transfer Agreement between Montaup
Electric Company (now New England Power
Company) and TransCanada Power Marketing
Ltd, dated April 7, 1998 (Filed herewith).
(x) Reinstatement Amendment, dated as of July
6, 1999 by and among Southern Energy Canal,
L.L.C. and Montaup Electric Company (now
New England Power Company) (Filed
herewith).
(13) 2001 Annual Report to Stockholders
(24) Power of Attorney (filed herewith).
Reports on Form 8-K
NEP filed a report on Form 8-K dated February 14, 2001
containing Item 5.
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/Edward Capomacchio, Jr.
Edward A. Capomacchio
Controller
Directors (a majority)
L. Joseph Callan
Peter G. Flynn
Michael E. Jesanis
Robert G. Powderly s/John G. Cochrane
Lawrence J. Reilly All by:
Terry L. Schwennesen John G. Cochrane
Richard P. Sergel Attorney-in-fact
Philip R. Sharp
Date (as to all signatures on this page)
June 28, 2001
NEP
EXHIBIT INDEX
-------------
Exhibit No. Description Page
- ----------- ----------- ----
(3)(a) Articles of Organization as Incorporated
amended through June 27, 1998 by Reference
Articles of Merger dated Filed
May 1, 2000 herewith
(3)(b) By-laws of the Company as Incorporated
amended April 19, 2000 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) 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)(c) 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)(d) 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
(10)(e) 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)(f) New England Power Pool Filed herewith
Agreement and Amendments
thereto
(10)(g) National Grid USA Service Filed herewith
Company, Inc. and the Company:
Specimen of Service Contract
(10)(h) Massachusetts Electric Incorporated
Company, et al. and the by Reference
Company: Form of Mutual
Assistance Agreement
(10)(i) Massachusetts Electric Incorporated
Company, et al. and the by Reference
Company: Restructuring
Settlement Agreement
approved by the Massachusetts
Department of Public Utilities
(10)(j) 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,
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)(k) 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 Incorporated
by Reference
(10)(l) 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)(m) New England Electric Companies' Incorporated
Deferred Compensation Plan as by Reference
amended through February 28,
1998 and amendments thereto
(10)(n) New England Electric System Incorporated
Companies Retirement Supplement by Reference
Plan as amended through June 1,
1996 and an Amendment thereto
(10)(o) New England Electric Companies' Incorporated
Executive Supplemental Retirement by Reference
Plan I as amended through
December 11, 1998 and an Amendment
thereto
(10)(p) New England Electric Companies' Incorporated
Executive Retirees Health and Life by Reference
Insurance Plan as Amended and
Restated January 1, 1996
(10)(q) New England Electric Companies' Incorporated
Incentive Compensation Plan I as by Reference
amended through January 1, 1998
(10)(r) New England Electric Companies' Incorporated
Incentive Compensation Plan II as by Reference
amended through January 1, 1998
(10)(s) New England Electric Companies' Incorporated
Incentive Compensation Plan III as by Reference
amended through January 1, 1998
(10)(t) New England Electric Companies' Incorporated
Senior Incentive Compensation by Reference
Plan as amended through
January 1, 1998
(10)(u) Forms of Life Insurance Program Incorporated
and Form of Life Insurance by Reference
(Collateral Assignment)
(10)(v) New England Electric Companies? Incorporated
Incentive Share Plan as amended by Reference
through February 24, 1997 and an
Amendment thereto
(10)(w) Forms of Severance Protection Incorporated
Agreements by Reference
(10)(x) 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)(y) 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)(z) 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)(aa)(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)(aa)(ii) Wholesale Sales Agreement between Filed herewith
the Company and USGen New England,
Inc. dated as of August 5, 1997 and
Amendments thereto
(10)(aa)(iii) Amended and Restated PPA Transfer Filed herewith
Agreement between the Company and
USGen New England, Inc. dated
as of October 29, 1997
(10)(aa)(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
(10)(aa)(v) Quebec Interconnection Transfer Incorporated
Agreement between the Company, by Reference
The Narragansett Electric Company,
and USGen New England, Inc.,
dated as of September 1, 1998
(10)(bb)(i) Equity Funding Agreement for New Incorporated
England Hydro-Transmission by Reference
Corporation dated as of
June 1, 1985, between New England
Hydro-Transmission Corporation and
several New England Electric
utilities, including Montaup
as amended as of May 1, 1986 and
September 1, 1987
(10)(bb)(ii) Equity Funding Agreement for New Incorporated
England Hydro-Transmission by Reference
Corporation dated as of June 1,
1985, between New England Hydro-
Transmission Electric Company, Inc.
and several New England electric
utilities, including Montaup as
amended as of May 1, 1986 and
September 1, 1987
(10)(bb)(iii) Unit Power Agreement for Sale of Incorporated
Unit Capacity and Energy from by Reference
Ocean State Power Project to
Montaup Electric Company dated as
of May 14, 1986 and amendements
thereto.
(10)(bb)(iv) Power Purchase Agreement dated as Incorporated
of October 17, 1986, between by Reference
Northeast Energy Associates and
Montaup as amended as of June 28,
1989
(10)(bb)(v) Unit Power Agreement for the sale Incorporated
of Second Unit Capacity and Energy by Reference
from Ocean State Power Project to
Montaup Electric Company dated as
Of September 28, 1988 and
amendments thereto.
(10)(bb)(vi) Amended and Restated Power Sales Filed herewith
Contract by and between Southern
Energy Canal L.L.C. and Montaup
Electric Company, dated December
18, 1988 and effective on December
30, 1998.
(10)(bb)(vii) Power Purchase Agreement between Filed herewith
Entergy Nuclear Generation Company
and Montaup Electric Company dated
November 18, 1998
(10)(bb)(viii)Power Purchase and Sale Agreement Filed herewith
between Montaup Electric Company
and Constellation Power Source, Inc.
dated December 21, 1998
(10)(bb)(ix) PPA Transfer Agreement between Filed herewith
Montaup Electric Company and
TransCanada Power Marketing Ltd,
Dated April 7, 1998
(10)(bb)(x) Reinstatement Amendment, dated Filed herewith
as of July 6, 1999 by and among
Southern Energy Canal, L.L.C. and
Montaup Electric Company
(13) 2001 Annual Report to Filed herewith
Stockholders
(24) Power of Attorney Filed herewith
EXHIBIT 3(a)
New England Power Company
Articles of Merger
As of May 1, 2000, Montaup Electric Company and New England
Power Company, the constituent corporations, merged into New
England Power Company. The undersigned officers of each of the
constituent corporations certify under the penalties of perjury
as follows:
1. An agreement of merger has been duly adopted in compliance
with the requirements of General Laws, Chapter 164, Section
96 and 102A, and will be kept as provided by Section 102A
thereof. The surviving corporation will furnish a copy of
said agreement to any of its stockholders, or to any person
who was a stockholder of any constituent corporation, upon
written request and without charge.
2. The effective date of the merger determined pursuant to the
agreement of merger shall be the date approved and filed by
the Secretary of the Commonwealth. If a later effective
date is desired, specify such date which shall not be more
than thirty days after the date of filing.
3. The following amendments to the Articles of Organization of
the surviving corporation have been effected pursuant to the
agreement of merger: None.
Exhibit 10 (f)
NEW ENGLAND POWER POOL
RESTATED NEW ENGLAND POWER POOL AGREEMENT
FERC ELECTRIC THIRD REVISED RATE SCHEDULE NO. 5
(As amended through the Sixty-Sixth Agreement
Amending 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 December 1, 1996 and
amended by subsequent amendments.
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 the
plural number, the terms contained in this Section shall have the
meanings set forth herein. If a term is identified in this Section
with an asterisk (*), the definition may be modified in certain
cases pursuant to the last subsection of this Section 1. If a term
includes language in brackets ([ ]), such language shall become
effective automatically on the CMS/MSS Effective Date. Certain
definitions are included in braces ({ }). These definitions are
still subject to further modification or deletion and will not
become effective except pursuant to a further Commission order. To
the extent appropriate to reflect the understandings of this
introductory text, future composite copies of this Agreement may
remove brackets ([]), and braces ({ }), and part or all of this
explanatory introductory language, and may renumber the
definitions, without further specific amendment to or restatement
of this Agreement.
1.1 Accepted Electric Industry 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. Accepted Electric Industry 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.
1.2 Adjusted Load * (not less than zero) of a Participant during
any particular hour is the Participant's Load during such hour less
any Kilowatts received (or Kilowatts which would have been received
except for the application of Section 14.7(b)) by such Participant
pursuant to a Firm Contract.
1.3 Adjusted Monthly Peak of a Participant for a month is its
Monthly Peak, provided that if there has been a transfer between
Participants, in whole or part, of the responsibilities under this
Agreement during such month pursuant to a Firm Contract, the
Adjusted Monthly Peak of each such Participant shall reflect the
effect of such transaction, but the Adjusted Monthly Peak of a
Participant shall not be changed from the Monthly Peak to reflect
the effect of any other transaction.
1.4 Adjusted Net Interchange of a Participant for an hour is (a)
the Kilowatts produced by or delivered to the Participant from its
Energy Entitlements or pursuant to arrangements entered into under
Section 14.6, as adjusted in accordance with Market 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. This section shall terminate and be
of no further force and effect after final settlement with respect
to services rendered until the CMS/MSS Effective Date.
1.5 Administrative Procedures are procedures adopted by the System
Operator in order to fulfill its responsibilities to apply and
implement NEPOOL System Rules.
1.6 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 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.
1.7 AGC Entitlement is the right for the purposes of settlement to
all or a portion of the AGC 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 under a Unit Contract, reduced by any
portion thereof which such Entity is selling pursuant to a Unit
Contract. 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[, 4-Hour Reserve Entitlement] or Operating Reserve
Entitlement.
1.8 Agreement is this restated contract and attachments, including
the Tariff, as amended and restated from time to time.
1.9 Annual Transmission Revenue Requirements of a Participant's
PTF or of all Participants' PTF for purposes of this Agreement are
the amounts determined in accordance with Attachment F to the
Tariff.
1.10 Automatic Generation Control or AGC is a measure of the
ability of a generating unit or portion thereof to respond
automatically within a specified time to a remote direction from
the System Operator to increase or decrease the level of output in
order to control frequency and to maintain currently proper power
flows into and out of the NEPOOL Control Area.
1.11 Balloting Agent is the Secretary of the Participants
Committee.
1.12 Bid Price is the amount which a Participant offers to accept,
in a notice furnished to the System Operator by it or on its behalf
in accordance with the Market 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. This definition shall terminate and be of no further force
and effect after final settlement with respect to services rendered
before the CMS/MSS Effective Date.
1.13 Bilateral Transaction is a transaction, including a Firm
Contract, System Contract, Load Asset Contract or other contract,
between two or more Participants submitted for the transfer of
Settlement Obligations in accordance with the Market Rules with
respect to Installed Capability, Energy at one or more Locations
within the NEPOOL Control Area, Operating Reserve[, 4-Hour Reserve]
and/or AGC. When used in the plural form, it may be any or all
such arrangements or combinations thereof, as the context requires.
1.14 Clearing Price is the amount determined for Energy, Operating
Reserve and AGC pursuant to Sections 14.8, 14.9 and 14.10,
respectively, until the CMS/MSS Effective Date, and thereafter
pursuant to Sections 14A.8(a), 14A.8(b) and 14A.8(c), respectively.
1.15 CMS is the Congestion management system under the NEPOOL
arrangements, including Locational Prices for Energy and Financial
Congestion Rights.
1.16 CMS/MSS Effective Date is the date on which the provisions of
Section 14A shall become fully effective and supersede the
provisions of Section 14. The CMS/MSS Effective Date shall be a
date fixed by the Participants Committee which occurs after NEPOOL
System Rules and computer programs to fully implement Section 14A
of the Agreement and Schedules 13, 14 and 15 of the Tariff are in
place and at least thirty (30) days have elapsed since the
Participants Committee has provided notice to the Commission of the
proposed CMS/MSS Effective Date.
1.17 Commission is the Federal Energy Regulatory Commission.
1.18 Congestion is a condition of the NEPOOL Transmission System in
which transmission limitations prevent unconstrained regional
economic dispatch of the power system. Following the CMS/MSS
Effective Date, Congestion is the condition that results in the
Congestion Component of the Locational Price at one Location being
different from the Congestion Component of the Locational Price at
another Location during any given hour of the Dispatch Day in the
Day-Ahead Market and Real-Time Market.
1.19 Congestion Component is the component of the Nodal Price that
reflects the marginal cost of Congestion at a given Node or
External Node relative to the Reference Node. When used in
connection with Zonal Price and Hub Price, the term Congestion
Component refers to the Congestion Components of the Nodal Prices
that comprise the Zonal Price and Hub Price averaged or weighted in
the same way that Nodal Prices are averaged or weighted to
determine the Zonal Price and Hub Price, respectively.
1.20 Congestion Cost is the cost of Congestion as defined in
Section 14.14 of the Agreement and Section 24 of the Tariff for
services until the CMS/MSS Effective Date. On and after the
CMS/MSS Effective Date, Congestion Cost is the cost of Congestion
as measured by the difference between the Congestion Components of
the Locational Prices at different Locations and/or Reliability
Regions on the NEPOOL Transmission System.
1.21 Congestion Revenue for each hour is the surplus revenue, if
any, for each hour after netting the revenues paid and collected
for the Congestion Components of Locational Price for all Energy
transactions on the NEPOOL Transmission System, including Energy
deliveries by Non-Participant Transmission Customers taking service
under the Tariff, as settled in accordance with the Market Rules.
Congestion Revenue is calculated for each hour of the Dispatch Day
in the Day-Ahead Market and Real-Time Market as provided in Section
E of Schedule 14 of the Tariff and the applicable Market Rules.
1.22 Congestion Revenue Fund is the fund of Congestion Revenue
administered by the System Operator in accordance with Section
14A.17 of the Agreement, Schedules 13 and 14 of the Tariff, and the
applicable Market Rules.
1.23 Control Area is an electric power system or combination of
electric power systems to which a common automatic generation
control scheme is applied in order to:
(i) 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);
(ii) maintain scheduled interchange with other Control
Areas, within the limits of Accepted Electric Industry
Practice;
(iii) maintain the frequency of the electric power
system(s) within reasonable limits in accordance with
Accepted Electric Industry Practice and the criteria of
the applicable regional reliability council or the NERC;
and
(iv) provide sufficient generating capacity to maintain
operating reserves in accordance with Accepted Electric
Industry Practice.
1.24 Curtailment is a reduction in firm or non-firm transmission
service in response to a transmission capacity shortage as a result
of system reliability conditions.
1.25 Day-Ahead is the calendar day immediately preceding a Dispatch
Day for which Participants submit Demand Bids and Supply Offers in
accordance with applicable Market Rules and the System Operator
schedules Resources for Energy, Operating Reserve, 4-Hour Reserve
and AGC in accordance with applicable NEPOOL System Rules.
1.26 Day-Ahead Market is the market provided for in Section 14A and
conducted in the calendar day immediately preceding a Dispatch Day
in which Energy, Operating Reserve, 4-Hour Reserve and AGC are
scheduled for a Dispatch Day, based on the Day-Ahead Demand Bids
and Supply Offers and applicable NEPOOL System Rules.
1.27 Demand Bid is a proposal by a Participant to receive and pay
for Energy, at a specified Location and at a specified Demand Bid
Price, that is submitted to the System Operator pursuant to the
Agreement and applicable Market Rules, and includes information
with respect to the quantity to be received and paid for and other
matters complying with the Market Rules.
1.28 Demand Bid Price is the price specified by a Participant to
the System Operator in a Demand Bid for Energy at a specified
Location.
1.29 Direct Assignment Facilities are facilities or portions of
facilities that are Non-PTF and are constructed for the sole
use/benefit of a particular Transmission Customer requesting
service under the Tariff or Generator Owner 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.
1.30 Dispatch Day is the period beginning at the minute ending 0001
and ending at 2400 each day.
1.31 Dispatchable Load is any portion of the Electrical Load of a
Participant that meets the requirements of the Market Rules to
qualify as Operating Reserve or 4-Hour Reserve or to have its
Energy consumption modified in Real-Time because of its ability to
respond to remote dispatch instructions from the System Operator.
A Demand Bid to receive and pay for Energy at an External Node
shall, if scheduled, be considered a Dispatchable Load for the
purposes of the Day-Ahead Market and the Real-Time Market.
1.32 Dispatch Price of a generating unit or combination of units,
or a Firm Contract or System Contract permitted to be bid to supply
Energy in accordance with Section 14.7(b) until the CMS/MSS
Effective Date or permitted to be included in a Supply Offer for
Energy in accordance with 14A.11(b) on and after the CMS/MSS
Effective Date, is the price to provide Energy from the unit or
units or Firm Contract or System Contract, as determined pursuant
to the Market Rules to incorporate the Bid Price or Supply Offer
Price, as appropriate, for such Energy and any loss adjustments, if
and as appropriate under applicable Market Rules.
1.33 Distribution Company has the meaning specified in Section
14A.12(b).
1.34 Distribution Company Load Zone has the meaning specified in
Section 14A.12(b).
1.35 EHV PTF are PTF transmission lines which are operated at 230
kV or above and related PTF facilities, including transformers
which link other EHV PTF facilities, but do not include
transformers which step down from 230 kV or a higher voltage to a
voltage below 230 kV.
1.36 Electrical Load (in Kilowatts) of a Participant during any
particular hour is the total during such hour (eliminating any
distortion arising out of (i) Interchange Transactions, or (ii)
transactions across the system of such Participant, or (iii)
deliveries between Entities constituting a single Participant, or
(iv) other electrical losses, if and as appropriate), of
(a) kilowatthours provided by such Participant to its retail
customers for consumption, plus
(b) kilowatthours of use by such Participant, plus
(c) kilowatthours of electrical losses and unaccounted for
use by the Participant on its system, plus
(d) kilowatthours used by such Participant for pumping Energy
for its Entitlements in pumped storage hydroelectric
generating facilities, plus
(e) kilowatthours delivered by such Participant to Non-
Participants, plus
(f) kilowatthours of Electrical Load responsibility incurred
due to a transfer from another Participant pursuant to a Load
Asset Contract for Electrical Load, minus
(g) kilowatthours of Electrical Load responsibility
transferred to another Participant pursuant to a Load Asset
Contract for Electrical Load.
The Electrical Load of a Participant may be calculated in any
reasonable manner which substantially complies with this
definition.
1.37 Eligible Customer is the following: (i) Any Participant that
is engaged, or proposes to engage, in the wholesale or retail
electric power business is an Eligible Customer under the Tariff.
(ii) Any electric utility (including any power marketer), Federal
power marketing agency, or any other entity generating electric
energy for sale or for resale is an Eligible Customer under the
Tariff. Electric energy sold or produced by such entity may be
electric energy produced in the United States, Canada or Mexico.
However, with respect to transmission service that the Commission
is prohibited from ordering by Section 212(h) of the Federal Power
Act, such entity is eligible only if the service is provided
pursuant to a 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.
1.38 End User Behind-the-Meter Generation is generation that has
all three of the following attributes: (a) it is owned by a
Governance Only Member; and (b) it is used to meet that Governance
Only Member's load or, for any hour in which the output of the End
User Behind-the-Meter Generation owned by the Governance Only
Member exceeds its Electrical Load, another Participant which is
not a Governance Only Member is obligated under tariff or contract
to report such excess to the ISO pursuant to applicable Market
Rules; and (c) it is delivered to the Governance Only Member
without the use of PTF or another Entity's transmission or
distribution facilities.
1.39 End User Organization is an End User Participant which is (a)
a registered tax-exempt non-profit organization with (i) an
organized board of directors and (ii) a membership (A) of at least
100 Entities that buy electricity at wholesale or retail in the New
England states or (B) with an aggregate peak monthly demand (non-
coincident) for load in New England, including load served by End
User Behind-the-Meter Generation, of at least ten (10) megawatts or
(b) a municipality or other governmental agency located in New
England which does not meet the definition of Publicly Owned
Entity.
1.40 End 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.
1.41 Energy is electrical energy, measured in kilowatthours or
megawatthours.
1.42 Energy Entitlement is a right for purposes of settlement to
all or a portion of the electric output of a generating unit at the
Node where such unit is interconnected to the NEPOOL Transmission
System 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 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[, 4-Hour Reserve Entitlement] or AGC
Entitlement.
1.43 Entitlement is an Installed Capability Entitlement, Energy
Entitlement, Operating Reserve Entitlement[, 4-Hour 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.
1.44 Entity is any person or organization whether the United States
of America or Canada or a state or province or a political
subdivision thereof or a duly established agency of any of them, a
private corporation, a partnership, an individual, an electric
cooperative or any other person or organization recognized in law
as capable of owning property and contracting with respect thereto
that is either:
(a) engaged in the electric power business (the generation
and/or transmission and/or distribution of electricity for
consumption by the public or the purchase, as a principal or
broker, of Installed Capability, Energy, Operating Reserve,
[4-Hour 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.
1.45 Excepted 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.
1.46 External Node is a bus or buses used for establishing a
Locational Price for Energy received by Participants from, or
delivered by Participants to, a neighboring Control Area.
1.47 Facilities Study is an engineering study conducted pursuant to
this Agreement or the Tariff by the System Operator and/or one or
more affected Participants to determine the required modifications
to the NEPOOL Transmission System, including the cost and scheduled
completion date for such modifications, that will be required to
provide a requested transmission service or interconnection.
1.48 FCR is a Financial Congestion Right.
1.49 Financial Congestion Right is a financial instrument that
evidences the rights and obligations specified in Schedule 14 of
the Tariff.
1.50 Firm Contract is any contract, other than a Unit Contract, for
the purchase of Installed Capability, Energy [at a Location],
Operating Reserves[, 4-Hour Reserves] and/or AGC, pursuant to which
the purchaser's right to receive such Installed Capability, Energy,
Operating Reserves[, 4-Hour Reserves] and/or AGC is subject only to
the supplier's inability to satisfy its obligations thereunder as
the result of events beyond the supplier's reasonable control.
1.51 First Effective Date is March 1, 1997.
1.52 Governance Only Member is an End User Participant that
participates in NEPOOL for governance purposes only and elects to
be a Governance Only Member before its application is approved by
NEPOOL.
1.53 HQ Contracts are the HQ Interconnection Agreement, the HQ
Phase I Energy Contract, and the HQ Phase II Firm Energy Contract.
1.54 HQ Energy Banking Agreement is the Energy Banking Agreement
entered into on March 21, 1983 by Hydro-Quebec, the Participants,
New England Electric Transmission Corporation and Vermont Electric
Transmission Company, Inc., as it may be amended from time to time.
1.55 HQ Interconnection is the United States segment of the
transmission interconnection which connects the systems of Hydro-
Quebec and the Participants. "Phase I" is the United States
portion of the 450 kV HVDC transmission line from a terminal at the
Des Cantons Substation on the Hydro-Quebec system near Sherbrooke,
Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut
River. "Phase II" is the United States portion of the facilities
required to increase to approximately 2000 MW the transfer capacity
of the HQ Interconnection, including an extension of the HVDC
transmission line from the terminus of Phase I at the Comerford
Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not
include any PTF facilities installed or modified to effect
reinforcements of the New England AC transmission system required
in connection with the HVDC transmission line and terminals.
1.56 HQ Interconnection Agreement is the Interconnection Agreement
entered into on March 21, 1983 by Hydro-Quebec and the
Participants, as it may be amended from time to time.
1.57 HQ Interconnection Capability Credit of a Participant for a
month during the Base Term (as defined in Section 1.63) of the HQ
Phase II Firm Energy Contract is the sum in Kilowatts of (1)(a) the
Participant's percentage share, if any, of the HQ Phase I Transfer
Capability times (b) the HQ Phase I Transfer Credit, plus (2)(a)
the Participant's percentage share, if any, of the HQ Phase II
Transfer Capability, times (b) the HQ Phase II Transfer Credit. The
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.
1.58 HQ Interconnection Transfer Capability is the transfer
capacity of the HQ Interconnection under normal operating
conditions, as determined in accordance with Accepted Electric
Industry Practice. The "HQ Phase I Transfer Capability" is the
transfer capacity under normal operating conditions, as determined
in accordance with Accepted Electric Industry 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.
1.59 HQ Net Interconnection Capability Credit of a Participant at a
particular time is its HQ Interconnection Capability Credit at the
time in Kilowatts, minus a number of Kilowatts equal to (1) the
percentage of its share of the HQ Interconnection Transfer
Capability committed or used by it for an "Entitlement Transaction"
at the time under the HQ Use Agreement, times (2) its HQ
Interconnection Capability Credit for the current month.
1.60 HQ Phase I Energy Contract is the Energy Contract entered into
on March 21, 1983 by Hydro-Quebec and the Participants, as it may
be amended from time to time.
1.61 HQ Phase I Percentage is the percentage of the total HQ
Interconnection Transfer Capability represented by the HQ Phase I
Transfer Capability.
1.62 HQ Phase I Transfer Credit is 60/69 of the HQ Phase I Transfer
Capability, or such other fraction of the HQ Phase I Transfer
Capability as the Participants Committee may establish.
1.63 HQ Phase II Firm Energy Contract is the Firm Energy Contract
dated as of October 14, 1985 between Hydro-Quebec and certain of
the Participants, as it may be amended from time to time. The
"Base Term" of the HQ Phase II Firm Energy Contract is the period
commencing on the date deliveries were first made under the
Contract and ending on August 31, 2000.
1.64 HQ Phase II Gross Transfer Responsibility of a Participant for
any month during the Base Term of the HQ Phase II Firm Energy
Contract (as defined in Section 1.63) 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.
1.65 HQ Phase II Net Transfer Responsibility of a Participant for
any month is its HQ Phase II Gross Transfer Responsibility for the
month minus a number of Kilowatts equal to (1) the highest
percentage of its share of the HQ Interconnection Transfer
Capability committed or used by it on any day of the month for an
"Entitlement Transaction" under the HQ Use Agreement, times (2) its
HQ Phase II Gross Transfer Responsibility for the month.
1.66 HQ Phase II Percentage is the percentage of the total HQ
Interconnection Transfer Capability represented by the HQ Phase II
Transfer Capability.
1.67 HQ Phase II Transfer Credit is 90/131 of the HQ Phase II
Transfer Capability, or such other fraction of the HQ Phase II
Transfer Capability as the Participants Committee may establish.
1.68 HQ Use Agreement is the Agreement with Respect to Use of
Quebec Interconnection dated as of December 1, 1981 among certain
of the Participants, as amended and restated as of September 1,
1985 and as it may be further amended from time to time.
1.69 Hub is a specific set of pre-defined Nodes, approved by the
Participants Committee, for which a Locational Price will be
calculated and which can be used to establish a reference price for
Energy purchases and the transfer of Settlement Obligations for
Energy and for the designation of FCRs in accordance with Schedule
14 of the Tariff.
1.70 Hub Price in each hour of the Dispatch Day in the Day-Ahead
Market and the Real-Time Market is the price used for Energy
purchases and Settlement Obligations for Energy which are treated
as being transferred at a Hub in the hour. Hub Prices are
calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.71 Installed Capability of an electric generating unit or
combination of units during the Winter Period is the Winter
Capability of such unit or units and during the Summer Period is
the Summer Capability of such unit or units.
1.72 Installed Capability Entitlement is (a) the right to all or a
portion of the Installed Capability of a generating unit or units
to which an Entity is entitled as an owner (either sole or in
common) or as a purchaser pursuant to a Unit Contract, (b) reduced
by any portion thereof which such Entity is selling pursuant to a
Unit Contract, and (c) further reduced or increased, as
appropriate, to recognize rights to receive or obligations to
supply Installed Capability pursuant to Firm Contracts or System
Contracts in accordance with Section 14.7(a). An Installed
Capability Entitlement relating to a unit or units may, but need
not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the
related Energy Entitlement, Operating Reserve Entitlements, or AGC
Entitlement.
1.73 Installed Capability Responsibility * of a Participant for any
month is the number of Kilowatts determined in accordance with
Section 12.2.
1.74 Installed System Capability of a Participant at a particular
time is (i) the sum of such Participant's Installed Capability
Entitlements plus (ii) its HQ Net Interconnection Capability Credit
at the time.
1.75 Interchange Transactions are transactions deemed to be
effected under Section 12 of the Prior NEPOOL Agreement prior to
the Second Effective Date, and transactions deemed to be effected
under Section 14 of this Agreement on and after the Second
Effective Date.
1.76 Internal Point-to-Point Service is the transmission service by
that name provided pursuant to Section 19 of the Tariff.
1.77 Interruption
Until the CMS/MSS Effective Date, Interruption is a reduction
in non-firm transmission service due to economic reasons
pursuant to Section 28.7 of the Tariff, other than a reduction
which results from a failure to dispatch a generating
resource, including a contract, used in a transaction
requiring Through or Out Service which is out of merit order.
On and after the CMS/MSS Effective Date, Interruption is a
reduction in non-firm transmission service due to economic
reasons pursuant to Section 28.7 of the Tariff, other than a
reduction which results from a failure to dispatch a
generating resource, including a Supply Offer or a Demand Bid
at an External Node, used in a transaction requiring Through
or Out Service which is out of merit order.
1.78 ISO is the Independent System Operator which is responsible
for the continued operation of the NEPOOL Control Area from the
NEPOOL control center and the administration of the Tariff, subject
to regulation by the Commission.
1.79 Kilowatt is a kilowatthour per hour.
1.80 Large End User is an End User Participant which is considered
for this purpose to be (a) a single end user with a peak monthly
demand (non-coincident) for load in New England, including load
served by End User Behind-the-Meter Generation, of at least one (1)
megawatt, or (b) a group of two or more corporate entities each
with a peak monthly demand (non-coincident) for load in New
England, including load served by End User Behind-the-Meter
Generation, of at least 0.35 megawatts that together totals at
least one (1) megawatt.
1.81 Liaison Committee is the committee whose responsibilities are
specified in Section 11C.
1.82 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
kilowatthours provided by such Participant to its retail
customers for consumption (excluding any kilowatthours which
may be classified as interruptible under Market Rules
approved by the Markets Committee), plus
kilowatthours delivered by such Participant pursuant to Firm
Contracts to its wholesale customers for resale, plus
kilowatthours of use by such Participant, exclusive of use by
such Participant for the operation and maintenance of its
generating unit or units, plus
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.
1.83 Load Asset Contract is a transaction for the transfer of
responsibility for Electrical Load (and may include Electrical Load
qualifying as Dispatchable Load), Installed Capability, or the
rights to compensation for Operating Reserve to the extent the
transfer relates to Dispatchable Load, the terms of which shall
conform to the requirements of applicable Market Rules.
1.84 Load Zone is a Reliability Region, except as otherwise
provided in Section 14A.12(b) of the Agreement and Schedule 13 of
the Tariff.
1.85 Local Network is the transmission facilities constituting a
local network identified on Attachment E to the Tariff, and any
other local network or change in the designation of a Local Network
as a Local Network which the 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.
1.86 Local Network Service is the service provided, under a
separate tariff or contract, by a Participant that is a
Transmission Provider to another Participant, or other entity
connected to the Transmission Provider's Local Network to permit
the other Participant or entity to efficiently and economically
utilize its resources to serve its load.
1.87 Location is a Node, External Node, Load Zone, or Hub.
1.88 Locational Price is the price of Energy at a Location or
Reliability Region, calculated in accordance with Section 14A.12 of
the Agreement and Schedule 13 of the Tariff. The Locational Price
for a Node is the Nodal Price at that Node; the Locational Price
for an External Node is the Nodal Price at that External Node; the
Locational Price for a Load Zone or Reliability Region is the Zonal
Price for that Load Zone or Reliability Region, respectively; and
the Locational Price for a Hub is the Hub Price for that Hub.
1.89 Lost Opportunity Cost is the amount determined for a Resource,
other than a Dispatchable Load, in accordance with Section
14A.13(d).
1.90 Lower Voltage PTF are all PTF facilities other than EHV PTF.
1.91 Marginal Loss is the additional Energy required to overcome
transmission losses or the decrease in Energy consumed through
losses on the NEPOOL Transmission System associated with serving a
small increment of demand at a Node or External Node. The cost of
Marginal Losses at each Location, relative to the cost of Marginal
Losses at the Reference Node, is reflected in the Marginal Loss
Component of the Locational Price at that Location.
1.92 Marginal Loss Component is the component of the Nodal Price at
a given Node or External Node that reflects the Marginal Loss at
that Node or External Node. When used in connection with Hub Price
or Zonal Price, the term Marginal Loss Component refers to the
Marginal Loss Components of the Nodal Prices that comprise the Hub
Price or Zonal Price, which Marginal Loss Components are averaged
or weighted in the same way that Nodal Prices are averaged or
weighted to determine the Hub Price and Zonal Price, respectively.
1.93 Marginal Loss Revenue for each hour is the surplus revenue, if
any, that is collected by the System Operator after netting
payments for Energy under Sections 14A.8 and 14A.9, and subtracting
Congestion Revenue, as settled in accordance with the Market Rules.
1.94 Marginal Loss Revenue Fund is the fund of Marginal Loss
Revenue administered by the System Operator in accordance with
Section 14A.16 of the Agreement, Schedule 13 of the Tariff, and the
applicable Market Rules.
1.95 Market Products are Installed Capability, Operable Capability,
Energy, each category of Operating Reserve and AGC.
1.96 Market Rules are the system rules and operating procedures
adopted pursuant to the System Operator Agreement in connection
with the administration of the NEPOOL Market.
1.97 Markets 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.
1.98 Megawatt is a measure of the rate at which Energy is produced
and is equal to a megawatthour per hour. Use of the term Megawatt
shall be construed to include fractional Megawatts.
1.99 Monthly Peak of a Participant for a month is the maximum
Adjusted Load of the Participant during any hour in the month.
1.100 MSS is the multi-settlement system provided for in
Section 14A.
1.101 NEPOOL is the New England Power Pool, the power pool
created under and governed by this Agreement, and the Entities
collectively participating in the New England Power Pool as
Participants.
1.102 NEPOOL Control Area is the integrated electric power
system to which a common Automatic Generation Control scheme and
various operating procedures are applied by or under the
supervision of the System Operator in order to:
(i) match, at all times, the power output of the
generators within the electric power system and capacity and
Energy purchased from entities outside the electric power
system, with the load within the electric power system;
(ii) maintain scheduled interchange with other
interconnected systems, within the limits of Accepted Electric
Industry Practice;
(iii) maintain the frequency of the electric power
system within reasonable limits in accordance with Accepted
Electric Industry Practice and the criteria of the NPCC and
NERC; and
(iv) provide sufficient generating capacity to
maintain operating reserves in accordance with Accepted
Electric Industry Practice.
1.103 NEPOOL Installed Capability at any particular time is the
sum of the Installed System Capabilities of all Participants at
such time.
1.104 NEPOOL Installed Capability Responsibility for any month
is the sum of the Installed Capability Responsibilities of all
Participants during that month.
1.105 NEPOOL Objective Capability for any year or period during
a year is the minimum NEPOOL Installed Capability, treating the
reliability benefits of the HQ Interconnection as Installed
Capability, as established by the 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).
1.106 NEPOOL Market is the market for electric energy, capacity
and certain ancillary services within the NEPOOL Control Area.
1.107 NEPOOL System Rules are the Market Rules, the NEPOOL
Information Policy, the Administrative Procedures, the Reliability
Standards and any other system rules, procedures or criteria for
the operation of the NEPOOL System and administration of the NEPOOL
Market, the NEPOOL Agreement and the NEPOOL Tariff.
1.108 NEPOOL Transmission System is the system of transmission
facilities defined as PTF.
1.109 NERC is the North American Electric Reliability Council.
1.110 Net Hourly Load Obligation for Energy ("NHLO") of a
Participant for an hour is an amount equal to (i) the Participant's
Electrical Load for the hour, (ii) plus or minus, as appropriate,
the Settlement Obligations for Energy which the Participant
transfers to or assumes from another Participant pursuant to a
Bilateral Transaction (other than a Load Asset Contract already
reflected in the determination of the Participant's Electrical
Load) in which the quantity of Settlement Obligation for Energy
transferred from the Participant purchaser to the Participant
seller thereunder is expressed in terms of a percentage (with or
without an optional cap on the total transfer) of the Participant
purchaser's Energy obligation, where the obligation is calculated
as the Electrical Load of the Participant purchaser less
megawatthours of Energy sales by the Participant purchaser to Non-
Participants. The Bilateral Transaction identified in (ii)
includes a transaction which is submitted in accordance with Market
Rule 4, Appendix 4-D, "Internal Obligation Transfer Contracts" and
is described in the second bullets of Market Rule 12, Appendix 12-
A-1, Sections B.IIa.4 and D.II.a4, as such Market Rules were in
effect on December 31, 1999.}
1.111 New Unit is an electric generating unit (including a unit
or units owned by a Non-Participant in which a Participant has an
Entitlement under a Unit Contract) first placed into commercial
operation after May 1, 1987 (or, in the case of a unit or units
owned by a Non-Participant, in which a Participant's Unit Contract
Entitlement became effective after May 1, 1987) and not listed on
Exhibit B to the Prior NEPOOL Agreement.
1.112 No-Load Price is the price, in dollars per hour, for a
generating unit that must be paid to Participants with Energy
Entitlements in the unit for being scheduled in the Day-Ahead
Market, in addition to the Start-Up Price and Supply Offer Price
for Energy, for each hour that the generating unit is scheduled in
the Day-Ahead Market.
1.113 Nodal Price in each hour of the Dispatch Day in the Day-
Ahead Market and Real-Time Market is the price for Energy received
or furnished at a Node or External Node in the hour, as calculated
in accordance with Section 14A.12 of the Agreement and Schedule 13
of the Tariff.
1.114 Node is a point on the NEPOOL Transmission System where
Energy is received or furnished, and for which Nodal Prices are
calculated.
1.115 Non-Participant is any entity which is not a Participant.
1.116 NPCC is the Northeast Power Coordinating Council.
1.117 OASIS is the Open Access Same-Time Information System of
the System Operator.
1.118 Operable Capability of an electric generating unit or
units in any hour is the portion of the Installed Capability of the
unit or units which is operating or available to respond within an
appropriate period (as identified in Market 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 Rules approved
by the Markets Committee.
1.119 Operating Reserve is any or a combination of 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve, and 30-Minute
Operating Reserve, as the context requires.
1.20 Operating Reserve Entitlement is the right to all or a portion
of the Operating Reserve of any category which can be provided by a
Resource to which an Entity is entitled as an owner (either sole or
in common), as a supplier of Dispatchable Load, or as a purchaser
pursuant to a Unit Contract, reduced by any portion thereof which
such Entity is selling pursuant to a Unit Contract. 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[, 4-Hour
Reserve Entitlement] or AGC Entitlement.
1.121 Other HQ Energy is Energy purchased under the HQ Phase I
Energy Contract which is classified as "Other Energy" under that
contract.
1.222 Participant is an eligible Entity (or group of Entities
which has elected to be treated as a single Participant pursuant to
Section 4.1) which is a signatory to this Agreement and has become
a Participant in accordance with Section 3.1 until such time as
such Entity's status as a Participant terminates pursuant to
Section 21.2.
1.123 Participants 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.
1.124 Pool-Planned Facility is a generation or transmission
facility designated as "pool-planned" pursuant to Section 18.1.
1.125 Pool-Planned Unit is one of the following units: New
Haven Harbor Unit 1 (Coke Works), Mystic Unit 7, Canal Unit 2,
Potter Unit 2, Wyman Unit 4, Stony Brook Units 1, 1A, 1B, 1C, 2A
and 2B, Millstone Unit 3, Seabrook Unit 1 and Waters River Unit 2
(to the extent of 7 megawatts of its Summer Capability and 12
megawatts of its Winter Capability).
1.126 Power Year is (i) the period of twelve (12) months
commencing on November 1, in each year to and including 1997; (ii)
the period of seven (7) months commencing on November 1, 1998; and
(iii) the period of twelve (12) months commencing on June 1, 1999
and each June 1 thereafter.
1.127 Prior NEPOOL Agreement is the NEPOOL Agreement as in
effect on December 1, 1996.
1.128 Proxy Unit is a hypothetical electric generating unit
which possesses a Winter Capability, equivalent forced outage rate,
annual maintenance outage requirement, and seasonal derating
determined in accordance with Section 12.2(a)(2).
1.129 PTF 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.
1.130 Publicly 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.
1.131 Real-Time is a current period of a Dispatch Day for which
the System Operator dispatches Resources for Energy and AGC,
designates Resources for AGC and Operating Reserve and, if
necessary, activates 4-Hour Reserves.
1.132 Real-Time Market is the market provided for in Section
14A in which obligations and prices with respect to Energy,
Operating Reserve, 4-Hour Reserve and AGC are determined from the
actual dispatch and designations by the System Operator during a
Dispatch Day, based on applicable Demand Bids and Supply Offers and
NEPOOL System Rules.
1.133 Reference Node is the Node identified by the System
Operator in accordance with the NEPOOL System Rules relative to
which all mathematical quantities pertaining to physical operation,
including Shift Factors and Withdrawal Factors, shall be calculated
with respect to the dispatch of the system and the derivation of
Locational Prices.
1.134 Regional Network Service is the transmission service by
that name provided pursuant to Section 14 of the Tariff.
1.135 Related Person of a Participant is:
for all Participants, either (i) a corporation, partnership,
business trust or other business organization 10% or more of
the stock or equity interest in which is owned directly or
indirectly by, or is under common control with, the
Participant, or (ii) a corporation, partnership, business
trust or other business organization which owns directly or
indirectly 10% or more of the stock or other equity interest
in the Participant, or (iii) a corporation, partnership,
business trust or other business organization 10% or more of
the stock or other equity interest in which is owned directly
or indirectly by a corporation, partnership, business trust or
other business organization which also owns 10% or more of the
stock or other equity interest in the Participant, or (iv) a
natural person, or a member of such natural person's immediate
family, who is, or within the last 12 months has been, an
officer, director, partner, employee, or representative in
NEPOOL activities of, or natural person having a material
ongoing business or professional relationship directly related
to NEPOOL activities with, the Participant or any corporation,
partnership, business trust or other business organization
related to the Participant pursuant to clauses (i), (ii) or
(iii) of this Section 1.135(a); and
for all End User Participants which are also natural persons,
a Related Person is (i) a member of such End User's immediate
family, or (ii) a Participant and any corporation,
partnership, business trust, or other business organization
related to the Participant pursuant to clauses (i), (ii) or
(iii) of Section 1.135(a), of which such End User Participant,
or a member of such End User Participant's immediate family,
is, or within the last twelve (12) months has been, an
officer, director, partner, or employee of, or with which an
individual End User Participant has, or within the last twelve
(12) months had, a material ongoing business or professional
relationship directly related to NEPOOL activities, or (iii)
another Participant which, within the last twelve (12) months,
has paid a portion of the End User Participant's expenses
under Section 19 of this Agreement, or (iv) a corporation,
partnership, business trust or other business organization in
which the End User Participant owns stock and/or equity with a
fair market value in excess of $50,000.
Notwithstanding the foregoing, for the purposes of this
definition, an individual shall not be deemed to have or had a
material on-going business relationship directly related to
NEPOOL activities with any corporation, partnership, business
trust, other business organization or Publicly Owned Entity
solely as a result of being served, as a customer, with
electricity or gas.
1.136 Reliability 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.
1.137 Reliability 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.
1.138 Reliability Must Run is a Resource or portion of a
Resource that is scheduled in the Day-Ahead Market by the System
Operator out of merit in order to create sufficient local Operating
Reserve to preserve reliability within a Reliability Region.
1.139 Reliability Region is, as of March 31, 2000, any one of
the regions identified in Attachment C to the Agreement.
Subsequent to March 31, 2000, the System Operator, in a filing with
the Commission and following consultation with the Reliability
Committee, may reconfigure Reliability Regions and add or subtract
Reliability Regions as necessary over time to reflect changes to
the grid or changes in patterns of usage and intra-zonal
Congestion. Reliability Regions reflect the operating
characteristics of, and the major transmission constraints on, the
NEPOOL Transmission System.
1.140 {Reserve Contract is a contract entered into pursuant to
Section 14A.10(c) between the System Operator and a Participant
under which the Participant agrees to furnish 10-Minute Non-
Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour
Reserve.}
1.141 {Reserve Price is the price a Participant agrees to
accept in a Reserve Contract for furnishing 10-Minute Non-Spinning
Reserve, 30-Minute Operating Reserve and/or 4-Hour Reserve.}
1.142 Resource means a generating unit, a Dispatchable Load, or
a Supply Offer to supply service from another Control Area at an
External Node.
1.143 Review Board is the board whose responsibilities are
specified in Section 11A.
1.144 RMR is Reliability Must Run.
1.145 RMR Charge is the charge to Participants pursuant to
Section 14A.19(d) to recover RMR Uplift.
1.146 RMR Uplift is the uplift for RMR determined in accordance
with Section 14A.19(d).
1.147 Scheduled Dispatch Period is the shortest period for
which the System Operator performs and publishes a projected
dispatch schedule based on projected Electrical Load and actual Bid
Prices and Participant-directed schedules for Resources submitted
in accordance with Section 14.2(d) until the CMS/MSS Effective
Date, and based on projected Electrical Load, Demand Bids, Supply
Offers, and Self-Schedules and Self-Supplies submitted in
accordance with applicable Market Rules for periods on and after
the CMS/MSS Effective Date.
1.148 Second Effective Date is May 1, 1999.
1.149 Sector has the meaning specified in Section 6.2.
1.150 Self-Schedule is the action of a Participant in
scheduling its Resource, in accordance with applicable Market
Rules, to provide service in an hour, whether or not in the
absence of that action the Resource would have been scheduled
or dispatched to provide the service by the System Operator.
1.151 Self-Supply is the action of a Participant in designating
its Resource in accordance with applicable Market Rules to
meet its own service requirements in whole or in part.
1.152 Service Agreement is the initial agreement and any
amendments or supplements thereto entered into by the Transmission
Customer and the System Operator for service under the Tariff.
1.153 Settlement Obligation, prior to the CMS/MSS Effective
Date, is an obligation as defined in Section 14.1(a) for Energy,
Section 14.1(b) for Operating Reserve and Section 14.1(c) for AGC,
and all applicable Market Rules and, on and after the CMS/MSS
Effective Date, is an obligation as defined in Section 14A.1(b) for
Energy, Section 14A.1(c) for Operating Reserve, Section 14A.1(d)
for 4-Hour Reserve and Section 14A.1(e) for AGC, and all applicable
Market Rules.
1.154 Shift Factor is the factor which relates to the change in
power flow over the PTF that results from an increment of
generation at a given Node or External Node and a corresponding
increment of load at the Reference Node, relative to the size of
the increment of generation. Shift Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the
Agreement and Schedule 13 of the Tariff.
1.155 Small End User is a End User Participant which does not
otherwise meet the definition of Large End User or End User
Organization.
1.156 Standard Offer Obligation has the meaning specified in
Section 14A.12(b)(ii) of the Agreement and Schedule 13 of the
Tariff.
1.157 Start-Up Price is the price, in dollars, that must be
paid for a generating unit to Participants with Energy Entitlements
in the unit each time the unit is scheduled in the Day-Ahead Market
to start up.
1.158 Summer Capability of an electric generating unit or
combination of units is the maximum dependable load carrying
ability in Kilowatts of such unit or units (exclusive of capacity
required for station use) during the Summer Period, as determined
by the Markets Committee in accordance with Section 10.4(d).
1.159 Summer Period in each Power Year is the four-month period
from June through September.
1.160 Supply Obligation is an obligation as defined in Section
14A.1(a) for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC.
1.161 Supply Offer is a proposal to furnish Energy at a Node or
External Node, Operating Reserve, 4-Hour Reserve and/or AGC from a
Resource that meets the applicable requirements set forth in the
Market Rules that a Participant with Supply Offer authority for the
Resource submits to the System Operator pursuant to the Agreement
and applicable Market Rules, and includes a Supply Offer Price and
information with respect to the quantity proposed to be furnished,
technical parameters for the Resource, timing and other matters.
1.162 Supply Offer Price is the price specified to the System
Operator in a Supply Offer to provide Energy, Operating Reserve,
AGC and/or 4-Hour Reserve from a Resource pursuant to this
Agreement and applicable Market Rules.
1.163 System Contract is any contract for the purchase of
Installed Capability, Energy [at a Location], Operating Reserves[,
4-Hour Reserves] and/or AGC, other than a Unit Contract, pursuant
to which the purchaser is entitled to a specifically determined or
determinable amount of such Installed Capability, Energy, Operating
Reserves[, 4-Hour Reserves] and/or AGC.
1.164 System Impact Study is an assessment pursuant to Part V,
VI or VII of the Tariff of (i) the adequacy of the NEPOOL
Transmission System to accommodate a request for the
interconnection of a new or materially changed generating unit or a
new or materially changed interconnection to another Control Area
or new Regional Network Service, Internal Point-to-Point Service or
Through or Out Service, and (ii) whether any additional costs may
be required to be incurred in order to provide the interconnection
or transmission service.
1.165 System Operator is the central dispatching agency
provided for in this Agreement which has responsibility for the
operation of the NEPOOL Control Area from the NEPOOL control center
and the administration of the Tariff. The System Operator is 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.
1.166 Target 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.
1.167 Tariff is the NEPOOL Open Access Transmission Tariff set
out in Attachment B to the Agreement, as modified and amended from
time to time.
1.168 Tariff 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.
1.169 Technical Committees are the Reliability Committee, the
Tariff Committee and the Markets Committee.
1.170 Third Effective Date is the date on which all Interchange
Transactions shall begin to be effected on the basis of separate
Bid Prices for each type of Entitlement. The Third Effective Date
shall be fixed at the discretion of the 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.
1.171 Through or Out Service is the transmission service by
that name provided pursuant to Section 18 of the Tariff.
1.172 Transition Period is the six-year period commencing on
March 1, 1997.
1.173 Transmission Customer is any Eligible Customer that (i)
is a Participant which is not required to sign a Service Agreement
with respect to a service to be furnished to it in accordance with
Section 48 of the Tariff or (ii) executes, on its own behalf or
through its Designated Agent, a Service Agreement, or (iii)
requests in writing, on its own behalf or through its Designated
Agent, that NEPOOL file with the Commission a proposed unexecuted
Service Agreement in order that the Eligible Customer may receive
transmission service under the Tariff.
1.174 Transmission 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 (i) own, or
lease 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, and (ii) provide
transmission service to non-affiliated customers pursuant to an
open access transmission tariff on file with the Commission.
1.175 Transmission Owners Committee is the committee whose
responsibilities are specified in Section 11B.
1.176 Transmission 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.
1.177 Unit Contract is a purchase contract pursuant to which
the purchaser is in effect currently entitled, [at a specified
Location], either (i) to a specifically determined or determinable
portion of the capability of a specific electric generating unit or
units, or (ii) to a specifically determined or determinable amount
of Installed Capability, Energy, Operating Reserves[, 4-Hour
Reserves] and/or AGC if, or to the extent that, a specific electric
generating unit or units is or can be operated.
1.178 Withdrawal Factor is the factor which measures the
proportion of a small increment of power injected at a given Node
that can be withdrawn at the Reference Node (with any difference
between the amounts injected and withdrawn attributable to Marginal
Losses). Withdrawal Factors are used to calculate Locational
Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.179 Winter Capability of an electric generating unit or
combination of units is the maximum dependable load carrying
ability in Kilowatts of such unit or units (exclusive of capacity
required for station use) during the Winter Period, as determined
by the Markets Committee in accordance with Section 10.4(d).
1.180 Winter Period in each Power Year is (i) the seven-month
period from November through May and the month of October for the
Power Year commencing on November 1 in 1997 or a prior Power Year;
(ii) the seven-month period from November through May for the Power
Year commencing on November 1, 1998; and (iii) the eight-month
period from October through May for the Power Year commencing on
June 1, 1999 and each June 1 thereafter.
1.181 Zonal Price in each hour of the Dispatch Day in the Day-
Ahead Market and the Real-Time Market is the price for Energy
received in a Load Zone or Reliability Region in the hour, as
calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.182 4-Hour Reserve is an option for Energy, which can be
called upon by the System Operator in one or more hours of the
Dispatch Day for at least the minimum period defined in the NEPOOL
System Rules and for the number of hours offered and at Energy
prices at least equal to the prices set forth in a Day-Ahead Supply
Offer (unless such prices are reduced in a Real-Time Supply Offer)
and to or from which Energy can be adjusted within four hours in
response to dispatch instructions and in accordance with applicable
NEPOOL System Rules, from one of the following Resources to the
extent the Resource providing 4-Hour Reserve has not been scheduled
to provide Energy, Operating Reserve or AGC in the Day-Ahead
Market: (i) a generating unit capable of providing Energy; (ii) a
load capable of reducing its consumption of Energy within four
hours, including Demand Bids at External Nodes; and (iii) to the
extent permitted by applicable NEPOOL System Rules, a Supply Offer
to supply Energy from another Control Area at an External Node.
1.183 4-Hour Reserve Entitlement is the right for the purpose
of satisfying a Supply Obligation for Energy from all or a portion
of the 4-Hour Reserve which can be provided by a Resource to which
an Entity is entitled as an owner (either sole or in common), as a
supplier of load or as a purchaser pursuant to a Unit Contract,
reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract. A 4-Hour Reserve 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, Operating Reserve
Entitlement or AGC Entitlement.
1.184 10-Minute Spinning Reserve
Until the CMS/MSS Effective Date, in an hour is the
contingency protection benefit for the system available from
the combination of the following Resources that are designated
by the System Operator in accordance with the Market Rules to
be available: (i) the Megawatts available from an electric
generating unit or units that are synchronized to the system
(including units outside the NEPOOL Control Area to the extent
permitted by applicable Market Rules), 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 the Market Rules is
necessary; and (ii) any Dispatchable 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 the Market
Rules is necessary.
On and after the CMS/MSS Effective Date, in an hour is an
option for Energy, which can be called upon by the System
Operator in such hour at Energy prices at least equal to the
prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of
the following Resources to the extent the Resource in the Day-
Ahead Market has not been scheduled or in the Real-Time Market
has not been dispatched for Energy and to or from which Energy
can be adjusted within ten (10) minutes in response to
dispatch instructions and sustaining such adjusted level of
Energy for so long as the System Operator determines in
accordance with the Market Rules is necessary: (i) a
generating unit that is synchronized to the system; or (ii) a
Dispatchable Load; and (iii) to the extent permitted by
applicable Market Rules, a Supply Offer to supply Energy from
another Control Area at an External Node.
1.185 10-Minute Non-Spinning Reserve
Until the CMS/MSS Effective Date, in an hour is the
contingency protection benefit for the system available from
the combination of the following Resources that are designated
by the System Operator in accordance with the Market Rules to
be available: (i) the Megawatts available from an electric
generating unit or units that are not synchronized to the
system (including units outside the NEPOOL Control Area to the
extent permitted by applicable Market Rules), during all or
part of the hour, and capable of providing contingency
protection by loading to supply Energy within ten minutes to
the full amount of generating capacity so designated, and
sustaining such Energy output for so long as the System
Operator determines in accordance with the Market Rules is
necessary; (ii) any Dispatchable Load of a Participant 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 the Market Rules is necessary; and (3) any other
Resources 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.
On and after the CMS/MSS Effective Date, in an hour is an
option for Energy, which can be called upon by the System
Operator in such hour at Energy prices at least equal to the
prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of
the following Resources to the extent the Resource in the Day-
Ahead Market has not been scheduled or in the Real-Time Market
has not been dispatched for Energy or for AGC or 10-Minute
Spinning Reserve, and to or from which Energy can be adjusted
within ten (10) minutes in response to dispatch instructions
and which is capable of sustaining such adjusted level of
Energy for so long as the System Operator determines in
accordance with Market Rules is necessary: (i) a generating
unit capable of providing such Energy; (ii) a Dispatchable
Load; and (iii) to the extent permitted by applicable Market
Rules, a Supply Offer to supply Energy from another Control
Area at an External Node.
1.186 30-Minute Operating Reserve
Until the CMS/MSS Effective Date, in an hour is the
contingency protection benefit for the system available from
the combination of the following Resources that are designated
by the System Operator in accordance with the Market Rules to
be available: (i) the Megawatts available from an electric
generating unit or units (including units outside the NEPOOL
Control Area to the extent permitted by applicable Market
Rules) that are capable of providing contingency protection by
loading to supply Energy within thirty minutes of demand at an
output equal to its full amount of generating capacity so
designated and sustaining Energy output for so long as the
System Operator determines in accordance with the Market Rules
is necessary; (ii) any Dispatchable 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 the Market Rules is necessary; and (3) any
other Resources 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.
On and after the CMS/MSS Effective Date, in an hour is an
option for Energy, which can be called upon by the System
Operator in such hour at Energy prices at least equal to the
prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer) from one of
the following Resources to the extent the Resource in the Day-
Ahead Market has not been scheduled or in the Real-Time Market
has not been dispatched for Energy or designated for AGC, 10-
Minute Spinning Reserve, or 10-Minute Non-Spinning Reserve,
and to or from which Energy can be adjusted in response to
dispatch instructions within thirty (30) minutes and which are
capable of sustaining such adjusted level of Energy for so
long as the System Operator determines in accordance with the
Market Rules is necessary: (i) a generating unit capable of
providing such Energy; (ii) a Dispatchable Load; and (iii) to
the extent provided in applicable Market Rules, a Supply Offer
to supply Energy from another Control Area at an External
Node.
1.187 Modification 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:
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):
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
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.
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):
the Installed Capability Responsibility of the
purchasing Participant shall be equal to the amount of
its Installed Capability Entitlements;
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
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 wherein:
X is the maximum Load of the purchasing
Participant in the month, and
Y is the NEPOOL Installed Capability
Responsibility multiplied by the purchasing
Participant's fraction P determined pursuant to
Section 12.2(a)(1), computed as if the Firm
Contract did not exist.
Terms used in this Agreement that are not defined above, or in
the sections in which such terms are used, shall have the
meanings customarily attributed to such terms in the electric
power industry in New England.
[Next Sheet is 58]
SECTION 2
PURPOSE; EFFECTIVE DATES
2.1 Purpose. This Restated NEPOOL Agreement is intended to
provide for a restructuring of the New England Power Pool by
modifying the pool's governance and market provisions to take
account of a changed competitive environment, by modifying the
transmission responsibilities of the Participants so that the pool
will perform the functions of a regional transmission group and
provide service to Participants and Non-Participants under a
regional open access transmission tariff, and by providing for the
activation of the ISO and the execution of a contract between the
ISO and NEPOOL to define the ISO's responsibilities.
2.2 Effective Dates; Transitional Provisions. The provisions of
Parts One, Two, Four and Five of this Agreement and the Tariff
became effective on the First Effective Date and replaced on the
First Effective Date the provisions of Sections 1-8, inclusive, 10,
11, 13, 14.2, 14.3, 14.4 and 16 of the Prior NEPOOL Agreement. The
provisions of Sections 12.1(a), 12.2, 12.4 (as to Installed
Capability only), 12.5 and 12.7(a) of this Agreement became
effective on April 1, 1998 and replaced on such date the provisions
of Section 9 of the Prior NEPOOL Agreement.
The effectiveness of the remaining Sections of this Restated
NEPOOL Agreement shall be delayed pending the preparation of
implementing criteria, rules and standards and computer
programs. These Sections 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.
[Next Sheet is 60]
SECTION 3
MEMBERSHIP
3.1 Membership. Those Entities which are Participants in NEPOOL
on the First Effective Date shall continue to be Participants.
Any other Entity may, upon compliance with such reasonable
conditions as the 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.
3.2 Operations Outside the Control Area. Subject to the
reciprocity requirements of the Tariff, if a Participant serves a
Load, or has rights in supply or demand-side resources or owns
transmission and/or distribution facilities, located outside of the
NEPOOL Control Area, such Load and resources shall not be included
for purposes of determining the Participant's rights,
responsibilities and obligations under this Agreement, except that
the Participant's Entitlements in facilities or its rights in
demand side-resources outside the NEPOOL Control Area shall be
included in such determinations if, to the extent, and while such
Entitlements are used for retail or wholesale sales within the
NEPOOL Control Area or such Entitlements or rights are designated
by a Participant for purposes of meeting its obligations under
Section 12 of this Agreement.
3.3 Lack of Place of Business in New England. If and for so long
as a Participant does not have a place of business located in one
of the New England states, the Participant shall be deemed to
irrevocably (1) submit to the jurisdiction of any Connecticut state
court or United States Federal court sitting in Connecticut (the
state whose laws govern this Agreement) over any action or
proceeding arising out of or relating to this Agreement that is not
subject to the exclusive jurisdiction of the Commission, (2) agree
that all claims with respect to such action or proceeding may be
heard and determined in such Connecticut state court or Federal
court, (3) waive any objection to venue or any action or proceeding
in Connecticut on the basis of forum non conveniens, and (4) agree
that service of process may be made on the Participant outside
Connecticut by certified mail, postage prepaid, mailed to the
Participant at the address of its member on the Participants
Committee as set out in the NEPOOL roster or at the address of its
principal place of business.
3.4 Obligation for Deferred Expenses. NEPOOL may provide for the
deferral on the books of the Participants from time to time of
capital or other expenditures, and the recovery of the deferred
expenses in subsequent periods. Any Entity which becomes a
Participant during the recovery period for any such deferred
expenses shall be obligated, together with the continuing
Participants, for its share of the current and deferred expenses
pursuant to Section 19.2.
3.5 Financial Security. For an Entity applying to become a
Participant or any continuing Participant that the 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.
[Next Sheet is 64]
SECTION 4
STATUS OF PARTICIPANTS
4.1 Treatment of Certain Entities as Single Participant. All
Entities which are controlled by a single person (such as a
corporation or a business trust) which owns at least seventy-five
percent of the voting shares of, or equity interest in, each of
them shall be collectively treated as a single Participant for
purposes of this Agreement, if they each elect such treatment.
They are encouraged to do so. Such an election shall be made in
writing and shall continue in effect until revoked in writing.
In view of the long-standing arrangements in Vermont, Vermont
Electric Power Company, Inc. and any other Vermont electric
utilities which elect in writing to be grouped with it shall
be collectively treated as a single Participant for purposes
of this Agreement; 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.
4.2 Participants to Retain Separate Identities. The signatories
to this Agreement shall not become partners by reason of this
Agreement or their activities hereunder, but as to each other and
to third persons, they shall be and remain independent contractors
in all matters relating to this Agreement. This Agreement shall
not be construed to create any liability on the part of any
signatory to anyone not a party to this Agreement. Each signatory
shall retain its separate identity and, to the extent not limited
hereby, its individual freedom in rendering service to its
customers.
[Next Sheet is 66]
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
5.1 NEPOOL Objectives. The objectives of NEPOOL are, through
joint planning, central dispatching, cooperation in environmental
matters and coordinated construction, central dispatch by the
operation and coordinated maintenance of electric supply and
demand-side resources and transmission facilities, the provision of
an open access regional transmission tariff and the provision of a
means for effective coordination with other power pools and
utilities situated in the United States and Canada,
(a) to assure that the bulk power supply of the NEPOOL
Control Area conforms to proper standards of reliability;
(b) to create and maintain open, non-discriminatory,
competitive, unbundled markets for Energy, capacity, and
ancillary services that function efficiently in a changing
electric power industry and have access to regional
transmission at rates that do not vary with distance;
(c) to attain maximum practicable economy, consistent with
proper standards of reliability and the maintenance of
competitive markets, in such bulk power supply; and
(d) to provide access to competitive markets within the
NEPOOL Control Area and to neighboring regions;
and to provide for equitable sharing of the resulting
responsibilities, benefits and costs.
5.2 Cooperation by Participants. In order to attain the
objectives of NEPOOL set forth in Section 5.1, each Participant
shall observe the provisions of this Agreement in good faith, shall
cooperate with all other Participants and shall not either alone or
in conjunction with one or more other Entities take advantage of
the provisions of this Agreement so as to harm another Participant
or to prejudice the position of any Participant in the electric
power business.
PART TWO
GOVERNANCE
SECTION 6
COMMITTEE ORGANIZATION AND VOTING
6.1 Principal Committees. There shall be four principal NEPOOL
Committees (the "Principal Committees"), as follows:
(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.
6.2 Sector 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; provided,
however, that a Participant and the Participants which are its
Related Persons shall not be eligible to join the End User Sector
if any one of them is not eligible to join the End User Sector. 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 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.
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.
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.
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.
an End User Sector, which an End User Participant is eligible
to join provided all of its Related Persons which are
Participants are also eligible to join the End User Sector.
Participants which join the End User Sector shall be entitled
to designate an individual voting member of each Principal
Committee and an alternate to the member; provided, however,
that a voting member, and the alternate to the member,
designated by a Small End User shall not be a Related Person
of another Participant in a Sector other than the End User
Sector.
Until the total number of End User Participants electing
to join the End User Sector and eligible to designate an
individual voting member ("End User Votes") is at least
ten (10), all End User Participants electing to join the
End User Sector shall be members of the Publicly Owned
Entity Sector. So long as the total number of End User
Votes is less than three (3), the End User Participants
in the Publicly Owned Entity Sector shall be represented
on each Principal Committee by a single voting member.
During such time as there are at least three (3), but
less than ten (10), End User Votes, End User Participants
electing to join the End User Sector 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 individual voting
member of such sub-sector 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 (10) End User Votes.
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.
6.3 Appointment 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, 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.
6.4 Term 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.
6.5 Regular 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.
6.6 Notice 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.
6.7 Attendance. 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.
6.8 Quorum. 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, the voting members then present
shall have the power to adjourn the meeting from time to time until
a Quorum shall be present.
6.9 Voting 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:
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%).
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.
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.
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".
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.
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:
(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.
6.10 Voting 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.
6.11 Voting On Amendments. Subject to Section 21.11 and Section
17A, amendments to the NEPOOL Agreement or Tariff shall be
accomplished as follows:
Amendments shall be drafted by a standing or ad hoc NEPOOL
committee or a Participant and sent to the Participants
Committee for its consideration.
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.
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 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.
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.
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.
6.12 Designated 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; provided,
however, that the vote of a member or alternate to that member
representing a Small End User may not be cast by a Participant or a
Related Person of a Participant in a Sector other than the End User
Sector. 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.
6.13 Limits 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. In the
End User Sector, no one person may vote on behalf of more than five
(5) Small End Users. Except as otherwise provided herein, 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.
6.14 Adoption 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.
6.15 Joint 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.
[Next Sheet is 90]
SECTION 7
PARTICIPANTS COMMITTEE
7.1 Officers. 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.
7.2 Adoption 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.
7.3 Establishing 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.
7.4 Appointment 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.
7.5 Duties 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 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.
(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.
(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.
7.6 Attendance 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.
7.7 Appeal 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.
[Next Sheet is 100]
SECTION 8
RELIABILITY COMMITTEE
8.1 Officers. 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.
8.2 Notice 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.
8.3 Voting; 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.
8.4 Responsibilities. 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 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.
(a) 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;
(b) 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.);
(c) 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.);
(d) 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;
(e) 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; and
(f) 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.
8.5 Establishment of Subcommittees and Task Forces. The
Reliability Committee shall have the authority to establish
subcommittees and task forces for particular studies.
8.6 Further 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.
[Next Sheet is 108]
SECTION 9
TARIFF COMMITTEE
9.1 Officers. 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.
9.2 Notice 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.
9.3 Voting; 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.
9.4 Responsibilities. 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:
(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; and
(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.
9.5 Establishment of Subcommittees and Task Forces. The Tariff
Committee shall have the authority to establish subcommittees and
task forces for particular studies.
9.6 Further 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.
[Next Sheet is 112]
SECTION 10
MARKETS COMMITTEE
10.1 Officers. 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.
10.2 Notice 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.
10.3 Voting; 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.
10.4 Responsibilities. 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;
(iv) calculation and equitable apportionment of losses
incurred in connection with Interchange Transactions; and
(v) interpool market contract coordination as
appropriate.
(a) develop operating procedures relating to the
administration of the NEPOOL Markets and periodically review
and recommend changes thereto as appropriate; and
(b) 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.
10.5 Establishment of Subcommittees and Task Forces. The Markets
Committee shall have the authority to establish subcommittees and
task forces for particular studies.
10.6 Further 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.
10.7 Development 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.
[Next Sheet is 118]
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.1 Organization. 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 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.2 Composition. 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.3 Qualifications. 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.4 Term. 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.5 Meetings. 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.6 Bylaws. 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, 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.7 Procedure 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.
(a) Hearing: A hearing (if any) will be held as soon as is
reasonably practicable.
(b) 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.
11A.8 Effect 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.9 An 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.
[Next Sheet is 128]
SECTION 11B
TRANSMISSION OWNERS COMMITTEE
11B.1 Organization. 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.
11B.2 Membership. 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.3 Appointment 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.4 Term 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.5 Regular 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.6 Notice 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 to the date of the meeting.
11B.7 Attendance. 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.8 Votes. 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.
11B.9 Appointment 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.10 Officers. 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.11 Adoption of Bylaws. The Transmission Owners Committee
may adopt bylaws, consistent with this Agreement, governing
procedural matters including the conduct of its meetings.
11B.12 Review 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.1 Organization; 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.2 Membership. 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.3 Regular 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.
11C.4 Notice 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.5 Attendance. 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.6 Officers. 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.
[Next Sheet is 135]
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY
OBLIGATIONS AND PAYMENTS
12.0 Continuing Reliability Measures.
(a) Commencing in 2000 the System Operator shall perform, and
furnish to Participants, an annual, independent "Regional
Resource Adequacy Assessment" to determine whether adequate
generation and transmission resources are in place or under
development to assure that regional and subregional
reliability standards established for NEPOOL can be met.
(b) During 2000, the Participants Committee shall commence
development of alternative, market-based reliability assurance
mechanisms. A status report on this development effort shall
be submitted to the Commission and furnished to Participants
on or before January 1, 2001.
(c) Certain provisions of the Agreement that impose
obligations on Participants, including Participants with
generation and transmission resources, were contained within
the Agreement at a time when wholesale power and transmission
services were subject to very different regulatory rules and
an Operable Capability market and Installed Capability auction
market were included within the Agreement. During 2000,
concurrent with the review pursuant to Section 12.0(b) and in
recognition of the implementation of CMS and MSS, the
Participants Committee shall also identify those of such
obligations, if any, that should be eliminated, modified, or
replaced.
12.1 Obligations to Provide Installed Capability. 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.
12.2 Computation 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)+Np)(1+T) - C(Dp)
As used in this Section 12.2(a)(1), the symbols used
in the formula and the additional symbols defined
below have the following meanings:
X is the Participant's tentative Installed
Capability Responsibility for the month.
P is the value of the Participant's fraction for
the month as determined in accordance with the
following formula:
P = (Fp + Dp) / (F + D), wherein:
Fp is 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 prior to
January 1, 1999, but which does not
constitute a Firm Contract as defined in
this Agreement.
Dp is the Participant's actual or potential
load reduction resulting from its NEPOOL
Interruptible and Dispatchable Loads for
the month.
F is 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.
D is the aggregate for the month of the
actual or potential load reduction
resulting from all Participants' NEPOOL
Interruptible and Dispatchable Loads.
C is 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 7.5(e).
A is the NEPOOL Objective Capability in megawatts
for the month as fixed by the Participants
Committee pursuant to Section 7.
N is 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).
Np is 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).
T is the Participant's Unit Availability
Adjustment Factor for the month. T may be
positive or negative and shall be determined in
accordance with the following formula:
T = (I-H) x J x R, wherein:
100
I for the Participant for the month is the
percentage which represents the weighted
average (using the Installed Capability of each
Installed Capability Entitlement for such month
for the weighting) of the Four Year Installed
Capability Target Availability Rates of the
Installed Capability Entitlements which are
included in the Participant's Installed System
Capability during the hour of the coincident
peak load of the Participants for the month.
The Four Year Target Availability Rate for an
Installed Capability Entitlement for any month
is the average of the monthly Target
Availability Rates for the forty-eight months
which comprise the period of four consecutive
calendar years ending within the Power Year
which includes such month, as determined on the
basis of the Target Availability Rates for each
of the forty-eight months, and as applied on a
basis which is consistent with the fuel or
maturity status of the unit for each of the
forty-eight months; 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.
H for the Participant for the month is the
percentage which represents the weighted
average (using the Installed Capability of each
Installed Capability Entitlement for such month
for the weighting) of the Four Year Actual
Availability Rates of the Installed Capability
Entitlements which are included in the
Participant's Installed System Capability
during the hour of the coincident peak load of
the Participants for the month. The Four Year
Actual Availability Rate for an Installed
Capability Entitlement for any month is the
percentage which represents the average of the
amounts determined for 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, 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.
H1 for an Installed Capability Entitlement in a
unit or combination of units for a Twelve-Month
Measurement Period is its Actual Availability
Rate. The Actual Availability Rate of an
Installed Capability Entitlement for a Twelve-
Month Measurement Period is a percentage and
shall be the greater of:
(i) the percentage of (a) the amount of generation which
could have been received with respect to the
Installed Capability Entitlement if the unit or
combination of units had been fully available at its
full Installed Capability throughout the Twelve-
Month Measurement Period, which is represented by
(b) the amount of generation which was actually
available during such period, or
(ii) the average Target Availability Rate expressed as a
percentage for the Installed Capability Entitlement for
the Twelve-Month Measurement Period less twenty
percentage points. The average Target Availability Rate
of an Installed Capability Entitlement for a Twelve-Month
Measurement Period is a percentage and is the average of
the monthly Target Availability Rates for the months
which comprise the Twelve-Month Measurement Period, as
determined on the basis of the Target Availability Rates
for each of the twelve months, and as applied on a basis
which is consistent with the fuel or maturity status of
the unit or combination of units for each month in the
Twelve-Month Measurement Period. The Target Availability
Rates shall be those utilized by the Participants
Committee in its most recent determination of NEPOOL
Objective Capability pursuant to Section 7.
J for the month is the estimated percentage point
change in NEPOOL Objective Capability which
would be required as a result of a one
percentage point change in the weighted average
equivalent availability rate of the generating
units in which the Participants have Installed
Capability Entitlements. The value for J shall
be adopted by the Participants Committee each
time it fixes NEPOOL Objective Capability
pursuant to Section 7.
R for the month is the phase-out factor for the
month, which shall be as follows:
R=0.75 for the Power Year beginning November
1, 1997.
R=0.50 for the 12 month period beginning
November 1, 1998.
R=0.25 for the 12 month period beginning
November 1, 1999.
R=0 for the 12 month period beginning
November 1, 2000 and all subsequent
12 month periods.
(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(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f-
F)c2)
As used in this Section 12.2(a)(2), the symbols used
in the formula have the following meanings:
R is the phase out factor as defined in Section
12.2(a)(1) above.
n is the New Unit Adjustment Factor, expressed as
a fraction, for the month for a New Unit.
c is the Winter Capability of the New Unit.
C is the Winter Capability of the Proxy Unit,
which shall be the number of Kilowatts, as
determined by the 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.
f is 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.
F is the equivalent forced outage rate of the
Proxy Unit. F, a fraction, shall be the
weighted average equivalent forced outage rate
(using the Winter Capability of each generating
unit for such weighting) of the generating
units in which the Participants have Installed
Capability Entitlements, adjusted to compensate
for the rounding of the annual maintenance
outage requirement of the Proxy Unit.
m is the four-year average annual maintenance
outage requirement of the New Unit, expressed
as a fraction of a year. The data used to
determine m shall include the annual
maintenance outage requirements for the current
Power Year and the next three Power Years, as
utilized for the New Unit in the most recent
determination by the Participants Committee of
NEPOOL Objective Capability pursuant to Section
7.
M is the annual maintenance outage requirement of
the Proxy Unit. M shall be a fraction, the
numerator of which shall be the number of weeks
(rounded to the nearest full number) that most
closely approximates the weighted four-year
average annual maintenance outage requirement
(using the Winter Capability of each generating
unit for such weighting) for the generating
units in which the Participants have Installed
Capability Entitlements, and the denominator of
which shall be 52 weeks.
d is the summer derating of the New Unit,
expressed as a fraction of the Winter
Capability of the New Unit.
D is the summer derating of the Proxy Unit. D
shall be a fraction and shall be equal to the
weighted average fractional summer derating
(using the Winter Capability of each generating
unit for such weighting) of the generating
units in which the Participants have Installed
Capability Entitlements.
K1, K2, K3, K4, and K5
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(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) +K5(f-
F)c) + K5(2500-a)
The symbols used in the above formula, as modified,
shall have the meanings previously specified, except
that the symbols "K6" and "a" shall have the
following meanings:
K6 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.
(a) 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 H1. 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.
(b) 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.
(c) 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 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.].
12.4 [Deleted.].
12.5 Consequences of Deficiencies in Installed Capability
Responsibility.
(a) At the conclusion of each month, the System Operator
shall determine whether each Participant has satisfied its
Installed Capability Responsibility obligation for the month.
If the minimum monthly Installed System Capability of a
Participant during the month was less than its Installed
Capability Responsibility, the number of Kilowatts of its
deficiency shall be computed and the Participant shall be
deemed to purchase from other Participants through NEPOOL
Kilowatts of surplus Installed System Capability equal to the
amount of its deficiency and shall pay to NEPOOL for the month
any applicable fees for services assessed pursuant to Section
19.2 plus the product of its total Kilowatts of deficiency and
the Installed Capability deficiency charge. 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) The Installed Capability deficiency charge shall be an
administratively-determined charge approved by the
Participants Committee, except that, if the Participants
Committee is unable to finally approve such a charge on or
before July 28, 2000, the Installed Capability deficiency
charge shall be the charge determined by the System Operator,
until such time as the Participants Committee finally approves
a different charge.
(c) The Installed Capability deficiency charge that is to
become effective on August 1, 2000 is subject to the
acceptance and/or approval by the Commission of the materials
filed in compliance with the Commission's June 28, 2000 order
in Docket Nos. EL00-62-000, et al. Pending Commission action
on such charge, any collections for deficiencies in Installed
Capability on and after August 1, 2000 shall be subject to
refund or surcharge back to August 1, 2000 if the deficiency
charge accepted and/or approved by the Commission is different
from the charge identified in the compliance filing.
(d) The Installed Capability Responsibility deficiency
charges for each month shall be divided among and paid to
those Participants whose minimum monthly Installed System
Capabilities during such month exceeded their Installed
Capability Responsibilities, in proportion to the amounts of
their respective excesses over their Installed Capability
Responsibilities.
12.6 [Deleted].
12.7 Payments to Participants Furnishing Installed Capability.
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.
[Next Sheet is 157]
Sheet 157 is intentionally blank.
[Next Sheet is 158]
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS
13.1 Maintenance and Operation in Accordance with Accepted Electric
Industry 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 Accepted Electric Industry
Practice.
13.2 Central Dispatch. Subject to the following sentence, each
Participant shall, to the fullest extent practicable, subject all
generating facilities and other resources owned or controlled by it
to central dispatch by the System Operator; provided, however, that
each Participant shall at all times be the sole judge as to whether
or not and to what extent safety requires that at any time any of
such facilities will be operated at less than full capacity or not
at all. Each Participant may remove from central dispatch a
generating facility or other resources owned or controlled by it if
and to the extent such removal is permitted by rules and standards
approved by the Participants Committee.
13.3 Maintenance and Repair. Each Participant shall, to the
fullest extent practicable: (a) cause generating facilities and
other resources owned or controlled by it to be withdrawn from
operation for maintenance and repair only in accordance with
maintenance schedules reported to and published by the System
Operator from time to time in accordance with procedures
established or approved by the 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.
13.4 Objectives of Day -to - Day System Operation. The day-to-day
scheduling and coordination through the System Operator of the
operation of generating units and other resources shall be designed
to assure the reliability of the bulk power system of the NEPOOL
Control Area. Such activity shall:
(a) satisfy the NEPOOL Control Area's Operating Reserve
requirements, including the proper distribution of those
Operating Reserves;
(b) satisfy the Automatic Generation Control requirements of
the NEPOOL Control Area; and
(c) satisfy the Energy requirements of all Electrical Load of
the Participants,
all at the lowest practicable aggregate dispatch costs to the
NEPOOL Control Area based upon Participant-directed schedules
and Bids until the CMS/MSS Effective Date and based upon Self-
Schedules, Self-Supplies, Supply Offers and Demand Bids on and
after that Date.
13.5 Satellite Membership. Each Participant which is responsible
for the operation of transmission facilities rated 69 kV or above
in the NEPOOL Control Area or generating units and other resources
which are subject to central dispatch by NEPOOL, or which is
responsible for implementing voltage reduction and load shedding
procedures in the NEPOOL Control Area, shall become a member of the
appropriate satellite dispatching center; provided that by mutual
agreement among the affected Participants and the appropriate
satellite, a Participant may be excused from joining the satellite
if it has arranged with a satellite member to assume responsibility
to the satellite for its facilities or obligations.
SECTION 14
INTERCHANGE TRANSACTIONS
14.1 Obligation for Energy, Operating Reserve and Automatic
Generation Control.
This Section 14 shall remain in effect for service under this
Agreement until the CMS/MSS Effective Date and shall be superseded
by the provisions of Section 14A of this Agreement for service on
and after the CMS/MSS Effective Date.
(a) Each Participant shall have for each hour an Energy
obligation equal to its Electrical Load plus the kilowatthours
delivered by such Participant to other Participants in the
hour pursuant to Firm Contracts or System Contracts, together
with any associated electrical losses.
(b) Each Participant shall have for each hour Operating
Reserve obligations equal to its share of the quantity of each
category of Operating Reserve required for the NEPOOL Control
Area in the hour.
Subject to adjustment pursuant to Section 14.6, a
Participant's share of each category of Operating Reserve
required for any hour shall be determined in accordance
with the following formula:
ORp=SAp + [(OR-SA) (ELp/EL)], wherein
ORp is the Participant's share of that category of
Operating Reserve for the hour.
SAp is 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.
OR is the aggregate number of Kilowatts of that
category of Operating Reserve determined by the
System Operator in accordance with the
directions of the Participants Committee to be
required for the NEPOOL Control Area for the
hour that is not assigned to Non-Participants.
SA is the aggregate number of Kilowatts of that
category of Operating Reserve for the hour that
the Participants Committee determines should
not be shared by all Participants, but not
including Operating Reserve assigned to Non-
Participants.
ELp is the Participant's Electrical Load for the
hour.
EL is the sum of ELp for all Participants.
(a) 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:
AGCp=AGC (ELp/EL), wherein
AGCp is the Participant's share of AGC for the hour.
AGC is the total amount of AGC determined by the
System Operator in accordance with market
operation rules approved by the 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.
ELp and EL are as defined in Section 14.1(b).
14.2 Obligation to Bid or Schedule, and Right to Receive Energy,
Operating Reserve and Automatic Generation Control.
(a) A Participant which has Energy Entitlements shall submit
to or have on file with the System Operator, in accordance
with the market operation rules approved by the 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
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 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.
14.3 Amount of Energy, Operating Reserve and Automatic Generation
Control Received or Furnished.
(a) For purposes of Sections 14.4, 14.5, and 14.8, the amount
of Energy which a Participant is deemed to receive or furnish
in any hour shall be the amount of its Adjusted Net
Interchange. If the Adjusted Net Interchange is negative, the
Participant shall be deemed to be receiving Energy in the
hour. If the Adjusted Net Interchange is positive, the
Participant shall be deemed to be furnishing Energy in the
hour.
(b) For purposes of Sections 14.4, 14.5, and 14.9, prior to
the Third Effective Date: the amount of each category of
Operating Reserve which a Participant is deemed to receive in
any hour is the Kilowatts of such Operating Reserve assigned
to the Participant for the hour under Section 14.1(b) less any
Kilowatts provided in the hour by the Participant in
accordance with the market operation rules approved by the
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.
14.4 Payments by Participants Receiving Energy Service, Operating
Reserve and Automatic Generation Control.
(a) For every hour in which a Participant's Adjusted Net
Interchange is negative, the number of megawatthours of its
Energy deficiency shall be computed and the Participant shall
pay for the hour the product of its total megawatthours of
deficiency and the Energy Clearing Price applicable for the
hour as determined in accordance with Section 14.8, together
with any applicable uplift charges assessed to the Participant
under Sections 14.14 and 14.15 of this Agreement and Section
24 of the Tariff and any applicable fees for services assessed
pursuant to Section 19.2.
(b) For every hour in which a Participant is deemed to
receive Operating Reserve of any category in accordance with
Section 14.3(b), the number of Kilowatts it is deemed to
receive for the hour in each category shall be computed. The
Participant shall pay therefor for the hour any applicable
uplift charge assessed under Section 14.15 and any applicable
fees for services assessed pursuant to Section 19.2 plus the
product of (i) the aggregate amount paid to Participants for
that category of Operating Reserve for the hour pursuant to
Section 14.5(b) and (ii) a fraction of which the numerator is
the Kilowatts of that category of Operating Reserve deemed
under Section 14.3(b) to have been received by the Participant
for the hour and the denominator is the aggregate Kilowatts of
that category of Operating Reserve deemed under Section
14.3(b) to have been received by all Participants for the
hour.
(c) For every hour in which a Participant is deemed under
Section 14.3(c) to have received AGC, the amount it is deemed
to receive shall be computed and the Participant shall pay
therefor any applicable uplift charge assessed under Section
14.15 and any applicable fees for services assessed pursuant
to Section 19.2 plus the product of (i) the aggregate amount
paid to Participants for AGC for the hour pursuant to Section
14.5(c) and (ii) a fraction of which the numerator is the AGC
the Participant is deemed under Section 14.3(c) to have
received for the hour and the denominator is the aggregate
amount of AGC all Participants are deemed under Section
14.3(c) to have received for the hour.
14.5 Payments to Participants Furnishing Energy Service, Operating
Reserve, and Automatic Generation Control.
(a) Subject to the provisions of Section 14.12, a Participant
that is deemed in an hour to furnish Energy service to other
Participants pursuant to Section 14.3, or to Non-Participants
for ancillary services under the Tariff or pursuant to
arrangements entered into under Section 14.6, shall receive
for each megawatthour furnished by it the Energy Clearing
Price for the hour determined in accordance with Section 14.8
or the Bid Price for that megawatthour, if higher than the
Energy Clearing Price and the unit is either within the Energy
Clearing Price Block (as defined in Section 14.8(c)) or is
operated out of merit if such higher Bid Price is
appropriately paid pursuant to market operation rules
governing out-of-merit generation approved by the 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:
(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 Rules approved by the Markets Committee prior to
the activation of the Participants Committee or the
Participants Committee thereafter.
(a) In no event shall Participants be paid for lost
opportunity costs resulting from a generating unit being
dispatched down or off to accommodate transmission
constraints, and nothing in this Agreement or the Market Rules
shall provide for any such payment.
14.6 Energy 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
emergency Energy received from Hydro-Quebec under the HQ
Interconnection Agreement shall be deemed to be Energy
provided to (and shall be paid for by) Participants requiring
such emergency Energy in the hour. The System Operator shall
schedule such Energy deliveries to accommodate, to the maximum
extent possible, the schedule of Energy deliveries from Hydro-
Quebec requested by the Participant. The Participants deemed
to have received such Energy shall pay therefor the higher of
the Energy Clearing Price (together with any applicable uplift
charges under Sections 14.14 and/or 14.15 of this Agreement
and/or Section 24 of the Tariff and any applicable fees for
services assessed pursuant to Section 19.2) or the price paid
to Hydro-Quebec for the Energy (or in the case of Energy
received under the HQ Energy Banking Agreement, the price paid
for the related Energy deliveries to Hydro-Quebec under the
Agreement and any amount payable to Hydro-Quebec with respect
to the transaction).
14.7 Participant Purchases Pursuant to Firm Contracts and System
Contracts.
(a) A Participant may undertake to transfer all or select
portions of its settlement rights and obligations under this
Agreement to or from another Participant with respect to any
of the NEPOOL markets pursuant to a Bilateral Transaction.
Such transfer of settlement rights and obligations under this
Agreement shall be as agreed to between the two parties to the
Bilateral Transaction and shall be submitted to the System
Operator in accordance with the Market Rules. If and to the
extent necessary to implement the agreement between the
parties, such Market Rules, upon approval by the Participants
Committee, shall supersede the provisions of the Agreement
that otherwise apply for determination of the respective
settlement rights and obligations 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 Rules approved by
the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee
thereafter.
14.8 Determination of Energy Clearing Price. For each hour, the
System Operator shall determine the Energy Clearing Price as
follows:
(a) The System Operator shall rank in the order of lowest to
highest (i) the Dispatch Prices derived from the Bid Prices to
furnish Energy in the hour and (ii) the cost to NEPOOL of any
Energy received from Non-Participants in the hour pursuant to
contracts referenced in Section 14.6.
(b) The Energy Clearing Price shall be the weighted average
of the Dispatch Prices (or NEPOOL cost) of the "Energy
Clearing Price Block" as defined in the next sentence. The
Energy Clearing Price Block shall be identified for each hour
in accordance with market operation rules approved by the
Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter to reflect
those resources with the highest Dispatch Prices or NEPOOL
cost that were centrally dispatched by the System Operator for
Energy deemed to have been furnished to the Participants,
excluding resources that were dispatched out of merit as
determined in accordance with market operation rules approved
by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee
thereafter.
14.9 Determination of Operating Reserve Clearing Price.
(a) For each hour as necessary, the System Operator shall
determine the Operating Reserve Clearing Price for each
category of Operating Reserve as follows:
(i) The System Operator shall determine the aggregate
Kilowatts of the applicable category of Operating Reserve
that are deemed pursuant to Section 14.3(b) to have been
received by Participants for the hour.
(ii) For 10-Minute Non-Spinning Reserve and 30-Minute
Operating Reserve, the System Operator shall rank in the
order of lowest to highest the Bid Prices of the
resources designated by the System Operator for that
category of Operating Reserve for the hour. The
applicable Operating Reserve Clearing Price for 10-Minute
Non-Spinning Reserve or 30-Minute Operating Reserve shall
be the weighted average of the highest Bid Prices for the
1000 Kilowatts (or such other number as may be specified
by the 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.
14.10 Determination of AGC Clearing Price. For each hour, the
System Operator shall determine the AGC Clearing Price. The AGC
Clearing Price shall be the weighted average "AGC Capability Price"
for the "AGC Clearing Price Block," as both terms are defined below
in this Section 14.10. The AGC Capability Price for each hour for
each AGC Entitlement designated by the System Operator to provide
AGC in the hour shall be a cost per unit of AGC capability based on
the Bid Price for the Entitlement for the hour divided by the
amount of AGC available in the hour from that Entitlement. The AGC
Clearing Price Block shall be identified by the System Operator for
each hour in accordance with market operation rules approved by the
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.
14.11 Funds to or from which Payments are to be Made.
(a) All payments for Energy, Operating Reserves or AGC
furnished or received, all uplift charges paid pursuant to
this Section 14 of this Agreement and Section 24 of the
Tariff, and all fees for services paid pursuant to Section
19.2, and any payments by Non-Participants for ancillary
services under Schedules 2-7 to the Tariff or pursuant to
arrangements referenced in Section 14.6, shall be allocated
each month through the Pool Interchange Fund as follows:
Step One. For each week in which Energy is delivered or
received under the HQ Energy Banking Agreement, all
payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking
Fund provided for in Section 14.11(b).
Step Two. (i) For each week in which Pre-Scheduled
Energy (as defined in the HQ Phase I Energy Contract) is
purchased pursuant to the HQ Phase I Energy Contract, the
aggregate amount which is paid pursuant to Section
14.6(b) for such Energy by each Participant which is a
participant in the Phase I arrangements with Hydro-Quebec
shall be determined and paid on the Participant's account
into the Phase I Savings Fund.
(ii) For each week in which Energy is purchased pursuant
to the HQ Phase II Firm Energy Contract, the
aggregate amount which is paid pursuant to Section
14.6(b) for such Energy by each Participant which is
a participant in the Phase II arrangements with
Hydro-Quebec shall be determined and paid on the
Participant's account into the Phase II Savings
Fund.
Step Three. For each week in which Other HQ Energy is
purchased pursuant to the HQ Phase I Energy Contract or
Energy is purchased pursuant to the HQ Interconnection
Agreement, the aggregate amount paid pursuant to Section
14.6(b) for such Energy shall be determined for each
Participant which is a participant in the Phase I or
Phase II arrangements with Hydro-Quebec. Such amount
shall be allocated between the Participant's share of the
Phase I Savings Fund and the Participant's share of the
Phase II Savings Fund created under the HQ Use Agreement
in the same ratio as (A) the sum of (x) the number of
kilowatthours of Other HQ Energy deemed to be purchased
by the Participant during the week and (y) the HQ Phase I
Percentage of the number of kilowatthours deemed to be
purchased by the Participant under the HQ Interconnection
Agreement during the week, bears to (B) the HQ Phase II
Percentage of the number of kilowatthours purchased under
the HQ Interconnection Agreement during the week.
Step Four. The balance remaining in the Pool Interchange
Fund after Steps One through Three shall be retained in
the Pool Interchange Fund for the month and shall be used
and disbursed after each month in the following order:
(i) (A) amounts owed to Non-Participants (other than
Hydro-Quebec) for the month under contracts entered into
with them pursuant to Section 14.6(a) shall be paid, and
(B) amounts owed to Hydro-Quebec for the month for Energy
deemed to be furnished pursuant to Section 14.6(b) to
Participants which are not participants in the Phase I or
Phase II arrangements with Hydro-Quebec shall be paid
and, in the event the price paid by any such Participant
for such Energy is the Energy Clearing Price, the excess,
if any, of the Energy Clearing Price over the amount owed
to Hydro-Quebec shall be paid to the Participant;
(ii) amounts paid by Participants for applicable fees for
services assessed pursuant to Section 19.2 shall be used
to reduce NEPOOL expenses; and
(iii) amounts owed to Participants for the month
pursuant to Section 14.5 shall then be paid.
(b) HQ Energy Banking Fund. All amounts allocated to
the HQ Energy Banking Fund for each month shall be used
and disbursed as follows:
(i) Participants which furnish Energy for delivery to
Hydro-Quebec under the HQ Energy Banking Agreement shall
receive therefor from their share of the Energy Banking
Fund the amount to which they are entitled for such
service in accordance with Section 14.5.
(ii) amounts required to be paid to Hydro-Quebec under
the HQ Energy Banking Agreement shall be paid from the
shares of the Fund of the Participants engaging in
transactions under the HQ Energy Banking Agreement for
the month in accordance with their respective interests
in the transactions for the month. If there is not
enough in any such share, the Participants with the
deficient shares shall be billed and pay into their
shares of the Fund the amounts required for payments to
Hydro-Quebec.
(iii) subject to the remaining provisions of this
Section, at the end of each month any balance remaining
in each Participant's share of the HQ Energy Banking Fund
shall (I) in the case of any Participant which is not a
participant in the Phase I or Phase II arrangements with
Hydro-Quebec, be paid to such Participant, and (II) in
the case of any Participant which is a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be
paid to the Escrow Agent under the HQ Use Agreement to be
held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use
Agreement, and shall be allocated between the
Participant's share of said Funds as follows:
(A) the balance remaining in the Participant's
share of the HQ Energy Banking Fund for the
month shall be divided by the number of
kilowatthours deemed to be received by the
Participant under the HQ Energy Banking
Agreement during the month to determine an
average savings amount per kilowatthour;
(B) for any hour during the month in which the
number of kilowatthours received by NEPOOL
under the HQ Energy Banking Agreement exceeded
the HQ Phase I Transfer Capability, an amount
equal to (A) the Participant's share of the
excess of (1) the number of kilowatthours
received over (2) the HQ Phase I Transfer
Capability times (B) the average savings amount
per kilowatthour determined for that
Participant under (i) above shall be allocated
to the Phase II Savings Fund; and
(C) the remaining balance of the Participant's
share of the HQ Energy Banking Fund for the
month shall be allocated to the Phase I Savings
Fund.
It is recognized that, in view of the time which may
elapse between the delivery of Energy to or by
Hydro-Quebec in an Energy Banking transaction under
the HQ Energy Banking Agreement and the return of
the Energy, the amounts of Energy delivered to and
received from Hydro-Quebec, after adjustment for
losses, may not be in balance at the end of a
particular month.
Further, if as of the end of any month and after
adjustment for electrical losses, the cumulative
amount of Energy so received from Hydro-Quebec
exceeds the amount so delivered, the aggregate
amount paid by Participants for the excess Energy
pursuant to Section 14.6(b) shall be paid to the
Energy Banking Fund. The Escrow Agent under the HQ
Use Agreement shall hold and invest these funds. On
the return of the excess Energy to Hydro-Quebec, the
amount so held by the Escrow Agent shall be repaid
to Hydro-Quebec and Participants in accordance with
the Energy Banking Agreement.
(c) Phase I HQ Savings Fund. The aggregate amount allocated
to each Participant's share of the Phase I HQ Savings
Fund for each month shall be used, first, to pay to
Hydro-Quebec the amount owed to it for the month for
Energy furnished under the Phase I HQ Energy Contract and
the HQ Phase I Percentage of the amount owed to it for
the month for Energy furnished to the Participants under
the HQ Interconnection Agreement. The balance of the
amount allocated to the Fund for the month shall be paid
to the Escrow Agent under the HQ Use Agreement to be held
and disbursed by it through the Phase I HQ Savings Fund
created thereunder in accordance with each Participant's
contribution to such balance.
(d) Phase II HQ Savings Fund. The aggregate amount allocated
to the Phase II HQ Savings Fund for each month shall be
used, first, to pay to Hydro-Quebec the amount owed to it
for the month for Energy deemed to be furnished to the
Participant under the Phase II HQ Firm Energy Contract
and the HQ Phase II Percentage of the amount owed to it
for the month for Energy deemed to be furnished to the
Participant under the HQ Interconnection Agreement. The
balance of the amount allocated to the Fund for the month
shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the
Phase II HQ Savings Fund created thereunder in accordance
with each Participant's contribution to such balance.
14.12 Development of Rules Relating to Nuclear and
Hydroelectric Generating Facilities, Limited-Fuel Generating
Facilities, and Interruptible Loads.
It is recognized that the central dispatch of Energy available
from nuclear generating facilities and from pondage associated
with hydroelectric generating facilities and from
interruptible loads and of pumping Energy for pumped storage
hydroelectric generating facilities and other limited-fuel
generating facilities involves special problems which must be
resolved to assure fair and non-discriminatory treatment of
Participants having Entitlements in such generating facilities
or having such interruptible loads or any other Participants
involved in such transactions. Accordingly, the 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.
14.13 Dispatch 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.
14.14 Congestion 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.
(b) Commencing on the implementation effective date of an
order by the Commission directing a different allocation of
congestion costs, 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 Rules,
the System Operator shall determine for the constrained
transmission area the aggregate Congestion Costs for the hour.
[Next Sheet is 196]
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
[Next Sheet is 197]
the constrained area that were used in the hour to
serve such Electrical Load, taking into account Firm
Contracts and System Contracts between Participants
and electrical losses, if and as appropriate.
(ii) The System Operator shall identify for each
Participant and Non-Participant the megawatt hours, if
any, of the rights of that Participant or Non-Participant
to use the then effective transfer capability across the
constrained interface.
(iii) The System Operator shall identify for each
Participant and Non-Participant the megawatt hours, if
any, by which the amount determined pursuant to clause
(i) above for that Participant or Non-Participant exceeds
the amount determined for that Participant or Non-
Participant pursuant to clause (ii) above. If the clause
(i) amount exceeds the clause (ii) amount, the
Participant or Non-Participant shall be responsible for
paying a share of the aggregate Congestion Costs in
proportion to the Participant's or Non-Participant's
share of the aggregate amount of such excesses for all
Participants and Non-Participants, and such Congestion
Costs shall be included, as a transmission charge, in the
Regional Network Service, Internal Point-to-Point Service
or Through or Out Service charge, whichever is
applicable.
(c) As used in this Section 14.14, the "Congestion Cost" of
an out-of-merit resource for an hour means the product of (i)
the difference between its Dispatch Price and the Energy
Clearing Price for the hour, times (ii) the number of megawatt
hours of out-of-merit generation produced by the resource for
the hour.
14.14A CMS/MSS Implementation Studies Related to Congestion.
(a) Study of Transmission Constraints and Reliability
Regions. The Participants Committee shall commission a study
to determine whether the implementation of CMS and MSS is
likely to result in substantial, adverse impacts on any load
pockets within New England. As an additional component of
this study, there shall be an initial determination of the
existence or lack of workable competition in the NEPOOL
Markets in Reliability Regions, Load Zones and any load
pockets. This study shall commence on or before July 1, 2000
and shall be completed no later than December 31, 2000. If
the results of this study determine that there is likely to be
substantial adverse impacts on any load pocket due to the
implementation CMS and MSS, the Participants Committee shall
undertake to develop new measures to mitigate such impacts.
Unless or until new measures
are implemented to replace or supplement existing
measures, the System Operator shall apply existing NEPOOL
System Rules to mitigate such impacts to the extent
possible and appropriate. In evaluating whether there
will be substantial adverse impacts, the study shall take
into account planned transmission enhancements to
increase transfer capability into any load pocket, the
anticipated operation of new or expanded generating units
and anticipated retirements of existing generating units,
the anticipated value of FCRs and revenues from the sale
thereof that will be available to load in any load
pocket, the concentration of ownership of generation and
responsibilities for serving load in the load pocket, and
the anticipated load response to such adverse impacts.
(b) Study of Market Rule and Procedure 17 ("Market Rule 17").
Before the CMS/MSS Effective Date, the System Operator and
Participants shall review Market Rule 17 and consider changes,
where appropriate, to that Market Rule in light of the
implementation of CMS and MSS. The review shall be supervised
and assisted by persons who have recognized antitrust
expertise and experience and are retained by or on behalf of
the Participants Committee. At a minimum, before the CMS/MSS
Effective Date, Market Rule 17 shall be amended to prescribe
the process to determine whether a Reliability Region or load
pocket within a Reliability Region is workably competitive
and, if a Reliability Region or load pocket is determined not
to be workably competitive, the types of mitigation measures
available to be applied to remedy such situation.
14.15 Additional 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 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.
SECTION 14A
PARTICIPANT MARKET TRANSACTIONS
ON AND AFTER THE CMS/MSS EFFECTIVE DATE
This Section 14A shall become effective, and shall supersede
Section 14 in its entirety, for service under this Agreement on and
after the CMS/MSS Effective Date. Certain provisions of this
Section 14A are subject to further modification to comply with
requirements of the Commission's June 28, 2000 order in Docket Nos.
EL00-62-000, et al. and further Commission orders with respect
thereto. This Section 14A shall have no effect for service or
charges under this Agreement prior to the CMS/MSS Effective Date
unless specific provisions are made applicable earlier pursuant to
the Market Rules. This Section 14A specifies the rights and
obligations of Participants under the Agreement with respect to the
supply of, and payment for, Energy, Operating Reserve, 4-Hour
Reserve and AGC.
14A.1 Supply Obligations and Settlement Obligations for Energy,
Operating Reserve, 4-Hour Reserve and Automatic Generation
Control.
(a) Supply Obligation. Each Participant with a Resource or
an Entitlement in a Resource that is scheduled in the Day-
Ahead Market by the System Operator, in accordance with an
applicable Supply Offer, Self-Schedule or designation for
Self-Supply, to provide Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve and/or AGC shall have a Day-
Ahead Market Supply Obligation for the service scheduled in
the amount so scheduled. The Day-Ahead Market Supply
Obligation shall be satisfied by the Participant for each hour
in one of the following two ways: (i) the Participant shall
furnish or cause to be furnished in Real-Time such service
under this Section 14A each hour pursuant to the schedule; or
(ii) the Participant shall pay at the applicable Real-Time
Nodal Price or Clearing Price for such amounts which it has
not furnished or caused to be furnished in accordance with
clause (i). Each Participant with a Resource or an
Entitlement in a Resource that is scheduled in the Day-Ahead
Market or that submits a Supply Offer, or that is scheduled
pursuant to a Self-Schedule or designated pursuant to a Self-
Supply in the Real-Time Market, for Energy at a Node or
External Node, Operating Reserve or AGC, shall have a Real-
Time Market Supply Obligation for each hour for which it is so
scheduled or designated. Its Real-Time Market Supply
Obligation for Energy shall be equal to the amounts of Energy
at a Node or External Node it provides in the Real-Time Market
in response to dispatch instructions by the System Operator
(including dispatch instructions pursuant to a Self-Schedule
or Self-Supply). Its Real-Time Market Supply Obligations for
each category of Operating Reserve and/or AGC shall be equal
to the amount of such service it is designated by the System
Operator to provide in the Real-Time Market (including service
designated by the Participant for Self-Supply and accepted by
the System Operator).
(b) Energy Settlement Obligation. Each Participant shall
have for each hour a Day-Ahead Market Settlement Obligation
for Energy at each Location equal to the megawatthours, if
any, of its Demand Bid accepted by the System Operator in the
Day-Ahead Market for Energy at that Location, adjusted up or
down, as appropriate, to reflect Bilateral Transactions
entered into by the Participant that transfer for the hour all
or part of a Day-Ahead Market Settlement Obligation for Energy
at that Location to or from another Participant. Each
Participant also shall have for each hour a Real-Time Market
Settlement Obligation for Energy at each Location equal to the
megawatthours, if any, of its Electrical Load at that Location
for the hour, adjusted up or down, as appropriate, to reflect
Bilateral Transactions entered into by the Participant that
transfer for the hour all or part of a Real-Time Market
Settlement Obligation for Energy at that Location to or from
another Participant. A Settlement Obligation for Energy shall
require the Participant to pay, or entitle the Participant to
be paid, in accordance with the provisions of Section 14A.8(a)
and applicable Market Rules.
(c) Operating Reserve Settlement Obligation. Settlement
Obligations for each category of Operating Reserve for each
hour are established by allocating the total Megawatts of that
category designated for the hour in Real-Time by the System
Operator to Participants under the Agreement and to Non-
Participants under the Tariff. Each Participant shall have
for each hour a Settlement Obligation for each category of
Operating Reserve that, subject to adjustment pursuant to
Section 14A.11, shall be the number of Megawatts determined in
accordance with the following formula:
ORp = SAp + [(OR-SA) (ELp/EL)] + ADJor, wherein
ORp is the Megawatts of the Participant's
Settlement Obligation for that category of
Operating Reserve for the hour.
SAp is the number of Megawatts, if any, of that
category of Operating Reserve for the hour that
is determined pursuant to applicable Market
Rules as properly being assigned specifically
to such Participant and not shared by all
Participants.
OR is the aggregate number of Megawatts of that
category of Operating Reserve designated by the
System Operator in the Real-Time Market in
accordance with applicable NEPOOL System Rules
to be required for the NEPOOL Control Area for
the hour.
SA is the aggregate number of Megawatts of that
category of Operating Reserve for the hour that
is determined pursuant to applicable Market
Rules as properly not being shared by all
Participants, including Operating Reserve
assigned to Non-Participants.
ELp is the Participant's Electrical Load for the
hour.
EL is the sum of ELp for all Participants.
ADJor is the adjustment required to reflect the
amount of that category of Operating Reserve
that the Participant has Self-Supplied and all
Bilateral Transactions entered into by the
Participant that transfer for the hour all or
part of a Settlement Obligation for that
category of Operating Reserve to or from
another Participant but have not been reflected
in the Participant's Electrical Load for the
hour.
A Settlement Obligation for Operating Reserve shall
require the Participant to pay in accordance with the
provisions of Section 14A.8(b) and applicable Market
Rules.
(d) 4-Hour Reserve Settlement Obligation. Each Participant
shall have for each hour a Settlement Obligation for 4-Hour
Reserve to the extent provided for in Section 14A.8(d),
adjusted up or down as appropriate to reflect all Bilateral
Transactions entered into by the Participant that transfer all
or a part of the Settlement Obligation for 4-Hour Reserve to
or from another Participant. A Settlement Obligation for 4-
Hour Reserve shall require the Participant to pay in
accordance with Section 14A.8(d) and applicable Market Rules.
(e) AGC Settlement Obligation. Settlement Obligations for
AGC for each hour are established by allocating the total AGC
designated for the hour in the Real-Time
Market by the System Operator to Participants under the
Agreement and Non-Participants under the Tariff. Each
Participant shall have for each hour a Settlement
Obligation for AGC that, subject to adjustment pursuant
to Section 14A.11, shall be determined in accordance with
the following formula:
AGCp = AGC (ELp/EL) + ADJAGC, wherein
AGCp is the Participant's share of AGC for the hour.
AGC is the total amount of AGC determined by the
System Operator in accordance with applicable
NEPOOL System Rules to be required for the
NEPOOL Control Area for the hour that is not
assigned to Non-Participants.
ELp and EL are as defined in Section 14A.1(c).
ADJAGC is the adjustment required to reflect all
Bilateral Transactions entered into by the
Participant to transfer all or part of a
Settlement Obligation for AGC to or from
another Participant but that have not been
reflected in the Participant's Electrical Load
for the hour and the amount, if any, that the
Participant has, in accordance with applicable
Market Rules, Self-Supplied.
A Settlement Obligation for AGC shall require the
Participant to pay in accordance with Section 14A.8(c)
and applicable Market Rules.
14A.2 Right to Receive Service. Except as emergency
circumstances may result in the System Operator requiring load
curtailments by Participants, and subject to the availability
of transmission capacity, each Participant shall be entitled
to receive from other Participants (or from the service made
available from Non-Participants pursuant to arrangements
entered into under Section 14A.11) such amounts, if any, of
Energy, Operating Reserve, 4-Hour Reserve and AGC as it
requires. If, for any hour, load curtailments or other
emergency measures are required, the amount of services that
Participants are entitled to receive shall be reduced by the
System Operator in a fair and non-discriminatory manner in
light of the circumstances and applicable NEPOOL System Rules.
14A.3 Participation in the Day-Ahead Market.
(a) Demand Bids and Supply Offers for the Day-Ahead Market
shall be submitted by Participants for each hour of the
Dispatch Day, in accordance with this Agreement and applicable
Market Rules. Such Demand Bids and Supply Offers shall
include the information required by the Market Rules.
(b) Any Participant with authority to submit a Supply Offer
in accordance with Section 14A.4 for a Resource that is
eligible to supply Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve or AGC, or for load that is
capable of reducing its consumption within four hours to
supply 4-Hour Reserve,
may submit in the Day-Ahead Market to, or have on file
with, the System Operator, a Supply Offer for each such
Resource or load reduction, to the extent permitted by
and in accordance with Section 14A.4 and applicable
Market Rules; provided that as one alternative to
submitting Supply Offers for Operating Reserve and/or 4-
Hour Reserve, a Participant desiring to provide such
services may enter into a Reserve Contract with the
System Operator pursuant to Section 14A.10(c) covering
such services.
(c) Any Participant wishing to purchase Energy in the Day-
Ahead Market may submit to, or have on file with, the System
Operator in accordance with applicable Market Rules a Day-
Ahead Demand Bid or Bids specifying Demand Bid Prices for such
Energy in each hour of the Dispatch Day at any Location,
including the Hub.
(d) Any Participant wishing to sell Energy into the Day-Ahead
Market from a Control Area outside the NEPOOL Control Area may
do so by submitting a Supply Offer for Energy in the Day-Ahead
Market at an External Node. Participants wishing to purchase
Energy in the Day-Ahead Market for sale outside of the NEPOOL
Control Area may do so by submitting a Demand Bid in the Day-
Ahead Market at an External Node.
(e) Any Participant seeking to Self-Schedule a Resource in
the Day-Ahead Market or to affect its Day-Ahead Settlement
Obligation through a Bilateral Transaction, a Self-Supply of
Operating Reserve, or a Self-Supply of AGC to the extent
permitted by applicable Market Rules, shall submit or cause to
be submitted all necessary information with respect thereto to
the System Operator in accordance with Section 14A.4(i) or
Section 14A.11 and applicable Market Rules.
(f) In accordance with Market Rules, any Participant seeking
to effect a transaction that moves Energy through or out of
the NEPOOL Control Area by combining a Demand Bid at an
External Node with a Supply Offer at any other Node may elect
to specify the maximum Congestion Cost it is willing to pay to
have its transaction scheduled or, once scheduled, to keep
that transaction from being wholly or partially curtailed.
14A.4 Nature of Demand Bids and Supply Offers; Limitations;
Self-Schedules and Self-Supplies.
(a) Carry Over Procedures: If a Supply Offer or Demand Bid
is not submitted for a Resource in the Day-Ahead Market,
the Supply Offer or Demand Bid shall be deemed to be the
last valid Supply Offer or Demand Bid on file with the
System Operator, except for Supply Offers and Demand Bids
at External Nodes, which shall be deemed to be
unavailable. If a Supply Offer or Demand Bid for
Dispatchable Load is not submitted for a Resource in the
Real-Time Market, the Supply Offer or Demand Bid shall be
deemed to be the Supply Offer or Demand Bid submitted in
the Day-Ahead Market, except for Supply Offers and Demand
Bids at External Nodes which shall not carry over and
must be submitted in accordance with applicable Market
Rules.
For a generating unit in which there are multiple
Entitlement holders, only one Participant shall be
permitted to submit Supply Offers for such unit. The
Entitlement holders in each unit with multiple
Entitlement holders shall designate a single Participant
that will be permitted to submit Supply Offers 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 the Supply Offer Price for Energy for
the unit shall be based on the replacement cost of fuel.
Such Supply Offer Price, operational parameters and
other information required under the Market Rules to be
furnished to the System Operator shall be furnished to
the System Operator by the Participant validly furnishing
replacement cost of fuel as of December 31, 1996.
Nothing in this Agreement shall affect the rights of any
Entitlement holder under the contractual arrangements
among such Entitlement holders relating to a generating
unit.
(b) Each Supply Offer for Energy shall specify the Node or
External Node where the Energy will be provided. Each
Demand Bid shall specify the Location where theEnergy
will be received. Supply Offers and Demand Bids at
External Nodes shall be adjusted as appropriate by the
System Operator to account for transmission losses on
Non-PTF, if any, between the PTF and the transmission
facilities of the neighboring Control Area. Metered
values for Electrical Load on the Non-PTF shall be
adjusted as appropriate by the System Operator to account
for transmission losses on the Non-PTF, if any, between
the PTF and the transmission facilities of the
neighboring Control Area. The System Operator shall post
on its Internet website loss factors for each External
Node.
(c) Each Supply Offer for Energy from a generating unit or
Supply Offer at an External Node in the Day-Ahead Market
shall contain the information required by applicable
Market Rules and shall, at a minimum, specify the offered
incremental Energy prices, and may include a Start-Up
Price and No-Load Price, if any, and operational
parameters. Each Supply Offer for Energy from Resources
in the Real-Time Market shall specify, in addition to the
Node or External Nodes, only incremental Energy prices.
Each Supply Offer Price for incremental Energy from a
segment of a Resource shall be equal to or greater than
the Supply Offer Price for any lesser quantity of Energy.
Each Demand Bid shall contain the information required by
the applicable Market Rules and shall at a minimum state
the bid decremental prices of Energy. Each Demand Bid
Price for a block of Energy shall be equal to or less
than the Price for any lesser quantity of Energy.
(d) Supply Offers may be submitted in the Day-Ahead Market
for 10-Minute Spinning Reserve, 10-Minute Non-Spinning
Reserve, 30-Minute Operating Reserve, 4-Hour Reserve, and
AGC. Each Supply Offer shall specify a separate Supply
Offer Price for the service offered.
(e) Supply Offers for 10-Minute Spinning Reserve, 10-Minute
Non-Spinning Reserve, and/or 30-Minute Operating Reserve
may be submitted in the Real-Time Market only for fast
start resources, as defined in the Market Rules. Each
Supply Offer shall specify a separate Supply Offer Price
for the service offered. Supply Offers for AGC also may
be submitted in the Real-Time Market from a generating
unit and shall specify the Supply Offer Price for such
service.
(f) To the extent a Resource qualifies to provide Operating
Reserve or 4-Hour Reserve and is not self-scheduled or has not
submitted a Supply Offer to provide such service(s), a Supply
Offer to provide Energy from a Resource in any hour in the
Day-Ahead Market may also be considered in accordance with the
Market Rules to be a Supply Offer to provide Operating Reserve
or 4-Hour Reserve at the Resource's Lost Opportunity Cost for
such hour based on its Day-Ahead Supply Offer Price for
Energy. The Supply Offer Price for a category of Operating
Reserve or 4-Hour Reserve from a Resource in an hour shall be
the greater for such hour of the submitted Supply Offer Price
for such service or the Lost Opportunity Cost.
Each Supply Offer to provide Energy from a Resource other
than a Dispatchable Load in any hour in the Real-Time
Market is also a Supply Offer to provide Operating
Reserve at the Resource's Lost Opportunity Cost for such
hour based on its Real-Time Energy Supply Offer Price if
and to the extent such Resource qualifies to provide
Operating Reserve under the applicable Market Rules. For
Resources submitting Supply Offers for Operating Reserve
in the Real-Time Market pursuant to Section 14A.4(e) or
as otherwise permitted under the Agreement or the Market
Rules, the Supply Offer Price for service from the
Resource in each hour shall be the greater of the
submitted Supply Offer Price or the Lost Opportunity Cost
for such hour.
(g) Each Real-Time Supply Offer Price for Energy from the
portion of a Resource scheduled to provide Operating Reserve,
4-Hour Reserve or AGC in the Day-Ahead Market shall be less
than or equal to the Day-Ahead Supply Offer Price for Energy
for such portion.
Each Real-Time Supply Offer Price for AGC from the
portion of a generating unit eligible to provide AGC and
scheduled to provide Energy, Operating Reserve, AGC or 4-
Hour Reserve in the Day-Ahead Market shall be less than
or equal to the Day-Ahead Supply Offer Price for AGC from
such generating unit.
Each Real-Time Supply Offer Price for any category of
Operating Reserve for the portion of a Resource scheduled
to provide Operating Reserve Day-Ahead and eligible to
submit a Supply Offer Price for that portion of the
Resource for that category of Operating Reserve in the
Real-Time Market shall be less than or equal to the Day-
Ahead Supply Offer Price for such category of Operating
Reserve from such portion of that Resource.
(h) If there are multiple Supply Offers for Energy submitted
by Participants in the Day-Ahead or Real-Time Market
specifying the same effective Supply Offer Price (as adjusted
for Marginal Losses), and no lower Supply Offer Prices (as
adjusted for Marginal Losses) are available in the applicable
Market to meet the next decrement of load at that Node or
External Node, then ties will be broken in accordance with or
scheduled amounts pro rated in accordance with the Market
Rules.
(i) Each Participant with authority to submit Supply Offers
for a Resource may submit a Self-Schedule for Energy from its
Resources in either the Day-Ahead or Real-Time-Market in
accordance with applicable Market Rules. The Self-Schedule
defines the Participant's plan to provide Energy from a given
generating unit or to consume Energy for a Dispatchable Load
(e.g., a pumped storage facility in the pumping mode), or to
import or export Energy at an External Node. The Self-
Scheduled Energy from a generating unit or consumed by a
Dispatchable Load must satisfy the operating parameters
included in the applicable Supply Offer or Demand Bid. For a
Self-Schedule of a Resource other than a Dispatchable Load to
be accepted, the Participant submitting that Self-Schedule
must also submit at least one or more Supply Offer Prices,
each equal to or less than zero, for the Energy associated
with the entire Self-Scheduled portion of that Resource.
14A.5 Scheduling Procedures in the Day-Ahead Market.
(a) The System Operator shall perform for each Dispatch Day
in accordance with the NEPOOL System Rules a security
constrained unit commitment schedule using a computer
algorithm which simultaneously minimizes the total cost for:
(i) supplying Energy to satisfy accepted Demand Bids in the
Day-Ahead Market; (ii) providing the quantity of Operating
Reserves and AGC required by NEPOOL System Rules; and (iii)
providing any necessary 4-Hour Reserves in accordance with
Section 14A.5(f) and applicable NEPOOL System Rules. The
schedule shall take into account all Self-Schedules and Self-
Supplies submitted by Participants for the Day-Ahead Market.
In accordance with the NEPOOL System Rules, the schedule shall
also take into account, among other things, phase shifters and
other power flow control devices, transmission system
limitations, including but not limited to internal system
limitations and external interface limits, and contingencies
reasonably identified pursuant to criteria posted on the
System Operator's Internet website that may constrain outputs
or require additional supply in specific locations.
(b) The amount of each category of Operating Reserve
scheduled in the Day-Ahead Market by the System Operator shall
be in accordance with the NEPOOL System Rules, shall take into
account the grid and generator configuration for the Dispatch
Day, and may be price sensitive in whole or in part such that
the required amount of Operating Reserve decreases as the
price for Operating Reserve increases. Any NEPOOL System Rule
in effect before the CMS/MSS Effective Date designed to
maintain reliability while producing just and reasonable
charges and payments for Operating Reserves during times of
emergency or shortages of available Energy and/or Operating
Reserves shall remain in effect on and after the CMS/MSS
Effective Date unless and until subsequently amended, and may
be in addition to or in lieu of the establishment of price
sensitive Operating Reserve requirements.
(c) The simultaneous optimization process used to determine
schedules in the Day- Ahead Market shall ensure that all
portions of Resources with Supply Offers not scheduled to
provide Energy shall cascade to the markets for AGC, Operating
Reserves and 4-Hour Reserves to the extent such Resources are
eligible to provide those services and consistent with the
Supply Offer Prices established in accordance with Section
14A.4. This process shall also ensure that all portions of
Resources with Supply Offers not scheduled to provide Energy
may be considered for meeting the requirements to provide AGC,
Operating Reserves and 4-Hour Reserves.
(d) In the scheduling of Resources for Operating Reserves, 4-
Hour Reserves and AGC in the Day-Ahead Market, the
simultaneous optimization process shall use the following
principles: Resources that are Self-Scheduled pursuant to
applicable Market Rules to provide Energy shall be reflected
in the schedule in accordance with the Self-Schedule except as
provided below; Resources that are designated for Self-Supply
in accordance with applicable Market Rules shall be reflected
in the schedules to the extent they are so designated except
as provided below; Resources, to the extent not scheduled or
Self-Scheduled for Energy or designated for Self-Supply and
eligible to provide Operating Reserve, shall be scheduled by
the System Operator based on the higher of their Lost
Opportunity Costs, if any, or their applicable Day-Ahead
Supply Offer Prices; and Resources, to the extent not
scheduled or Self-Scheduled for Energy or designated for Self-
Supply and eligible to provide AGC, shall be scheduled based
on their Lost Opportunity Costs, if any, plus their Day-Ahead
Supply Offer Prices for AGC. The System Operator may direct
changes to any Self-Schedule and/or Self-Supply if, but only
to the extent, necessary for reliability.
(e) At the conclusion of the scheduling process set forth in
Section 14A.5(a), the System Operator shall publish each day
in accordance with the Market Rules and in a way that is
consistent with the NEPOOL Information Policy the information
required by Section 14A.18. The System Operator's schedule
for the Day-Ahead Market shall identify to each Entitlement
holder, the expected start and shut down times for all of its
Resources or Entitlements that are scheduled in the Day-Ahead
Market.
(f) If the System Operator's Day-Ahead forecast of the NEPOOL
load exceeds the aggregate of the Participants' Demand Bids
accepted in the Day-Ahead Market for any hour of the Dispatch
Day, the System Operator may schedule, in accordance with the
applicable NEPOOL System Rules, 4-Hour Reserves to be
available to cover part or all of the difference.
14A.6 Participation in the Real-Time Market.
(a) Supply Offers and Demand Bids for the Real-Time Market
shall be submitted by Participants for each hour of the
Dispatch Day of the Real-Time Market, to the extent permitted
by and in accordance with Section 14A.4 and applicable Market
Rules. Such Supply Offers and Demand Bids shall include the
information required by the Market Rules.
(b) Each Participant with authority to submit a Supply Offer
in accordance with Section 14A.4 for a Resource that is
eligible to supply Energy, Operating Reserve, or AGC, may
submit in the Real-Time Market to, or have on file with, the
System Operator, or modify, a Supply Offer for each such
Resource, to the extent permitted by and in accordance with
applicable Market Rules and subject to the limitations of
Section 14A.4(g). New or modified Supply Offers may, among
other matters, (i) offer Energy at a Node or External Node,
Operating Reserves and AGC from a generating unit not
scheduled in the Day-Ahead Market which can be dispatched by
the System Operator in the Real-Time Market, (ii) increase or
decrease the Supply Offer Price for Energy from a Resource
scheduled in the Day-Ahead Market, (iii) reduce the Supply
Offer Price
for Energy from a generating unit scheduled to provide
AGC, Operating Reserves, or 4-Hour Reserves in the Day-
Ahead Market, and (iv) propose new Supply Offers and/or
Demand Bids at External Nodes.
(c) Each Participant seeking to Self-Schedule its Resource in
the Real-Time Market or to affect its Real-Time Settlement
Obligation through a Bilateral Transaction, a Self-Supply of
Operating Reserve, or a Self-Supply of AGC to the extent
permitted by applicable Market Rules, shall submit or cause to
be submitted all necessary information with respect thereto to
the System Operator in accordance with Section 14A.4(i) or
Section 14A.11 and applicable Market Rules.
14A.7 Scheduling Procedures in the Real-Time Market.
(a) A Participant at its own cost may bring on line a
generating unit not scheduled to operate in the Day-Ahead
Market, after giving such notice as is required by the Market
Rules, and receiving the System Operator's approval, so that
the generating unit can be dispatched by the System Operator
based on the Participant's Real-Time Energy Supply Offer. The
Participant electing to bring its generating unit on line in
accordance with this Section 14A.7 shall not be entitled to
any uplift under Section 14A.19 with respect to its costs in
this instance, although such Participant may qualify for
uplift under other provisions of this Agreement or applicable
Market Rules.
(b) The System Operator shall centrally dispatch all
available Resources, including Self-Scheduled Resources, in
Real-Time in accordance with NEPOOL System Rules, based on the
schedule in the Day-Ahead Market, increases or decreases in
load, the occurrence of contingencies, and the submission of
new or modified Real-Time Demand Bids or Supply Offers, new or
modified Self-Schedules and new or modified Self-Supply
designations made in accordance with applicable Market Rules.
This dispatch shall also include adjustments to the Day-Ahead
Market schedule to reflect the activation of resources
scheduled for 4-Hour Reserve if necessary to maintain system
reliability.
(c) The amount of each category of Operating Reserve
designated in the Real-Time Market by the System Operator
shall be in accordance with the NEPOOL System Rules, shall
take into account the grid and generator configuration for the
Dispatch Day, and may be price sensitive in whole or in part
such that the required amount of Operating Reserve decreases
as the price for Operating Reserve increases. Any NEPOOL
System Rule in effect before the CMS/MSS Effective Date
designed to maintain reliability while producing just and
reasonable charges and payments for Operating Reserves during
times of emergency or shortages of available Energy and/or
Operating Reserves shall remain in effect on and after the
CMS/MSS Effective Date unless and until subsequently amended,
and may be in addition to or in lieu of the establishment of
price sensitive Operating Reserve requirements.
(d) A simultaneous optimization process shall be used to
determine the Energy, AGC and Operating Reserve to be provided
by each Resource in the Real-Time Market. This process shall
ensure that all portions of Resources with Supply Offers not
scheduled to provide Energy shall cascade to the markets for
AGC and Operating Reserves to the extent such Resources are
eligible to provide those services and consistent with Supply
Offer Prices established in accordance with Section 14A.4.
This process shall also ensure that all portions of Resources
with Supply Offers not dispatched to provide Energy may be
considered for meeting the requirements to provide AGC and
Operating Reserves.
(e) In selecting Resources to provide Operating Reserves and
AGC in Real-Time, the simultaneous optimization process shall
use the following principles: Resources that are Self-
Scheduled to provide Energy in accordance with applicable
Market Rules shall be reflected in the dispatch to the extent
they so perform, except as provided below; Resources that are
permitted by Market Rules to be designated for Self-Supply and
are so designated shall be reflected in the dispatch to the
extent they are so designated and perform or remain available,
except as provided below; Resources, to the extent not
scheduled or Self-Scheduled for Energy or designated for Self-
Supply and eligible to provide 10-Minute Spinning Reserve in
the Real-Time Market, shall be designated by the System
Operator based on their Lost Opportunity Costs, if any.
Resources, to the extent not scheduled or Self-Scheduled for
Energy or designated for Self-Supply and eligible to provide
10-Minute Non-Spinning Reserves or 30 Minute Operating
Reserves shall be designated based on the higher of their Lost
Opportunity Costs, if any, or their applicable Supply Offer
Prices. Generating units, to the extent they are not
scheduled or Self-Scheduled for Energy or designated for Self-
Supply and eligible to provide AGC, shall be designated based
on their Lost Opportunity Costs, if any, plus their Real-Time
Supply Offer Prices for AGC. The System Operator may direct
changes to any Self-Schedule and/or Self-Supply if, but only
to the extent, necessary for reliability.
(f) Supply Offers and Demand Bids at External Nodes will be
dispatched in the Real-Time Market based on the Real-Time
Supply Offer Price and Demand Bid Price, respectively, for the
hour. If the net aggregate amount of service pursuant to
eligible Supply Offers or Demand Bids at an External Node
would exceed the applicable interface limit, then Supply
Offers with the lowest price or the Demand Bids with the
highest price shall be scheduled. If such competing Supply
Offers and/or Demand Bids have the same prices, ties will be
broken or transactions pro rated in accordance with the Market
Rules.
14A.8 Settlement Obligation Payments for Energy, Operating
Reserves, 4-Hour Reserves and Automatic Generation Control.
(a) For each hour in which a Participant has a Settlement
Obligation for Energy at a Location in the Day-Ahead Market
pursuant to Section 14A.1(b), the Participant shall pay or
receive for the megawatthours of the Settlement Obligation at
that Location at the applicable Day-Ahead Market Locational
Price for that hour, as determined in accordance with Section
14A.12. For each hour in which a Participant has a Settlement
Obligation for Energy at a Location in the Real-Time Market
pursuant to Section 14A.1(b), the Participant either (i) shall
pay the applicable hourly Real-Time Market Locational Price
for the number of megawatthours, if any, by which the
Participant's Settlement Obligation for Energy received at
that Location in the Real-Time Market is more than the
Participant's Settlement Obligation for Energy received at
that Location in the Day-Ahead Market, or (ii) shall receive
the applicable hourly Real-Time Market Locational Price for
the number of megawatthours, if any, by which the
Participant's Settlement Obligation for Energy received at
that Location in the Real-Time Market is less than the
Participant's Settlement Obligation for Energy received at
that Location in the Day-Ahead Market, as determined in
accordance
with Section 14A.12. The Participant shall also pay any
applicable uplift charges under Section 14A.19. A
Participant shall pay the Zonal Price for Energy received
in a Load Zone unless it elects, in accordance with
applicable Market Rules, to pay the Nodal Price for such
Energy.
(b) For each hour in which a Participant has a Settlement
Obligation for Operating Reserve pursuant to Section 14A.1(c),
the Participant shall pay for Operating Reserve in each
category in which it has an obligation a percentage share of
the aggregate payments to Participants pursuant to Section
14A.9 for satisfying their Supply Obligations for each such
category of Operating Reserve for the hour equal to the
Participant's percentage share of the total Settlement
Obligations for Operating Reserve of such category for the
hour, as determined pursuant to Section 14A.1(c). In
addition, the Participant shall pay any applicable uplift
charge assessed under Section 14A.19.
(c) For each hour in which a Participant has a Settlement
Obligation for AGC pursuant to Section 14A.1(e), the
Participant shall pay a percentage of the aggregate payments
to Participants pursuant to Section 14A.9 for satisfying their
Supply Obligations for AGC for the hour equal to the
Participant's percentage share of the total Settlement
Obligation for AGC for the hour as determined pursuant to
Section 14A.1(e).
(d) For any hour in which the System Operator schedules 4-
Hour Reserves in the Day-Ahead Market, the aggregate payment
to Participants pursuant to Section 14A.9 for satisfying their
Supply Obligations for 4-Hour Reserves for the hour shall be
allocated to Participants and paid by them as follows:
Step 1. The hourly per Megawatt cost for 4-Hour
Reserve for the hour shall be determined by dividing
the total 4-Hour Reserve payments pursuant to
Section 14A.9 for the hour by the number of
Megawatts of 4-Hour Reserve scheduled in the Day-
Ahead Market to be available in the hour.
Step 2. If a Participant's Net Hourly Load
Obligation for Energy for the hour is positive and
exceeds the Participant's accepted Demand Bids for
the hour in the Day-Ahead Market, it shall pay for
each Megawatt of such excess the per Megawatt cost
determined in accordance with Step 1 above, but not
more than its pro rata share of the 4-Hour Reserve
cost for the hour.
Step 3. If the allocation in Step 2 above is
insufficient to recover the full 4-Hour Reserve cost
for the hour, the remaining cost shall be allocated
to all Participants for the hour, including those
required to make payments in accordance with Step 2,
in proportion to their shares of the aggregate Net
Hourly Load Obligation for Energy for the hour.
The provisions of Step 2 and Step 3 above are subject to
future modifications to comply with the Commission's June
28, 2000 order in Docket Nos. EL00-62-000, et al., and
future orders pertaining thereto, with respect to the
allocation of uplift costs and in light of filings
concerning the use of Net Hourly Load Obligation for
Energy as an allocation factor, and Steps 2 and 3 do not
become effective except pursuant to a future Commission
order.
14A.9 Supply Obligation Payments For Energy, Operating
Reserves, 4-Hour Reserves and Automatic Generation
Control.
(a) Subject to the provisions of Section 14A.16, each
Participant with a Supply Obligation for Energy in an hour in
the Day-Ahead Market at any Node or External Node shall
receive for each megawatthour scheduled at the Node or
External Node in the Day-Ahead Market the Day-Ahead Nodal
Price for the hour at that Node or External Node, as
determined in accordance with Section 14A.12. Subject to the
provisions of Section 14A.16, a Participant with a Supply
Obligation for Energy at any Node or External Node in an hour
in the Real-Time Market that is more than the Participant's
Supply Obligation for Energy at that Node or External Node for
the hour in the Day-Ahead Market, shall receive for each
additional megawatthour of such excess the Real-Time Market
Nodal Price for the hour at that Node or External Node, as
determined in accordance with Section 14A.12. Subject to the
provisions of Section 14A.16, each Participant with a Supply
Obligation for Energy at any Node or External Node in an hour
in the Real-Time Market that is less than the Participant's
Supply Obligation for Energy at that Node or External Node for
the hour in the Day-Ahead Market shall pay for each
megawatthour of such deficiency the Real-Time Market Nodal
Price for the hour at that Node or External Node, as
determined in accordance with Section 14A.12. In addition,
Participants may receive or be required to pay applicable
uplift charges, if any, pursuant to Section 14A.19 or the
Market Rules and to pay for 4-Hour Reserves pursuant to
Section 14A.8(d).
(b) Each Participant with a Supply Obligation for Operating
Reserve or 4-Hour Reserve in an hour in the Day-Ahead Market
shall receive for each Megawatt of each category of Operating
Reserve and/or 4-Hour Reserve scheduled the applicable Day-
Ahead Market Operating Reserve Clearing Price or 4-Hour
Reserve Clearing Price, as appropriate, as determined in
accordance with Section 14A.13. For any hour in which the
Participant's Supply Obligation for Operating Reserve of any
category in the Real-Time Market exceeds the Participant's
Supply Obligation for such service for the hour in the Day-
Ahead Market, the Participant shall receive for the additional
Megawatts the applicable Real-Time Market Operating Reserve
Clearing Price for the hour, as determined in accordance with
Section 14A.13. For any hour in which the Participant's
Supply Obligation for Operating Reserve of any category in the
Real-Time Market is less than the Participant's Supply
Obligation for such service for the hour in the Day-Ahead
Market, the Participant shall pay for each Megawatt of such
deficiency the applicable Real-Time Market Operating Reserve
Clearing Price for the hour, as determined in accordance with
Section 14A.13. If a Participant has a Supply Obligation for
4-Hour Reserve in any hour in the Day-Ahead Market and fails
to provide all or a portion of the Energy from its 4-Hour
Reserve in response to the System Operator's dispatch
instructions, the Participant shall pay the Real-Time Market
30-Minute Operating Reserve Clearing Price for each Megawatt
not provided, in addition to any payments required under
Section 14A.8(d).
(c) Each Participant with a Supply Obligation for AGC in an
hour in the Day-Ahead Market shall receive for the scheduled
amount the Day-Ahead Market AGC Clearing Price for the hour,
as determined in accordance with Section 14A.14. For any hour
in which the Participant's Supply Obligation for AGC in the
Real-Time Market exceeds the Participant's Supply Obligation
for AGC for the hour in the Day-Ahead Market, the Participant
shall receive for such excess the Real-Time Market AGC
Clearing Price for the hour, as determined in accordance with
Section 14A.14. For any hour in which the Participant's
Supply Obligation for AGC in the Real-Time Market is less than
the Participant's Supply Obligation for AGC for the hour in
the Day-Ahead Market, the Participant shall pay for such
deficiency the Real-Time Market AGC Clearing Price for the
hour, as determined in accordance with Section 14A.14.
(d) In no event shall Participants be paid lost opportunity
costs resulting from a generating unit being dispatched down
or off to accommodate transmission constraints, and nothing in
this Agreement or the Market Rules shall provide for any such
payment.
14A.10 Contract and Scheduling Authority.
(a) The Participants Committee is authorized to enter into
contracts on behalf of and in the names of all Participants
with Non-Participants to purchase or furnish emergency Energy
that is available for the System Operator to schedule in order
to ensure reliability in the NEPOOL Control Area or
neighboring Control Areas. For sales to another Control Area,
the terms of any such contractual arrangement shall not
require the furnishing of such emergency service until the
service needs of all Participants have been provided for with
the least expensive resources practicable. Emergency purchases
pursuant to this Section 14A.10 should not be required unless
the Participants have been unable to furnish such Supply
Offers as the System Operator determines are required to
ensure reliability. For emergency purchases and sales
pursuant to this Section 14A.10, the treatment of the
transaction with the Non-Participant in the determination of a
Locational Price shall be in accordance with applicable Market
Rules. Energy (and related services) from any such emergency
purchases shall be deemed to be furnished to and shall be paid
for by Participants with Settlement Obligations in the Real-
Time Market, in accordance with this Section 14A.10(a) and
applicable Market Rules.
(b) The NEU Management Committee (as defined in the HQ Use
Agreement) 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
14A.10(a). 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 any other HQ Contract shall be
deemed to be Energy furnished at the appropriate External Node
to each Participant which has submitted a Supply Offer at the
appropriate External Node for such Energy for the hour in the
amount reflected for the Participant in the System Operator's
scheduling of Energy deliveries in the hour from Hydro-Quebec;
except that emergency Energy received from Hydro-Quebec under
the HQ Interconnection Agreement shall be deemed to be Energy
provided to (and shall be paid for by) Participants requiring
such emergency Energy in the hour. The System Operator shall
schedule such Energy deliveries to accommodate, to the extent
possible, the schedule of Energy deliveries from Hydro-Quebec
requested by the Participants within their Supply Offers. The
Participants deemed to have received such Energy shall have a
corresponding Supply Obligation and shall satisfy this and all
other Supply Obligations at this External Node and all other
Nodes in accordance with Section 14A.1, 14A.8 and 14A.9. The
Participants are responsible for paying to Hydro-Quebec the
price for Energy deliveries under the HQ Phase II Firm Energy
Contract and under the HQ Energy Banking Agreement.
(c) The System Operator is authorized in accordance with
applicable Market Rules to enter into Reserve Contracts with
individual Participants under which the System Operator pays
for and receives options or rights to all or a portion of 10-
Minute Non-Spinning Reserve, 30-Minute Operating Reserve
and/or 4-Hour Reserve from generating units or Dispatchable
Loads for forward periods, such as a week or a month, as
determined by the System Operator. Such Reserve Contracts
shall be in accordance with applicable Market Rules and shall
be entered into with Participants which offer the service in
response to a request for proposals, shall include the Reserve
Price at which the Operating Reserve or 4-Hour Reserve will be
made available and the price at which Energy will be furnished
on the activation of the Operating Reserve or 4-Hour Reserve,
and shall contain standard terms and conditions specified by
the System Operator in accordance with the Market Rules.
14A.11 Bilateral Transactions and Participant Transactions with
Non-Participants.
(a) Two Participants may undertake to transfer all or select
portions of the Settlement Obligations of one of them under
this Agreement to the other Participant with respect to any of
the NEPOOL Markets pursuant to a Bilateral Transaction. Such
transfer of Settlement Obligations under this Agreement shall
be as agreed to between the two parties to the Bilateral
Transaction and shall be submitted to the System Operator in
accordance with the Market Rules. Each Bilateral Transaction
submitted shall specify whether the transaction is to settle
in the Day-Ahead Market or the Real-Time Market and, if it is
for Energy, a Location.
(b) In the event a Participant has the right to receive
Energy, Operating Reserve, 4-Hour Reserve and/or AGC from a
Non-Participant under a System Contract, such Contract may be
submitted to the System Operator in a Supply Offer as a
proposal to furnish Energy, Operating Reserve, 4-Hour Reserve,
and/or AGC, to the extent the System Contract permits central
dispatch by the System Operator in accordance with the Market
Rules and otherwise qualifies for such service.
14A.12 Determination of Locational Prices.
The System Operator shall calculate Locational Prices for the
Day-Ahead and Real-Time Markets as described below.
(a) Nodal Prices. The System Operator shall calculate the
Nodal Price at each Node for each hour of the Dispatch Day for
the Day-Ahead Market using the Day-Ahead unit commitment
model, and for the Real-Time Market using the Real-Time
scheduling software. In calculating Nodal Prices the System
Operator shall use the Demand Bids and Supply Offers submitted
pursuant to Sections 14A.3, 14A.4 and 14A.6. The Real-Time
Nodal Price at each Node for each hour shall be the time
interval weighted-average of the Clearing Prices calculated at
that Node for each time interval within that hour, except as
noted in subsection (d) below with respect to the prices used
for Real-Time settlements at External Nodes.
The System Operator shall calculate Nodal Prices for an
hour for the Day-Ahead Market or the Real-Time Market at
a given Node i using the following formula, or a formula
similar in substance and effect:
Y (i) = X r =+ Y L/i + Y c/i
where:
Y I= the Nodal Price at Node i in $/megawatthour;
X r= the marginal cost in $/megawatthour, based on
Demand Bids and Supply Offers, to serve
additional load at the Reference Node;
Y L/i=the Marginal Loss Component of the Nodal Price
at Node i in $/megawatthour; and
Y c/I=the Congestion Component of the Nodal Price at
Node i in $/megawatthour.
The Marginal Loss Component of the Nodal Price at any
Node i on the NEPOOL Transmission System is calculated
using the equation
Y L/I= (WF I - 1) X r
in which WFi, the Withdrawal Factor at Node i relative to
the system Reference Node, is calculated using the
following equation:
where:
L = NEPOOL Transmission System losses;
Pi = the net amount of Energy injected into the
NEPOOL Transmission System at Node i; and
= the ratio of: (1) the amount by which NEPOOL
Transmission System losses occurring in the
Day-Ahead Schedule or Real-Time dispatch would
have increased, as calculated by the System
Operator's Day-Ahead or Real-Time computer
algorithm, if a very small additional amount of
Energy had been injected at Node i (in addition
to the injections and withdrawals already
scheduled to occur on the NEPOOL Transmission
System in the Day-Ahead schedule or occurring
on the NEPOOL Transmission System in the Real-
Time dispatch), to (2) the size of the
additional injection of Energy at Node i.
The Congestion Component of the Nodal Price at Node i is
calculated using the equation:
where:
K = the set of thermal or interface constraints;
GFik = the Shift Factor for the generator at Node
i on constraint k in the pre- or post-
contingency case that limits flows across that
constraint; and
the reduction in system cost that results from
an incremental relaxation of constraint k,
expressed in $/megawatthour.
Substituting the equations for calculating the Marginal
Loss Component and the Congestion Component of the Nodal
Price for the terms into the equation for calculating the
Nodal Price for a given Node i yields:
(b) Zonal Prices. For Congestion pricing purposes, Load Zones
based on Reliability Regions have been established and Zonal
Prices shall be calculated by the System Operator for each
Load Zone. Each Load Zone shall be coterminous with a
Reliability Region, except that a Participant which owns and
operates distribution lines and other facilities used for the
distribution of Energy to retail customers in a single state
in New England and which is subject to regulation by the
public utility regulatory authority in that state (a
"Distribution Company"), which (i) serves retail customers in
more than one Reliability Region in a single state and (ii) is
subject to a state-imposed obligation to provide its retail
customers with a power supply at fixed prices for a limited
time period following the commencement of retail access
("Standard Offer Obligation"), may elect, by notice to the
System Operator and the Secretary of the Participants
Committee, within the time prescribed by the Market Rules, to
have its entire service territory treated as a single Load
Zone (a "Distribution Company Load Zone") until its Standard
Offer Obligation ends. In addition, Vermont shall be a single
Load Zone for those Distribution Companies in Vermont that
maintain their single Participant status for settlement
purposes with other Distribution Companies in Vermont pursuant
to Section 4 of the Agreement even if Vermont spans more than
one Reliability Region. The election by one or more
Distribution Companies in Vermont not to be treated as a
single Participant with other Vermont Participants shall not
affect the Load Zone for the remaining Distribution Companies
in Vermont maintaining the single Participant election.
After consulting with the Participants, the System
Operator may reconfigure Reliability Regions and add or
subtract Reliability Regions as necessary over time to
reflect changes to the grid, patterns of usage and
intrazonal Congestion. The System Operator shall file
any such changes with the Commission.
The System Operator shall calculate Zonal Prices for each
Reliability Region for both the Day-Ahead and Real-Time
Markets for each hour using a load-weighted average of
the Nodal Prices for the Nodes within that Reliability
Region. The load weights used in calculating the Day-
Ahead Zonal Prices for the Reliability Region shall be
determined in accordance with applicable Market Rules and
shall be based on the Demand Bids for the Nodes that make
up that Reliability Region. The System Operator shall
determine, in accordance with applicable Market Rules,
the load weights used in Real-Time based on the
calculated Real-Time load distribution. The System
Operator shall calculate Zonal Prices for Reliability
Regions using the following formula, or a formula similar
in substance and effect, where the Zonal Price for a
Reliability Region j can be written as:
where:
= Zonal Price for Reliability Region j in
$/megawatthour;
is as defined in Section 14A.12(a);
is the Marginal Loss Component of the Zonal Price
for Reliability Region j in $/megawatthour;
is the Congestion Component of the Zonal Price for
Reliability Region j in $/megawatthour;
Nj = the set of Nodes that make up the
Reliability Region j; and
Wij = the load-weighting factor for Node i used
to calculate the Zonal Price for
Reliability Region j, determined such that
the weighting factors for any given
Reliability Region sum to one.
For a Distribution Company Load Zone, the Zonal Price
shall be determined by the weighted average of the Zonal
Prices for the Reliability Regions making up the Load
Zone, with the weights equal to that Distribution
Company's share of the load in each of those Reliability
Regions. The load weights used in calculating the Day-
Ahead Zonal Prices for the Distribution Company Load
Zones shall be determined in accordance with applicable
Market Rules and shall be based on the Demand Bids for
the Nodes that make up the Distribution Company Load
Zones.
The System Operator shall determine, in accordance with
applicable Market Rules, the load weights used in Real-
Time based on the calculated Real-Time load distribution.
The System Operator shall calculate Zonal Prices for
each hour of the Dispatch Day for Distribution Company
Load Zones using the following formula: Zonal Price
equals the Distribution Company's load in each
Reliability Region making up the Distribution Company
Load Zone times the Zonal Price for each such Reliability
Region summed for all such Reliability Regions making up
the Distribution Company Load Zone, divided by the sum of
the Distribution Company's load in each Reliability
Region making up the Distribution Company Load Zone. The
Congestion and Marginal Loss Components of the Zonal
Price for each Distribution Company Load Zone shall be
calculated as the weighted average of the Congestion and
Marginal Loss Components, respectively, of the Zonal
Prices in the Reliability Regions making up that Load
Zone, using the same weights that are used to calculate
the Zonal Price for that Distribution Company Load Zone.
(c) Hub Prices. On behalf of the Participants, the System
Operator shall maintain and facilitate the use of a Hub or
Hubs for the Energy market, comprised of a set of Nodes within
NEPOOL, which Nodes shall be identified by the System Operator
on its Internet website. The System Operator has used the
following criteria to establish an initial Hub and shall use
the same criteria to establish any additional Hubs:
(i) each Hub shall contain a sufficient number of Nodes
to try to ensure that a Hub Price can be calculated for
that Hub at all times;
(ii) each Hub shall contain a sufficient number of Nodes
to ensure that the unavailability of, or an adjacent line
outage to, any one Node or set of Nodes would have only a
minor impact on the Hub Price;
(iii) each Hub shall consist of Nodes with a
relatively high rate of service availability;
(iv) each Hub shall consist of Nodes among which
transmission service is relatively unconstrained; and
(v) no Hub shall consist of a set of Nodes for which
directly connected load and/or generation at that set of
Nodes is dominated by any one entity or its affiliates.
The System Operator shall calculate hourly Hub Prices for
both the Day-Ahead and Real-Time Markets using a fixed-
weighted average of the Nodal Prices that comprise the
Hub. The System Operator shall calculate Hub Prices
using the following formula, or a formula similar in
substance and effect, where the Hub Price for a Hub j can
be written as:
where:
Y h/j= Hub Price for Hub j in $/megawatthour;
Formula is as defined in Section 14A.12(a);
is the Marginal Loss Component of the Hub Price for
Hub j in $/megawatthour;
is the Congestion Component of the Hub Price for Hub
j in $/megawatthour;
H j= the set of Nodes in Hub j; and
the load weighting factor for Node i used to
calculate the Hub Price for Hub j, determined such
that the weighting factors for any given Hub sum to
one.
Participants may transfer their Settlement Obligations at
the Hub Price in the Day-Ahead and Real-Time Markets
pursuant to Bilateral Transactions. In accordance with
Section 14A.8 of the Agreement, Participants with
Settlement Obligations for Energy at the Hub shall pay or
be charged the Hub Price for such Settlement Obligations.
(d) Nodal Prices for External Nodes. The System Operator
shall calculate Nodal Prices for External Nodes. The External
Nodes shall be identified in applicable Market Rules.
External Nodes shall be used for pricing Energy transactions
by
Participants receiving Energy from or delivering Energy
to neighboring Control Areas. The Nodal Prices for
External Nodes shall be calculated in the same way as
Nodal Prices for Nodes, with the exception of the
calculation of the Marginal Loss Component of the price.
The Marginal Loss Component of Nodal Prices for External
Nodes shall be calculated so as to ensure that it does
not include the effect of withdrawals at a Node or
External Node on the cost of losses incurred outside the
NEPOOL Control Area. In order to accomplish this, a
hypothetical transaction will be modeled, in which an
increment of load at each External Node is served by an
increment of generation at the Reference Node. The
amount of Energy that would flow out of the NEPOOL
Transmission System over each interconnection point
between the NEPOOL Transmission System and an adjoining
Control Area or the Non-PTF transmission system will be
calculated next. Finally, the Marginal Loss Component of
the Nodal Price at each External Node will be calculated
as the weighted average of the Marginal Loss Components
at each of the interconnection points between the NEPOOL
Transmission System and an adjoining Control Area or the
Non-PTF transmission system. The weight assigned to each
interconnection will be equal to the proportion of the
total amount of Energy delivered off of the NEPOOL
Transmission System in association with this hypothetical
transaction that flows over that interconnection. As a
result, the Marginal Loss Component of the price at each
External Node will only include the effects on Marginal
Losses on the NEPOOL Transmission System.
The Shift Factors for each External Node determine the
proportion of the Energy in such a transaction that would
flow over each interconnection point between the NEPOOL
Transmission System and external Control Areas or the
Non-PTF transmission system and, therefore, the Marginal
Loss Component of the Nodal Price at an External Node i
shall be calculated using the following equation, or a
formula similar in substance and effect:
where:
= the Marginal Loss Component of the Nodal Price
at an External Node i in $/megawatthour;
I= the set of interconnection points between the
NEPOOL Transmission System and adjacent Control
Areas or the Non-PTF transmission system;
GF in= Shift Factor at External Node i for the
interconnection line that passes through Node n; and
Formula = the Marginal Loss Component of the Nodal
Price at Node n in $/megawatthour, where WFn is the
withdrawal factor at Node n and formula is as
defined in Section 14A.12(a).
The price used for Real-Time settlements at External
Nodes will be the Real-Time price as determined based on
the Real-Time dispatch except in the circumstance in
which imports or exports were constrained in the hour
ahead scheduling process either by constraints that are
not monitored in Real-Time or by closed interface
constraints that are not affected by internal
dispatchable generators. In this special circumstance,
the price used for Real-Time settlements of imports from
External Nodes will be the lower of the Real-Time price
at the External Node or the hour ahead price at the
External Node. Similarly, in this situation, the price
used for Real-Time settlements of exports to External
Nodes will be the higher of the Real-Time price at the
External Node or the hour ahead price at the External
Node.
(e) Additional Rules and Procedures. Consistent with this
Section 14A.12, the implementation of its provisions shall
further be detailed, defined and carried out pursuant to
Market Rules.
14A.13 Determination of Operating Reserve and 4-Hour Reserve
Clearing Prices
(a) Operating Reserve and 4-Hour Reserve shall be scheduled
in the Day-Ahead Market and designated in the Real-Time Market
in accordance with the simultaneous optimization processes
described in Sections 14A.5 and 14A.7, respectively, and the
NEPOOL System Rules. As a result, in the Day-Ahead Market and
Real-Time Market, the respective Clearing Price for an hour
for 10-Minute Spinning Reserve shall equal or exceed the
Clearing Price for 10-Minute-Non-Spinning Reserve, which shall
equal or exceed the Clearing Price for 30-Minute Operating
Reserve, which shall equal or exceed the Clearing Price for 4-
Hour Reserve.
(b) For each hour, in accordance with the NEPOOL System
Rules, the System Operator shall calculate the Operating
Reserve Clearing Price for each category of Operating Reserve
in the Day-Ahead Market and the Real-Time Market as follows:
(i) The System Operator shall determine the aggregate
Megawatts of the applicable category of Operating Reserve
that are scheduled for the hour in the Day-Ahead Market
or designated for the hour in the Real-Time Market.
(ii) For each category of Operating Reserve in each of
the Day-Ahead Market and Real-Time Market, the System
Operator shall rank in the order of lowest to highest the
Reserve Prices, Lost Opportunity Costs and Supply Offer
Prices, as applicable, of the Resources scheduled by the
System Operator for that category of Operating Reserve
for the hour for the Day-Ahead Market or designated each
interval during the hour in the Real-Time Market.
(iii) The Operating Reserve Clearing Price per
Megawatt for each category of Operating Reserve in each
Market shall be the time-weighted average of the highest
Reserve Prices, Lost Opportunity Costs or Supply Offer
Prices, as applicable, for that category of Operating
Reserve that are scheduled for the hour in the Day-Ahead
Market or designated each interval during the hour in the
Real-Time Market by the System Operator, as determined in
accordance with the applicable Market Rules.
(a) For each hour in the Day-Ahead Market for which the
System Operator calculates it requires 4-Hour Reserves, the
System Operator shall determine the 4-Hour Reserve Clearing
Price as follows:
(i) The System Operator shall determine the aggregate
Megawatts of 4-Hour Reserves scheduled for the hour in
the Day-Ahead Market.
(ii) The System Operator shall rank from lowest to
highest the Reserve Prices, Lost Opportunity Costs and
Supply Offer Prices, as applicable, of the Resources
scheduled for 4-Hour Reserves for the hour in the Day-
Ahead Market.
(iii) The 4-Hour Reserve Clearing Price per Megawatt
in the Day-Ahead Market shall be the highest Reserve
Prices, Lost Opportunity Costs or Supply Offer Prices, as
applicable, for 4-Hour Reserves that are scheduled by the
System Operator for the hour in accordance with
applicable Market Rules.
(b) The System Operator shall calculate a Lost Opportunity
Cost for each hour for a Resource, other than Dispatchable
Load, which shall, for each increment of Supply Offer
Megawatts, be equal to the product of (i) the amount, if any,
by which the Nodal Price for the hour at the Node or External
Node where Energy from the Resource would be supplied in the
Day-Ahead Market or Real-Time Market exceeds the Resource's
Energy Supply Offer Price, for that increment of Supply Offer
Megawatts, for that market and (ii) the additional Megawatts,
in that increment of Supply Offer Megawatts, the Resource
would have been scheduled or dispatched to in the Day-Ahead
Market or Real-Time Market, respectively, had it been
scheduled or dispatched to supply Energy at the Megawatt level
specified in its Supply Offer relating to its Supply Offer
Price and operating parameters.
14A.14 Determination of AGC Clearing Price.
For each hour, the System Operator shall determine an AGC
Clearing Price for the Day-Ahead Market and for the Real-Time
Market. In the case of each Market, the AGC Clearing Price
shall be the time-weighted average "AGC Capability Price," as
defined below in this Section 14A.14. The AGC Capability
Price for a generating unit furnishing AGC per the System
Operator's schedule for the hour in the Day-Ahead Market or
designated each interval during the hour in the Real-Time
Market shall be equal to (A) the cost per unit of making the
AGC capability of a generating unit available based on the AGC
Supply Offer Price for the Entitlement for the hour, plus any
Lost Opportunity Cost, divided by (B) the amount of AGC
scheduled in the hour in the Day-Ahead Market or designated in
the interval in the Real-Time Market from that Resource. The
AGC Capability Price used to determine the AGC Clearing Price
shall be the highest AGC Supply Offer for the generating units
that, in the case of the Day-Ahead Market, were scheduled by
the System Operator to provide AGC for the hour, or, in the
case of the Real-Time Market, were designated each interval
during the hour to provide AGC beyond their Supply Obligations
for AGC in the Day-Ahead Market.
14A.15 Funds to or from which Payments are to Be Made.
(a) All payments for Energy (except for payments to or from
the Congestion Revenue Fund and the Marginal Loss Revenue
Fund), Operating Reserve, 4-Hour Reserve and AGC furnished or
received, all uplift charges paid pursuant to this Section 14A
of this Agreement, and any payments by Non-Participants for
ancillary services under Schedules 2 through 7 to the Tariff
or pursuant to arrangements referenced in Section 14A.10,
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
14A.15(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 14A.10(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 14A.10(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 14A.10(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:
(iii)(A) amounts owed to Non-Participants (other
than Hydro-Quebec) for the month under contracts
entered into with them pursuant to Section 14A.10(a)
shall be paid, and (B) amounts owed to Hydro-Quebec
for the month for Energy deemed to be furnished
pursuant to Section 14A.10(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 applicable Locational Price, the
excess, if any, of such Locational Price over the
amount owed to Hydro-Quebec shall be paid to the
Participant; and
(iv) amounts owed to Participants for the month
pursuant to this Section 14A 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 from their share of the Energy Banking Fund the
amount to which they are entitled for such service in
accordance with Section 14A.9.
(ii) amounts required to be paid to Hydro-Quebec under
the HQ Energy Banking Agreement shall be paid from the
shares of the Fund of the Participants engaging in
transactions under the HQ Energy Banking Agreement for
the month in accordance with their respective interests
in the transactions for the month. If there is not
enough in any such share, the Participants with the
deficient shares shall be billed and pay into their
shares of the Fund the amounts required for payments to
Hydro-Quebec.
(iii) subject to the remaining provisions of this
Section, at the end of each month any balance remaining
in each Participant's share of the HQ Energy Banking Fund
shall (I) in the case of any Participant which is not a
participant in the Phase I or Phase II arrangements with
Hydro-Quebec, be paid to such Participant, and (II) in
the case of any Participant which is a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be
paid to the Escrow Agent under the HQ Use Agreement to be
held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use
Agreement, and shall be allocated between the
Participant's share of said Funds as follows:
(A) the balance remaining in the Participant's
share of the HQ Energy Banking Fund for
the month shall be divided by the number
of kilowatthours deemed to be received by
the Participant under the HQ Energy
Banking Agreement during the month to
determine an average savings amount per
kilowatthour;
(B) for any hour during the month in which the
number of kilowatthours received by NEPOOL
under the HQ Energy Banking Agreement
exceeded the HQ Phase I Transfer
Capability, an amount equal to (a) the
Participant's share of the excess of (1)
the number of kilowatthours received over
(2) the HQ Phase I Transfer Capability
times (b) the average savings amount per
kilowatthour determined for that
Participant under (A) 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
14A.10(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 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 II HQ Savings Fund created
thereunder in accordance with each Participant's contribution
to such balance.
14A.16 Marginal Losses.
(a) Marginal Loss Cost. Marginal Loss cost shall be
reflected in and recovered through the Marginal Loss
Components of Locational Prices. Participants pay for
Marginal Loss cost by paying the Locational Price for Energy.
Locational Prices shall be calculated in accordance with
Section 14A.12 of the Agreement and Schedule 13 of the Tariff.
(b) Marginal Loss Revenue. To the extent that there is any
Marginal Loss Revenue in any settlement period, such revenue
shall be collected in a Marginal Loss Revenue Fund and
allocated to load-serving entities in proportion to their Net
Hourly Load Obligations for Energy in accordance with the
Market Rules.
(c) Additional Rules and Procedures. Consistent with this
Section 14A.16, the implementation of its provisions shall
further be detailed, defined and carried out pursuant to
Market Rules.
14A.17 Congestion Cost and Revenues.
(a) Congestion Cost. When Congestion exists, Congestion Cost
shall be reflected in and recovered through the Congestion
Components of Locational Prices. Participants pay for
Congestion Costs by paying the Locational Price for Energy.
Locational Prices shall be calculated in accordance with
Section 14A.12 of the Agreement and Schedule 13 of the Tariff.
(b) Congestion Revenue. For each hour of the Dispatch Day in
the Day-Ahead and Real-Time Markets, the System Operator shall
calculate and collect Congestion Revenue and maintain a
Congestion Revenue Fund.
(c) Additional Rules and Procedures. Consistent with this
Section 14A.17, the implementation of its provisions shall
further be detailed, defined and carried out pursuant to
Market Rules.
14A.B Market Monitoring and Reports.
(a) The System Operator shall complete and circulate to the
Participants Committee and post on its Internet website for
each month a market monitoring report. The monthly report
shall be completed no later than sixty (60) days after the
close of the calendar month of market activities covered by
the report and shall contain the following information for
each Load Zone and Reliability Region: (a) separately
identified Congestion Costs, RMR Uplift and any other amounts
that are paid for by Load Zone and/or Reliability Region, (b)
the number of Supply Offers from Participants that were not
Related Persons of each other and that were capable of meeting
the marginal load within the Load Zone and/or Reliability
Region to the extent that the number falls below limits
prescribed in the Market Rules, (c) the aggregate import
limitation to the Load Zone and/or Reliability Region, (d) the
existence and a description of internal transmission
constraints within the Load Zone and/or Reliability Region and
(e), to the extent disclosure can be made consistent with the
NEPOOL Information Policy, patterns of behavior that the
System Operator has identified in the course of market
monitoring that may affect price or other charges that are
paid for Energy in the Load Zone and/or Reliability Region in
a manner not consistent with the conditions that would prevail
in a competitive market. If the System Operator has not
commenced or taken corrective action with respect to Supply
Offers, Demand Bids, or other behavior inconsistent with the
conditions that would prevail in a competitive market
identified in one of its monthly reports within thirty (30)
days of the issuance of that report, any Participant may
commence a complaint proceeding at the Commission to seek
remediation of such behavior. The Participant or Participants
initiating such a complaint proceeding shall, upon the
issuance of a protective order by the Commission covering
confidentiality and other relevant matters and subject to the
terms of such protective order, be entitled to access to the
data underlying the System Operator's conclusions as to
behavior inconsistent with conditions that would prevail in a
competitive market. The ability to initiate such a complaint
proceeding at the Commission shall not prejudice the ability
of such complaining Participant or Participants to pursue
market power issues in any other forum. Nothing in this
section shall preclude any Participant from contesting, in the
context of a proceeding involving the issuance of a protective
order by the Commission, the disclosure or other release of
confidential information.
(a) Studies Related to Congestion. The System Operator shall
perform, on an ongoing basis, an evaluation of the
effectiveness, efficiency and workability of the each of the
main components of the CMS, including, without limitation, the
system of Locational Prices and FCRs. Within sixty (60) days
after the first anniversary of the CMS/MSS Effective Date, the
System Operator shall issue a written report to the
Participants Committee at least ten (10) business days prior
to a Participants Committee meeting for discussion and shall
not further distribute that report publicly until after the
Participants Committee meeting. Such report shall contain in
detail the System Operator's evaluations, conclusions and
recommendations, if any, for changes to the CMS. To the
extent practicable, the System Operator shall retain all data
necessary to analyze the CMS.
(b) Day-Ahead Market Information Reports. The System
Operator shall make available as provided below for the Day-
Ahead Market each day in accordance with the Market Rules and
in a way that is consistent with the NEPOOL Information Policy
the following items, but not limited to:
(i) Each Participant shall be notified of the following:
(A) The set of accepted Supply Offers for
Resources, including Supply Offers at External
Nodes, that will define the prices and
quantities of the Participant's Supply
Obligations for the Dispatch Day with respect
to Energy, Operating Reserve, 4-Hour Reserve
and AGC for each hour in the Day-Ahead Market.
These schedules shall define expected start-
up, loading levels, and shut down schedules for
the Participant's Resources.
(B) The set of accepted Demand Bids, including
Demand Bids at External Nodes, that will define
the Participant's Settlement Obligations to pay
for a specified quantity of Energy at each
specified Location for each hour in the Day-
Ahead Market.
(ii) the System Operator shall publish on a daily basis
the following information:
(A) Day-Ahead Locational Prices for each hour of
the Dispatch Day determined in accordance with
Section 14A.12, as well as all non-confidential
data and assumptions used by the System
Operator to calculate each such price. These
prices will include Nodal Prices at all Nodes
and External Nodes for Resources, Zonal Prices
for each Load Zone, and Hub Prices for each
Hub. In posting Locational Prices, the System
Operator shall include all components of such
prices, including the Nodal Price at the
Reference Node, the Marginal Loss Component,
and the Congestion Component.
(B) The aggregate quantities of Supply Offers and
Demand Bids accepted in each hour of the Day-
Ahead Market.
(C) Hourly Clearing Prices and the amounts
scheduled in the Day-Ahead Market for Operating
Reserves, 4-Hour Reserves, and AGC.
(D) The System Operator's load forecast for each
hour of the Dispatch Day compared to accepted
Demand Bids.
(E) The projected Net Supply Offer Shortfall Uplift
as determined pursuant to Section 14A.19(a) and
RMR Uplift and costs for voltage support for
each Reliability Region.
(c) Real-Time Market Information Reports. The System
Operator shall publish for the Real-Time Market during the
Dispatch Day, in a way that is consistent with the NEPOOL
Information Policy the following items, but not limited to:
(i) Real-Time Market Locational Prices, including the
Nodal Prices (including External Nodes), Zonal Prices,
and Hub Prices, as well as all non-confidential data and
assumptions used by the System Operator to calculate each
such price. As far in advance of each hour of the Real-
Time Market as is feasible, the System Operator shall
post its estimate of the Locational Prices for the
remainder of the Dispatch Day.
(ii) As far in advance of each hour of the Real-Time
Market as is feasible, updates to the load forecast.
(iii) Hourly Clearing Prices and amounts designated
in the Real-Time Market for Operating Reserves and AGC.
(iv) Actual loads compared to forecasted load and
accepted Demand Bids.
(d) Special Reporting. The System Operator shall publish
with the Real-Time Market information the following data
concerning emergency purchases and sales and Reserve Contracts
entered into pursuant to Section 14A.10:
(i) The hourly price and schedule for Energy under the
emergency purchase or sale.
(ii) Prices and quantities at which the Operating Reserve
or 4-Hour Reserve are scheduled or designated by the
System Operator for the hour pursuant to Reserve
Contracts.
14A.19 Additional Uplift Charges.
(a) Net Supply Offer Shortfall Uplift. It is anticipated
that a generating unit may be scheduled by the System Operator
in the Day-Ahead Market for all or part of a day when the
Supply Offer Costs (as defined below) exceed the aggregate
revenues received pursuant to this Section 14A for the
generating unit from all Day-Ahead Markets. A Net Supply
Offer Shortfall Uplift shall be calculated as provided in this
Section 14A.19 to provide for payment of this shortfall to the
affected generator and allocation of such difference. Except
as provided below, each generating unit scheduled by the
System Operator in the Day-Ahead Market shall be entitled to
receive its Supply Offer Costs, provided that the foregoing
evaluation shall be made only on an aggregate basis for the
total hours scheduled to supply Energy, Operating Reserves, 4-
Hour Reserves, and/or AGC in the Dispatch Day and not on an
individual hour-by-hour basis, and shall be made only on a
single Day-Ahead Market basis, so that, for example, the net
shortfall for a unit scheduled for a particular Dispatch Day
shall be entitled to this treatment only for the hours in that
first Dispatch Day in that Day-Ahead Market even if the unit's
minimum run time extends beyond the Dispatch Day. Any
shortfall between Supply Offer Costs and aggregate market
revenues in the subsequent period during uninterrupted
operation of the Resource for hours that extend beyond the
satisfaction of the Resource's minimum run time, will be
addressed through the Net Supply Offer Shortfall Uplift
determined for that Dispatch Day. Cost responsibility for
this difference shall be allocated among Participants in
accordance with subsection (c) of this Section 14A.19 for
those hours in which the generating unit is scheduled to
provide service during the Dispatch Day, with the allocation
among such hours determined in accordance with applicable
Market Rules.
For purposes of this Section 14A.19, "Supply Offer Costs"
for a generating unit shall mean the aggregate of the
Start-Up Price, if applicable, plus the summation for the
Dispatch Day of the No Load Price in each applicable hour
and the product in each applicable hour of the applicable
Supply Offer Prices and the amounts of Energy, Operating
Reserve, 4-Hour Reserve and AGC scheduled from the unit
in the Day-Ahead Market.
The Net Supply Offer Shortfall Uplift is calculated as
the Supply Offer Costs of a generating unit minus the
aggregate revenues received by a Participant for the
amounts of Energy, Operating Reserve, 4-Hour Reserve and
AGC scheduled from the unit in the Day-Ahead Market for
that Dispatch Day.
A Participant with an Entitlement in a generating unit
that is Self-Scheduled in the Day-Ahead Market shall only
be entitled to receive payment of a Net Supply Offer
Shortfall Uplift associated with the unit during hours
that the unit is not Self-Scheduled. The calculation of
Net Supply Offer Shortfall Uplift for a Self-Scheduled
unit shall exclude No-Load costs for the hours the unit
is Self-Scheduled and include revenues associated with
the difference between the applicable Clearing Price and
Supply Offer Price for the service from the unit beyond
the Self-Scheduled service. If the System Operator
schedules a generating unit to start-up and operate in
the hours immediately prior to, and/or continue operation
for a period beyond, the hours for which the unit was
Self-Scheduled in the Day-Ahead Market, the Start-Up
Price shall not be included in Supply Offer Costs for the
purpose of determining whether the generating unit is
entitled to receive a Net Supply Offer Shortfall Uplift
for the hours of the Dispatch Day for which the unit was
not Self-Scheduled.
(b) Real-Time Uplift. There may be circumstances where the
Real-Time Nodal Price for Energy paid to a generating unit in
the Real-Time Market is less than the Real-Time Supply Offer
Price for the generating unit. These circumstances may be
caused by the time-weighted averaging calculation of the Real-
Time Market Nodal Prices or as a result of the System Operator
dispatching certain fast response generating units within an
hour in response to anticipated system conditions in that
hour. In such circumstances, the generating unit shall
receive a Real-Time Uplift equal to the difference between the
Real-Time Nodal Price and the corresponding Supply Offer Price
for those megawatthours produced at the higher Supply Offer
Price but only to the extent those megawatthours were produced
pursuant to the dispatch instructions of the System Operator
as described in the Market Rules.
(c) Allocation of Net Supply Offer Shortfall Uplift. Where
payment is due to a Participant under Section 14A.19(a), the
aggregate amount of such payments shall be recovered from
Participants, including the Participant to which such payment
is made, as an uplift charge to be paid in accordance with
this Section 14A.19(c).
Net Supply Offer Shortfall Uplift will first be allocated
among the Energy market and the three Operating Reserve
Markets based on cost causation principles in accordance
with applicable Market Rules. Net Supply Offer Shortfall
Uplift will be allocated to specific markets to the
extent that the benefit of incurring the uplift is
recognized in that market because incurring the uplift
relieved an otherwise binding constraint affecting the
Clearing Price in that market. To the extent that
incurrance of the uplift benefits more than one market
such uplift will be allocated pro rata to all four
markets in accordance with the aggregate Settlement
Obligations (in dollars) in the Energy and Operating
Reserve markets adjusted as specified in the Market
Rules.
Charges for Net Supply Offer Shortfall Uplift allocated
to the Day-Ahead Energy Market ("Regional Energy Uplift")
shall be determined for each hour and paid by each
Participant in accordance with the following formula:
DACH = (UCa) (X dai - SS dai)
(Xda - SSda )
in which
DACH is the amount to be paid by the Participant
pursuant to this Section 14A.19(c) provided
that if this amount is negative the Participant
shall neither pay nor receive credit for such
amount.
UCa is the sum for the hour of uplift payments to
generators made pursuant to Section 14A.19(a)
in the Day-Ahead Market.
Xdai is the Settlement Obligation for Energy of the
Participant for the hour in the Day-Ahead
Market adjusted for Bilateral Transactions as
to which both the buyer(s) and the seller(s)
elect or have elected to transfer Regional
Energy Uplift obligations in the Day-Ahead
Market with respect to any Bilateral
Transaction in accordance with the Market
Rules.
Xda is the aggregate Settlement Obligation for
Energy of all Participants for the hour in the
Day-Ahead Market adjusted for Bilateral
Transactions as to which both the buyer(s) and
the seller(s) elect or have elected to transfer
Regional Energy Uplift obligations in the Day-
Ahead Market with respect to any Bilateral
Transactions in accordance with the Market
Rules.
SSdai is the amount of the Participant's Self-
Supply of its Day-Ahead Settlement Obligation
for Energy that is actually supplied in the
Real-Time Market from the Self-Scheduled
Resources of the Participant.
SSda is the aggregate of Participants' Self-Supply
of their Day-Ahead Settlement Obligations for
Energy that are supplied in the Real-Time
Market from the Self-Scheduled Resources of
those Participants.
Charges for Net Supply Offer Shortfall Uplift allocated
to each Operating Reserve Market ("Regional Operating
Reserve Uplift") shall be determined for each hour and
paid by each Participant in accordance with an equivalent
calculation to that specified for the Energy Market, as
follows. The calculation for each Operating Reserve
Market will be specified in the Market Rules and will be
based on the Settlement Obligation for the relevant
category of Operating Reserve after accounting for those
Bilateral Transactions described in the definitions of
Xdai and Xda above with respect to the relevant category
of Operating Reserve.
(d) Allocation of Real-Time Uplift. Where payment is due to
a Participant under Section 14A.19(b), the aggregate amount of
such payments shall be recovered from Participants, including
the Participant to which such payment is made, as an uplift
charge to be paid in accordance with this Section 14A.19(d).
Charges for Real-Time Uplift allocated to Participants in
the Real-Time Energy Market ("Real-Time Energy Uplift")
shall be determined for each hour and paid by each
Participant in accordance with the following formula:
RTCH = (UCb) (Xrti - SSrti )
(Xrt - SSrt )
in which
RTCH is the amount to be paid by the Participant
pursuant to this Section 14A.19(d) provided
that if this amount is negative the Participant
shall neither pay nor receive credit for such
amount.
UCb is the sum for the hour of uplift payments to
generators made pursuant to Section 14A.19(b)
in the Real-Time Market.
Xrti is the Settlement Obligation for Energy of the
Participant for the hour in the Real-Time
Market adjusted for Bilateral Transactions as
to which both the buyer(s) and the seller(s)
elect or have elected to transfer Real-Time
Energy Uplift obligations in the Real-Time
Market with respect any Bilateral Transaction
in accordance with the Market Rules.
Xrt is the aggregate Settlement Obligation for
Energy of all Participants for the hour in the Real-Time
Market adjusted for Bilateral Transactions as to which
both the buyer(s) and the seller(s) elect or have elected
to transfer Real-Time Energy Uplift obligations in the
Real-Time Market with respect to any Bilateral
Transactions in accordance with the Market Rules.
SSrti is the amount of the Participant's Self-
Supply of its Real-Time Settlement Obligation
for Energy that is actually supplied in the
Real-Time Market from the Self-Scheduled
Resources of the Participant.
SSrt is the aggregate of Participants' Self-Supply
of their Real-Time Settlement Obligations for
Energy that are supplied in the Real-Time
Market from the Self-Scheduled Resources of
those Participants.
(e) Uplift Allocation And Pre-Existing Contracts. With
respect to any Bilateral Transaction entered into prior to
September 26, 2000 (the "Effective Date"), the allocation of
Regional Energy Uplift cost responsibility, Regional Operating
Reserve Uplift cost responsibility and Real-Time Energy Uplift
cost responsibility provided for in Sections 14A.19(c) and
14A.19(d) shall not alter the obligations of either the buyer
or seller under such Bilateral Transaction as of the date
immediately prior to the Effective Date without the agreement
of both the buyer and seller.
(f) RMR Uplift. It is also anticipated that it may be
necessary from time to time to schedule a Participant's
generating unit or Dispatchable Load to provide Operating
Reserve in one or more hours at prices for Operating Reserve
that exceed the applicable Clearing Price for that Operating
Reserve service in the Day-Ahead Market in order to satisfy
locational Operating Reserve requirements in a particular
Reliability Region or Reliability Regions in accordance with
applicable Market Rules. When this occurs the Participant
providing such service shall be entitled to receive for the
Dispatch Day the aggregate of the applicable Supply Offer
Prices for Operating Reserve to provide the requested
Operating Reserve service for all of the scheduled hours in
the Dispatch Day. This comparison of Supply Offer Price
against Clearing Price for the applicable Operating Reserve
products shall be made on an aggregate basis for all hours
scheduled in the Day-Ahead Market for that Dispatch Day, and
not on an individual hour-by-hour basis.
Where payment is made to a Participant under these
circumstances, the amount by which the payment to the
Participant exceeds the amount that would be paid if the
Participant had only received the applicable Day-Ahead
Market Operating Reserve Clearing Prices for the
scheduled service during the hours in question shall be
recovered as RMR Uplift from Participants which are
obligated to pay under the Settlement Obligations for
Operating Reserve associated with load in the affected
Reliability Region or Reliability Regions for the hours
during which the service is scheduled in the Dispatch
Day.
Except as provided below, RMR Uplift shall be paid by
each Participant for each hour in accordance with the
following formula:
CHd = UCd)(ELi ) + ADJrr
ELrr
in which
CHd is the amount to be paid by a Participant
pursuant to this Section 14A.19(f) for RMR
Uplift for the affected Reliability Region(s).
UCd is the aggregate RMR Uplift payments to
Participants for the hour for out of merit
services for the affected Reliability Region(s)
to be allocated and paid pursuant to this
Section 14A.19(f).
ELi is the number of kilowatthours of Electrical
Load of the Participant for the hour in the
affected Reliability Region(s).
ELrr is the aggregate number of kilowatthours of
Electrical Load of all Participants for the
hour in the affected Reliability Region(s).
ADJrr is the total uplift charge adjustment for the
Participant required to reflect Operating
Reserve that the Participant has Self-Supplied
and all Bilateral Transactions entered into by
the Participant for the transfer of Settlement
Obligations for Operating Reserve pursuant to
Section 14A.1(c) for the hours to the extent
that each Bilateral Transaction is not
reflected in the Participant's Electrical Load
for the hour. The adjustment for each
Bilateral Transaction shall equal the pro rata
portion of the transferring Participant's
Operating Reserve Settlement Obligations
covered by such Bilateral Transaction. The
adjustment shall be negative for all Bilateral
Transactions under which the Participant
transfers its Settlement Obligations for
Operating Reserve to another Participant; the
adjustment shall be positive for all Bilateral
Transactions under which the Participant
assumes the Settlement Obligations for
Operating Reserve of another Participant.
Notwithstanding the foregoing, the first six million
dollars ($6,000,000) of the RMR Uplift under this Section
14A.19(f) shall be allocated for each hour among and paid
by all Participants which have Settlement Obligations for
Operating Reserve for the hour in accordance with the
formula in Section 14A.1(c) for each of the following two
periods:
(i) the twelve-month period commencing on the
CMS/MSS Effective Date; and
(ii) the period commencing on the first anniversary
of the CMS/MSS Effective Date and ending on December 31,
2004.
Any such RMR Uplift in excess of six million dollars
($6,000,000) with respect to either period shall be
allocated among and paid by the Participants with
Settlement Obligations for Operating Reserve associated
with load in the affected Reliability Region(s) in
accordance with the formula of this Section 14A.19(f).
[Next Sheet is 199]
PART FOUR
TRANSMISSION PROVISIONS
SECTION 15
OPERATION OF TRANSMISSION FACILITIES
15.1 Definition of PTF. PTF or pool transmission facilities are
the transmission facilities owned by Participants rated 69 kV or
above required to allow energy from significant power sources to
move freely on the New England transmission network, and include:
1. All transmission lines and associated facilities owned by
Participants rated 69 kV and above, except for lines and
associated facilities that contribute little or no
parallel capability to the NEPOOL Transmission System (as
defined in the Tariff). The following do not constitute
PTF:
(a) Those lines and associated facilities which are
required to serve local load only.
(b) Generator leads, which are defined as radial
transmission from a generation bus to the nearest point
on the NEPOOL Transmission System.
(c) Lines that are normally operated open.
2. Parallel linkages in network stations owned by
Participants (including substation facilities such as
transformers, circuit breakers and associated equipment)
interconnecting the lines which constitute PTF.
3. If a Participant with significant generation in its
transmission and distribution system (initially 25 MW) is
connected to the New England network and none of the
transmission facilities owned by the Participant qualify
to be included in PTF as defined in (1) and (2) above,
then such Participant's connection to PTF will constitute
PTF if both of the following requirements are met for
this connection:
(a) The connection is rated 69 kV or above.
(b) The connection is the principal transmission link
between the Participant and the remainder of the New
England PTF network.
4. Rights of way and land owned by Participants required for
the installation of facilities which constitute PTF under
(1), (2) or (3) above.
The 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.
15.2 Maintenance and Operation in Accordance with Accepted Electric
Industry 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 Accepted Electric Industry Practice.
15.3 Central Dispatch. Each Participant which owns or operates PTF
or other transmission facilities rated 69 kV or above shall, to the
fullest extent practicable, subject all such transmission
facilities owned or operated by it to central dispatch by the
System Operator; provided, however, that each Participant shall at
all times be the sole judge as to whether or not and to what extent
safety requires that at any time any of such facilities will be
operated at less than their full capability or not at all.
15.4 Maintenance and Repair. Each Participant shall, to the
fullest extent practicable: (a) cause transmission facilities owned
or operated by it to be withdrawn from operation for maintenance
and repair only in accordance with maintenance schedules reported
to and published by the System Operator in accordance with
procedures approved or established by the 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.
15.5 Additions to or Upgrades of PTF. The possible need for an
addition to or upgrade of PTF may be identified in connection with
the planning process of Section 51 of the Tariff, an application or
request for service under the Tariff, or 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.
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 Schedules 11
and 12 of the Tariff, including without limitation the
provisions relating to responsibility for the costs of new PTF
or modifications or other upgrades to PTF exceeding regional
system, regulatory or other public requirements set forth in
Section (3)(b) of Schedule 11 to the Tariff and Schedule 12 of
the Tariff.
Sheet 206 is intentionally blank.
SECTION 16
SERVICE UNDER TARIFF
16.1 Effect of Tariff. The Tariff specifies the terms and
conditions under which the Participants will provide regional
transmission service through NEPOOL. This Section 16 specifies
various rights and obligations with respect to the revenues to be
collected by NEPOOL for the Participants under the Tariff and
related matters.
16.2 Obligation to Provide Regional Service. The Participants
which own PTF shall collectively provide through NEPOOL regional
transmission service over their PTF facilities, and the facilities
of their Related Persons which constitute PTF in accordance with
Section 15.1, to other Participants and other Eligible Customers
pursuant to the Tariff. The Tariff provides open access for all of
the types of regional transmission service required by Participants
and other Eligible Customers over PTF and it is intended to be the
only source of such service, except for service provided for
Excepted Transactions.
16.3 Obligation to Provide Local Network Service. Each Participant
which owns transmission facilities other than PTF shall provide
service over such facilities to other Participants or other
Eligible Customers connected to the Transmission Provider's
transmission system pursuant to a tariff (a "Local Network Service
Tariff") filed by the Transmission Provider with the Commission. A
Participant is also obligated to provide service under its Local
Network Service Tariff or otherwise (i) to permit a Participant or
other Entity with an Entitlement in a generating unit in the
Participant's local network to deliver the output of the generating
unit to an interconnection point on PTF and (ii) to permit the
delivery to an Eligible Customer taking Internal Point-to-Point
Service under the Tariff of the Energy and/or capacity covered by
its Completed Application for that Internal Point-to-Point Service.
A Local Network Service Tariff shall provide:
(i) for a pro rata allocation of monthly revenue
requirements not otherwise paid for through charges to
Eligible Customers for Local Point-to-Point Service among
the Transmission Provider's Network Customers receiving
service under the tariff on the basis of their loads
during the hour in the month in which the total connected
load to the Local Network is at its maximum, without any
adjustment for credits for generation;
(ii) for the recovery under the Local Network Service
Tariff from 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;
(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 Year
One Two Three Four Five
and Six
____ ____ _____ _____ ________
% of 100 % 80% 60% 40% 20%
charge
to be
paid
(i) that if the Transmission Provider receives a
distribution pursuant to Section 16.6 from NEPOOL out of
revenues paid for Through or Out Service, the amounts
received shall reduce its Local Network Service revenue
requirements; and
(ii) 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.
16.4 Transmission Service Availability. The availability of
transmission capacity to provide transmission service under the
Tariff shall be determined in accordance with the Tariff. In
determining the availability of transmission capacity, existing
committed uses of the Participants' transmission facilities shall
include uses for existing firm loads and reasonably forecasted
changes in such loads, and for Excepted Transactions.
16.5 Transmission Information. Information concerning (i)
available transmission capacity, (ii) transmission rates and (iii)
system conditions that may give rise to Interruptions or
Curtailments shall be made available to all Participants and Non-
Participants through the OASIS on a timely and non-discriminatory
basis. All Participants owning PTF or other transmission
facilities rated 69 kV or higher shall make available to the System
Operator the information required to permit the maintenance of the
OASIS in compliance with Commission Order 889 and any other
applicable Commission orders; provided that no Participant shall be
required to furnish information which is required to be treated as
confidential in accordance with NEPOOL policy without appropriate
arrangements to protect the confidentiality of such information.
16.6 Distribution of Transmission Revenues. Payments required by
the Tariff for the use of the NEPOOL Transmission System shall be
made to NEPOOL and shall be distributed by it in accordance with
this Section 16.6.
A. Regional Network Service Revenues. Revenues received by
NEPOOL for providing Regional Network Service each month
during the Transition Period shall be distributed to 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 Year Year Year Year Year
One Two Three Four Five Six
Allocated 25% 20% 15% 10% 5% 2.5%
Flows:
Annual 75% 80% 85% 90% 95% 97.5%
Trans-
Mission
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.
A. 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.
B. 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.
C. 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.
D. 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.
[Next Sheet is 216]
SECTION 17
POOL-PLANNED UNIT SERVICE
17.1 Effective 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.
17.2 Obligation 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.
17.3 Rules for Determination of Facilities Covered by Particular
Transactions. It is anticipated that it may be necessary with
respect to a particular transmission use under subsection (a), (b)
or (c) of Section 17.2 to determine whether the transaction is
effected entirely over PTF, entirely over facilities that are not
PTF, or partially over each.
The following rules shall be controlling in the determination
of the facilities required to effect the use:
(a) To the extent that EHV PTF is available to effect the
transaction, over all or part of the distance to be covered,
the use shall be deemed to be effected on such EHV PTF over
such portion of the distance to be covered.
(b) To the extent that EHV PTF is not available for the
entire distance to be covered by the use, but Lower Voltage
PTF is available to cover all or part of the distance not
covered by EHV PTF, the transaction shall be deemed to be
effected on such Lower Voltage PTF.
If a Participant has ownership or contractual rights with
respect to an Excepted Transaction which are independent
of this Agreement and the Tariff and are adequate to
provide for a transfer of the types specified in
subsections 17.2(a), (b) or (c), and such rights are not
limited to the transfer in question, the transfer shall
be deemed to have been effected pursuant to such rights
and not pursuant to the provisions of this Agreement. A
copy of each instrument establishing such rights, or an
opinion of counsel describing and authenticating such
rights, shall be filed with the Secretary of the
Participants Committee.
17.4 Payments for Uses of EHV PTF During the Transition Period.
(a) Each Participant shall pay each month for its uses of EHV
PTF for transfers of Entitlements pursuant to subsections (a)
or (b) of Section 17.2, one-twelfth of the NEPOOL EHV PTF
Participant Summer or Winter Wheeling Rate in effect for the
calendar year ending December 31, 1996, as determined in
accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its current Entitlements which qualify for transfer
pursuant to subsections (a) or (b) of Section 17.2, except as
otherwise provided in Section 17.3; provided that such payment
shall be required with respect to only one-half the Kilowatts
covered by a NEPOOL Exchange Arrangement (as hereinafter
defined).
Each Participant which is a party to the HQ Phase II Firm
Energy Contract (other than a Participant (i) whose
system is directly interconnected to the HQ
Interconnection or (ii) which has contractual rights
independent of this Agreement and the Tariff which give
it direct access to the HQ Interconnection and which are
not limited to transfers of Energy delivered over the HQ
Interconnection) shall also pay each month for the use of
EHV PTF for deliveries under the Phase II Firm Energy
Contract during the Base Term of the HQ Phase II Firm
Energy Contract, one-twelfth of the NEPOOL EHV PTF
Participant Summer or Winter Wheeling Rate in effect for
the calendar year ending December 31, 1996, as determined
in accordance with the Prior NEPOOL Agreement, for each
Kilowatt of its HQ Phase II Net Transfer Responsibility
for the month. If, and to the extent that, such
Responsibility continues for any period by which the term
of said Contract extends beyond the Base Term, each such
Participant shall continue to pay the above rate during
the extension period with respect to its continuing
Responsibility. A Participant shall not be deemed to be
directly interconnected to the HQ Interconnection for
purposes of this paragraph solely because of its
participation in arrangements for the support and/or use
of PTF facilities installed or modified to effect
reinforcements of the New England AC transmission system
required in connection with the HQ Interconnection. A
copy of each contract establishing rights independent of
this Agreement and the Tariff which provides direct
access to the HQ Interconnection, or an opinion of
counsel describing and authenticating such rights, shall
be filed with the Secretary of the 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.
17.5 Payments for Uses of Lower Voltage PTF. Each Participant
which uses another Participant's Lower Voltage PTF pursuant to this
Section 17 shall pay each month to the owner of such Lower Voltage
PTF (1) for each Kilowatt of its use of such Lower Voltage PTF for
transfer of Entitlements pursuant to Subsections 17.2(a), (b) or
(c) during the month, and (2) during the Base Term of the HQ Phase
II Firm Energy Contract (and during any extension of the term of
said Contract if and to the extent its HQ Phase II Net Transfer
Responsibility continues during the extension period) for each
Kilowatt of its HQ Phase II Net Transfer Responsibility for the
month, the owner's Lower Voltage PTF Winter Wheeling Rate or Summer
Wheeling Rate for the 1996 calendar year, as determined in
accordance with the Prior NEPOOL Agreement; 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.
17.6 Use 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.
17.7 Limits on Individual Transmission Charges. Any charges for
transmission service pursuant to this Section 17 by any Participant
to another Participant shall be just, reasonable and not unduly
discriminatory or preferential. No provision of this Section 17
shall be construed to waive the right of any Participant to seek
review of any charge, term or condition applicable to such
transmission service by another Participant by the Commission or
any other regulatory authority having jurisdiction of the
transaction.
[Next Sheet is 225]
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.1 Each 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.2 Nothing 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.
17A.3 Each 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.4 The 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.5 Each 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.6 Each Transmission Owner retains the right to take
whatever actions it deems necessary to fulfill its obligations
under local, state or federal law.
17A.7 In 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.
(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.
[Next Sheet is 230]
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
18.1 Designation of Pool-Planned Facilities. At the request of a
Participant, the Participants Committee shall designate as "pool-
planned" a generating or transmission facility, for purposes of
Chapter 164, Sections 11-22 of the Massachusetts General Laws, to
be constructed by the Participant or its Related Person if the
Participants Committee determines that the facility is consistent
with NEPOOL planning. Designation of a transmission facility as a
Pool-Planned Facility does not determine whether or not the
facility is PTF. 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.
18.2 Construction of Facilities. Subject to Sections 13.1, 15.2,
15.5, 18.3, 18.4 and 18.5, and to the provisions of the Tariff,
each Participant shall have the right to determine whether, and to
what extent, additions to and modifications in its generating and
transmission facilities shall be made. However, each Participant
shall give due consideration to recommendations made to it by the
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.
18.3 Protective Devices for Transmission Facilities and Automatic
Generation Control Equipment. Each Participant shall install,
maintain and operate such protective equipment and switching,
voltage control, load shedding and emergency facilities as the
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.
18.4 Review 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 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.
18.5 Participant 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
19.1 Annual 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 Small End User or an
End User Organization shall pay an annual fee of $500.
(b) Each End User Participant which is a Large End User 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 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.
19.2 NEPOOL 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.
19.3 Restructuring 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 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 from the date of payment to
August 18, 2000 at the rate of 8% per annum, and thereafter 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 files as a supplement to the
Tariff. Each month during the first twenty 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 /A1 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.
A is 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.
A1 is 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/B1 in which
Y is the percentage to be received for a month by
a Participant or other Entity of the aggregate
amount to be received pursuant to this
subsection (b) by all Participants or other
Entities for the month.
B is the amount of Early Restructuring Expense
paid by the Participant or other Entity which
has not previously been reimbursed.
B1 is the aggregate amount of Early Restructuring
Expense paid by all Participants and other
Entities which has not previously been
reimbursed.
Notwithstanding the foregoing, the Participants will
amend the Agreement by November 1, 2000 to specify how
the balance of the Early Restructuring Expense is to be
paid. It is also understood that the Commission could
order refunds and reallocations with respect to amounts
collected under Schedule 2 of the ISO Tariff for 2000.
To the extent such refunds and reallocations are ordered
by the Commission, refunds and reallocations of Early
Restructuring Expenses shall also be made so that the
total amount of Early Restructuring Expenses collected
from each Participant in 2000 shall be proportionate to
the amount ultimately due from such Participant in 2000
under Schedule 2 of the ISO Tariff.
(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.
(a) The Participants agree to amend the Agreement within
eighteen 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 with such amendment to become
effective on January 1, 2001, or on such other date as the
Commission shall provide that such amendment shall become
effective.
(b) 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
SECTION 20 INDEPENDENT SYSTEM OPERATOR
(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 Accepted
Electric Industry 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, 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.
(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
(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.
A. 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.
(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.
B. 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.
(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.
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:
if the arbitration process does not result in a
decision within the time period specified and
the proceeding is initiated within thirty days
after the expiration of such time period; or
on the grounds specified in Sections 10 and 11
of Title 9 of the United States Code for
judicial vacation or modification of an
arbitration award and the proceeding is
initiated within thirty days of the issuance of
the arbitrator's decision.
(6) Other Disputes: In the event a dispute arises with
a Non-Participant which receives or is eligible to
receive service under this Agreement or the Tariff with
respect to such service, the Non-Participant shall have
the right to have the dispute considered by the
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 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 the
Participant fails to meet this requirement for continuation of
service, the actions described in subsection (d) of this
Section 21.2 may be taken. If a Participant disputes a NEPOOL
invoice with respect to charges for transmission service 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.
(d) In the event a Participant fails to pay when due in
accordance with NEPOOL System Rules (including, without
limitation, the NEPOOL Billing Policy attached to the Tariff
(the "Billing Policy")) all amounts invoiced to it by NEPOOL,
or by the ISO on behalf of NEPOOL (a "Payment Default"), or
the Participant fails to comply with the Financial Assurance
Policy for NEPOOL Members attached to the Tariff (the "Member
Financial Assurance Policy"), or the Participant fails to
perform any other obligations under the Agreement or the
Tariff, and such failure continues for at least ten days,
NEPOOL, or the ISO on behalf of NEPOOL, may (but shall not be
required to) notify such Participant in writing,
electronically and by first class mail sent in each case to
such Participant's member or alternate on the Participants
Committee or billing contact, that it is in default, and
NEPOOL may initiate a proceeding before the Commission to
terminate such Participant's status as a Participant. Either
simultaneously with the giving of the notice described in the
preceding sentence or within ten days thereafter (unless the
default or failure giving rise to such notice is cured during
such period), NEPOOL, or the ISO on behalf of NEPOOL, shall
notify each other member and alternate on the Participants
Committee and each Participant's billing contact of the
identity of the Participant receiving such notice, whether
such notice relates to a Payment Default, to a failure to
comply with the Member Financial Assurance Policy, or to
another failure to perform obligations under the Agreement or
the Tariff, and the actions the ISO plans to take and/or has
taken in response to such default or failure. 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 notice and the initiation of such
proceeding, in accordance with
[Next Sheet is 265]
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.
21.3 Assignment. The Agreement shall inure to the benefit of, and
shall be binding upon, the successors and assigns of the respective
signatories hereto, but no assignment of a signatory's interests or
obligations under the Agreement or any portion thereof shall be
made without the written consent of the 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.
21.4 Force Majeure. A Participant shall not be considered to be in
default in respect of any obligation hereunder if prevented from
fulfilling such obligation by an event of Force Majeure. An event
of Force Majeure means any act of God, labor disturbance, act of
the public enemy, war, insurrection, riot, fire, storm or flood,
explosion, breakage or accident to machinery or equipment, any
Curtailment, any order, regulation or restriction imposed by a
court or governmental military or lawfully established civilian
authorities, or any other cause beyond a Participant's control,
provided that no event of Force Majeure affecting any Participant
shall excuse that Participant from making any payment that it is
obligated to make under this Agreement. A Participant whose
performance under this Agreement is hindered by an event of Force
Majeure shall make all reasonable efforts to perform its
obligations under this Agreement, and shall promptly notify the
Participants Committee of the commencement and end of any event of
Force Majeure.
21.5 Waiver of Defaults. No waiver of the performance by a
Participant of any obligation under this Agreement or with respect
to any default or any other matter arising in connection with this
Agreement shall be effective unless given by the 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.
21.6 Other Contracts. No Participant shall be a party to any other
agreement which in any manner is inconsistent with its obligations
under this Agreement.
21.7 Liability and Insurance.
(a) Each Participant will indemnify and save each of the
other Participants, its officers, directors and Related
Persons (each an "Indemnified Party") harmless from and
against all actions, claims, demands, costs, damages and
liabilities asserted by a third party against the Indemnified
Party seeking indemnification and arising out of or relating
to bodily injury, death or damage to property caused by or
sustained on facilities owned or controlled by such
Participant that are the subject of this Agreement, or caused
by a failure to act in accordance with this Agreement by the
Participant from which indemnification is sought, except (i)
to the extent that such liabilities result from the negligence
or willful misconduct of the Participant seeking
indemnification, and (ii) each Participant shall be
responsible for all claims of its own employees, agents and
servants growing out of any workmen's compensation law. The
amount of any indemnity payment under the provisions of this
Section 21.7 shall be reduced (including, without limitation,
retroactively) by any insurance proceeds or other amounts
actually recovered by the Indemnified Party in respect of the
indemnified action, claim, demand, cost, damage or liability.
Notwithstanding the foregoing, no Participant shall be liable
to any Indemnified Party for any claim for loss of profits or
revenues, attorneys' fees or costs, cost of capital or
financing, loss of goodwill or cost of replacement power
arising from a Participant's carrying out, or failing to carry
out, any obligations contemplated by this Agreement or for any
other indirect, incidental, special, consequential, punitive,
or multiple damages or loss; provided, however, that nothing
herein shall reduce or limit the obligations of any
Participant to Non-Participants.
(b) Each Participant shall furnish, at its sole expense, such
insurance coverage as the Participants Committee may
reasonably require with respect to its obligation pursuant to
Section 21.7(a).
21.8 Records and Information. Each Participant shall keep such
records as may reasonably be required by a NEPOOL committee or the
System Operator, and shall furnish to such committee or the System
Operator such records, reports and information (including
forecasts) as it may reasonably require, provided the
confidentiality thereof is protected in accordance with NEPOOL's
information policy.
21.9 Consistency with NPCC and NERC Standards. The standards,
criteria and rules adopted by NEPOOL committees under this
Agreement shall be consistent with those adopted by the NPCC and
NERC or any successor to either.
21.10 Construction.
(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.
21.11 Amendment. 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.
21.12 Termination. 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.
21.13 Notices 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.
(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.
21.14 Severability and Renegotiation. If any provision of this
Agreement is held by a court or regulatory authority of competent
jurisdiction to be invalid, void or unenforceable, the remainder of
the terms, provisions, covenants and restrictions of this Agreement
shall continue in full force and effect and shall in no way be
affected, impaired or invalidated, except as otherwise explicitly
provided in this Section.
If any provision of this Agreement is held by a court or
regulatory authority of competent jurisdiction to be invalid,
void or unenforceable, or if the Agreement is modified or
conditioned by a regulatory authority exercising jurisdiction
over this Agreement, the Participants shall endeavor in good
faith to negotiate such amendment or amendments to this
Agreement as will restore the relative benefits and
obligations of the Participants under this Agreement
immediately prior to such holding, modification or condition.
If after sixty days such negotiations are unsuccessful the
Participants may exercise their withdrawal or termination
rights under this Agreement.
21.15 No 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.
21.16 Counterparts. 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.
Sheet Nos. 279 through 299 are reserved for future use.
ATTACHMENT A
METHODOLOGY FOR
DETERMINATION OF
TRANSMISSION FLOWS
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.
A. 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
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.
ATTACHMENT B
NEPOOL OPEN ACCESS TRANSMISSION TARIFF
See FERC Electric Tariff, Fourth Revised Volume 1.
ATTACHMENT C
RELIABILITY REGIONS
Exhibit 10(g)
NATIONAL GRID USA SERVICE COMPANY, INC.
25 Research Drive
Westborough, Massachusetts 01582
SERVICE CONTRACT
January 1, 2001
National Grid USA Service Company, Inc.
25 Research Drive
Westborough, MA 01582
National Grid USA Service Company, Inc. (hereinafter called
Service Company) is a company engaged primarily in the rendering of
services to companies in the National Grid USA holding-company
system. The organization, conduct of business and method of cost
allocation of the Service Company are designed to meet the
requirements of Section 13 under the Public Utility Holding Company
Act of 1935 and the rules and regulations promulgated thereunder to
the end that services performed by the Service Company for said
associate companies will be rendered to them at cost, fairly and
equitably allocated. Services will be rendered by Service Company
only upon receipt from time to time of specific or general request
therefor. Said requests may always be modified or canceled by you
at your discretion. The parties hereto agree as follows:
1. The Service Company agrees to furnish you upon the terms
and conditions herein set forth such of the services described in
Schedule 1 hereto as you may from time to time request. Service
Company will also furnish, if available, such services not
described in Schedule 1 as you may request. Notwithstanding the
foregoing the Service Company shall not furnish under this
agreement any engineering, construction, or maintenance services
for a nuclear generating plant.
2. The Service Company has and will maintain a staff trained
and experienced in the provision of services of a general and
administrative nature. In addition to the services of its own
staff, Service Company will, after consultation with you concerning
services to be rendered pursuant to your request, arrange for
services of non-affiliated experts, consultants, accountants and
attorneys.
3. All of the services rendered under this agreement will be
at actual cost thereof. Direct charges will be made for services
where a direct allocation of cost is possible. The methods of
determining such costs and the allocation thereof are set forth in
Schedule II hereto. These methods are reviewed annually and more
frequently, if appropriate. Such methods may be modified or
changed by Service Company without the necessity of an amendment of
this agreement provided that in each instance all services rendered
hereunder will be at actual cost thereof, fairly and equitably
allocated, and all in accordance with the requirements of the
Public Utility Holding Company Act of 1935 and the rules and
regulations and orders thereunder. You will be advised from time
to time of any material changes in such methods.
4. Bills will be rendered during the first week of each month
covering amounts due for the month calculated on an estimated basis
using the actual expenses incurred to the extent possible during the
second previous month. This estimated amount would be adjusted on
the bill to be rendered by the conclusion of the following month.
Any amount remaining unpaid after fifteen days following receipt of
the bill shall bear interest thereon from the date of the bill at an
annual rate of 2% above the lowest interest rate then being charged
by the Fleet Bank on 90 day commercial loans. Services will be
performed hereunder for not more than one year commencing January 1,
2001, and continuing through December 31, 2001, unless terminated at
an earlier date by either party giving thirty days' written notice to
the other of such termination at the end of any month.
5. This agreement will be subject to termination or
modification at any time to the extent its performance may conflict
with any federal or state law or any rule, regulation or order of a
federal or state regulatory body having jurisdiction. The agreement
shall be subject to approval of any federal or state regulatory body
whose approval is a legal prerequisite to its execution and delivery
or performance.
NATIONAL GRID USA SERVICE COMPANY, INC.
S/John G Cochrane
By:_____________________________________
Treasurer
Accepted: January 31, 2001
Exhibit 10(aa)(ii)
AMENDMENT NO. 3
TO
WHOLESALE SALES AGREEMENT
Amendment No. 3 dated as of December 23, 1999 by and among New
England Power Company, a Massachusetts corporation ("NEP") and
USGen New England, Inc. (formerly named USGen Acquisition
Corporation), a Delaware corporation ("USGenNE"), and Constellation
Power Source, Inc. ("CPS"), a Delaware corporation, ("Amendment")
to the Wholesale Sales Agreement, dated as of August 5, 1997 and
amended as of September 25, 1997 and September 1, 1998 ("Sales
Agreement"), by and among NEP and USGenNE. NEP, USGenNE and CPS
may be referred to herein individually as a "Party" or together as
the "Parties."
Whereas USGenNE and CPS intend that USGenNE will assign all of
its rights and obligations under the Sales Agreement to CPS
effective March 1, 2000, and NEP will release USGenNE from all
further liabilities and obligations under the Sales Agreement
effective as of the date of such assignment.
NOW, THEREFORE, in consideration of the premises and
considerations and warranties, covenants and other agreements
hereinafter set forth, the parties hereto, intending to be legally
bound hereby, agree as follows:
1) Definitions. All capitalized terms have the meaning set forth
herein, and if not defined herein, have the meaning set forth in
the Sales Agreement.
2) Effective Date. This Amendment is effective upon execution
and binding upon the parties, their successors and assigns upon
execution and thereafter.
3) Assignment. Effective 12:01 a.m. on March 1, 2000, USGenNE
hereby sells, assigns, conveys, transfers and delivers to CPS,
and CPS hereby assumes from USGenNE, all of USGenNE's right,
title, interest, claim and demand in, to and under the Sales
Agreement and all of its obligations thereunder; provided that,
USGenNE shall not assign the obligations incurred, its right to
recovery of damages, or the exercise of remedies and
indemnification as provided pursuant to the Sales Agreement for
events or causes occurring prior to March 1, 2000
("Assignment").
4) Recognition Of, and Consent To, Assignment. NEP acknowledges
and consents in accordance with Article 10, Section 10.1 of the
Sales Agreement, to the Assignment.
5) Release. NEP releases, holds harmless and forever discharges
USGenNE and each of its affiliates, including PG&E Corporation,
a California corporation, from any and all claims, liabilities,
obligations, and indemnities relating to any event or cause
occurring on or after March 1, 2000 arising under or with
respect to the Sales Agreement. NEP hereby waives and all
rights and benefits that it now has, or in the future may have,
conferred upon it by virtue of any statute or common law
principle that provides that a general release does not extend
to claims which a Party does not know or suspect in its favor at
the time of executing the release. Nothing herein relieves
USGenNE, or any of its affiliates, of any claim, liability,
obligation or indemnity relating to any event or cause occurring
prior to March 1, 2000 and arising under or relating to the
Sales Agreement. For further certainty, USGenNE agrees to pay
all amounts accrued or due pursuant to ARTICLE 5 of the Sales
Agreement related to deliveries of Wholesale Nuclear
Entitlements that occurred prior to March 1, 2000.
6) Amendments As Of The Effective Date. The following amendments
will become effective as of 12:01 a.m. on March 1, 2000:
a) All references to "Buyer" in the Sales Agreement will be
deemed to refer to CPS, which shall thereafter exercise all
of the right, title, interest, claim and demand in, to and
under the Sales Agreement and all of the obligations
thereunder designated as those of Buyer.
b) In ARTICLE 2 of the Sales Agreement, the definition of
"Wholesale Standard Offer Service Agreements" is amended by
replacing the existing definition with the following:
Wholesale Standard Offer Service Agreements. The
agreements dated as of September 1, 1998 entered into by
USGen New England, Inc. ("USGenNE") with Massachusetts
Electric Company and Nantucket Electric Company (jointly,
"MECO") and The Narragansett Electric Company ("NECO"),
as such agreements may be amended or assigned (in whole
or in part) from time to time, which cumulatively entitle
the seller(s) thereunder to deliver to MECO and NECO,
respectively, 90.78% of the requirements of such
companies for wholesale standard offer service as
provided therein.
c) The second paragraph of ARTILCE 4, Section 4.2 is amended
by adding at the end of such paragraph the following:
Buyer further acknowledges and agrees that NEP is
pursuing the sale or other disposition of all of its
Nuclear Interests and that, upon the sale or other
disposition of any of NEP's Nuclear Interests, NEP shall
be released from any further obligation to deliver to
Buyer any Wholesale Nuclear Entitlement relating to such
Nuclear Interest. For the avoidance of doubt, the phrase
" other disposition" as used in this Section 4.2 and
Section 3.1, shall mean (i) in the case of Seabrook Unit
1 or Millstone Unit 3, a termination of NEP's entitlement
to power produced by the applicable unit in a
circumstance involving the transfer of all of NEP's
interest as a joint owner therein to a non-affiliated
third party or (ii) in the case of Vermont Yankee, a
termination of NEP's obligation to purchase power from
the unit in a circumstance involving a transfer of
ownership of the Vermont Yankee Nuclear Power Station by
its owner, Vermont Yankee Nuclear Power Corporation, to a
non-affiliated third party.
d) The last paragraph of ARITLCE 5, Section 5.1(b) of the
Sales Agreement (as amended by Amendment 1 to the Sales
Agreement), is amended by replacing the existing text with
the following:
Unless and until such time as USGenNE assigns any of all
of its rights, interests and obligations under the
Wholesale Standard Offer Service Agreements to CPS, 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 (cumulatively, by each
and every seller) during the month or (b) the total
number of megawatt-hours delivered by NEP from the
Purchased Quantity for the month.
As of such time as USGenNE assigns any or all of its
rights, interests and obligations under the Wholesale
Standard Offer Service Agreements to CPS, 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
sum of (x) the number of megawatt-hours delivered by CPS
to MECO under its agreement with MECO for the delivery of
wholesale standard offer service, multiplied by .9078 and
divided by the percentage of the total requirements of
MECO for wholesale standard offer service that CPS is
entitled to provide and (y) the number of megawatt-hours
delivered by CPS to NECO under its agreement with NECO
for the delivery of wholesale standard offer service,
multiplied by .9078 and divided by the percentage of the
total requirements of NECO for wholesale standard offer
service that CPS is entitled to provide or (b) the total
number of megawatt-hours delivered by NEP from the
Purchased Quantity for the month.
e) ARTICLE 8, Section 8.1 of the Sales Agreement is amended
to replace Buyer's address with the following:
Sarah Wright
Constellation Power Source, Inc.
111 Market Place
Suite 500
Baltimore, Maryland 21202
phone: (410) 468-3483
fax: (410) 468-3540
With a copy to:
David M. Perlman, General Counsel
Constellation Power Source, Inc.
111 Market Place
Suite 500
Baltimore, Maryland 21202
phone: (410) 468-3490
fax: (410) 468-3499
f) ARTICLE 10, Section 10.1 (ii) of the Sales Agreement is
amended by replacing "PG&E Corporation" with "Constellation
Energy Group" and by deleting the phrase "; provided,
further, however, that no such assignment and assumption
shall relieve or in any way discharge PG&E Corporation from
the performance of its duties and obligations under the
Guaranty dated as of the date of this Agreement executed by
PG&E Corporation," at the end of such Section.
g) The Sales Agreement is amended by the addition of the
following new ARTICLE 21.
ARTICLE 21. CREDIT SUPPORT; SET OFF
21.1 Buyer Credit Support. If at any time during the
term of this Agreement Buyer's Net Worth (as defined
below) falls below One Hundred Twenty Five Million
Dollars ($125,000,000) and at such time Buyer does not
have a credit rating on its senior unsecured debt
securities of at least Investment Grade (as defined
below), then within ten (10) business days after a
request from NEP, Buyer shall deliver credit support to
NEP in an amount equal to Ten Million Dollars
($10,000,000) and, at Buyer's election, in the form of
either: (a) a performance bond issued by a surety company
with a rating of "B+" or better from A.M. Best Company;
(b) a letter of credit directed to NEP from a commercial
bank with long-term debt ratings of "Baa2" or better
from Moody's Investors Service, Inc. ("Moody's") and
"BBB" or better from Standard & Poor's Corporation
("S&P"); or (c) a guaranty from an affiliate of Buyer
that has an Investment Grade rating on its senior
unsecured debt securities. Such credit support shall be
available to be drawn upon by NEP in the event that an
event of default occurs with respect to Buyer hereunder
and shall otherwise be in form and substance reasonably
acceptable to NEP. For purposes of the Article 21, "Net
Worth" shall mean total assets (exclusive of intangible
assets) less total liabilities as reflected on a balance
sheet prepared in accordance with generally accepted
accounting principles consistently applied and
"Investment Grade" shall mean (i) with regard to a credit
rating assigned by Moody's, a credit rating equal to or
better than "Baa3"; and (ii) with regard to a credit
rating assigned by S&P, a credit rating equal to or
better than "BBB-".
21.2 NEP Credit Support. If at any time during the term
of this Agreement the credit rating assigned to the
senior unsecured debt securities of NEP by Moody's or S&P
falls below Investment Grade, then within ten (10)
business days after a request from Buyer, NEP shall
deliver credit support to Buyer in an amount equal to
Twenty Million Dollars ($20,000,000) and, at NEP's
election, in the form of either: (a) a performance bond
issued by a surety company with a rating of "B+" or
better from A.M. Best Company; (b) a letter of credit
directed to NEP from a commercial bank with long-term
debt ratings of "Baa2" or better from Moody's and "BBB"
or better S&P; or (c) a guaranty from an affiliate of NEP
that has an Investment Grade rating on its senior
unsecured debt securities. Such credit support shall be
available to be drawn upon by Buyer in the event that an
event of default occurs with respect to NEP hereunder and
shall otherwise be in form and substance reasonably
acceptable to Buyer.
21.3 Buyer Financial Statements. Buyer shall deliver to
NEP financial statements certified by a firm of certified
public accountants of national standing annually within
ninety (90) days following the end of Buyer's fiscal year
and unaudited quarterly financial statements within
forty-five (45) days following the end of each quarter.
21.4 Set Off. If at any time Buyer fails to pay any
amounts due hereunder and fails to cure such payment
default within the Cure Period provided therefore under
and in accordance with Section 7.1(b) of this Agreement,
then NEP and its affiliates shall be entitled to set off
the amount of such delinquent payment against amounts
owed by NEP and any of its affiliates to Buyer under
other agreements among such parties. At any time after a
default on the part of NEP under this Agreement, and a
failure by NEP to cure such default within the period
provided in Section 7.1(a) of this Agreement, the Buyer
may set off any of all amounts which NEP owes to the
Buyer under this Agreement against any or all amounts
which the Buyer owes to NEP under this Agreement.
1) Other Agreements.
a) Transition. Each of the Parties hereto acknowledge and
agree that deliveries of Wholesale Nuclear Entitlements
under the Sales Agreement during each Contract Period are
made in accordance with nominations submitted at least 30
days prior to the commencement of the Contract Period in
accordance with ARTICLE 4, Section 4.2 of the Sales
Agreement. The Parties further acknowledge and agree that
March 1, 2000 is the commencement of a Contract Period. To
facilitate CPS's assumption of the right to purchase the
Wholesale Nuclear Entitlements as of March 1, 2000,
USGenNE, CPS and NEP agree that CPS may exercise USGenNE's
right to make a nomination under Section 4.2 of the Sales
Agreement for the Contract Period beginning March 1, 2000
at any time between the date first written above and
January 30, 2000 and otherwise in accordance with the terms
of the Sales Agreement, NEP will accept and honor CPS's
nomination as if made by USGenNE and USGenNE agrees not to
make a nomination for such Contract Period or any period
thereafter.
b) Regulatory Obligations. NEP agrees to file this
Amendment with FERC promptly after execution and in no
event later than thirty (30) days after execution.
c) Indemnification. USGenNE agrees to defend, indemnify and
hold harmless CPS and its officers, directors, employees,
agents (other than USGenNE), successors, assigns and
affiliates, and each affiliates' officers, directors,
employees, agents, successors and assigns against any and
all costs, damages, settlements, or other liabilities
(including reasonable fees of attorneys, consultants and
other professionals retained to assist in the defense or
settlement) ("Losses") related to claims, suits, actions or
causes of action relating to any event or cause occurring
before March 1, 2000 arising under or with respect to the
Sales Agreement. CPS agrees to defend, indemnify and hold
harmless USGenNE and its officers, directors, employees,
agents (other than CPS), successors, assigns and
affiliates, and each affiliates' officers, directors,
employees, agents, successors and assigns against any and
all costs, damages, settlements, or other liabilities
(including reasonable fees of attorneys, consultants and
other professionals retained to assist in the defense or
settlement) ("Losses") related to claims, suits, actions or
causes of action relating to any event or cause occurring
on or after March 1, 2000 arising under or with respect to
the Sales Agreement. Each of CPS and USGenNE will make a
good faith effort to provide prompt notice to the other of
any claim or action reasonably likely to give rise to a
claim under this section but in any event will provide
notice to the other within 15 days of receipt of a notice
of the commencement of any suit, action or proceeding
before an arbitrator, court of law or regulatory agency
brought by a person other than the other, including without
limitation governmental agencies, that could potentially
give rise to a claim under this section. The indemnitor
(either USGenNE or CPS, as the case may be) will have the
right to participate in, or by giving written notice to the
indemnitee (either USGenNE or CPS, as the case may be),
assume at its own expense the defense of an action brought
by a person other than a the indemnitor against the
indemnitee. The indemnitee will seek in good faith to
recover any Losses under applicable insurance policies, and
the indemnitor's obligations hereunder will be reduced to
the extent of such recovery, provided that nothing in this
Agreement shall be deemed to create an obligation to insure
by either USGenNE or CPS. The indemnitee agrees not to
compromise or settle any claim or action subject to
indemnification under this section without the prior
written consent of the indemnitor.
IN WITNESS WHEREOF, the undersigned Parties hereto
have executed this Amendment as of the date first written above.
NEW ENGLAND POWER COMPANY
S/James S. Robinson
By: _____________________________
Name: James S. Robinson
Title: Vice President, Generation
Investments
USGen NEW ENGLAND, INC.
s/James V. Mahoney
By: _____________________________
Name: James V. Mahoney
Title: Senior Vice President
CONSTELLATION POWER SOURCE, INC.
s/John R. Collins
By: _____________________________
Name: John R. Collins
Title: Vice President and Treasurer
Exhibit (10)(aa)(iii)
AMENDED AND RESTATED PPA TRANSFER AGREEMENT
This AMENDED AND RESTATED PPA TRANSFER AGREEMENT ("Agreement")
is dated as of October 29, 1997 and is made by and between NEW
ENGLAND POWER COMPANY, a Massachusetts corporation ("NEP"), and
USGEN NEW ENGLAND, INC. (formerly named USGen Acquisition
Corporation), a Delaware corporation ("Asset Purchaser"), and
amends and restates and, together with the OSP PPA Transfer
Agreement dated of even date herewith between NEP and Asset
Purchaser (the "OSP PPA Transfer Agreement"), supersedes in its
entirety the PPA Transfer Agreement dated as of August 5, 1997
between NEP and the Asset Purchaser (the "Original PPA Transfer
Agreement"). This Agreement sets forth an amendment to, and
restatement in their entirety of, the terms and conditions under
which NEP will transfer to Asset Purchaser the economic benefits
and performance obligations, subject to NEP's continuing
obligations to make certain payments, associated with certain Power
Purchase Agreements between NEP and third party power suppliers
(the "Power Sellers") that NEP and Asset Purchaser desire to be
transferred concurrently with the sale of NEP's generation business
to Asset Purchaser pursuant to the Asset Purchase Agreement, dated
as of August 5, 1997, as amended (as so amended, the "APA"), by and
among NEP, The Narragansett Electric Company and Asset Purchaser.
1. The following Power Purchase Agreements (each, as amended or
supplemented, a "Commitment") are incorporated into this
Agreement by reference:
Doc.
No. Party Date
2068 Altresco Pittsfield, L.P. 12/9/87*
2071 Milford Power L.P. 4/24/96
2072 Pawtucket Power Associates L.P. 12/14/87*
2062 Ogden Haverhill Associates 12/30/85*
2065 SES Millbury Company, L.P. 12/17/85
2063 Massachusetts Refusetech, Inc. 1/6/81*
2064 Refuse Energy Systems Company 1/1/6
2075 L'Energia L.P. 2/26/91
2058 Lawrence Hydroelectric Associates 1/1/85
2061 Ridgewood Providence Power Partners, L.P. 11/6/87*
2060 Pontook Hydro L.P. 1/26/85
2102 Waste Management of New Hampshire, Inc. 5/20/91*
2067 Suncook Energy Corporation 9/7/94*
2059 Mascoma Hydro Corporation 11/14/86
2066 Phillip's Energy, Inc. 9/7/94*
2073 Massachusetts Water Resources Authority 9/21/95
2069 Clark University 2/12/82*
2070 Clark University 2/12/82*
2078 General Electric Lynn River Works 7/7/92
2079 Refuse Fuels Associates 6/12/80*
2080 Simpson Paper 1/1/85
2074 Canal I 12/1/65*
2035 HydroQuebec Phase II 10/14/85
2033 HydroQuebec Phase I 3/21/83
2103 Connecticut Light & Power 1/4/89*
2592 Cambridge Electric Light Company,
Commonwealth Electric Light Company 7/3/93*
* Indicates agreement has been amended or supplemented.
A Commitment shall be automatically deleted from the above
Commitment list without further action by the parties: (i) on
the effective date of any Novation (as defined in Section 7,
below), (ii) upon the expiration of a Commitment pursuant to
its terms, or (iii) upon the termination of a Commitment
pursuant to the written agreement of the parties thereto.
2. This Agreement shall become effective on the Effective Date
(as defined in Section 13) and shall remain in effect until
Asset Purchaser has made payment to NEP of amounts owed
pursuant to Section 4(a), below, and NEP has made payment to
Asset Purchaser and/or the Power Sellers of amounts owed
pursuant to Section 3, 4(b) and 8, below, for the last month
in which a Commitment is listed on the Section 1 Commitment
list; provided however that the provisions of Section 8 of
this Agreement shall survive until NEP has paid all amounts
due thereunder.
3. Commencing as of the Effective Date, NEP agrees to provide to
Asset Purchaser all electric capacity, energy and any other
benefits it receives under each Commitment listed on the
Section 1 Commitment list as of the first day of the month
simultaneously with NEP's receipt thereof from each Power
Seller. All electric energy shall be delivered to Asset
Purchaser at the point at which the Power Seller makes
delivery to NEP as established under the Commitment. Asset
Purchaser shall be responsible for making all arrangements
necessary for the further transmission of such energy. NEP
shall, however, promptly reimburse Asset Purchaser for all
costs actually and reasonably incurred by Asset Purchaser in
transmitting such energy from such delivery points to the
NEPOOL Pool Transmission Facility system either pursuant to
this Section 3 or pursuant to a Commitment which has been
amended and assigned pursuant to Section 7, provided that NEP
shall not be responsible for an increase in such cost
attributable to any amendment to a Commitment by the Asset
Purchaser.
4. (a) Commencing as of the month following the Effective Date,
Asset Purchaser agrees to pay to NEP each month all amounts
properly due from NEP to the Power Seller for the preceding
month associated with capacity, energy and any other benefits
made available to NEP by the Power Seller and accordingly by
NEP to it from each Commitment listed on the preceding month's
Section 1 Commitment list, less the amount of NEP's Monthly
Payment Obligation specified in Section 8 below. For purposes
of the first monthly payment due from Asset Purchaser to NEP
under this Agreement in connection with each Commitment,
energy payments shall be based on meter readings taken on the
first day for which Asset Purchaser has a payment obligation
under this Agreement and capacity payments shall be based on
the ratio of the number of days in the month for which Asset
Purchaser has a payment obligation under this Agreement to the
total number of days in the month. Asset Purchaser shall make
such payment sufficiently in advance of the time that such
payment is due by NEP to the Power Seller as to allow NEP to
make timely payment under such Commitment. In turn, each
month NEP agrees to timely pay each Power Seller all amounts
due under each Commitment, which includes the amount NEP
receives from Asset Purchaser in connection with such
Commitment and the amount of NEP's payment obligation
specified in Section 8 below.
(b) Upon the Effective Date, NEP shall irrevocably and
unconditionally assign and thereafter hold for the benefit of
and/or credit to Asset Purchaser against payments due from it
to NEP under Section 4(a) hereof or at the termination of this
Agreement pay to Asset Purchaser any and all amounts which are
then or thereafter received by NEP from the Power Sellers
under the Commitments, including, without limitation, any
aggregate differential balances under any Commitment and the
benefit of and proceeds from any security deposits, letters of
credit or other similar instruments or accounts established
for the benefit of NEP by the Power Seller, but excluding any
credits or refunds received by NEP after the Effective Date
which relate to billing errors or reconciliations of pre-
Effective Date bills, and any amounts paid by the Power
Sellers to NEP with respect to disputes arising before the
Effective Date that are attributable to a period prior to the
Effective Date.
5. (a) Effective as of the Effective Date, NEP hereby
irrevocably and unconditionally appoints Asset Purchaser as
its representative and agent for all purposes under each
Commitment. Asset Purchaser is hereby authorized to take all
actions that NEP may lawfully take under the Commitment
without further approval by NEP, including, without
limitation, the following: with respect to all matters
arising under the Commitments, deal directly with the Power
Sellers, the New England Power Pool ("NEPOOL"), the
Independent System Operator (as designated under the Restated
NEPOOL Agreement as filed with the Federal Energy Regulatory
Commission on December 31, 1996, and as amended from time to
time), other transporters of electric energy, federal, state
and local governmental authorities, and any other persons; act
on NEP's behalf in the prosecution or defense, as the case may
be, of any rights or liabilities arising under the
Commitments; monitor the Power Sellers' performance under the
Commitments; review and audit all bills and related
documentation rendered by the Power Sellers; and on NEP's
behalf enter into amendments to the Commitments of any nature;
provided, however Asset Purchaser shall not amend any
Commitment with respect to any of NEP's interconnection rights
and obligations, or extend the term thereof or increase NEP's
obligations thereunder without NEP's consent, which shall not
be unreasonably withheld. Asset Purchaser shall have the
right to delegate to its affiliated or third parties any of
its responsibilities under this Section 5. NEP hereby agrees
to provide and deliver to Asset Purchaser all information
which NEP now has or hereafter acquires or to which it is
entitled with respect to each Commitment and Asset Purchaser
hereby agrees to be subject to any confidentiality provisions
of such Commitment with respect to such information. NEP also
agrees to participate at Asset Purchaser's request and under
Asset Purchaser's direction in any governmental proceeding
with respect to the Commitments or this Agreement.
(b) NEP agrees not to agree to any amendment to or waiver of
rights under a Commitment without Asset Purchaser's consent,
which Asset Purchaser may grant or withhold in its sole
discretion, and will not take any actions inconsistent with
the provisions of this Section 5.
6. (a) NEP will indemnify, defend and hold harmless the Asset
Purchaser from and against any and all claims, demands or
suits (by any person), losses, liabilities, damages (excluding
consequential or special damages), obligations, payments,
costs and expenses (including, without limitation, the costs
and expenses of any and all actions, suits, proceedings,
assessments, judgments, settlements, and compromises relating
thereto and reasonable attorneys' fees and reasonable
disbursements in connection therewith) to the extent the
foregoing are not covered by insurance (each, an
"Indemnifiable Loss"), asserted against or suffered by Asset
Purchaser relating to, resulting from or arising out of any
relationship or payment obligation of NEP resulting from or
contained in this Agreement or any obligation of NEP for any
acts or omissions under the Commitments incurred prior to the
Effective Date. For purposes hereof, any willful or negligent
failure of NEP to perform any act required to be performed by
it under a Commitment which increases the amounts payable by
Asset Purchaser under Section 4(a) hereof shall be an
Indemnifiable Loss for which Asset Purchaser shall be entitled
to indemnification hereunder.
(b) Asset Purchaser will indemnify, defend and hold harmless
NEP from and against any and all Indemnifiable Losses asserted
against or suffered by NEP relating to, resulting from or
arising out of any relationship or payment obligation of Asset
Purchaser resulting from or contained in this Agreement. For
purposes hereof, NEP's costs incurred in administering the
Commitments and performing its obligations under this
Agreement shall not be an Indemnifiable Loss.
(c) Any person entitled to receive indemnification under this
Agreement (an "Indemnitee") having a claim under these
indemnification provisions shall make a good faith effort to
recover all losses, damages, costs and expenses from insurers
of such Indemnitee under applicable insurance policies so as
to reduce the amount of any Indemnifiable Loss hereunder. The
amount of any Indemnifiable Loss shall be reduced (i) to the
extent that Indemnitee receives any insurance proceeds with
respect to an Indemnifiable Loss and (ii) to take into account
any net Tax benefit recognized by the Indemnitee arising from
the recognition of the Indemnifiable Loss and any payment
actually received with respect to an Indemnifiable Loss.
(d) The expiration, termination or extinguishment of any
covenant or agreement shall not affect the parties'
obligations under this Section 6 if the Indemnitee provided
the person required to provide indemnification under this
Agreement (the "Indemnifying Party") with proper notice of the
claim or event for which indemnification is sought prior to
such expiration, termination or extinguishment.
(e) The rights and remedies of NEP and Asset Purchaser under
this Section 6 are exclusive and in lieu of any and all other
rights and remedies which NEP and Asset Purchaser may have
under this Agreement or otherwise for monetary relief with
respect to any relationship or payment obligation resulting
from this Agreement.
(f) NEP and Asset Purchaser each agree that, notwithstanding
any provisions in this Agreement to the contrary, all parties
to this Agreement retain their remedies at law or in equity
with respect to willful or intentional breaches of this
Agreement.
(g) If any Indemnitee receives notice of the assertion of any
claim or of the commencement of any claim, action, or
proceeding made or brought by any person who is not a party to
this Agreement or any affiliate of a party to this Agreement
(a "Third Party Claim") with respect to which indemnification
is to be sought from an Indemnifying Party, the Indemnitee
will give such Indemnifying Party reasonably prompt written
notice thereof, but in any event not later than ten (10)
calendar days after the Indemnitee's receipt of notice of such
Third Party Claim. Such notice shall describe the nature of
the Third Party Claim in reasonable detail and will indicate
the estimated amount, if practicable, of the Indemnifiable
Loss that has been or may be sustained by the Indemnitee. The
Indemnifying Party will have the right to participate in or,
by giving written notice to the Indemnitee, to elect to assume
the defense of any Third Party Claim at such Indemnifying
Party's own expense and by such Indemnifying Party's own
counsel, and the Indemnitee will cooperate in good faith in
such defense at such Indemnitee's own expense.
(h) If within ten (10) calendar days after an Indemnitee
provides written notice to the Indemnifying Party of any Third
Party Claim the Indemnitee receives written notice from the
Indemnifying Party that such Indemnifying Party has elected to
assume the defense of such Third Party Claim as provided in
the last sentence of clause (g), the Indemnifying Party will
not be liable for any legal expenses subsequently incurred by
the Indemnitee in connection with the defense thereof;
provided, however, that if the Indemnifying Party fails to
take reasonable steps necessary to defend diligently such
Third Party Claim within twenty (20) calendar days after
receiving notice form the Indemnitee that the Indemnitee
believes the Indemnifying Party has failed to take such steps,
the Indemnitee may assume its own defense, and the
Indemnifying Party will be liable for all reasonable expenses
thereof. Without the prior written consent of the Indemnitee,
the Indemnifying Party will not enter into any settlement of
any Third Party Claim which would lead to liability or create
any financial or other obligation on the part of the
Indemnitee for which the Indemnitee is not entitled to
indemnification hereunder. If a firm offer is made to settle
a Third Party Claim without leading to liability or the
creation of a financial or other obligation on the part of the
Indemnitee for which the Indemnitee is not entitled to
indemnification hereunder and the Indemnifying Party desires
to accept and agree to such offer, the Indemnifying Party will
give written notice to the Indemnitee to that effect. If the
Indemnitee fails to consent to such firm offer within ten (10)
calendar days after its receipt of such notice, the Indemnitee
may continue to contest or defend such Third Party Claim and,
in such event, the maximum liability of the Indemnifying Party
as to such Third Party Claim will be the amount of such
settlement offer, plus reasonable costs and expenses paid or
incurred by the Indemnitee up to the date of such notice.
(i) Any claim by an Indemnitee on account of an Indemnifiable
Loss which does not result from a Third Party Claim (a "Direct
Claim") will be asserted by giving the Indemnifying Party
reasonably prompt written notice thereof, stating the nature
of such claim in reasonable detail and indicating the
estimated amount, if practicable, but in any event not later
than ten (10) calendar days after the Indemnitee becomes aware
of such Direct Claim, and the Indemnifying Party will have a
period of thirty (30) calendar days within which to respond to
such Direct Claim. If the Indemnifying Party does not respond
within such thirty (30) calendar day period, the Indemnifying
Party will be deemed to have accepted such claim. If the
Indemnifying Party rejects such claim, the Indemnitee will be
free to seek enforcement of its rights to indemnification
under this Agreement.
(j) If the amount of any Indemnifiable Loss, at any time
subsequent to the making of an indemnity payment in respect
thereof, is reduced by recovery, settlement or otherwise under
or pursuant to any insurance coverage, or pursuant to any
claim, recovery, settlement or payment by or against any other
entity, the amount of such reduction, less any costs, expenses
or premiums incurred in connection therewith (together with
interest thereon from the date of payment thereof at the prime
rate then in effect of the Bank of Boston), will promptly be
repaid by the Indemnitee to the Indemnifying Party. Upon
making any indemnity payment, the Indemnifying Party will, to
the extent of such indemnity payment, be subrogated to all
rights of the Indemnitee against any third party in respect of
the Indemnifiable Loss to which the indemnity payment relates;
provided, however, that (i) the Indemnifying Party will then
be in compliance with its obligations under this Agreement in
respect of such Indemnifiable Loss and (ii) until the
Indemnitee recovers full payment of its Indemnifiable Loss,
any and all claims of the Indemnifying Party against any such
third party on account of said indemnity payment is hereby
made expressly subordinated and subjected in right of payment
to the Indemnitee's rights against such third party. Without
limiting the generality or effect of any other provision
hereof, each such Indemnitee and Indemnifying Party will duly
execute upon request all instruments reasonably necessary to
evidence and perfect the above-described subrogation and
subordination rights, and otherwise cooperate in the
prosecution of such claims at the direction of the
Indemnifying Party. Nothing in this clause (j) shall be
construed to require any party hereto to obtain or maintain
any insurance coverage.
(k) A failure to give timely notice as provided herein will
not affect the rights or obligations of any party hereunder
except if, and only to the extent that, as a result of such
failure, the party which was entitled to receive such notice
was actually prejudiced as a result of such failure.
7. NEP and Asset Purchaser agree to work cooperatively and use
all reasonable efforts to amend each Commitment and assign
each such amended Commitment to Asset Purchaser so that NEP
will be released of all further liabilities and obligations
under the Commitment and Asset Purchaser will be directly in
contract with the Power Seller (a "Novation"). Any such
Novation shall include all modifications necessary to reflect
the substitution of Asset Purchaser for NEP as the purchasing
party under the Commitment (including modifications to
Commitment price indices, where appropriate) and to properly
describe interconnection, delivery point and transmission
system references and obligations in the Commitment. The
provisions of Section 8(d) shall apply to all such Novations.
It is intended by the parties that all such Novations
preserve the economic benefit and other rights of the
Commitment to the Asset Purchaser without increasing the Asset
Purchaser's obligations under the Commitment while continuing
to afford to NEP the protections for its transmission system
embodied in the interconnection provisions of the Commitment;
provided however that nothing contained herein is intended to
limit the ability of Asset Purchaser to direct the
availability, dispatch, quantity or timing of the capacity or
electrical output of a plant, facility or system which is the
subject of a Commitment, subject to the current terms of such
Commitment. NEP and Asset Purchaser agree to execute all
agreements and documents reasonably required by the other in
connection with all such Novations.
8. (a) In the month in which the Effective Date occurs, NEP
shall be obligated to pay the Power Sellers an aggregate
amount equal to (i) the Monthly Payment Obligation (as defined
in 8(d)(1) below), as adjusted in accordance with Section
8(d)(4) below, multiplied by (ii) a fraction, the numerator of
which is the total number of days in the month in which the
Effective Date occurs, less the number of days in such month
up to the Effective Date, and the denominator of which is the
total number of days in the month in which the Effective Date
occurs, and such adjusted amount shall be deducted by Asset
Purchaser from the amount due NEP under Section 4 above for
such month.
(b) Commencing as of the month following the Effective Date
and continuing for each succeeding month through and including
January 2008, NEP shall be obligated to pay the Power Sellers
each month an aggregate amount equal to the Monthly Payment
Obligation, as adjusted in accordance with Section 8(c) and
Section 8(d)(4) below, and such adjusted amount shall be
deducted by Asset Purchaser from the amount due NEP under
Section 4 above.
(c) In the event that the amount of NEP's Monthly Payment
Obligation set forth in Section 8(b) (as adjusted to reflect
any increases pursuant to this Section 8(c)) shall in any
month exceed the amount due NEP from Asset Purchaser under
Section 4, NEP shall increase the amount of its obligation in
the next month (in addition to its obligation set forth in
Section 8(b)) by the amount of such excess plus interest
thereon at the Applicable Discount Rate (as defined in Section
8(d)(3)) from the date payment from Asset Purchaser for such
month would have been due to the date of the next payment by
Asset Purchaser under Section 4 (the "Excess Obligation") and
Asset Purchaser shall also be allowed to deduct such Excess
Obligation from the amount due NEP under Section 4 for such
month. Should there be an Excess Obligation as of January 31,
2008, NEP shall within thirty days thereafter pay at the
direction of Asset Purchaser the amount of such Excess
Obligation.
(d) To the extent that a "Trigger Event" (as hereinafter
defined) shall occur with respect to any Commitment, NEP will,
with the consent of Asset Purchaser, make a full or a partial
lump-sum payment ("Trigger Payment") to the appropriate Power
Seller or such other party as the Asset Purchaser may direct,
as the case may be. Subject to subsection (6) below, Trigger
Payments shall, unless otherwise agreed to by Asset Purchaser,
be made concurrently with the Trigger Event, or as soon
thereafter as is practicable (but not later than the later of
(x) sixty (60) days thereafter and (y) one hundred twenty
(120) days after reasonable notice was given by Asset
Purchaser that a Trigger Event was likely to occur) ("Trigger
Payment Date").
(1) NEP's monthly payment obligations under Sections 8(a) and
(b) above, and before adjustment in accordance with
subsection (5) below, are detailed on Schedule B hereto
("Monthly Payment Obligation"). For each Commitment, and
for each year from 1998 through 2007, a corresponding
percentage of the Monthly Payment Obligation is set forth
on Schedule A hereto (the "Applicable Percentage").
(2) "Trigger Event" shall mean: (i) a Novation; (ii) a
termination of a Commitment; (iii) a negotiated
modification of a Commitment under which the obligations
of NEP are reduced; or (iv) a legislative, regulatory or
court-ordered change in the terms of a Commitment under
which the obligations of NEP are reduced; provided,
however, that if at the time any one of the events
specified in (i), (ii), or (iii) above shall occur, Asset
Purchaser shall be in default with respect to
indemnification as to its payment obligations under
Section 6(b) hereof, no Trigger Event shall be deemed to
have arisen from any such event unless and until such
default shall have been cured.
(3) The amount of any Trigger Payment (i) if in respect of a
Trigger Event listed in subsection (2)(i) or (ii) above,
shall, except as otherwise approved by Asset Purchaser,
be the discounted amount as of the Trigger Payment Date
(using as the discount rate a percentage equal to the sum
of (x) the yield reported on page PX1 of the Bloomberg
Financial Market Services Screen (or, if not available,
any other nationally recognized trading screen reporting
on-line intraday trading in United States government
securities) at 4:00 p.m. (New York time) on the day prior
to the Trigger Payment Date for the off-the-run 5-year
Treasury Note plus (y).50% (the "Applicable Discount
Rate")) of (A) NEP's remaining Monthly Payment
Obligations as of the Trigger Payment Date multiplied by
(B) the Commitment's Applicable Percentage for the year
in which the Trigger Payment Date occurs, and (ii) if in
respect of a Trigger Event listed in subsection (2)(iii)
or (iv) above, shall, except as otherwise approved by
Asset Purchaser, equal (x) the amount calculated under
clause (i) above multiplied by (y) a fraction (but in no
event less than zero nor greater than one (1)) calculated
by mutual agreement in accordance with the following
sentence (the "Reduction Factor"). The parties shall
mutually agree to a Reduction Factor for each applicable
Trigger Event that represents the proportion by which the
discounted present value, using the Applicable Discount
Rate, of the projected costs under the affected
Commitment minus $.032 per kWh (as adjusted to be held
constant in 1998 dollars using the Consumer Price Index),
has been reduced as a result of such Trigger Event. Any
controversy in connection with the calculation of the
Reduction Factor shall be determined and settled by
arbitration in New York, New York, by a person or persons
mutually agreed upon, or in the event of a disagreement
as to the selection of the arbitrator or arbitrators, in
accordance with the rules of the American Arbitration
Association. Any award rendered therein shall specify
the findings of fact of the arbitrator or arbitrators and
the reasons for such award, with the reference to and
reliance on relevant law. Any such award shall be final
and binding on each and all of the parties thereto and
their personal representatives, and judgment may be
entered thereon in any court having jurisdiction thereof
and the fees of such arbitrators in connection with the
determination shall be paid by the party against whom the
award was made, or if a compromise was made, shared
equally.
(4) Upon the making of any such Trigger Payment, except as
otherwise agreed to by Asset Purchaser, the amounts
thereafter payable in accordance with Section 8(a) or
Section 8(b) shall be reduced by the sum of (i) the
reductions arising under this subsection (4) from all
previous Trigger Payments made by NEP plus (ii)(x) in the
case of a Trigger Payment made under Section 8(d)(3)(i),
by an amount equal to (A) the Applicable Percentage used
in calculating such Trigger Payment multiplied by (B) the
Monthly Payment Obligation and (y) in the case of a
Trigger Payment made under Section 8(d)(3)(ii), by an
amount equal to (A) the Applicable Percentage used in
calculating such Trigger Payment multiplied by (B) the
Monthly Payment Obligation multiplied by (C) the
Reduction Factor.
(5) Notwithstanding the foregoing, NEP's obligation to make
any Trigger Payment shall, at the option of NEP, be
deferred, in whole or in part, pending satisfaction of
the following conditions: (i) NEP shall be reasonably
satisfied that the full amount of such Trigger Payment
will be currently deductible for Federal and state income
tax purposes and that such deduction shall be fully
utilized in its Federal and state tax returns and (ii)
NEP shall have received approval from all necessary
regulatory authorities for any financing that NEP
reasonably requires in order to fund such Trigger
Payment. NEP shall use reasonable efforts to obtain and
maintain, from all regulatory authorities having
jurisdiction, approvals for the issuance of up to
$100,000,000 in long-term securities for the purposes of
funding Trigger Payments.
(6) If NEP shall elect to defer making a Trigger Payment
pursuant to subsection (5) above, then not later than the
date that such Trigger Payment is otherwise due, NEP will
grant a first priority, perfected security interest to
Asset Purchaser in such portion of NEP's Contract
Termination Charge revenues and related Service
Agreements (the "CTCs") with Massachusetts Electric
Company ("MECO") and The Narragansett Electric Company
("NECO") as is equal to the amount by which each Monthly
Payment Obligation would be reduced pursuant to
subsection (4) above had the Trigger Payment not been
deferred. Such security interest shall be granted
pursuant to a duly executed security agreement in form
and substance reasonably satisfactory to Asset Purchaser,
and shall provide that proceeds of the collateral shall
be assigned to Asset Purchaser and paid by MECO and NECO
to Asset Purchaser or as otherwise directed by Asset
Purchaser; provided, however, that unless and until there
shall occur an event of default under such security
agreement, the Asset Purchaser will waive its right to
receive proceeds directly from MECO and NECO pursuant to
such assignment. Further, NEP shall not be permitted to
exercise its election under subsection (5) unless the
granting of the security interest contemplated in this
subsection (6) and the assignment of proceeds in
connection therewith shall be consented to by MECO and
NECO.
(7) During the term of this Agreement, NEP shall not grant,
permit or suffer to exist any encumbrance, pledge,
security interest, assignment, lien or other disposition
of its rights to such portion of the CTCs referred to in
subsection (6) above as is sufficient at all times to
cover NEP's then remaining aggregate Monthly Payment
Obligations and will at its sole expense take all actions
required to remove and/or defend against any claim or
encumbrance that may be created or asserted by any other
party thereon.
(8) Asset Purchaser shall release any security interest
granted hereunder with respect to any Trigger Payment if:
(a) NEP has provided Asset Purchaser with a letter of
credit, collateral or other security in substitution for,
and replacement of, the collateral referred to in Section
8(d)(6) which shall be at least equivalent in value to
the security represented by such collateral as agreed
between NEP and the Asset Purchaser, in the exercise of
by each of its reasonable commercial judgment, or (b) NEP
has paid Asset Purchaser the present value of the
remaining security, using the Applicable Discount Rate
applied in calculating the related deferred Trigger
Payment.
9. This Agreement and all rights, obligations, and performances
of the parties hereunder, are subject to all applicable
Federal and state laws, and to all duly promulgated orders and
other duly authorized action of governmental authority having
jurisdiction.
10. Except as otherwise set forth in Section 5 hereof, this
Agreement and all of the provisions hereof shall be binding
upon and inure to the benefit of the parties hereto and their
respective successors and permitted assigns, but neither this
Agreement nor any of the rights, interests or obligations
hereunder shall be assigned by any party hereto, including by
operation of law without the prior written consent of the
other party, nor is this Agreement intended to confer upon any
other person except the parties hereto any rights or remedies
hereunder. Notwithstanding the foregoing, (i) the Asset
Purchaser may assign all of its rights and obligations
hereunder to any wholly owned Subsidiary (direct or indirect)
of PG&E Corporation and upon NEP's receipt of notice from
Asset Purchaser of any such assignment, the Asset Purchaser
will be released from all liabilities and obligations
hereunder, accrued and unaccrued, such assignee will be deemed
to have assumed, ratified, agreed to be bound by and perform
all such liabilities and obligations, and all references
herein to Asset Purchaser shall thereafter be deemed
references to such assignee, in each case without the
necessity for further act or evidence by the parties hereto or
such assignee; provided, however, that no such assignment and
assumption shall release the Asset Purchaser from its
liabilities and obligations hereunder unless the assignee
shall have acquired all or substantially all of the Asset
Purchaser's assets; provided, further, however, that no such
assignment and assumption shall relieve or in any way
discharge PG&E Corporation from the performance of its duties
and obligations under the Guaranty dated as of the date of
this Agreement executed by PG&E Corporation; and (ii) the
Asset Purchaser or its permitted assignee may assign,
transfer, pledge or otherwise dispose of its rights and
interests hereunder to a trustee or lending institution(s) for
the purpose of financing or refinancing the Purchased Assets
(as defined in the APA), including upon or pursuant to the
exercise of remedies under a financing or refinancing, or by
way of assignments, transfers, conveyances or dispositions in
lieu thereof; provided, however, that no such assignment or
disposition shall relieve or in any way discharge the Asset
Purchaser or such assignee from the performance of its duties
and obligations under this Agreement. NEP agrees to execute
and deliver such documents as may be reasonably necessary to
accomplish any such assignment, transfer, conveyance, pledge
or disposition of rights hereunder so long as NEP's rights
under this Agreement are not thereby altered, amended,
diminished or otherwise impaired.
11. This Agreement, the APA and any other agreement entered into
by the parties pursuant to the APA constitute the entire
agreement between the parties and supersede all previous
offers, negotiations, discussions, communications and
correspondence. This Agreement may be amended only by a
written agreement signed by the parties. This Agreement is
not intended to confer upon any other person (including,
without limitation, the Power Sellers) except the parties
hereto any rights or remedies. The interpretation and
performance of this Agreement shall be according to and
controller by the laws of The Commonwealth of Massachusetts
(regardless of the laws that might otherwise govern under
applicable Massachusetts principles of conflicts of laws).
12. All payments required under this Agreement shall be paid in
cash by federal or other wire transfer of immediately
available funds to an account designated by the party to
receive such payment.
13. This Agreement shall be of no force and effect until the
Effective Date. If the APA shall have been terminated before
the occurrence of the Closing Date (as defined in the APA),
this Agreement shall, without any action of the parties
hereto, terminate as of the time of the termination of the
APA. As used in this Agreement, "Effective Date" shall mean
the Closing Date (as defined in the APA). This Agreement
amends and restates and, together with the OSP PPA Transfer
Agreement, supersedes in its entirety the Original PPA
Transfer Agreement.
IN WITNESS WHEREOF, the parties have caused their duly
authorized representatives to execute this Agreement on their
behalf as of the date first above written.
NEW ENGLAND POWER COMPANY
s/Michael E. Jesanis
By:______________________________
Name: Michael E. Jesanis
Title: Treasurer
USGEN NEW ENGLAND, INC.
s/M. Richard Smith
By:__________________________
Name: M. Richard Smith
Title: Vice President
EXHIBIT 10(bb)(vi)
AMENDED AND RESTATED POWER SALES CONTRACT
THIS AMENDED AND RESTATED POWER SALES CONTRACT (the "Contract") is
made and entered into this 18th day of December 1998 (the "Contract Date"), by
and between SOUTHERN ENERGY CANAL, L.L.C., a Delaware limited liability
company ("Seller") and MONTAUP ELECTRIC COMPANY, a Massachusetts corporation
("Purchaser"). Seller and Purchaser are referred to herein individually as a
"Party" and collectively as the "Parties."
RECITALS:
A. Seller is a party to that certain Asset Sale Agreement dated May 15,
1998 (the "Asset Sale Agreement") between Seller (as successor by assignment
to Southern Energy New England, L.L.C.) and Canal Electric Company ("CEC")
providing for the sale of Canal Unit 1 from CEC to Seller.
B. Purchaser is a party to that certain Power Contract between Purchaser
and CEC dated December 1, 1965 (the "Original Contract") for the sale of 25%
of the capacity and energy from Canal Unit I to Purchaser, and CEC is a party
to Power Contract s dated December 1, 1965 with each of Boston Edison Company,
Commonwealth Electric Company and Cambridge Electric Light Company and New
England Power Company (the "Other Purchasers' Original Contracts"), each of
which is substantially identical to the Original Contract and provides for the
sale of 25% of the capacity and energy to each of the other purchasers.
C. In connection with the closing of the Asset Sale Agreement, CEC has
assigned the Original Contract and the Other Purchasers' Original Contracts to
Seller effective as of the closing, and the Parties hereto desire to enter
into this Contract t o amend, restate, supersede and replace the Original
Contract, effective on the closing of the Asset Sale Agreement.
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements hereinafter set forth, the Parties hereto mutually
covenant and agree as follows:
1 Definitions
"Affiliate" means any other entity (other than an individual) that, directly
or indirectly, through one or more intermediaries, controls, or is controlled
by, or is under common control with, such entity. For purposes of the
foregoing, "control" means the direct or indirect ownership of more than
seventy percent of the outstanding capital stock or other equity interest
having ordinary voting power.
"Asset Sale Agreement" has the meaning set forth in Recital A.
"Base Amount" has the meaning set forth in Section 5(a).
"Bid Procedures" means the bid procedures agreed to by Seller and the Contract
Purchasers Committee from time to time for bidding Canal Unit I to the ISO
consistent with the then effective Operational Characteristics.
"Business Day" means any day other than a Saturday, Sunday or a Holiday that
is observed on a weekday. If any performance date referenced in this Contract
is not a Business Day, such performance date shall be the next succeeding
Business Day.
"Canal Unit I" means Unit I at the Canal Station in Sandwich, Massachusetts.
"CEC" means Canal Electric Company, formerly known as Plymouth County Electric
Company.
"Commonwealth/Cambridge" means collectively, Commonwealth Electric Company and
Cambridge Electric Company. Commonwealth/Cambridge shall be deemed to be one
Contract Purchaser.
"Contract Costs" means the costs Purchaser incurs under and in connection with
this Contract.
"Clean Air Act" means the federal environmental statute enacted at 42 U.S.C.A.
7401 et seq. to regulate and control air pollution.
"Contract" means this Amended and Restated Power Sales Contract between Seller
and Purchaser.
"Contract Date" means the date of this Contract.
"Contract Parties" means Seller and the Contract Purchasers.
"Contract Purchasers" means Purchaser and the Other Purchasers.
"Contract Purchasers Committee" means the standing committee of
representatives of the Contract Purchasers and Seller established pursuant to
Section 3 of this Contract.
"Contract Year" means a calendar year during the term of this Contract;
provided, however, the first Contract Year shall begin on the Effective Date
and end on December 31, 1999, and the last Contract Year shall end on the
expiration of the term of this Contract.
"Creditworthiness Criteria" means an entity which has a credit rating of at
least "BBB-," from the Standard & Poor's Rating Group (a division of McGraw
Hill), or its successor ("S&P") or an equivalent rating from Moody's Investor
Services, Inc. or its successor ("Moody's"). The Creditworthiness Criteria
may be satisfied by the delivery of collateral security for the obligations of
a Party hereunder in the form of (i) a guarantee in form and substance
reasonably satisfactory to the other Party from an entity that meets the
Creditworthiness Criteria, or (ii) a direct-pay, irrevocable, standby letter
of credit from a major U.S. commercial bank having a credit rating of at least
"A" from S&P or "A-2" from Moody 7 s; each in an amount, form and substance
reasonably approved by the other Party.
"CTC" or "Contract Termination Charges" shall have the meaning set forth in
that certain settlement filed by Purchaser with FERC in Docket Nos. ER97-2800
et al, which settlement FERC approved with conditions on December 19, 1997.
"Defaulting Party" shall have the meaning set forth in Section 27(a).
"Delivery Point" means the point where capacity, energy and ancillary services
generated by Canal Unit I are delivered to the NEPOOL PTF.
"Demand Charge" shall have the meaning set forth in Section 5.
"Edison" means Boston Edison Company.
"Effective Date" has the meaning set forth in Section 2(a).
"Energy" shall have the meaning assigned to such term by the Restated NEPOOL
Agreement.
"Energy Charge" shall have the meaning set forth in Section 6.
"Emissions Allowances" means NOx Emission Allowances and SO2, Allowances.
"Emissions Charge" shall have the meaning set forth in Section 7.
"Existing NOx Allowances" shall have the meaning set forth in Section 7.
"Event of Default" shall have the meaning set forth in Section 27(a).
"Fuel" means number six (No. 6) fuel oil.
"Fuel Procurement Policy" means the policy established by Seller and approved
by the Contract Purchasers Committee to procure Fuel for Canal Unit 1.
"FERC" means Federal Energy Regulatory Commission.
"Good Utility Practice" means any of the practices, methods or 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 that in
the exercise of reasonable judgment in light of the facts known at the time a
decision was made, could have been expected to accomplish the desired result
at reasonable cost consistent with reliability, safety and expedition and
giving due regard for the compliance with applicable law and the requirements
of governmental agencies having jurisdiction and the rules, regulations and
procedures of NEPOOL and the ISO. Good Utility Practice is not intended to be
limited to the optimum practice, method or act to the exclusion of all others,
but rather to be a spectrum of acceptable practices,, methods or acts.
"Hearing" shall have the meaning set forth in Section 23(b).
"Holiday" means New Year's Day, President's Day, Patriot's Day, Memorial Day,
Independence Day, Labor Day, Columbus Day, Veteran's Day, Thanksgiving Day,
the day following Thanksgiving Day, and Christmas Day.
"Installed Capacity" shall have the meaning assigned to such term by the
Restated NEPOOL Agreement.
"Interest Rate" means, for any date, two (2) percent over the per annum rate
of interest equal to the prime lending rate as may from time to time be
published in The Wall Street Journal under "Money Rates"; provided, however,
that the Interest Rate shall never exceed the maximum lawful rate permitted by
applicable law.
"ISO" means ISO New England, Inc., the independent system operator for the New
England region, and its successors and assigns.
"Market Implementation Date" means the effective date of the implementation of
the bid-based market for energy in NEPOOL.
"Mediation Notice" shall have the meaning set forth in Section 23(a).
"NEPCO" means New England Power Company.
"NEPOOL" means the New England Power Pool, and its successors and assigns.
"NEPOOL Defined Products" means any electrical generation-related products
established by NEPOOL which may be produced by Canal Unit 1, including without
limitation, Installed Capacity, Operable Capacity, Energy, Ten Minute Spinning
Reserve, Ten Minute Nonspinning Reserve, Thirty Minute Operating Reserve and
Automatic Generation Control, as such terms are defined by the Restated NEPOOL
Agreement.
"NEPOOL PTF" means the NEPOOL Pool Transmission Facilities, as defined by the
Restated NEPOOL Agreement.
"New Contract Purchasers" means Purchaser and the Other Purchasers which enter
into an Other Purchasers' New Contract, from time to time.
"Non-Defaulting Party" shall have the meaning set forth in Section 27(a)(iii).
"NOx Emission Allowance" means an authorization under Massachusetts air
quality regulations to emit one ton of nitrogen oxides during the period May 1
through September 30 of any given year.
"NOx Season" means the months of May through September of each year.
"Operational Characteristics" means the operating characteristics of Canal
Unit I as set forth in the NEPOOL NX-12(a) report or any similar report
delivered by Seller to the Contract Purchasers seasonally, as revised from
time to by Seller to reflect changes in the actual physical operating
characteristics of Canal Unit I or as agreed to by the Contract Purchasers
Committee in accordance with Section 3(b)(ii).
"Original Contract" has the meaning set forth in Recital B.
"Other Purchasers" means Commonwealth/Cambridge, Edison and NEPCO and their
respective successors and permitted assigns.
"Other Purchasers New Contracts" means any agreement between Seller and any of
the Other Purchasers which terminates, amends or replaces such Other
Purchaser's Original Contract.
"Other Purchasers' Original Contracts" has the meaning set forth in Recital B.
"Party" and collectively the "Parties" refers to Seller and/or Purchaser.
"Purchaser" means Montaup Electric Company and its successors and permitted
assigns.
"Restated NEPOOL Agreement" means the NEPOOL Agreement dated December 31,
1996, as amended from time to time.
"RFP" means a request for proposal as defined in Section 25(b) hereof.
"SCR" means selective catalytic reduction equipment and process installed on
Canal Unit 1.
"SCR Amount" shall have the meaning set forth in Section 5(b).
"SCR Operation Date" means the date the SCR becomes operational for Canal Unit
1.
"Seller" means Southern Energy Canal, L.L.C, and its successors and assigns.
"Senior Officers Committee" means a committee of senior officers of each
Contract Party established in accordance with Section 23(a).
"SO2 Allowance" means an authorization under the Clean Air Act to emit one ton
of sulfur dioxide on an annual basis.
2. Effective Date; Assignment and Amendment
(a) This Contract shall become effective upon the closing of the Asset
Sale Agreement (the "Effective Date"). If the Effective Date does not occur
on or before December 31, 1998, Purchaser shall have the right to terminate
this Agreement and resume service under the Original Contract if Purchaser
gives Seller written notice of such termination by January 5, 1999.
(b) Purchaser hereby consents to the assignment of the Original Contract
by CEC to Seller, and the Parties hereby amend and restate in its entirety the
Original Contract. Such assignment, amendment and restatement shall be
effective on the Effective Date. Purchaser acknowledges and agrees that it is
not aware of any claims against CEC under the Original Contract and Seller
shall have no liability for any claims or demands of Purchaser under the
Original Contract or this Contract arising with respect to acts or omissions
prior to the Effective Date.
(c) If FERC has not issued a final non-appealable order acceptable to
Purchaser, in its sole discretion, approving Purchaser's recovery of Contract
Costs as just and reasonable pursuant to the provisions of Purchaser's CTC by
the Reopener Date, t hen within five (5) Business Days after the Reopener
Date, Purchaser may deliver written notice to Seller requiring the Parties to
amend the terms of this Contract so that the charges to Purchaser will be
computed in accordance with the terms of the Original Contract. As used
herein the Reopener Date" shall be July 3 1, 1999, however, if FERC has issued
an order that is acceptable to Purchaser but is not final and non-appealable
by such date, the Reopener Date shall be automatically extended for sixty (60)
days. Such amendment of this Contract shall also require that the Parties
will make payments to each other as necessary to true-up any charges from the
Effective Date of this Contract until the effective date of any such amendment
as compared to charges under the Original Contract for such period. Purchaser
shall diligently seek to obtain an order from FERC approving the recovery of
Contract Costs as just and reasonable pursuant to the provisions of
Purchaser's CTC.
(d) Notwithstanding Sections 5 and 6 below, if the Effective Date occurs
before January 1, 1999, CEC shall bill Purchaser in accordance with the
Original Contract for service provided between the Effective Date and January
1, 1999, and Seller will recover from CEC such portion of the charges as are,
attributable to service between the Effective Date and January 1, 1999.
Seller will use reasonable efforts to have CEC perform all accountings
required under the Original Contract after January 1, 1999.
3. Contract Purchasers Committee
(a) For the mutual advantage of the Contract Parties, a Contract
Purchasers Committee shall be established consisting of one (1) representative
from each of the Contract Purchasers and one (1) representative from Seller.
The New Contract Purchasers shall each have the right to vote and any Other
Purchasers shall have the rig ht to attend meetings but shall only have the
right to vote on matters which require each such Other Purchaser's consent
under such Other Purchaser's Original Contract. The Purchaser and Seller shall
each appoint to the Contract Purchasers Committee officers or representatives
that have the authority to act on behalf of their respective Parties to the
extent required under the terms of this Contract. The Contract Purchasers
Committee shall meet at least once every six months during the ten-n at such
times as may be announced by Seller. Each member of the Contract Purchasers
Committee shall have the right to call a meeting on at least ten (10) Business
Days prior notice to the other members of the Contract Purchasers Committee.
(b) The approval of the Contract Purchasers Committee, which approval
shall not be unreasonably withheld, is required for the following:
(i) a change in the Bid Procedures shall require the unanimous approval of
the Contract Purchasers Committee; provided, however, any change which has or
may have a material adverse effect on Canal Unit I shall require the written
approval of Seller, which shall not be unreasonably withheld;
(ii) Seller's change in the Operational Characteristics shall require the
unanimous approval of the Contract Purchasers Committee, except any change
required, in Seller's reasonable judgment, to adhere to Good Utility Practice;
(iii) Seller's scheduling of any planned outage for routine maintenance and
overhauls if such planned outage is scheduled during a time other than the
spring or fall shall require the approval of a majority of the Contract
Purchasers Committee; Seller shall consult with the Contract Purchasers
Committee regarding all planned outages including the planned outage to
install the SCR for Canal Unit 1. Seller shall keep the Contract Purchasers
Committee informed of the outage schedule for the SCR, and changes thereto
which in Seller's reasonable judgment are necessary or prudent to install the
SCR shall not require approval of the Contract Purchasers Committee;
(iv) any change to the Fuel Procurement Policy shall require the unanimous
approval of the Contract Purchasers Committee;
(v) the acquisition and disposition of NOx Emission Allowances and SO,
Allowances for Canal Unit I shall require the approval of a majority of the
Contract Purchasers Committee (to the extent acquisitions are approved, Seller
may acquire Emission Allowances from Contract Purchasers in accordance with
Section 7(g)); provided, however, Seller shall not be liable for the failure
of the Contract Purchasers Committee to approve the acquisition of NOx
Emission Allowances and/or SO, Allowances sufficient for the operation of
Canal Unit 1;
(vi) the appointment of an agent by Seller pursuant to Sections 8 and 9
which is not an Affiliate of Seller shall require the approval of a majority
of the Contract Purchasers Committee;
(vii) instituting a material capital addition or other action for which
approval of the Contract Purchasers Committee is required pursuant to Section
9 shall require the approval of a majority of the Contract Purchasers
Committee.
(c) Seller's representative shall have the night to attend all Contract
Purchasers Committee meetings but shall not have the power to vote except in
the case of a deadlock on a matter which Seller determines should be resolved
to comply with Good Utility Practice. In the event an Affiliate of Seller
becomes a Contract Purchaser (as a result of an assignment of an Other
Purchaser's Original or New Contract), Seller's right to vote in the preceding
sentence shall terminate, but Seller's Affiliate shall have the power to vote
on all matters except the approval of any fuel or other contract between
Seller and an Affiliate of Seller which requires the consent of the Contract
Purchasers Committee. In such instance the unanimous vote of the other
members of the Contract Purchasers Committee shall be required to approve such
matters.
(d) In the event of a deadlock in the Contract Purchasers Committee which
is not resolved by Seller in accordance with Section 3(c), any Party may give
notice to the other Party instituting the dispute resolution provisions of
Section 23 hereof.
(e) Seller and Purchaser acknowledge that they have reached agreement as
to the initial Bid Procedures for the period prior to the Market
Implementation Date and for the period from and after the Market
Implementation Date. Any change to the Bid Procedures shall be made in
accordance with Section 3(b)(i) except Seller shall have the right to make any
change that in Seller's reasonable judgment is necessary to comply with NEPOOL
or ISO rules and procedures or any change in the Operational Characteristics.
4. Sale, Purchase and Power Price
(a) Commencing on the Effective Date and during the term of this Contract,
Seller shall make available and provide to Purchaser and Purchaser shall be
entitled to twenty-five percent (25%) of the capacity and associated energy,
along with any other generation- related products produced by Canal Unit 1
including, without limitation, operable capacity, operating reserves and
automatic generation control. Purchaser acknowledges that it has no right to
any output of Canal Unit I following the termination of this Contract unless
otherwise agreed to in writing by Seller.
(b) With respect to each month commencing on the Effective Date, Purchaser
shall pay Seller the amounts provided in this Contract.
5. Demand Charge
The Demand Charge for each respective month during the term of this
Contract shall be the Base Amount for such month plus the SCR Amount for such
month. If the Effective Date occurs on a date other than the first day of a
month, the Demand Charge for such month shall be appropriately pro-rated.
(a) Base Amount. The Base Amount for each month during the term of this
Contract shall be as follows:
Year
1999 - $734,895.00 each month
2000 - $691,042.00 each month
2001 - $748,271.00 each month
2002 - $758,121.00 for each month from January through September, and
$236,499.00 for October.
(b) SCR Amount. The SCR Amount for each month during the term of this
Contract beginning with January 2000 shall be:
Year
2000 - $72,500.00 each month
2001 - $71,042.00 each month
2002 - $89,767.00 each month from January through September, and $29,594.00
for October.
Notwithstanding the foregoing, if the SCR Operation Date has not occurred on
or prior to the beginning of the NOx Season in 2000 or any year thereafter,
the SCR Amount for such year shall be reduced as follows:
(i) For each month during the NOx Season prior to the SCR Operation Date,
the aggregate amount of the SCR Amount for such year shall be reduced by one-
fifth (1/5th).
(ii) If the SCR Operation Date occurs during a month in the NOx Season, the
SCR Amount shall be prorated for such month.
(iii) If the SCR Operation Date has not occurred on or prior to May 1, 2000,
any amounts of the SCR Amount which have been paid by Purchaser prior to the
SCR Operation Date shall be used by Seller as an advance to pay for
Purchaser's share of any N Ox Allowances needed for the operation of Canal
Unit 1 in accordance with Section 7(b) hereof, and any residual advance shall
then be used as an offset against any further SCR Amount payable by Purchaser
hereunder.
Seller shall notify the Contract Purchasers Committee of the
occurrence of the SCR Operation Date. Except as otherwise provided above,
Seller shall have no liability to Purchaser for any delay in the SCR Operation
Date.
6. Energy Charge
The Energy Charge shall be 25% of all Fuel and Fuel handling costs
incurred by Seller for Canal Unit I in accordance with the following:
(a) Fuel shall be purchased by Seller from any Fuel supplier, including
any Affiliate of Seller, in accordance with the Fuel Procurement Policy in
effect from time to time. The Parties acknowledge and agree that they have
reached agreement as to the initial Fuel Procurement Policy. Any changes to
the Fuel Procurement Policy shall be made in accordance with Section 3(b)(iv).
(b) The delivered cost of Fuel shall be charged to the Contract Purchasers
monthly at Seller's cost based upon the sum of the daily deliveries to the
Canal Unit 1 day tank.
7. Emissions Allowances
(a) Seller shall allocate to Canal Unit I fifty percent (50%) of the Nox
Emission Allowances allocated to the Canal Station (Canal Unit 1 and Canal
Unit 2) by governmental agencies (the "Existing NOx Allowances").
(b) To the extent the Existing NOx Allowances are insufficient for the
operation of Canal Unit I prior to the SCR Operation Date, Purchaser shall
pay, as the "Emissions Charge," 25% of the cost of all NOx Emission Allowances
acquired by Seller for Canal Unit I to comply with emission requirements
applicable to Canal Unit 1. Seller shall charge Purchaser for twenty five
percent (25%) of the cost of any NOx Emission Allowances, in excess of the
Existing NOx Allowances, purchased by Seller from CEC at the closing of the
Asset Sale Agreement. The amounts for the purchased NOx Emission Allowances
shall be charged to the Contract Purchasers as the NOx Emission Allowances are
used, and the purchased NOx Emission Allowances shall be deemed to be used
prior to the Existing NOx Allowances. Seller may charge the Contract
Purchasers interest on the purchase price of unexpensed NOx Allowances at the
Interest Rate minus 2% per annum.
(c) Seller is planning to install an SCR for Canal Unit I to become
operational on or before May 1, 2000 which will be designed to achieve a
reduction in NOx emissions for Canal Unit 1. Seller's cost of installing the
SCR is included in the SCR A mount in the Demand Charges for 2000 and
thereafter, and Purchaser shall not otherwise be responsible for any capital
or operations and maintenance costs associated with the SCR.
(d) Purchaser shall pay Seller for 25% of the cost of SO2 Allowances
which are required for the operation of Canal Unit 1 in excess of the SO,
Allowances allocated to Canal Unit I prior to the Effective Date.
(e) If Seller projects that Seller will have excess Emission Allowances
for any year during the term of this Contract, Seller shall so notify the
Contract Purchasers Committee and Seller shall liquidate such Emission
Allowances or retain such Emission Allowances for use in following years in
accordance with the direction of the Contract Purchasers Committee. Seller
shall distribute to Purchaser 25% of the proceeds of such a liquidation.
(f) If Seller is planning to purchase additional NOx Allowances in
accordance with the terms of this Agreement, Purchaser shall have the night to
provide NOx Allowances to Seller, and in such event Purchaser shall receive a
credit for the amount of NOx Allowances provided to Seller. Such credit shall
be used to offset the charges Purchaser is obligated to pay for the Nox
Allowances acquired by Seller for Canal Unit I or other charges pursuant to
this Contract.
(g) Seller shall pay or bear the cost of any fine or penalty arising from
Seller's failure to observe and comply with Good Utility Practices in the
operation of Canal Unit 1, where such failure results in insufficient
Emissions Allowances for Canal Unit 1. Seller shall under no circumstances be
obligated to operate Canal Unit I in a manner that would result in
noncompliance with any emissions related requirement.
8. Scheduling Protocol Prior to the Market Implementation Date During
the term of the Contract up to the Market Implementation Date:
(a) Seller shall provide information regarding Canal Unit 1 to the ISO in
accordance with the Bid Procedures to enable the ISO to dispatch Canal Unit 1.
(b) Seller shall be responsible for coordinating the submission of all
necessary information on behalf of Contract Purchasers and for communicating
the outcome of the dispatch to Contract Purchasers.
(c) Purchaser shall be entitled to 25% of the capacity and associated
energy along with any other generation-related products produced by Canal Unit
1, including without limitation, operable capacity, operating reserves, and
automatic generation control.
(d) Seller and Purchaser shall take all action necessary in accordance
with NEPOOL procedures to ensure that Purchaser shall receive appropriate
credit for its 25% of the generation related products produced by Canal Unit
1, including without limitation, energy, installed capacity, operable
capacity, operating reserves, and automatic generation control resulting from
the ISO dispatch of Canal Unit 1.
(e) Seller may appoint an agent to perform its obligations under this
Section 8. The appointment of any agent which is not an Affiliate of Seller
shall require the consent of a majority of the Contract Purchasers Committee,
which consent may not be unreasonably withheld.
9. Scheduling Protocol After Market Implementation Date During the term
of the Contract from and after the Market Implementation Date:
(a) Purchaser shall receive its 25% share of Installed Capacity and
Operable Capacity and shall be responsible for bidding such Installed Capacity
and Operable Capacity to the ISO. Purchaser shall be entitled to all payments
from ISO for such share of Installed Capacity and Operable Capacity.
(b) Seller on behalf of all Contract Purchasers shall submit bids to the
ISO for all NEPOOL Defined Products, other than Installed Capacity and
Operable Capacity, in accordance with the Bid Procedures and the Operational
Characteristics of Canal Unit I in order to enable the ISO to dispatch Canal
Unit I in accordance with NEPOOL procedures.
(c) Seller and Purchaser shall take all action necessary in accordance
with NEPOOL procedures to ensure that Purchaser shall receive credit with the
ISO for Purchaser's 25% of all NEPOOL Defined Products resulting from Canal
Unit 1.
(d) Seller shall be responsible for coordinating the submission of the
bids, in compliance with the Bidding Procedures, to ISO on behalf of Contract
Purchasers and Seller shall communicate the outcome of the dispatch to
Contract Purchasers. The Purchaser and Seller shall cooperate to provide
information to each other to comply with ISO rules and procedures.
(e) Seller may appoint an agent to perform its obligations under this
Section 9. The appointment of any agent which is not an Affiliate of Seller
shall require the consent of a majority of the Contract Purchasers Committee,
which consent may not be unreasonably withheld.
10. Accountings and Payment
(a) Seller will deliver to Purchaser an invoice within ten (10) Business
Days after the end of the month, or at such later date as is practicable, for
all amounts payable by Purchaser with respect to the previous month. Such
bills will be rendered in such detail as Purchaser may reasonably request.
All bills are due and payable on the last Business Day of the month when
rendered, but no earlier than seven (7) Business Days after receipt of the
invoice.
Each monthly billing may include expenses or charges for the amounts payable
hereunder, estimated on a periodic basis. Adjustments of items included in
prior billings shall be made in current billings. Adjustments shall accrue
interest at the Interest Rate. Adjustments of such items may be made at any
time within one year after the invoice as the result of-.
(1) Occurrences which change amounts owed or paid to third parties by
Seller or owed or paid to Seller by third parties.
(2) Errors or omissions in computing the billing as required by this
Contract.
Purchaser shall pay Seller by wire transfer to an account specified by Seller
from time to time.
(b) Within 120 days after the end of each Contract Year, Seller shall
render to Purchaser an accounting of such Contract Year's fuel usage and other
amounts billed as a pass through to Purchaser, and any adjustment of the total
amount billed for the period of said accounting shall be made in accordance
with said yearly accounting.
No Party shall have the night to challenge said yearly accounting or
adjustment, to invoke dispute resolution under Section 23 of the same, or to
bring any court or administrative action of any kind questioning the propriety
of said accounting, with respect to any adjustment under paragraph (a)(2) of
this Section (namely, any error or omission in computing the billing as
required by this Contract), after a period of one year from the date said
accounting is rendered.
For purposes of this one year limitation provision, any adjustments made under
paragraph (a)(1) of this Section (namely, adjustments occasioned by
occurrences changing amounts owed to or by third parties), shall be deemed to
have been made, whether or not actually made, in the year in which said
adjustments are finally determined as between Seller and third parties.
(c) Seller's books and records which directly pertain to the charges
rendered to Purchaser shall be open to reasonable inspection and audit by
Purchaser.
(d) Overdue payments shall accrue interest at the Interest Rate from, and
including, the due date to, but excluding, the date of payment.
11. Delivery
The electricity generated for the Purchaser by Canal Unit I shall be
delivered to Purchaser in the form of three (3) phase, sixty (60) cycle,
alternating current at the Delivery Point. Purchaser will make its own
arrangements for the transmission of power beyond the Delivery Point.
12. Term
Unless earlier terminated pursuant to Section 2, 17 or 27, this
Contract shall expire on October 10, 2002.
13. Purchaser's Right to Replacement Contract
Purchaser shall have the option to enter into a new contract for the
purchase of 25% of the capacity, energy, ancillary services and other NEPOOL
Products from Canal Unit I for the five (5) year period commencing with the
expiration of this Contract by delivering written notice to Seller on or
before December 31, 1999 of its irrevocable election to enter into such
contract. The terms of such replacement contract shall be as set forth on
Schedule 1 attached hereto. If such option is exercised, the Parties shall
negotiate in good faith to finalize and execute the replacement contract
promptly after December 31, 1999.
14. Force Majeure
Seller shall use all due diligence in accordance with Section 18 to
deliver to Purchaser regularly and without interruption the electricity to
which it is entitled under this Contract, but Seller shall be excused from
delivering electricity hereunder if and to the extent that it shall be
prevented from doing so by action of any court or any public authority or by
reason of delays in construction, or total or partial shutdown of Canal Unit I
by reason of breakdown, scheduled or unscheduled repair s or maintenance,
strike, labor troubles, civil disorders, flood, fire or any cause beyond the
reasonable control of Seller. Seller will use due diligence to resume normal
delivery of electricity in accordance with Good Utility Practice.
15. Insurance
Seller agrees to keep insured at all times Canal Unit I and all
appurtenant facilities against all property risks on which insurance is
available at commercially reasonable terms and conditions from reputable
insurance companies including but without limitation thereto:
(a) fire, explosion, wind, flood, earthquake, falling aircraft, vandalism,
malicious mischief, not and civil commotion.
(b) full breakdown of turbines, explosion, collapse or rupture of boilers
and pressure vessels.
All the foregoing insurance shall be carried in an amount at least
equal to the reproduction cost new of the insured property less depreciation
or, at Seller's option, a limit equal to two times the probable maximum loss
for the facility as determined by an independent expert. Seller also agrees
to carry basic public liability insurance with limits of at least
$100,000/$1,000,000, basic property damage insurance with limits of at least
$500,000 and a comprehensive excess combined personal injury and property
damage policy with limits of at least $15,000,000.
16. No Right of Setoff
Except as expressly provided in Section 5(b), neither Party shall be
entitled to set off, deduct or withhold against the payments required to be
made by it under this Contract any amounts which may from time to time be owed
to it by the other Party. However, the foregoing shall not affect in any
other way the rights and remedies which a Party may have with respect to any
such amounts.
17. Cancellation of Contract
(a) If Seller is unable to make energy deliveries to Purchaser because
either (1) Canal Unit I is damaged to the extent of being completely or
substantially completely destroyed, whether or not by reason of causes noted
in Section 14 hereof, (2) Canal Unit I is taken by exercise of the right of
eminent domain or a similar right or power; or (3) (A) Canal Unit I cannot be
used because a necessary license or other necessary public authorization
cannot be obtained or is revoked despite Seller's reasonable efforts in
accordance with Good Utility Practice to maintain such license or public
authorization, or because the use of such license or such authorization is
made subject to specified conditions which are not met, and (B) the situation
cannot be rectified to an extent which will permit Seller to make deliveries
to Purchaser from Canal Unit 1, then and in each such case, either Party may
cancel this Contract upon at least ten (10) Business Days prior notice to the
other Party.
(b) In all other circumstances no cancellation of the Contract or
discontinuance of payments shall be permitted.
18. Operation and Maintenance
Seller will operate and maintain Canal Unit I in accordance with Good
Utility Practice, all applicable law and in' Contract Purchasers' best
interest consistent with Good Utility Practice. Outages for inspection,
maintenance and necessary capital replacements will be scheduled in accordance
with Good Utility Practice and insofar as practicable shall be mutually agreed
upon by a majority of the Contract Purchasers Committee to the extent the
capital replacements affect the Contract Parties' rights and obligations under
this Contract. In the event of an unscheduled outage due to the failure or
impairment of any equipment or other cause, Seller will use its reasonable
efforts in accordance with Good Utility Practice to restore Canal Unit It of
service as soon as reasonably practical. Seller agrees to use due diligence
to maintain at Canal Unit I fuel inventory for the operation of Canal Unit 1
in accordance with Good Utility Practice.
19. Change in Law
In the event of a change in law, regulation or other legal requirement
after the date of this Contract which materially increases Seller's costs of
providing service to Purchaser, Seller shall confer with the Contract
Purchasers Committee to discuss the most economical manner to address such
change in costs in an effort to minimize the increase in costs. Seller shall
obtain the approval of a majority of the Contract Purchaser's Committee as to
the prudent course of action if such action require s any additional cost,
including without limitation any material capital addition. Seller shall
adjust the Demand Charge and/or the Energy Charge in a reasonable manner to
allow Seller to recover from Purchaser 25% of the increased costs resulting
from such change in law, regulation or other legal requirements and incurred
in accordance with the actions approved by a majority of the Contract
Purchasers Committee. Twenty-five percent (25%) of the reasonable costs of
any such material capital addition shall be passed through to Purchaser at a
reasonable rate of return, amortized over the normal useful life of the
capital addition.
The Contract Purchasers Committee shall not unreasonably withhold its
consent to action proposed by Seller to respond to such change in law,
regulation or other legal requirement, and in no event shall Seller be
prevented from complying with such change. In the event of a change in law,
regulation or other legal requirement after the date of this Contract which
materially decreases Seller's costs of providing service to Purchaser, Seller
shall adjust the Demand Charge and/or the Energy Charge in a reasonable manner
to pass through to Purchaser 25% of the benefits of any cost reduction
resulting from such change.
20. Taxes
Purchaser shall pay any and all sales taxes, gross receipts taxes,
excise taxes, franchise fees or any other fees or charges, including, without
limitation, any BTU tax or carbon tax, imposed by any federal, state or local
government or any regulatory agency over the provision of service hereunder or
Canal Unit 1 (including without limitation any tax imposed on NEPOOL Defined
Products produced by Canal Unit I or any tax imposed on interconnection
services) with the exception of income taxes or property taxes. Seller
represents and warrants that as of the date hereof it is not aware of any such
taxes, fees or charges which are imposed by any governmental authority and
which would be payable by Purchaser in accordance with this Section 20.
21. Interpretation
The interpretation and performance of this Contract shall be in
accordance with and controlled by the law of the Commonwealth of
Massachusetts.
22. Regulation
This Contract, and all rights, obligations and performance of the
Parties hereunder, are subject to all present and future applicable federal,
state and local laws and to all present and future duly issued and promulgated
orders, regulations, requirements and other duly authorized action of any
governmental authority having jurisdiction in the premises.
23. Dispute Resolution
(a) In case of any dispute between the Parties and after notice of
such dispute has been delivered from one Party to the other Party, such
dispute shall be referred to the Contract Purchasers Committee for resolution.
If the Contract Purchasers Committee fails to resolve the dispute in a manner
satisfactory to each Party within 30 days after notice of said dispute is
received by a Party, either Party may submit the matter to a Senior Officers
Committee composed of the Presidents or other senior officers of each Party.
Each Contract Party shall designate a senior officer to serve on the Senior
Officers Committee for the purpose of resolving the dispute. If the Senior
Officers Committee fails to resolve the dispute within 15 days following the
submission of the dispute to said committee, either Party may give the other
Party notice (a "Mediation Notice") that the dispute shall be referred to
mediation in accordance with Section 23(b). If the dispute between the
Parties involves one o r more of the Other Purchasers, each of the Other
Purchasers shall have the rights of the Parties under this Section 23(a).
(b) If either Party delivers a Mediation Notice to the other Party,
the Parties shall participate in a non-binding dispute resolution procedure
whereby each Party presents its case at a hearing (the "Hearing") before a
neutral mediator approved by each Party. If the Parties fall to agree upon
the mediator within seven (7) days after the date of the Mediation Notice,
either Party may direct the American Arbitration Association to select the
mediator.
Each Party may be represented at the Hearing by lawyers. If the
mediation proceedings do not result in a resolution of the dispute, such
mediation proceedings shall be without prejudice to the legal position of
either Party.
The Parties shall each bear their respective costs incurred in
connection with this procedure, except that the fees and expenses of the
neutral mediator and the costs of the facility for the Hearing shall be
allocated in the amount of fifty percent (50%) to each Party. If the dispute
is not resolved pursuant to Section 23(a) or within twenty one (21) days after
the date of the Mediation Notice, either Party may pursue any and all remedies
and legal proceedings as are available. If the dispute between the Parties
involves one or more of the Other Purchasers, each of the Other Purchasers
shall have the rights of the Parties under this Section 23(b), and the fees
and expenses of the neutral mediator and the costs of the facility for the
Hearing shall be allocated equally among the Parties and the Other Purchasers
involved in the dispute.
(c) Nothing in this Section 23 shall limit the rights of either Party
to seek in any court of competent jurisdiction such interim relief as may be
needed to maintain the status quo, to prevent irreversible harm, or otherwise
protect the subject matter of the mediation until the matter shall have been
finally resolved; provided, however, any such interim relief ordered by a
court shall not determine or prejudge the substantive issues to be decided by
such mediation.
(d) Notwithstanding anything to the contrary in this Section 23 or any
other provision in this Contract, if Purchaser disputes an amount invoiced
pursuant to Section 10 of this Contract, Purchaser shall pay the invoiced
amount in full prior to invoking this Section 23, subject to later return with
interest accrued in the interim at the Interest Rate.
24. Communications and Addresses
Except as the Parties may otherwise agree, any notice, request, bill
or other communication from one Party to the other, relating to this Contract
or the rights, obligations or performance of the Parties hereunder, shall be
in writing and shall be effective upon delivery to the other Party. Any
notice, request, demand, or statement, which may be given to or made upon a
Party hereto by the other Party hereto under any of the provisions of this
Contract, shall be in writing unless it is specifically provided otherwise
herein, and shall be treated as duly delivered either ( 1) when the same is
delivered in person or by reliable courier service or (2) three (3) days after
being deposited in the United States mail, by certified mail, postage prepaid,
and properly addressed to the Party to be served at the addresses listed below
the signature of such Party, or such other address as a Party may notify the
other in accordance with this Section 24.
25. Amendments
(a) Any amendments to this Contract shall be in writing. If the terms of
any of the Other Purchasers' New Contracts, as amended from time to time, are
different from the terms of this Contract, Seller shall give Purchaser the
right to amend this Contract to the same or substantially similar terms to
such Other Purchaser's New Contract. Purchaser shall notify Purchaser in
writing within 15 days after Seller enters into any Other Purchaser's New
Contract or any amendment thereto which contains different terms than the
terms herein. Purchaser shall have 15 days after receipt of such notice to
enter into an amendment of this Contract to contain such different terms.
(b) Prior to Seller or its Affiliate accepting an assignment of any Other
Purchaser's New Contract or Original Contract, Seller shall first issue a
request for proposals (an "RFP") to Purchaser regarding the terms (other than
price) under which Seller or its Affiliate is willing to accept such an
assignment. The RFP shall allow Purchaser to submit an offer for the
assignment of this Contract to Seller or its Affiliate, and such offer shall
not be deemed to be nonconforming simply because this Contract contains
different terms than an Other Purchaser's Original Contract or New Contract.
If Purchaser submits a conforming offer, Seller or its Affiliate shall not
accept an assignment from an Other Purchaser for a price that is less
favorable to Seller than the offer submitted by Purchaser. Seller and its
Affiliate shall not be under an obligation to accept any offer in response to
the RFP, and if Seller or its Affiliate changes the terms under which it
intends to accept an assignment of an Other Purchaser's Original Contract or
New Contract, Seller shall reissue the RFP.
(c) Seller's obligation under Section 25(b) shall terminate upon
Purchaser's assignment of this Contract to a third party.
26. Assignment
(a) Neither Party may assign this Contract without the written consent of
the other Party except in accordance with this Section 26.
(b) Upon not less than fifteen (15) days prior written notice to
Purchaser, Seller may assign this Contract to any party which acquires Canal
Unit I and which meets the Creditworthiness Criteria, provided, however,
Purchaser shall not unreasonably withhold its consent if a proposed assignee
is a direct or indirect subsidiary of an entity which meets the
Creditworthiness Criteria. Seller may assign this Contract as security to its
lenders and their agents.
(c) Upon not less than fifteen (1 5) days prior written notice, Purchaser
may assign this Contract to any party which meets the Creditworthiness
Criteria provided, however, Seller shall not unreasonably withhold its consent
if a proposed assignee is a direct or indirect subsidiary of an entity which
meets the Creditworthiness Criteria. Purchaser may assign this Contract as
security to its lenders and their agents.
(d) Any other assignment of this Contract shall not operate to relieve the
assigning Party of its obligations under this Contract without the written
consent of the other Party. Each Party agrees to execute such consents as are
reasonably requested by the other Party for an assignment to its lenders.
27. Default: Remedies; Limitation of Liability
(a) As used herein, "Event of Default" shall mean, in relation to a Party
(the "Defaulting Party"):
(i) Purchaser as the Defaulting, Party fails to make any payment that is
required hereunder to be made to Seller when due, and such failure continues
for five (5) Business Days after written notice from Seller;
(ii) Seller as the Defaulting Party breaches Section 4(a) by making
deliveries of Purchaser's portion of NEPOOL Products from Canal Unit 1 to
third parties;
(iii) the Defaulting Party fails to perform any of its material obligations
hereunder, other than as provided in subsection (i) or (ii), and such failure
is not excused by force majeure and continues for sixty (60) days after the
Defaulting Party receives written notice from the other Party (the "Non
Defaulting Party") of such failure; provided, however, with respect to a
failure to cure any such obligation, if a period in excess of sixty (60) days
is required to cure such failure, the Defaulting Party shall have such
additional amount of time, not to exceed one hundred eighty (I 80) days, as
may be necessary to cure such failure provided that the Defaulting Party uses
reasonable diligence to remedy such failure in accordance with Good Utility
Practice; or (iv) the Defaulting Party makes an assignment or general
arrangement for the benefit of creditors, files a petition in, or otherwise
commences any proceedings in, bankruptcy or under similar law, or otherwise
becomes bankrupt (however evidenced).
(b) In the event Seller falls to deliver energy from Canal Unit I as a
result of Seller's breach of its obligations under Section 18 which is not
excused by Section 14, during any cure period provided in Section 27(a)(iii)
Purchaser shall be entitled to all remedies available under Section (c) except
termination of this Contract. Purchaser shall give Seller prompt written
notice whenever Purchaser believes that the provisions of this Section 27(b)
are applicable.
(c) Upon an Event of Default, the Non-Defaulting Party may resort to all
remedies available at law or in equity, subject to the limitations set forth
in Section 27(d). If it is necessary for any Party to institute legal
proceedings or retain an attorney in attempting to collect a delinquent bill.
the other Party shall pay any and all expenses and costs of collection,
including reasonable attorneys' fees, incurred by such collecting Party.
(d) Except as otherwise explicitly stated herein, in no event shall either
Party be liable for punitive, exemplary, special, consequential or incidental
damages arising from any breach or default under this Contract, or from any
act or omission under or in connection with this Contract. Seller's rights to
payment of the Demand Charge, Energy Charge and other amounts payable
hereunder shall not be deemed to be consequential damages. Purchaser's rights
to payment for its incremental costs of Energy and other NEPOOL Defined
Products as damages in the event of a breach of this Contract shall not be
deemed to be consequential damages.
28. Indemnity
Each Party expressly agrees to indemnify, hold harmless and defend the
other Party against all claims, liability, costs or expense for loss, damage
or injury to persons or property in any manner directly or indirectly
connected with or arising out of, the generation, transmission or distribution
of electric energy on its own side of the Delivery Point.
29. Prior Agreements Superseded
Unless otherwise specifically provided, upon the Effective Date this
Contract supersedes any and all prior agreements and contracts by and between
the Parties relative to Canal Unit 1, including without limitation the
Original Contract.
This Contract has been made within the Commonwealth of Massachusetts and shall
bind and inure to the benefit of the Parties hereto and their respective
successors and permitted assigns.
IN WITNESS WHEREOF, the Parties have caused this Amended and Restated
Power Sales Contract to be executed by their officers duly authorized
thereunto and have duly caused their corporate or company seals to be affixed
hereto.
SOUTHERN' ENERGY CANAL, L.L.C.
By: /s/ Henry Coolidge
Henry Coolidge, President
Address:
c/o Southern Energy Resources, Inc.
900 Ashwood Parkway, Suite 500
Atlanta, GA 30338
Attention: Alan Harrelson
Vice President North American Assets
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Kevin A. Kirby, Vice President
Address:
Montaup Electric Company
c/o EUA Service Corporation
75 West Center Street
West Bridgewater, MA 02379
SCHEDULE 1
TERMS OF REPLACEMENT CONTRACT
Same terms as the Power Contract, except:
Demand Charge shall be 25% of the following:
October 11, 2002 through December 31, 2002 $ 9,370,000.00
January 1, 2003 through December 31, 2003 $42,260,000.00
January 1, 2004 through December 31, 2004 $46,460,000.00
January 1, 2005 through December 31, 2005 $52,520,000.00
January 1, 2006 through December 31, 2006 $53,810,000.00
January 1, 2007 through October 10, 2007 $55,130,000.00
Any increases to the Demand Charge in the existing contract as a result of
change of law shall be added to the above charges.
Any increases in property taxes following 2005 will be passed through to
Contract Purchasers.
Voting among the Contract Purchasers Committee will be weighted based on
percentage of entitlement from Canal Unit 1. For example, if two Contract
Purchasers elect to enter into the Replacement Contract and Seller's Affiliate
contracts for the remaining 50%, Seller's Affiliate would have 50% of the
votes on the Contract Purchasers Committee.
Each Party shall negotiate in good faith to make other reasonable
modifications to terms of the Contract as may be requested by either Party.
EX-10 (bb)(vii)
POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR GENERATION COMPANY
AND
MONTAUP ELECTRIC COMPANY
FOR PILGRIM NUCLEAR POWER STATION
TABLE OF CONTENTS
ARTICLE 1. Definitions
ARTICLE 2. Purchase and Sale of Installed Capability,
Operable Capability and Energy
ARTICLE 3. Term, Termination
ARTICLE 4. Purchase Rate for Installed Capability,
Operable Capability and Energy
ARTICLE 5. Dispatch
ARTICLE 6. Billing, Meter Reading
ARTICLE 7. Limitation of Liability; Indemnification;
Insurance; Relationship of Parties
ARTICLE 8. Miscellaneous Provisions
ARTICLE 9. Assignment
ARTICLE 10. Force Majeure
ARTICLE 11. Default
ARTICLE 12. Governing Law, Dispute Resolution
ARTICLE 13. Waiver
ARTICLE 14. Corporate Authorization
ARTICLE 15. Notice
POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR GENERATION COMPANY
AND
MONTAUP ELECTRIC COMPANY
AGREEMENT entered into this 18th day of November 1998 by and between
Entergy Nuclear Generation Company , a Delaware corporation (hereafter
referred to as "Seller"), and Montaup Electric Company, a Massachusetts
corporation having its principal place of business at W. Bridgewater,
Massachusetts 02379, (hereafter referred to as "Company").
WHEREAS, Seller wishes to purchase from Boston Edison Company ("Boston
Edison") the specific generating facility known as Pilgrim Nuclear Power
Station (the "Facility"), pursuant to the terms of a certain Purchase and Sale
Agreement dated November 18, 1998 by and between Boston Edison and Seller (the
"Purchase and Sale Agreement"); and
WHEREAS, Company contemplates that in connection with such purchase by
Seller it will be necessary to terminate Company's rights and obligations
under a certain power sale agreement with Boston Edison initially entered into
on August 1, 1972, which provides for the sale of power from the Facility by
Boston Edison to Company (the "Power Sale Agreement"); and
WHEREAS, Company and Boston Edison have agreed to amend the Power Sale
Agreement in order to effectuate such termination pursuant to the terms of the
Third Amendment to the Power Sale Agreement dated November 18, 1998 by and
between Company a nd Boston Edison ("Third Amendment"); and
WHEREAS, as a condition to, and upon such termination and the closing
of, the sale of the Facility to Seller, Seller wishes to sell to Company and
Company wishes to purchase from Seller Installed Capability, Operable
Capability and Energy from the Facility;
NOW, THEREFORE, in consideration of the mutual promises and agreements
contained herein, Seller and Company hereby agree as follows:
ARTICLE 1. Definitions
When used with initial capitalizations, whether in the singular or in
the plural, the following terms shall have the meanings set forth below.
(a) Agreement: This document, including its appendices, as
amended from time to time.
(b) Capability Audit: The procedure used pursuant to the NEPOOL
Agreement to determine the Summer Net Capability and the Winter Net Capability
of the Facility as currently set forth in the NEPOOL Standards.
(c) Company's Entitlement: The percentage specified below of the
Installed Capability, Operable Capability and Energy of the Facility for the
applicable calendar years.
1999 11.00000%
2000 11.00000%
2001 11.00000%
2002 8.80000%
2003 5.50000%
2004 5.50000%
(d) Energy: The actual hourly electricity production of the Facility
adjusted for station service use and transformer losses.
(e) Delivery Point: The point where capacity and energy generated by the
Facility is delivered to the Pool Transmission Facilities, as defined by the
NEPOOL Agreement.
(f) Facility: The Pilgrim Nuclear Power Station, a 670 MW nuclear
generating facility located in Plymouth, Massachusetts.
(g) FERC: The Federal Energy Regulatory Commission.
(h) Installed Capability: The Winter Net Capability during the Winter
Period and the Summer Net Capability during the Summer Period.
(i) ISO-NE: The Independent System Operator of New England provided for
in the NEPOOL Agreement, or its successor.
(j) MDTE: The Massachusetts Department of Telecommunications and Energy.
(k) NEPOOL: The New England Power Pool, established by the NEPOOL
Agreement, or its successor.
(l) NEPOOL Agreement: The agreement, dated September 1, 1971, as amended
from time to time, governing the operation of NEPOOL, as in full force and
effect.
(m) NEPOOL Standards: All Criteria, Rules and Standards (CRS), NEPOOL
Automated Billing System Procedures (NABS), Operating Procedures (OP), and
Market Rules (MR) issued or adopted by NEPOOL, ISO-NE and its satellite
agencies, or their successors, as amended from time to time and all successor
regulations, rules and standards.
(n) Operable Capability: The portion of Installed Capability of the
Facility which is operating or available to respond within an appropriate
period (as defined by NEPOOL) to the ISO-NE call to meet the Energy
requirements of the NEPOOL operating area.
(o) Party: Seller or Company and its respective successors or assigns.
(p) Prime Rate: That rate as announced by BankBoston (or its successor)
as its prime rate in effect on the first day of the month.
(q) Prudent Utility Practice: Any practices, methods and acts engaged in
or approved by a significant portion of the electric utility industry during
the relevant time period, or any of the practices, methods and acts which, in
the exercise of reasonable judgment in light of 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 and giving due regard for the requirements of
governmental agencies having jurisdiction. Prudent Utility Practice is not
intended to be limited to the optimum practice, method, or act to the
exclusion of all others, but rather to be acceptable practices, methods, or
acts generally accepted in the electric utility industry.
(r) Summer Net Capability (Capability): The Maximum Claimed Capability,
as defined in NEPOOL CRS - 4 , of the Facility during the Summer Period,
expressed in kilowatts, and as determined by Capability Audit, exclusive of
the capacity required for Facility use.
(s) Summer Period: Summer Period shall have the meaning set forth in the
NEPOOL Agreement.
(t) Winter Net Capability (Capability): The Maximum Claimed Capability,
as defined in NEPOOL CRS - 4 , of the Facility during the Winter Period,
expressed in kilowatts, and as determined by Capability Audit, exclusive of
the capacity required for Facility use.
(u) Winter Period: Winter Period shall have the meaning set forth in the
NEPOOL Agreement.
ARTICLE 2. Purchase and Sale of Installed Capability, Operable Capability
and Energy
(a) Seller agrees to sell and to deliver and Company agrees to purchase
and to accept delivery of the Company's Entitlement at the Delivery Point, for
Company's own use and/or sale to others for the term of this Agreement.
(b) Seller shall use Prudent Utility Practices in all aspects of the
management and operation of the Facility. Seller shall use commercially
reasonable efforts to maintain the Facility's Installed Capability at the
level demonstrated by the most recent Capability Audit at the time of the
Purchase and Sale Agreement and use its commercially reasonable efforts to
make Energy and Operable Capability available to Company on an ongoing basis.
Notwithstanding the foregoing, Seller may permanently retire the Facility
upon 30 days written notice to the Company, at which time this Agreement will
terminate.
(c) Periodically after the execution of this Agreement, Seller shall
undergo Capability Audits pursuant to NEPOOL Standards to demonstrate and
audit the Summer Net Capability and/or the Winter Net Capability of the
Facility. The Capability Audit shall be performed pursuant to NEPOOL
Standards or standards mutually agreed to by the Parties if NEPOOL ceases to
establish such standards. Seller agrees to provide to Company the results of
the demonstrations and audits (NX-17s and supporting material).
(d) Seller shall schedule maintenance activities in accordance with NEPOOL
Standards. As soon as practically possible, Seller shall provide advance
notice of planned maintenance activities and unplanned outages by telephone or
telecopy to Company's designated agent.
ARTICLE 3. Term, Termination
The obligations of the Parties under this Agreement shall commence on
the Effective Date as defined in the Third Amendment and, subject to the
termination provisions set forth in this Agreement, shall continue through
December 31, 2004. In addition, applicable provisions of this Agreement
shall remain in effect after termination hereof, including Article 7 and
provisions necessary to provide for final billings, billing adjustments, and
payments.
ARTICLE 4. Purchase Rate for Installed Capability, Operable Capability
and Energy
(a) Company shall pay Seller monthly (on a $/Mwh basis) for Installed
Capability, Operable Capability and Energy, according to the following
formula:
TMAt = Pt x Ut
where:
TMAt = Total monthly amount due in month (t)
Pt = The Purchase price expressed in $/Mwh
= 35.00 $/Mwh for all the months in the year 1999
= 38.00 $/Mwh for all the months in the year 2000
= 35.19 $/Mwh for all the months in the year 2001
= 38.89 $/Mwh for all the months in the year 2002
= 43.52 $/Mwh for all the months in the year 2003
= 47.22 $/Mwh for all the months in the year 2004
Ut = The Energy portion of the Company's Entitlement delivered to
Company in month (t) expressed in megawatthours.
ARTICLE 5. Dispatch
(a) Seller shall make the Facility available for dispatch by ISO-NE.
(b) Seller shall comply with all NEPOOL Standards applicable to Seller.
(c) Seller shall submit all forms to ISO-NE with a copy to Company.
(d) Seller's and Company's designated agent shall mutually agree to any
revision to the existing ISO-NE NX-12B Forms to be submitted to ISO-NE in
accordance with the provisions of the NEPOOL Agreement and NEPOOL Standards.
(e) Whenever Company's system or the systems with which it is directly
interconnected experience an emergency, as designated by the affected utility,
or whenever it is necessary to aid in the restoration of service on Company's
system or on the systems with which it is directly or indirectly
interconnected, or, whenever requested by ISO-NE, Seller or its designee shall
curtail or interrupt the delivery of all or a portion of the production of
electricity at the Facility provided such curtailment or interruption shall
continue only for as long as reasonably necessary to deal with the emergency.
(f) Whenever Seller's Facility experiences an emergency, Seller or its
designee shall have the right to curtail or interrupt all or a portion of
Seller's obligation hereunder, provided such curtailment or interruption shall
continue only for so long as reasonably necessary to deal with the emergency,
and provided Seller promptly notifies Company of the occurrence of such an
emergency.
ARTICLE 6. Billing, Meter Reading
(a) Seller shall deliver Company's Entitlement to the Delivery Point.
Seller is responsible for maintaining metering and telemetering equipment at
the Facility. The metering equipment shall be capable of registering and
recording instantaneous, and time-differentiated electric energy and other
related data from the Facility, and shall comply with the requirements of
NEPOOL's Standards as may be issued or revised from time to time. The
telemetering shall be capable of transmitting such data to location(s)
specified by Company.
(b) Each day, Seller shall be required to provide Company with hourly
integrated megawatt hour readings for each hour of the previous day. Seller
shall record hourly meter readings and log sheets and, upon Company's request,
provide copies of daily meter recordings and log sheets by electronic means
with hard copy back-up. All metering equipment installed shall be routinely
tested in accordance with Prudent Utility Practice. Any meter tested and
found to register within one-half of one percent (0.5%) of the recognized
comparative standard shall be considered correct and accurate. If at any
time, any metering equipment is found to be defective or inaccurate, Seller
shall cause such metering equipment to be made accurate or re placed at
Seller's expense. Notwithstanding subarticle (e) below, in such event, a
billing adjustment shall be made by Seller correcting all measurements made by
the defective meter for either: (i) the actual period during which inaccurate
measurements were made, if such period is determinable to the mutual
satisfaction of the Company and Seller; or (ii) if such period is not
determinable, for a period equal to one-half the time elapsed since the prior
test, but in no event greater than six months.
(c) Seller shall submit, by telecopy or other agreeable same day delivery
mechanism, an invoice for all applicable Article 4 charges to Company as soon
as practicable after the end of each calendar month that shall include the
time and date of the meter readings. This invoice shall include such
reasonable detail to enable the Company to determine the basis for the charges
of such month. Seller and Company agree to provide additional information
reasonably requested by the other Party as necessary for billing purposes or
data verification. Invoices may be rendered on an estimated basis. Each
invoice shall be subject to adjustment for any errors in arithmetic,
computing, estimating or otherwise. Seller and Company shall include any such
invoicing adjustments as promptly as practicable.
(d) All payments shown to be due on such invoice, except amounts in
dispute, shall be due and payable as shown on the invoice. Company shall pay
by wire transfer per instructions on the invoice on or before ten (10) days
after receipt of the invoice.
(e) Any undisputed amounts unpaid after the Due Date shall bear interest
at a rate equal to the Prime Rate then in effect on the Due Date, compounded
on a monthly basis. Company may dispute all or any part of any invoice by
written notification to Seller within 30 days of receipt of such invoice. All
amounts paid by the Company which are subsequently determined to have been
improperly invoiced by Seller under this Agreement shall be subject to refund
with interest at a rate equal to the Prime Rate then in effect on the Due
Date, compounded on a monthly basis.
(f) Seller shall keep complete and accurate records and meter readings of
its operations and shall maintain such data for a period of at least one (1)
year after invoice for the final billing is rendered. Company shall have the
right, upon five (5) business days prior notice, during normal business hours,
to examine and inspect all such records and meter readings in so far as may be
necessary for the purpose of ascertaining the reasonableness and accuracy of
all relevant data, estimates or statements of charges submitted to it
hereunder but shall not impair or interfere with the operation of the Facility
owned by Seller.
ARTICLE 7. Limitation of Liability; Indemnification; Insurance;
Relationship of Parties
(a) Notwithstanding subarticle (b) hereof or any other provision of this
Agreement to the contrary, neither Company nor Seller nor their respective
officers, directors, agents, employees, parent, subsidiaries or affiliates or
their officers, directors, agents or employees shall be liable or responsible
to the other Party or its parent, subsidiaries, affiliates, officers,
directors, agents, employees, successors or assigns, or their respective
insurers, for incidental, indirect, exemplary, punitive or consequential
damages, connected with or resulting from performance or non-performance of
this Agreement, or anything done in connection therewith including, without
limitation, claims in the nature of lost revenues, income or profits (other
than payments expressly required and properly due under this Agreement), and
increased expense of, reduction in or loss of power generation production or
equipment used therefor, irrespective of whether such claims are based upon
breach of warranty, tort (including negligence, whether of Seller, Company or
others), strict liability, contract, operation of law or otherwise, but
excluding acts of gross negligence or willful misconduct.
(b) Each Party (the "Indemnifying Party") shall defend, indemnify and save
the other Party (the "Indemnified Party"), its officers, directors, agents,
employees and affiliates and their respective officers, directors, agents and
employees harmless from and against any and all claims, liabilities, demands,
judgments, losses, costs, expenses (including reasonable attorneys' fees),
suits, or damages arising by reason of bodily injury, death or damage to third
party property sustained by any person or entity (whether or not a party to
this Agreement) caused by or attributable to a breach of this Agreement by the
Indemnifying Party or an action of gross negligence or willful misconduct of
the Indemnifying Party or an officer, direct or, agent or employee of
Indemnifying Party.
(c) Seller shall maintain insurance coverage at its sole expense.
(d) The rights, obligations and protections afforded by subarticles (a)
and (b) above shall survive the termination, expiration or cancellation of
this Agreement, and shall apply to the full extent permitted by law.
(e) Nothing in this Agreement shall be construed as creating any
relationship between the Parties other than that of independent contractors
for the sale and purchase of Installed Capability, Operable Capability and
Energy generated at the Facility. The Parties do not intend to create any
rights, or grant any remedies to, any third party beneficiary of this
Agreement.
ARTICLE 8. Miscellaneous Provisions
(a) The Parties hereto agree that time shall be of the essence of this
Agreement.
(b) This Agreement may not be modified or amended except in writing signed
by or on behalf of both Parties by their duly authorized officers, and if
applicable, after obtaining any required regulatory approvals.
(c) It shall be the responsibility of Seller to take all necessary actions
to satisfy any regulatory requirements which may be imposed on Seller by any
statute, rule or regulation concerning the sale of Installed Capability,
Operable Capability and Energy. Company shall cooperate with Seller and
provide information or such other assistance, without cost to Company, as may
be reasonably necessary for Seller to satisfy regulatory requirements relating
specifically and only to the sale of Installed Capability, Operable Capability
and Energy from the Facility. Seller shall cooperate with Company and provide
information or such other assistance, without cost to Seller, as may be
reasonably necessary for Company to satisfy regulatory requirements relating
specifically and only to the purchase of Installed Capability, Operable
Capability and Energy from the Facility.
(d) Notwithstanding subarticle (c) above, Seller agrees to provide, at no
cost to Company, all necessary forms, data, and other information reasonably
requested of Company by ISO-NE, NEPOOL, or any governmental or regulatory
agency or authority having jurisdiction.
ARTICLE 9. Assignment
(a) Neither Party shall have the right to assign this Agreement or its
rights or obligations hereunder without the express written consent of the
other Party. Such consent shall not be unreasonably withheld. No assignment
shall be effective until any and all necessary regulatory approvals of the
assignment have been obtained.
(b) Notwithstanding the provisions in Section 9(a) above:
(i) Seller may assign this Agreement to any affiliate to whom the Facility
is transferred, without the Company's prior consent; provided that Seller
shall not be released from liability hereunder without the Company's prior
written consent.
(ii) Seller may collaterally assign its rights in this Agreement to its
lenders.
(iii) The Company has the right to assign or transfer all of its rights and
obligations under this Agreement, without the consent of Seller, provided that
Company shall first provide Seller with thirty (30) days prior written notice
of the proposed assignment or transfer and documentary evidence of the
assignee's or transferee's financial capacity to satisfy any and all
obligations so assigned; and provided further that such documentary evidence
may be that such assignee or transferee has a current agency report indicating
an investment grade rating from any two of the following:
Standard & Poor's, Moody's, Duff & Phelps, or Fitch. Any assignment or
transfer by the Company shall include an explicit requirement that the
assignee or transferee agrees to undertake each and every obligation that the
Company has under this Agreement. The Seller understands and acknowledges
that the Company intends to assign or transfer all of its rights and
obligations under this Agreement.
ARTICLE 10. Force Majeure
(a) If either Party is rendered wholly or partly unable to perform its
obligations under this Agreement because of a Force Majeure event, that Party
shall be excused from whatever performance is affected by the Force Majeure
event to the extent so affected, provided that the non-performing Party shall:
(i) provide prompt notice to the other Party of the occurrence of the Force
Majeure event giving an estimation of its expected duration and the probable
impact on the performance of it s obligations hereunder and submitting good
and satisfactory evidence of the existence of the Force Majeure event; (ii)
exercise all reasonable efforts to continue to perform its obligations
hereunder; (iii) expeditiously take action to correct or cure the Force
Majeure event and submit good and satisfactory evidence that it is making all
reasonable efforts to correct or cure the Force Majeure event; (iv) exercise
all reasonable efforts to mitigate or limit damages to the other Party to the
extent such action shall not adversely effect its own interests; and (v)
provide prompt notice to the other Party of the cessation of the Force Majeure
event; provided further that any obligations of either Party which arose
before the occurrence of the Force Majeure event causing non-performance shall
not be excused as a result of the occurrence of a Force Majeure event.
(b) "Force Majeure" means the failure or imminent threat of failure of
facilities or equipment, flood, freeze, earthquake, storm, fire, lighting,
other acts of God, epidemic, war, acts of a public enemy, riot, civil
disturbance or disobedience, strike, lockout, work stoppages, other industrial
disturbance or dispute, sabotage, restraint by court order or other public
authority, and action or non-action by, or failure or inability to obtain the
necessary authorizations or approvals from, any governmental agency or
authority, which by the exercise of due diligence such Party could not
reasonably have been expected to avoid and by exercise of due diligence its
effect can not be overcome. Nothing contained herein shall be construed so as
to require the Parties to settle any strike, lockout, work stoppage or any
industrial disturbance or dispute in which it may be involved, or to seek
review of or take an appeal from any administrative or judicial action. In no
event shall the lack of funds or an inability to obtain funds or any action by
any governmental authority that disallows, prevents or limits the recovery
through rates of all or any portion of the charges imposed by this Agreement
be a Force Majeure event.
ARTICLE 11. Default
(a) "Event of Default" shall mean in relation to a Party (the "Defaulting
Party"):
(i) the Defaulting Party fails to perform any of its material obligations
hereunder, and such failure is not excused by Force Majeure and continues for
thirty (30) days after the Defaulting Party receives written notice from the
Non-Defaulting Party of such failure; provided, however, if a period in excess
of thirty (30) days is required to cure such failure, the Defaulting Party
shall have an additional amount of time, not to exceed 180 days, as may be
necessary to cure such failure, provided t hat the Defaulting Party uses
reasonable diligence to remedy such failure and provided further that, the
foregoing "cure" provisions shall not apply to: y) failure by Company to make
payments to Seller pursuant to Article 6, or z) failure by Seller to make
available and deliver Company's Entitlement; or (ii) the Defaulting Party
makes an assignment or general arrangement for the benefit of creditors, files
a petition, or otherwise commences any proceeding, in bankruptcy or under
similar law, otherwise becomes bankrupt (however evidenced) or is unable to
pay its debts as they fall due.
(b) Upon an Event of Default, the Non-Defaulting Party may resort to all
remedies available at law or in equity, including, without limitation: (i) the
termination of service; (ii) specific enforcement of the provisions of this
Agreement ; and/or (iii) the recovery of damages except to the extent such
damages are waived or limited pursuant to this Agreement.
ARTICLE 12. Governing Law, Dispute Resolution
(a) The interpretation and performance of this Agreement shall be in
accordance with, and controlled by the law of, the Commonwealth of
Massachusetts, notwithstanding its conflicts of law's principles.
(b) If any dispute, disagreement, claim or controversy exists between
Seller and Company arising out of or relating to this Agreement, such disputed
matter shall be submitted to a committee comprised of one designated agent of
each Party. Such committee shall be instructed to attempt to resolve the
matter within twenty (20) days thereafter. If Company's and Seller's
designees do not agree upon a decision within thirty (30) days after the
submission of the matter to them, either Party may institute formal legal
proceedings.
ARTICLE 13. Waiver
The failure of either Party to require compliance with any provision
of this Agreement shall not affect that Party's right to later enforce the
same. It is agreed that the waiver by either Party of performance of any of
the terms of this Agreement, or of any breach thereof, shall not be held or
deemed to be a waiver by that Party of any subsequent failure to perform the
same, or any other term or condition of this Agreement, or of any breach
thereof.
ARTICLE 14. Corporate Authorization
Prior to or simultaneous with the Effective Date of this Agreement,
the Parties shall provide sufficient evidence to each other that each has the
legal power and authority to perform this Agreement, that their respective
officers executing this Agreement have been duly authorized to do so and that
this Agreement, upon execution and delivery, shall be legally binding and
enforceable.
ARTICLE 15. Notice
Except as otherwise provided herein, any notice, invoice or other
communication which is required or permitted by this Agreement shall be in
writing and delivered by personal service, telecopy, or mailed certified or
registered first class mail, postage prepaid, properly addressed as follows:
a) In the case of Company to:
Montaup Electric Company
c/o EUA Service Corp.
W. Bridgewater, Massachusetts 02379 U.S.A.
Attention: Robert P. Clarke
Telecopy No: 508-583-2356
b) In the case of Seller to:
Carolyn C. Shanks, CPA
Vice President, Finance and Administration
Entergy Nuclear Generation Company
P.O. Box 31995
Jackson, MS 39286-1995
Street Address:
1340 Echelon Parkway
Jackson, MS 39213
Telecopy No: 601-368-5323
Another address or addressee may be specified in a notice duly given
as provided. Each notice, invoice or other communication which shall be
mailed, delivered or transmitted in the manner described above shall be deemed
sufficiently given an d received for all purposes at such time as it is
delivered to the addressee (with return receipt, the delivered receipt, the
affidavit of the messenger or with respect to a telecopy, the answer back,
being deemed conclusive evidence of such delivery) or at such time as delivery
is refused by the addressee upon presentation.
IN WITNESS WHEREOF the Parties have executed this Agreement as of the date
first written above.
ENTERGY NUCLEAR GENERATION COMPANY
By: /s/ Donald C. Hintz
Name: Donald C. Hintz
Title: President and Chief Executive Officer
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Name: Kevin A. Kirby
Title: Vice President
EX-10 (bb)(viii)
POWER PURCHASE AND SALES AGREEMENT (REDACTED VERSION)
POWER PURCHASE AND SALE AGREEMENT
BETWEEN
MONTAUP ELECTRIC COMPANY
AND
CONSTELLATION POWER SOURCE, INC.
December 21, 1998
TABLE OF CONTENTS
Page
ARTICLE 1. Definitions
ARTICLE 2. Effective Date; Term and Conditions Precedent
ARTICLE 3. Delivery of Power; Hydro Quebec Transmission Use Rights;
Designation of Purchaser as Agent; Assignment of Commitments
ARTICLE 4. Payments
ARTICLE 5. Covenants of the Parties
ARTICLE 6. Force Majeure
ARTICLE 7. Events of Default; Remedies
ARTICLE 8. Representations and Warranties
ARTICLE 9. Indemnification
ARTICLE 10. Dispute Resolution
ARTICLE 11. Miscellaneous
SCHEDULE 1 Commitments
SCHEDULE 1-A Agreements Related to Hydro-Quebec Interconnection
SCHEDULE 2 Seller Payments
SCHEDULE 3 Seller Required Regulatory Approvals
SCHEDULE 4 Purchaser Required Regulatory Approvals
SCHEDULE 5 Exceptions to Seller's Title to the Commitments
SCHEDULE 6 Defaults Under the Commitments
SCHEDULE 7 Legal Proceedings
SCHEDULE 8 Form of Guaranty
POWER PURCHASE AND SALE AGREEMENT
This POWER PURCHASE AND SALE AGREEMENT ("Agreement") is dated as of
December 21, 1998 and is made by and between MONTAUP ELECTRIC COMPANY, a
Massachusetts corporation ("Seller"), and CONSTELLATION POWER SOURCE, INC. a
Delaware corporation ("Purchaser") (each individually a "Party", or
collectively the "Parties").
RECITALS
WHEREAS, Seller is engaged in a complete divestiture of its generation
assets and purchase power entitlements in accordance with the terms of
comprehensive restructuring settlement agreements between Seller, its retail
affiliates and regulatory and other parties in Massachusetts and Rhode Island
which were approved by the FERC in Docket Nos. ER97-2800-000, et al.; and
WHEREAS, Seller desires to sell, and Purchaser desires to purchase,
the economic benefits and performance obligations, subject to Seller's
continuing obligations to make certain payments, associated with the power
purchase agreements and transmission support agreements hereinafter described
between Seller and third party power suppliers.
NOW, THEREFORE, in consideration of the mutual covenants,
representations, warranties and agreements hereinafter set forth, and
intending to be legally bound hereby, the parties hereto agree as follows:
ARTICLE 1 DEFINITIONS
1.1 Definitions.
(a) As used in this Agreement, the following terms have the meanings
specified in this Section 1.1(a).
"Administration Services" means those services provided by Seller: (i)
to maintain the interconnection and meter the electricity produced and
delivered under the BHI PPA (for which Seller is entitled to collect and
retain the costs therefor from BHI), (ii) to determine and invoice the
appropriate charges to be paid by Seller and Purchaser, (iii) to collect the
aforementioned charges to be paid by Purchaser and (iv) to provide such
operational data with respect to the Commitments that is reasonably available
to Seller (to the extent permissible under that Commitment) and as Purchaser
may request from time to time.
"Affiliate" has the meaning set forth in Rule 12b-2 of the General
Rules and Regulations under the Exchange Act.
"Ancillary Agreements" means the Wholesale Standard Offer Service
Agreement, the Seller Guaranty and the Subtransmission Service Agreement, if
Purchaser elects, on or prior to the Effective Date in its sole discretion, to
enter into such agreement.
"Business Day" shall mean any day other than Saturday, Sunday and any
day which is a legal holiday or a day on which banking institutions in Boston,
Massachusetts are authorized by law or other governmental action to close.
"Commitment" means the contracts described in Schedule 1 attached
hereto and made a part hereof, together with any modifications, amendments or
supplements thereto.
"Eastern" means Eastern Edison Company, a Massachusetts corporation.
"Encumbrances" means any mortgages, pledges, liens, security
interests, assignment, conditional and installment sale agreements, activity
and use limitations, conservation easements, easements, deed restrictions,
encumbrances and charges of any kind.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Federal Power Act" means the Federal Power Act of 1935, as amended.
"FERC" means the Federal Energy Regulatory Commission.
"Good Utility Practice" means any of the applicable practices, methods
and acts engaged in or approved by a significant portion of the electric
utility industry during the relevant time period; which in each case in the
exercise of reasonable judgment in light of the facts known or that should
have been known at the time a decision was made, could have been expected to
accomplish the desired result in a manner consistent with law, regulation,
safety, environmental protection, economy, and expedition. Good Utility
Practice is intended to be acceptable practices, methods or acts as generally
accepted in the region, and is not intended to be limited to the optimum
practices, methods or acts to the exclusion of all others.
"Holding Company Act" means the Public Utility Holding Company Act of
1935, as amended.
"Interest Rate" means, for any date, the lesser of (a) the per annum
rate of interest equal to the prime lending rate then in effect at the main
office of BankBoston, or such other lending institution as agreed to by Seller
and Purchaser and (b) the maximum rate permitted by applicable law.
"Material Adverse Effect" means any change in or effect on Seller,
Purchaser, Commitments or Power Sellers after the date of this Agreement that
is materially adverse to any of the transactions contemplated hereby, other
than (i) any change or effect resulting from changes in the international,
national, regional or local wholesale or retail markets for electric power;
(ii) any change or effect resulting from changes in the international,
national, regional or local markets for any fuel used at any of the facilities
providing Power under the Commitments; (iii) any change or effect resulting
from changes in the North American, national, regional or local electric
transmission systems; and (iv) any materially adverse change in or effect on
or in connection with the Commitments which is cured (including by the payment
of money) by Seller promptly in accordance with the terms of the Commitment
before the Effective Date.
"MDTE" means the Massachusetts Department of Telecommunications and
Energy.
"Moody's" means Moody's Investors Service, Inc., and any successor
thereto.
"NEPOOL" means the New England Power Pool, and any successor thereto,
"Net Worth" means total assets (exclusive of intangible assets) less
total liabilities as reflected on a balance sheet prepared in accordance with
generally accepted accounting principles consistently applied.
"Person" means any individual, a partnership, a limited liability
company, a joint venture, a corporation, a trust, an unincorporated
organization and a governmental entity or any department or agency thereof.
"Power Seller" or "Power Sellers" means the party or parties with
which Seller has contracted for the purchase of Power or the provision of
transmission facilities or services under each of the Commitments.
"Purchaser" means Constellation Power Source, Inc., a Delaware
corporation and its successors and permitted assigns.
"Purchaser Representatives" means Purchaser's accountants, counsel,
environmental consultants, financial advisors and other authorized
representatives.
"Replacement Price" means the price at which Purchaser, acting in a
commercially reasonable manner, purchases substitute Power for the Power not
delivered by Seller, plus any additional transmission charges incurred by
Purchaser to the Delivery Point; or, absent any such purchase, the market
price for such quantity at such Delivery Point during the applicable delivery
period as determined by Purchaser in a commercially reasonable manner;
provided, that the "market price" for NEPOOL products other than capacity and
energy shall be determined by reference to the applicable price for such
products as determined by the NEPOOL independent system operator.
"Retail Companies" means, as applicable, each, any or all of
Blackstone Valley Electric Company, Eastern Edison Company and Newport
Electric Corporation.
"RIPUC" means the Rhode Island Public Utilities Commission.
"S&P" means Standard & Poor's Ratings Group, a division of McGraw
Hill, Inc., and any successor thereto.
"Sales Price" means the price at which Seller, acting in a
commercially reasonable manner, resells the Power not received by Purchaser,
reduced by additional transmission charges, if any, incurred by Seller to
effect such resale.
"SEC" means the Securities and Exchange Commission.
"Securities Act" means the Securities Act of 1933, as amended.
"Seller" means Montaup Electric Company, a Massachusetts corporation
and its successors and permitted assigns.
"Standard Offer Service" means the electric service, if any, required
to be provided by one or more of the Retail Companies to its retail customers
who do not elect to purchase electricity from an alternative supplier in the
market.
"Subsidiary" when used in reference to any other Person means any
entity of which outstanding securities having ordinary voting power to elect a
majority of the Board of Directors or other Persons performing similar
functions of such entity are owned directly or indirectly by such other
Person.
"Subtransmission Service Agreement" means the Subtransmission Service
Agreement between Seller and Purchaser pursuant to which Seller agrees to sell
and Purchaser agrees to purchase certain subtransmission service to facilitate
deliveries of Power under the BHI PPA.
"Taxes" means all taxes, charges, fees, levies, penalties or other
assessments imposed by any United States federal, state or local or foreign
taxing authority, including, but not limited to, income, excise, property,
sales, transfer, franchise, payroll, withholding, social security or other
taxes, including any interest, penalties or additions attributable thereto.
"Transition Costs" means the Contract Termination Charges calculated
and collected in accordance with the settlement agreements between Seller and
the Retail Companies, approved by FERC in Docket Nos. ER97-2800-000, ER97-
3127-000 and ER97-2338-000.
"Wholesale Standard Offer Service Agreement" means the Wholesale
Standard Offer Service Agreement between the Retail Companies and Purchaser of
even date herewith pursuant to which Purchaser has agreed to deliver and sell
and the Retail Companies have agreed to receive and purchase of the Retail
Companies' Standard Offer Service load obligations.
(b) Each of the following terms has the meaning specified in the
Section or Schedule set forth opposite such term:
Term Section/Schedule
AAA 10.1
BHI Schedule 1
BHI PPA Schedule 1
Canal PPA Schedule 1
Commitment List Schedule 1
Delivery Point 3.1(a)
Direct Claim 9.2(c)
Due Date 4.4(a)
Effective Date 2.1(a)
Event of Default 7.1
Final Order 2.1(a)(ii)
Firm Energy Contract Schedule 1
Force Majeure 6.2
GSP 11.11
Indemnifiable Loss 9.1(a)
Indemnifying Party 9.1(d)
Indemnitee 9.1(c)
Initial Purchaser Credit Support 5.8(a)
McNeil PPA Schedule 1
Northeast PPA Schedule 1
Northeast Security 2.1(b)(vii)
Non-Performing Party 3.5(a)
Other Party 3.5(a)
Power 3.1(a)
Purchaser Payment 4.1(a)
Purchaser Required Regulatory Approvals Schedule 4
Resale Proceeds 4.4(a)
Seller Additional Security 5.9(c)
Seller Guarantor 5.9(a)
Seller Guaranty 5.9(a)
Seller Required Regulatory Approvals Schedule 3
Seller Payment 4.1
Term 2.2(a)
Third Party Claim 9.2(a)
Trigger Payment 4.3(a)
Trigger Payment Date 4.3(a)
Trigger Event 4.3(b)
ARTICLE 2 EFFECTIVE DATE; TERM AND CONDITIONS PRECEDENT
2.1 Effective Date; Conditions Precedent.
(a) The obligations of Seller and Purchaser hereunder are subject to
satisfaction of the following conditions precedent and this Agreement shall
become effective, unless the Parties otherwise agree, at midnight on the last
day of the month in which all such conditions have been satisfied if the
conditions are satisfied on or before the 5th Business Day prior to the last
day of such month or if not, then midnight on the last day of the next
succeeding month after the month in which such conditions have been satisfied,
as the case may be; such date is hereinafter referred to as the "Effective
Date":
(i) No preliminary or permanent injunction or other order or decree by any
federal or state court which prevents the consummation of transactions
contemplated hereby shall have been issued and remain in effect (each Party
agreeing to use its reasonable efforts to have any such injunction, order or
decree lifted) and no statute, rule or regulation shall have been enacted by
any state or federal government or governmental agency in the United States
which prohibits the consummation of the transactions contemplated hereby;
(ii) All federal, state and local government consents and approvals
required for the consummation of the transactions contemplated hereby,
including, without limitation, Seller Required Regulatory Approvals and
Purchaser Required Regulatory Approvals, shall have been obtained or become
Final Orders (a "Final Order" means a final order after all opportunities for
rehearing and appeal are exhausted). If such approvals are conditional in any
material respect or materially modify , directly or indirectly, the
obligations of a Party hereto, such approvals must be acceptable to each
Party, in its reasonable discretion; and
(iii) All consents and approvals for the consummation of transactions
contemplated hereby required under the terms of any note, bond, mortgage,
indenture, contract or other agreement to which Seller or Purchaser, or any of
their Subsidiaries or Affiliates, are a party shall have been obtained.
(b) The obligation of Purchaser to effect the transactions contemplated by
this Agreement shall be subject to the fulfillment of the following additional
conditions:
(i) There shall not have occurred and be continuing a Material Adverse
Effect;
(ii) Seller shall have performed and complied with in all material respects
the covenants and agreements contained in this Agreement which are required to
be performed and complied with by Seller on or prior to the Effective Date,
and the representations and warranties of Seller set forth in this Agreement
shall be true and correct in all material respects as of the date of this
Agreement and as of the Effective Date as though made at and as of the
Effective Date;
(iii) There shall be no Encumbrances on any or all of Seller's rights under
the Commitments;
(iv) Purchaser shall have received certificates from authorized officers of
Seller, dated the Effective Date, to the effect that, to the best of such
officers' knowledge, the conditions set forth in Sections 2.1(b)(i), (ii) and
(ii i) have been satisfied;
(v);
(vi) Seller shall have taken all actions necessary, including the
completion and delivery of all agreements and documents required by NEPOOL,
any other power pool, independent system operator, electric reliability
council or govern mental or regulatory authority as reasonably requested by
Purchaser to enable Purchaser to receive credit for the Power sold and
delivered to Purchaser hereunder and to enable Purchaser to transact with
respect to such Power for its own account;
(vii);
(viii) Seller and Eastern shall have and obtained a finding by the MDTE that
Eastern's actions in regard to the Wholesale Standard Offer Service Agreement
are in accordance with G.L. c. 164, 94A and 1B(b) and that the Wholesale
Standard Offer Service Agreement may become effective, such finding to be
final and no longer subject to rehearing, reconsideration or appeal; and
(ix) Purchaser shall have received an opinion from McDermott, Will & Emery,
counsel for Seller, dated the Effective Date and satisfactory in form and
substance to Purchaser and its counsel, substantially as follows:
(A) Each of Seller, the Retail Companies and the Seller Guarantor is a
corporation organized, existing and in good standing under the laws of its
state of incorporation and has the corporate power and authority to execute,
deliver and perform this Agreement and the Ancillary Agreements and to
consummate the transactions contemplated hereby and thereby; and the execution
and delivery of this Agreement and such Ancillary Agreements and the
consummation of the transactions contemplated hereby and thereby have been
duly authorized by all requisite corporate action taken on the part of Seller,
the Retail Companies and the Seller Guarantor, as applicable;
(B) This Agreement and the Ancillary Agreements have been executed and
delivered by Seller, the Retail Companies and the Seller Guarantor, as
applicable and (assuming that Seller Required Regulatory Approvals and
Purchaser Required Regulatory Approvals are obtained) are valid and binding
obligations of Seller, the Retail Companies and the Seller Guarantor, as
applicable enforceable against Seller, the Retail Companies and the Seller
Guarantor in accordance with their terms, except (1) that such enforcement may
be subject to bankruptcy, insolvency, reorganization, moratorium or other
similar laws now or hereafter in effect relating to creditors' rights, and (2)
that the remedy of specific performance and injunctive and other forms of
equitable relief may be subject to certain equitable defenses and to the
discretion of the court before which any proceeding therefor may be brought;
(C) The execution, delivery and performance of this Agreement and the
Ancillary Agreements by Seller, the Retail Companies and the Seller Guarantor
will not (1) constitute a violation of the Certificates of Incorporation or
Bylaws (or similar governing documents), as in effect on the Effective Date,
of Seller, the Retail Companies and the Seller Guarantor, as applicable (2)
result in a default (or give rise to any right of termination, cancellation or
acceleration) under any of the terms, conditions or provisions of any note,
bond, mortgage, indenture, license, agreement or other instrument or
obligation to which Seller, the Retail Companies and the Seller Guarantor, as
applicable is a party or by which Seller, t he Retail Companies and the Seller
Guarantor, as applicable may be bound, including, without limitation, the
Commitments except for such defaults (or rights of termination, cancellation
or acceleration) as to which requisite waivers or consents have been obtained;
or (3) violate any order, writ, injunction, decree, statute, rule or
regulation applicable to Seller, the Retail Companies and the Seller Guarantor
or any of their respective assets;
(D) No declaration, filing or registration with, or notice to, or
authorization, consent or approval of any governmental authority is necessary
for the consummation by Seller, the Retail Companies and the Seller Guarantor
of the transactions contemplated by this Agreement and the Ancillary
Agreements, other than (1) Seller Required Regulatory Approvals, all of such
Seller Required Regulatory Approvals which are applicable to the transactions
contemplated hereby and thereby having been obtained and being in full force
and effect with such terms and conditions as shall have been imposed by any
applicable governmental authority, and (2) such declarations, filings,
registrations, notices, authorizations, consents or approvals which, if not
obtained or made, would not, in the aggregate have a Material Adverse Effect.
As to any matter contained in such opinion which involves the laws of any
jurisdiction other than the federal laws of the United States or the laws of
Massachusetts, such counsel may rely upon opinions of counsel admitted in such
other jurisdictions and reasonably acceptable to Purchaser. Any opinions
relied upon by such counsel as aforesaid shall be delivered together with the
opinion of such counsel. Such opinion may expressly rely as to matters of
fact upon certificates furnished by Seller, the Retail Companies and the
Seller Guarantor and appropriate officers and directors of Seller, the Retail
Companies and the Seller Guarantor and by public officials.
(c) The obligation of Seller to effect the transactions contemplated by
this Agreement shall be subject to the fulfillment of the following additional
conditions:
(i) Purchaser shall have performed in all material respects covenants and
agreements contained in this Agreement required to be performed on or prior to
the Effective Date;
(ii) The representations and warranties of Purchaser set forth in this
Agreement shall be true and correct in all material respects as of the date of
this Agreement and as of the Effective Date as though made at and as of the
Effective Date;
(iii) Seller shall have received a certificate from an authorized officer of
Purchaser, dated the Effective Date, to the effect that, to the best of such
officer's knowledge, the conditions set forth in Sections 2.1(c)(i) and (ii))
have been satisfied;
(iv) FERC approval of the Stipulations and Agreements filed in FERC Docket
No. ER97-3127-000 by and between the Office of the Attorney General of
Massachusetts, the Massachusetts Division of Energy Resources,Eastern Edison
Company and Seller, dated October 29, 1997; Docket No. ER97- 2800-000 by and
between the RIPUC, the Rhode Island Division of Public Utilities and Carriers,
Blackstone Valley Electric Company, Seller and Newport Electric Corporation;
Docket No. ER97-3127-000 and ER97-2800-000 between Seller and the Pascoag
Fire District of Rhode Island; Docket No. ER97-3127-00 and ER97-2800-000
between Seller and the Gas and Electric Department of the Town of
Middleborough; and Docket No. ER97-2338-000 between Seller and the Taunton
Municipal Lighting Plant, Pascoag Fire District of Rhode Island and the Gas
and Electric Department of the Town of Middleborough shall continue to be in
full force and effect;
(v) All Seller Required Regulatory Approvals and all other consents and
approvals required of Seller to consummate the transactions contemplated by
this Agreement shall have been obtained and in full force and effect;
(vi); and
(vii) Seller shall have received an opinion from Hunton & Williams, counsel
for Purchaser, dated the Effective Date and satisfactory in form and substance
to Seller and their counsel, substantially to the effect that:
(A) Purchaser is a corporation organized, existing and in good standing
under the laws of the State of Delaware and has the corporate power and
authority to execute and deliver this Agreement and the Ancillary Agreements a
nd to consummate the transactions contemplated hereby; and the execution and
delivery of this Agreement and such Ancillary Agreements and the consummation
of the transactions contemplated hereby have been duly authorized by all
requisite corporate action taken on the part of Purchaser;
(B) This Agreement and the Ancillary Agreements have been executed and
delivered by Purchaser and (assuming that Seller Required Regulatory Approvals
and Purchaser Required Regulatory Approvals are obtained) are valid and
binding obligations of Purchaser, enforceable against Purchaser in accordance
with their terms, except (1) that such enforcement may be subject to
bankruptcy, insolvency, reorganization, moratorium or other similar laws now
or hereafter in effect relating to creditors' rights and (2) that the remedy
of specific performance and injunctive and other forms of equitable relief may
be subject to certain equitable defenses and to the discretion of the court
before which any proceeding therefor may be brought;
(C) The execution, delivery and performance of this Agreement and the
Ancillary Agreements by Purchaser will not constitute a violation of the
Certificate of Incorporation or Bylaws (or similar governing documents), as in
effect on the Effective Date, of Purchaser;
(D) No declaration, filing or registration with, or notice to, or
authorization, consent or approval of any governmental authority is necessary
for the consummation by Purchaser of the transactions contemplated by this
Agreement and the Ancillary Agreements other than (1) Purchaser Required
Regulatory Approvals, all of such Purchaser Required Regulatory Approvals
which are applicable to the transactions contemplated hereby and thereby
having been obtained and being in full force and effect with such terms and
conditions as shall have been imposed by any applicable governmental authority
and (2) such declarations, filings, registrations, notices, authorizations,
consents or approvals which, if not obtained or made , would not, in the
aggregate have a Material Adverse Effect.
As to any matter contained in such opinion which involves the laws of any
jurisdiction other than the federal laws of the United States and the laws of
Delaware, such counsel may rely upon opinions of counsel admitted to practices
in such other jurisdictions. Any opinions relied upon by such counsel as
aforesaid shall be delivered together with the opinion of such counsel. Such
opinion may expressly rely as to matters of facts upon certificates furnished
by appropriate officers and directors of Purchaser and its Subsidiaries and by
public officials.
(d).
(e) Each of the Parties shall cooperate in good faith and shall use
reasonable efforts to cause the foregoing conditions precedent to be satisfied
as soon as reasonably possible. If, notwithstanding the reasonable efforts by
both Parties, the conditions precedent set forth in this Section 2.1 have not
been satisfied or waived by the Party entitled to the benefit thereof and the
Effective Date has not occurred, in each case, on or before the second
anniversary of the date hereof, or the Parties mutually agree prior to such
date that it will not be possible to satisfy a condition precedent, then
either Party may terminate this Agreement, without additional cost or
liability resulting from such termination, upon thirty (30) days prior written
notice to the other Party.
2.2 Term.
(a) The "Term" of this Agreement shall be the period from and including
the date hereof and shall continue in effect, unless sooner terminated in
accordance with its terms, until every obligation of either Party to pay the
other Party an amount hereunder, including, without limitation, payments
pursuant to Article 4, has been satisfied in full in accordance with the terms
of this Agreement.
(b) At the expiration of the Term, the Parties shall no longer be bound by
the terms and provisions hereof, except (i) to the extent necessary to enforce
the rights and the obligations of the Parties arising under this Agreement
before such expiration or termination and (ii) the obligations of the Parties
hereunder with respect to confidentiality, indemnification and audit rights
shall survive the expiration or termination of this Agreement and shall
continue for a period of two (2) calendar years following such termination.
ARTICLE 3 DELIVERY OF POWER; HYDRO QUEBEC TRANSMISSION USE RIGHTS;
DESIGNATION OF PURCHASER AS AGENT; ASSIGNMENT OF COMMITMENTS
3.1 Delivery of Power.
(a) Commencing as of the Effective Date, each month Seller agrees to sell
and deliver and Purchaser agrees to purchase and receive all capacity, energy,
any other NEPOOL products and services and any other benefits it receives
under each Commitment (collectively, "Power") simultaneously with Seller's
receipt thereof from each Power Seller. All Power shall be delivered to
Purchaser at the point at which the Power Seller makes delivery to Seller as
established under such Commitment (each, a "Delivery Point"). Purchaser shall
be responsible for making all arrangements necessary for the further
transmission of such Power.
(b) With respect to each Commitment, and until such time as there is an
early termination, replacement or restructuring of the Commitment or a direct
amendment and assignment of the Commitment to Purchaser pursuant to Section
3.4, Seller shall perform the Administration Services and from time to time
during the Term of this Agreement take all actions necessary, including,
without limitation, the completion and delivery of all agreements and
documents required by NEPOOL, any other power pool, independent system
operator, electric reliability council or governmental or regulatory authority
as reasonably requested by Purchaser to enable Purchaser to receive credit for
the Power sold and delivered to Purchaser hereunder and to enable Purchaser to
transact with respect to such Power for its own account.
3.2 Hydro Quebec Firm Energy Contract; Transmission Use Rights.
(a) Commencing as of the Effective Date, and terminating upon termination
of the Firm Energy Contract pursuant to Article 21 of said Contract, Seller
shall sell and deliver and Purchaser shall purchase and receive all Power that
Seller receives under the Firm Energy Contract in accordance with Section 3.1
of this Agreement. Purchaser shall be responsible for scheduling its energy
receipts under the Firm Energy Contract directly with NEPOOL and, if billed
directly by NEPOOL for energy delivered under the Firm Energy Contract, shall
be responsible for making payments therefor directly to NEPOOL. Failure of
Purchaser to make such payments shall constitute an Event of Default under
this Agreement.
(b) Seller shall invoice Purchaser for and Purchaser shall pay Seller on a
monthly basis, Seller's associated share of transmission facility support
payments under those agreements set forth on Schedule 1-A associated with the
delivery of Power by Seller to Purchaser that Seller receives under the Firm
Energy Contract, as such amounts are increased by any costs incurred by Seller
(including, without limitation, general and administrative costs incurred by
Seller in administering Seller's open access transmission tariff as the
Parties shall agree) or as decreased by any revenues received by Seller, both
associated with the sale of transfer capability under Section 3.2(c).
(c) Purchaser agrees that, to the extent it elects not to use a portion of
the transfer capability available to it pursuant to Section 3.2(a),Purchaser
shall so notify Seller in writing, and Seller shall make such transfer
capability available under Seller's open access transmission tariff on file
with the FERC. Seller shall credit Purchaser with the revenues Seller
receives from the sale of transmission service associated with such transfer
capability as provided in Section 3.2(b). Purchaser agrees to provide Seller
with all information available to Purchaser that Seller reasonably requests
for the purpose of calculating the charges to each customer that uses a
portion of such transfer capability.
(d)
3.3 Designation of Purchaser as Agent.
(a) As of the Effective Date, Seller hereby irrevocably and
unconditionally appoints Purchaser as its representative and agent for all
purposes under each Commitment. Purchaser is authorized to take all actions
that Seller may lawfully take under such Commitment without further approval
by Seller and in Purchaser's sole discretion including, without limitation,
the following: with respect to all matters arising under the Commitments
(including, without limitation, directing and scheduling the availability,
dispatch, quantity or timing of the Power under each Commitment) deal directly
with the Power Sellers, NEPOOL, the independent system operator (as designated
under the Restated NEPOOL Agreement, as amended from time to time), other
transporters of electric energy, federal, state and local governmental or
judicial authorities, and any other persons; act on Seller's behalf in the
prosecution or defense, as the case may be, of any rights or liabilities
arising under the Commitments; monitor the Power Seller's performance under
the Commitments; review and audit all bills and related documentation rendered
by the Power Sellers; and on Seller's behalf enter into amendments to the
Commitments of any nature; provided, however, that Seller's prior written
consent shall be required for (i) actions that increase the price charged for
or the quantity of power to be purchased by Seller under a Commitment, (ii)
Commitment term extensions, and (iii) any other matter which Seller reasonably
believes will increase Seller's financial obligations under a Commitment, and
(iv) any other matter which Seller reasonably believes will materially
adversely affect Seller's indemnification rights under a Commitment, which
consent shall not be unreasonably withheld. Seller agrees to participate at
Purchaser's request and under Purchaser's reasonable direction in any
governmental or judicial proceeding with respect to the Commitments, including
but not limited to bringing an action to enforce the Commitments. Seller
agrees to cooperate with and assist Purchaser in the exercise of its rights
under this Section 3.3(a) as Purchaser shall reasonably request from time to
time, so long as Purchaser reimburses Seller for the reasonable costs and
expenses it incurs in providing such cooperation and assistance (other than
with respect to the Administration Services). Seller hereby agrees to provide
to Purchaser reasonable access to (including, at the expense of Purchaser,
copies of) all information which Seller now has or hereafter acquires with
respect to each Commitment (to the extent permissible under that Commitment).
(b) In assuming responsibility for taking all actions which Seller may
otherwise lawfully take under the Commitments pursuant to Section 3.3(a),
Purchaser shall act as Seller's agent with respect to each Commitment
commencing on the Effective Date and ending (i) with respect to each
Commitment that is assigned to Purchaser pursuant to Section 3.4, at the time
that such assignment is effective; and (ii) with respect to each Commitment
that is not assigned to Purchaser, upon the expiration or termination of such
Commitment. Seller shall give such notice to each Power Seller and take such
other steps as may be required or appropriate under applicable law to
establish the authority of Purchaser as agent and to permit Purchaser to take
action under each Commitment consistent with this Agreement. Seller agrees
that (i) prior to the appointment of Purchaser as agent for a Commitment, all
communications between Seller and the Power Seller related to that Commitment
shall be with Purchaser's prior written consent and participation unless such
consent or participation is expressly waived by Purchaser; and (ii) subsequent
to the appointment of Purchaser as Seller's agent for a Commitment, Seller
shall communicate with the Power Seller on matters related to that Commitment
only as expressly requested by Purchaser, except in each case for such
communications as are necessary for Seller to perform the Administration
Services so long as Seller notifies Purchaser of the occurrence and the
content of such communications at such time, or as soon as practicable
thereafter.
(c) Seller shall not agree to any amendment to or waiver of rights, or
convey to any other person any rights, under a Commitment without Purchaser's
prior written consent, which consent shall not be unreasonably withheld, shall
not take any actions inconsistent with the provisions of this Article 3 or
take any action or fail to take any action that would result in a material
breach of Seller's obligations under the Commitments. Seller shall not,
except at the express request of Purchaser, (i) take any actions that increase
the costs to be incurred or affect the quantity of Power to be purchased under
any Commitment or (ii) exercise any options that may exist under a Commitment,
including any extension of the term of a Commitment or (iii) take any actions
inconsistent with the provisions of Sections 3.3(a) and(b), except as shall be
necessary to perform its obligations under the Commitments for the period
prior to the Effective Date and except with respect to the Firm Energy
Contract, to the extent that any actions taken or omitted to be taken
thereunder or in connection therewith are prudent and are not within the sole
control of Seller.
(d) Seller shall request the Power Sellers to direct all communications
regarding operations of the facilities under the Commitments, dispatch,
scheduling and other matters relevant to the respective Commitments and
provided to Seller, directly to Purchaser. To the extent that Seller receives
any such information or any notices or documents relating to the Commitments,
Seller shall promptly forward such information, notices or documents to
Purchaser.
(e) Upon the request of Purchaser, Seller shall enforce the provisions of
any Commitment and/or its rights thereunder, or otherwise support Purchaser in
any dispute between Purchaser and the Power Sellers; provided, however, that
Seller s hall be compensated for its reasonable costs associated with such
efforts.
3.4 Termination or Assignment of Commitments by Purchaser.
Purchaser is hereby authorized and shall be entitled, as Seller's
representative and in Seller's name, to negotiate directly with the Power
Sellers the early termination, replacement or restructuring of the Commitments
or a direct amendment and assignment of the Commitments to Purchaser so that
Seller will be released of all further liabilities and obligations under each
Commitment and Purchaser will be directly in contract with the Power Seller.
Seller shall work cooperatively and use all reasonable efforts to assist
Purchaser in such negotiations. If Purchaser and a Power Seller have agreed
to a termination, replacement or amendment and assignment of a Commitment,
then Seller shall be deemed to have accepted all of the terms agreed to by
Purchaser and Power Seller and shall take all actions and execute and deliver
all agreements, documents, instruments and certificates as necessary to
consummate such termination, replacement, restructuring or amendment and
assignment; provided, how ever, that in the case of an amendment and
assignment of a Commitment to Purchaser, the terms of such amendment and
assignment must continue to afford to Seller the protections for its or its
Affiliates' transmission system embodied in the Commitment . Any amendment
and assignment shall include all modifications necessary to reflect the
substitution of Purchaser for Seller as the purchasing party under such
Commitment (including modifications to Commitment price indices, where
appropriate) and to properly describe interconnection, delivery point and
transmission system references in such Commitment. Except as provided in
Section 4.3, Seller and Purchaser agree that any such termination or
assignment of a Commitment shall not entitle Seller or Purchaser to an
adjustment of the Seller Payment obligations.
3.5 Failure to Deliver or Receive Power; Remedies.
(a) If either Party fails to deliver or receive ("Non-Performing Party"),
as the case may be, Power in accordance with the terms and conditions of this
Agreement, the other Party ("Other Party") shall, as promptly as practicable,
give not ice of such failure to the Non-Performing Party.
(b) The Other Party shall be entitled to receive from the Non-Performing
Party an amount calculated as follows, unless excused by Force Majeure or the
Other Party's failure to perform:
(i) if at any time Seller fails to deliver all or part of the Power
delivered to it by the Power Sellers under the Commitments in accordance with
the terms and conditions of this Agreement, Seller shall pay Purchaser, on the
date payment would otherwise be due to Seller pursuant to Section 4.4, an
amount for each unit of such deficient quantity equal to the positive
difference, if any, obtained by subtracting the per unit price applicable to
such quantity under the related Commitment from the per unit Replacement
Price, plus any reasonable administrative expenses and reasonable attorneys'
fees incurred as a result of Seller's failure to deliver; and
(ii) if Purchaser fails to take delivery of all or part of the Power
delivered to it in accordance with the terms and conditions of this Agreement,
Purchaser shall pay Seller, on the date payment would otherwise be due, an
amount f or each unit of such deficient quantity equal to the positive
difference, if any, obtained by subtracting the per unit Sales Price from the
per unit price applicable to such quantity under the related Commitment, plus
any reasonable administrative expenses and reasonable attorneys' fees incurred
as a result of Purchaser's failure to take delivery.
3.6 Duty to Mitigate Damages.
Each Party agrees that it has a duty to mitigate damages and covenants that it
will use commercially reasonable efforts to minimize any damages it may incur
as a result of the other Party's performance or non-performance of this
Agreement.
3.7 Exclusive Remedy.
The damages provided in Section 3.5 shall be the sole and exclusive
remedy of each Party for any failure of the other Party to deliver or receive,
as applicable, Power in the quantities or at the times required by this
Agreement.
ARTICLE 4 PAYMENTS
4.1 Payments.
(a) Commencing as of the month following the Effective Date of this
Agreement, Purchaser agrees to pay to Seller each month all amounts due and
payable in accordance with the applicable provisions of the Commitments from
Seller to the Power Seller for the preceding month associated with Power
delivered or made available to Purchaser by Seller from each Commitment in the
preceding month (each such payment obligation referred to herein as the
"Purchaser Payment"). Seller expressly acknowledges and agrees that unless
and until a Commitment is terminated or assigned to Purchaser pursuant to
Section 3.4, Seller shall remain liable for and timely pay to the applicable
Power Sellers all amounts due thereunder.
(b) Commencing as of the month following the Effective Date of this
Agreement and continuing for each succeeding month set forth on Schedule 2,
Seller shall pay Purchaser each month the amounts set forth on Schedule 2 in
respect of each Commitment applicable to the preceding month (each such amount
referred to herein as the "Seller Payment"). Subject to Section 4.3, Seller
shall remain obligated to pay each of the Seller Payments through and
including the last month of the last year listed on Schedule 2,
notwithstanding the termination, expiration, replacement, amendment,
assignment or any other change to a Commitment during the Term hereof (or any
failure of the Power Seller under any Commitment to deliver Power or otherwise
honor its obligations to Seller thereunder). Amounts set forth in Section
2.1(d), if any, shall be set-off against the Seller Payments due in the first
ten (10) months after the occurrence of the Effective Date in ten equal
installments.
(c) Except as otherwise provided in Section 4.3, the Purchaser Payment
with respect to each Commitment and the Seller Payment with respect to that
Commitment owing by each Party for any month shall be offset so that only the
net amount shall be p aid by the Party having the greater payment obligation
for such Commitment for such month.
(d) In the event that the amount of the Seller Payment with respect to any
Commitment shall in any month exceed the Purchaser Payment with respect to
such Commitment under this Section 4.1, Seller shall pay the amount of such
exceedance to Purchaser on the date such Purchaser Payment would otherwise be
due under Section 4.4.
4.2 Purchaser Right to Amounts Owed by Power Sellers.
(a) Upon the Effective Date, Seller shall irrevocably and unconditionally
assign and thereafter hold for the benefit of and/or credit to Purchaser
against payments due from it to Seller under Section 4.1 hereof or, at the
election of Purchaser, pay to Purchaser, any and all amounts which are then or
thereafter received by Seller from the Power Sellers under the Commitments,
including, without limitation, any aggregate differential balances under any
Commitment, any energy bank balances and the benefit of and proceeds from any
security deposits, letters of credit or other similar instruments or accounts
established for the benefit of Seller by the Power Seller, but excluding any
credits or refunds received by Seller after the Effective Date which relate to
billing errors or reconciliations of pre-Effective Date bills, any amounts
paid by the Power Sellers to Seller with respect to disputes that are
attributable to a period prior to the Effective Date, and any amounts paid by
the Power Sellers to Seller with respect to indemnification rights under a
Commitment.
(b).
4.3 Acceleration of Payments Upon Termination or Assignment of Commitment.
(a) To the extent that a Trigger Event occurs with respect to a
Commitment, Seller shall, either (i) continue to make the remaining payments
due from Seller to Purchaser in respect of such Commitment pursuant to Section
4.1 or (ii) upon the mutual agreement of the Parties make a full or partial
lump-sum payment (the "Trigger Payment") to Purchaser. If Purchaser and
Seller agree to a Trigger Payment, such amount shall be paid by Seller to
Purchaser concurrently with the Trigger Event , or as soon thereafter as is
practicable (but not later than sixty (60) days after the Trigger Event
occurred; the date on which the payment occurs being referred to as the
"Trigger Payment Date".
(b) A "Trigger Event" shall mean: (i) an amendment and assignment of a
Commitment to Purchaser; or (ii) a termination or expiration of a Commitment,
whether by its terms or as a result of negotiations; provided, however, that
if at the time any one of the events specified in (i) or (ii) above shall
occur, an Event of Default on the part of Purchaser shall have occurred and be
continuing, no Trigger Event shall be deemed to have arisen from any such
event unless and until such Event of Default shall have been cured.
(c) The amount of any Trigger Payment shall, except as otherwise mutually
agreed by Purchaser and Seller, be the discounted amount as of the Trigger
Payment Date (using as the annual discount rate 11.115%) of Seller's remaining
payment obligations with respect to the affected Commitment(s) pursuant to
Schedule 2 as of the Trigger Payment Date.
(d) Upon the making of any such Trigger Payment the amounts thereafter
payable in accordance with Schedule 2 shall be reduced by the reduction
arising under this Section 4.3 from such Trigger Payment.
4.4 Billing and Payment.
(a) Seller shall timely pay all amounts due to the Power Sellers under the
Commitments each month during the Term hereof, which includes the amount
Seller receives from Purchaser in connection with such Commitment. Within
three (3) Business Days after Seller's receipt of an invoice from a Power
Seller pursuant to a Commitment associated with Power delivered or made
available to Purchaser by Seller under such Commitment in the preceding month
(or after Seller's delivery of a statement to the Power Seller under a
Commitment, if Seller prepares or causes the monthly billing statement to be
prepared under a Commitment), Seller shall deliver such invoice or statement
to Purchaser. On or before the date which is (i) one (1) Business Day prior
to the due date set forth on such invoice or (ii) if Seller fails to timely
deliver an invoice as provided herein, then ten (10) Business Days after
Purchaser's receipt of such invoice or statement (either of such dates, the
"Due Date"), Purchaser shall remit payment of the positive difference, if any,
of (A) the amount set forth in such invoice or statement to Seller minus (B)
the Seller Payment applicable to the Commitment to which such invoice or
statement relates for such month minus (C) amounts received by Seller from
sales of Power to third parties in accordance with Section 3.5(b)(ii) (such
net amounts received by Seller referred to herein as "Resale Proceeds"), such
Resale Proceeds to be paid by Seller to the Power Seller s in partial
satisfaction of Seller's obligations to the Power Sellers. All payments
required under this Agreement shall be paid in cash by federal or other wire
transfer of immediately available funds to an account designated by the Party
to receive such payment.
(b) Each invoice or statement shall incorporate all information reasonably
necessary to determine the payments due thereunder, including actual and
estimated billing information with respect to the Commitments and true-ups and
adjustments from prior months.
(c) Each invoice or statement shall be subject to adjustment for a period
of twelve (12) months from the date of its issuance for any changes in
estimates or any errors in arithmetic, computation or otherwise.
4.5 Taxes.
Purchaser shall be responsible for any Taxes, costs, losses or charges
imposed on or associated with the Power.
4.6 Overdue Payments.
Overdue payments shall accrue interest at the Interest Rate from, and
including, the Due Date to, but excluding, the date of payment.
4.7 Billing Disputes.
If either Party, in good faith, disputes an invoice, the disputing
Party shall pay the entire amount of the invoice no later than the Due Date
and immediately notify the other Party of the basis for the dispute. If any
amount paid under dispute is ultimately determined to be due to the disputing
Party, it shall be credited within one (1) day of such determination along
with interest accrued at the Interest Rate until the date paid. Inadvertent
overpayments shall be returned by the receiving Party upon request or deducted
by the receiving Party from subsequent payments, with interest accrued at the
Interest Rate until the date paid or deducted.
ARTICLE 5 COVENANTS OF THE PARTIES
5.1 Conduct of Business of the Company.
Seller and Purchaser shall conduct their businesses with respect to
the Commitments according to their ordinary and usual course of business
consistent with Good Utility Practice.
5.2 Maintenance of Existence.
Seller agrees that during the Term of this Agreement, it will maintain
its corporate existence and its good standing in all of the states in which it
transacts business, will not dissolve and will not consolidate with or merge
into another Person unless the Person with which it merges or into which it
consolidates assumes in writing all of the obligations of Seller hereunder,
and satisfies the Seller Credit Support obligations pursuant to Section 5.9.
5.3 Access to Information.
(a) Seller will, during ordinary business hours and upon reasonable notice
(i) give Purchaser and Purchaser Representatives reasonable access to all
books and records of Seller relating to the Commitments; (ii) permit Purchaser
to make such reasonable inspections thereof as Purchaser may reasonably
request; and (iii) furnish Purchaser, at Purchaser's expense, with such
financial and operating data and other information in Seller's possession with
respect to the Commitments as Purchaser may from time to time reasonably
request; provided, however, (A) Seller shall not be required to take any
action which would constitute a waiver of the attorney-client privilege and
(B) Seller need not supply Purchaser with any information which Seller is
under a legal obligation not to supply.
(b) All information furnished to or obtained by Purchaser and Purchaser
Representatives pursuant to this Section 5.3 shall be subject to the
confidentiality provisions of Section 5.5.
5.4 Further Assurances.
Subject to the terms and conditions of this Agreement, each of the
Parties hereto will use reasonable efforts to take, or cause to be taken, all
action, and to do, or cause to be done, all things necessary, proper or
advisable under applicable laws and regulations to consummate and make
effective the transactions contemplated hereby.
5.5 Confidentiality.
(a) Seller and Purchaser each agree not to disclose to any Person and to
keep confidential, and to cause and instruct its Affiliates, officers,
directors, employees, members and representatives not to disclose to any
Person and to keep confidential, any and all of the following information: (i)
the terms and provisions of this Agreement and the Ancillary Agreements; (ii)
any financial, pricing or supply quantity relating to the Power to be supplied
by Seller hereunder; (iii) any information that is clearly marked
"Confidential;" (iv) any oral communication that is subsequently reduced to
writing and marked "Confidential;" and (v) any information that is required to
be kept confidential by the terms of a Commitment. Notwithstanding the
foregoing, any such information may be disclosed (A) to the extent required by
applicable laws and regulations or by any subpoena or similar legal process of
any court or agency of federal, state or local government so long as the
receiving Party gives the disclosing Party written notice as soon as
practicable prior to such disclosure; (B) to lenders, advisors and accountants
of such Parties; (C) to the extent the non-disclosing Party shall have
consented in writing prior to any such disclosure; (D) to the extent any
confidential information is available from public non-confidential sources or
has been independently developed by the receiving Party prior to its receipt
from the disclosing Party; and (E) by Purchaser to prospective buyers of the
Power purchased by Purchaser under this Agreement. This Section 5.5 shall
supersede any prior confidentiality agreement between Purchaser and Seller.
Notwithstanding any provision to the contrary herein, Seller may provide
copies or in formation regarding this Agreement to any regulatory agency
requesting and/or requiring such information; provided, that any such
disclosure includes a request for confidential treatment of the Agreement
and/or the redaction of terms considered commercially sensitive by the
Purchaser from the copies of the Agreement which are placed in the public
record or otherwise made available to third parties.
(b) Information of a confidential nature which (i) has become public other
than as a result of a breach of this Section 5.5; or (ii) was received by the
disclosing Party from another source who in turn disclosed the information
without violating legal restrictions shall not be subject to this Section 5.5.
(c) The Parties shall consult with each other prior to issuing any public
announcement, statement or other disclosure with respect to this Agreement or
the transactions contemplated hereby and shall not issue any such public
announcement, statement or other disclosure without the prior written consent
of the other Party, which consent shall not be unreasonably withheld.
5.6 Consents and Approvals.
Seller and Purchaser shall cooperate with each other and (i) promptly
prepare and file all necessary documentation, (ii) effect all necessary
applications, notices, petitions and filings and execute all agreements and
documents, and (iii) use all commercially reasonable efforts to obtain all
necessary consents, approvals and authorizations of all other parties, in the
case of each of the foregoing clauses (i), (ii) and (iii), necessary or
advisable to consummate the transactions contemplated by this Agreement
(including, without limitation, Seller Required Regulatory Approvals and
Purchaser Required Regulatory Approvals) or required by the terms of any note,
bond, mortgage, indenture, deed of trust, license, franchise, permit,
concession, contract, lease or other instrument to which Seller or Purchaser
is a party or by which any of them is bound. Seller shall have the right to
review and approve in advance all characterizations of the information
relating to the Commitments, and each of Seller and Purchaser shall have the
right to review in advance all characterizations of the information relating
to the transactions contemplated by this Agreement which appear in any filing
made in connection with the transactions contemplated hereby.
5.7 Fees and Commissions.
Seller and Purchaser each represent and warrant to the other that,
except for Reed Consulting Group, which is acting for and at the expense of
Seller, no broker, finder or other Person is entitled to any brokerage fees,
commissions or finder' s fees in connection with the transaction contemplated
hereby by reason of any action taken by the party making such representation.
Seller and Purchaser will pay to the other or otherwise discharge, and will
indemnify and hold the other harmless from and against, any and all claims or
liabilities for all brokerage fees, commissions and finder's fees (other than
as described above) incurred by reason of any action taken by such Party.
5.8 XX.
5.9 XX
5.10 Parties Bound by Terms.
The rates, terms and conditions for service specified in this
Agreement shall remain in effect for the entire Term hereof, and shall not be
subject to change through any unilateral application by either Party to the
FERC or the applicable governmental entity acting under the Federal Power Act
(or pursuant to any other provision of law) or to any other governmental
agency or authority. Each Party hereby irrevocably waives the right to seek
any change or to support any application or complaint or other legislative,
judicial or regulatory action made seeking a change in such rates or a change
in such terms and conditions, absent the mutual agreement of the Parties.
ARTICLE 6 FORCE MAJEURE
6.1 Performance Excused.
If either Party is rendered unable by an event of Force Majeure to
carry out, in whole or part, its obligations hereunder, then, during the
pendency of such Force Majeure but for no longer period, the Party affected by
the event (other than t he obligation to make payments then due or becoming
due with respect to performance which occurred prior to the event) shall be
relieved of its obligations insofar as they are affected by Force Majeure but
for no longer period. The Party affected by an event of Force Majeure shall
provide the other Party with written notice setting forth the full details
thereof as soon as practicable after the occurrence of such event and shall
take all reasonable measures to mitigate or minimize the effects of such event
of Force Majeure; provided, however, that this provision shall not require
Seller to deliver, or Purchaser to receive, Power at points other than the
Delivery Point.
6.2 Definition. For purposes of Seller's obligation to deliver, and
Purchaser's obligation to receive, Power received by Seller from the Power
Sellers, the term "Force Majeure" with respect to such Power deliveries under
a Commitment shall solely have the meaning given in such Commitment.
ARTICLE 7 EVENTS OF DEFAULT; REMEDIES
7.1 Events of Default.
Any one or more of the following shall constitute an "Event of
Default" hereunder:
(a) failure of either Party to pay when due any amount due
hereunder, including without limitation, amounts due under the Firm Energy
Contract as described in Section 3.2(a) and such failure is not remedied
within after writ ten notice of such failure is given by the other Party;
(b) failure of either Party, in a material respect, to comply
with, observe or perform any covenant or obligation under this Agreement
(other than the events that are otherwise specifically covered in this Article
7 as a separate Event of Default) and such failure is not cured within ten
(10) days after receipt of written notice thereof from the other party;
(c) any representation or warranty made by either Party herein
shall be false or misleading in any material respect;
(d) a custodian, receiver, liquidator or trustee of either Party
or of any of the property of either, is appointed or takes possession and such
appointment or possession remains uncontested or in effect for more than ; or
either Party makes an assignment for the benefit of its creditors or admits in
writing its inability to pay its debts as they mature; or either Party is
adjudicated bankrupt or insolvent; or an order for relief is entered under the
Federal Bankruptcy Code against such Party; or any of the material property of
either Party is sequestered by court order and the order remains in effect for
more than ; or a petition is filed against either Party under any
bankruptcy, reorganization, arrangement, insolvency, readjustment of debt,
dissolution or liquidation law of any jurisdiction, whether now or
subsequently in effect, and is not stayed or dismissed within after filing;
(e) either Party files a petition in voluntary bankruptcy or seeking
relief under any provision of any bankruptcy, reorganization, arrangement,
insolvency, readjustment of debt, dissolution or liquidation law of any
jurisdiction, whether now or subsequently in effect; or consents to the filing
of any petition against it under any such law; or consents to the appointment
of or taking possession by a custodian, receiver, trustee or liquidator of the
property of either Party;
(f) an "Event of Default" (as defined in the Wholesale Standard Offer
Service Agreement) on the part of "Supplier" (as defined in the Wholesale
Standard Offer Service Agreement) or on the part of any of the "Companies" (as
defined in the Wholesale Standard Offer Service Agreement), as the case may
be, has occurred and is continuing under the Wholesale Standard Offer Service
Agreement (such "Event of Default" on the part of "Supplier" shall constitute
an Event of Default on the part o f Purchaser hereunder and such "Event of
Default" on the part of one or more of the "Companies" shall constitute an
Event of Default on the part of Seller hereunder); or
(g) the failure of a Party to provide alternate credit support in
accordance with the terms of Section 5.8 or 5.9, as the case may be, within
ten (10) Business Days after receipt of a written notice with respect thereto,
after the occurrence of any of the events described in Sections 7.1(d) or
7.1(e) with respect to such Party's credit support provider.
7.2 Remedies Upon Default.
The Parties shall have the following remedies available to them with
respect to the occurrence of an Event of Default with respect to the other
Party hereunder:
Upon the occurrence of an Event of Default by either Party hereunder,
the non-defaulting Party shall have the right (i) to collect all amounts then
or thereafter due in accordance with existing invoices to it from the
defaulting Party hereunder, and (ii) upon two (2) days prior written notice,
immediately and at any time thereafter, to liquidate and terminate this
Agreement by closing out this Agreement at its market value at such time (so
that a settlement payment in an amount equal to the difference, if any,
between such then prevailing market value and the value specified in such
agreement shall be due to Purchaser if such market value is greater than such
contract value and with such settlement payment being due to Seller if the
opposite is the case) and by setting off all market damages so determined and
payable by each of the Parties to the other, whereupon all such amounts shall
be aggregated or netted to a single liquidated amount, payable within one
Business Day by the Party owing the greater such amount to the other. In
addition, if Purchaser is the defaulting Party, then Seller shall have the
right during the continuation of such default and prior to any termination of
this Agreement to cease making the Commitments available to Purchaser
hereunder and to instead sell such Commitments to third parties for the
account of Seller.
7.3 Limitation of Remedies, Liability and Damages.
The Parties confirm that the express remedies and measures of damages
provided in this Agreement satisfy the essential purposes hereof. For breach
of any provision for which and express remedy or measure of damages is
provided, such express remedy or measure of damages shall be the sole and
exclusive remedy, the obligor's liability shall be limited as set forth in
such provision and all other remedies or damages at law or in equity are
waived. If no remedy or measure of damages is expressly herein provided, the
obligor's liability shall be limited to direct actual damages only, such
direct actual damages shall be the sole and exclusive remedy and all other
remedies or damages at law or in equity are waived. Unless expressly herein
provided, neither Party shall be liable for any consequential, incidental,
punitive, exemplary or indirect damages, lost profits or other business
interruption damages, by statute, in tort or contract, under any indemnity
provision or otherwise. It is the intent of the Parties that the limitations
herein imposed on remedies and the measure of damages be without regard to the
cause or causes related thereto, including, without limitation, the negligence
of any Party, whether such negligence be sole, joint or concurrent, or active
or passive. To the extent any damages required to be paid hereunder are
liquidated, the Parties acknowledge that the damages are difficult or
impossible to determine, otherwise obtaining an adequate remedy is in
convenient and the liquidated damages constitute a reasonable approximation of
the harm or loss.
ARTICLE 8 REPRESENTATIONS AND WARRANTIES
8.1 Representations and Warranties of Seller. Seller represents and
warrants to Purchaser as follows:
(a) Organization; Qualification. Seller is a corporation duly organized,
validly existing and in good standing under the laws of the State of
Massachusetts and has all requisite corporate power and authority to own,
lease, and operate it s properties and to carry on its business as is now
being conducted. Seller is duly qualified or licensed to do business as a
foreign corporation and is in good standing in each jurisdiction in which the
property owned, leased or operated by it or t he nature of the business
conducted by it makes such qualification necessary, except in each case in
those jurisdictions where the failure to be so duly qualified or licensed and
in good standing would not have a Material Adverse Effect.
(b) Authority Relative to this Agreement. Seller has full corporate power
and authority to execute and deliver this Agreement and to consummate the
transactions contemplated hereby. The execution and delivery of this
Agreement and the consummation of the transactions contemplated hereby have
been duly and validly authorized by the Board of Directors of Seller and no
other corporate proceedings on the part of Seller are necessary to authorize
this Agreement or to consummate the transactions contemplated hereby. This
Agreement has been duly and validly executed and delivered by Seller, and
assuming that this Agreement constitutes a valid and binding agreement of
Purchaser, subject to the receipt of Seller Required Regulatory Approvals and
Purchaser Required Regulatory Approvals, constitutes a valid and binding
agreement of Seller, enforceable against Seller in accordance with its terms,
except that such enforceability may be limited by applicable bankruptcy,
insolvency, moratorium or other similar laws affecting or relating to
enforcement of creditors' rights generally or general principles of equity.
(c) Consents and Approvals; No Violation.
(i) Other than obtaining Seller Required Regulatory Approvals and
Purchaser Required Regulatory Approvals, neither the execution and delivery of
this Agreement by Seller nor the performance by Seller of its obligations
under this Agreement will (A) conflict with or result in any breach of any
provision of the Certificate of Incorporation or Bylaws (or other similar
governing documents) of Seller; (B) require any consent, approval,
authorization or permit of, or filing with or notification to, any
governmental or regulatory authority, except where the failure to obtain such
consent, approval, authorization or permit, or to make such filing or
notification, would not have a Material Adverse Effect; (C) result in a
default (or give rise to any right of termination, cancellation or
acceleration) under any of the terms, conditions or provisions of any note,
bond, mortgage, indenture, license, agreement or other instrument or
obligation to which Seller is a party or by which Seller or any of the
Commitments may be bound, including, without limitation, the Commitments
except for such defaults (or rights of termination, cancellation or
acceleration) as to which requisite waivers or consents have been obtained or
which, in the aggregate, would not have a Material Adverse Effect; or (D)
violate any order, writ, injunction, decree, statute, rule or regulation
applicable to Seller, or any of its assets, which violation would have a
Material Adverse Effect
(ii) Except for such notices or approvals set forth on Schedule 3 (the
"Seller Required Regulatory Approvals"), no declaration, filing or
registration with, or notice to, or authorization, consent or approval of any
governmental or regulatory body or authority is necessary for the consummation
by Seller of the transactions contemplated hereby, other than such
declarations, filings, registrations, notices, authorizations, consents or
approvals which, if not obtained or made, will not, in the aggregate, have a
Material Adverse Effect.
(d) Title and Related Matters. Except as set forth in Schedule 5, Seller
has good and valid title to the Power, free and clear of all Encumbrances.
(e) The Commitments.
(i) Each of the Commitments (A) constitutes a valid, binding and
enforceable obligation of Seller and to the best knowledge of Seller
constitutes a valid and binding and enforceable obligation of the other
parties thereto and (B) is in full force and effect.
(ii) Except as set forth in Schedule 6, there is not, under any of the
Commitments, any default or event which, with notice or lapse of time or both,
would constitute a default on the part of Seller and to the best knowledge of
Seller on the part of the other parties thereto. The Commitments have not been
amended, supplemented or modified except as described in Schedule 1 and the
Commitments (as described in Schedule 1) contain the entire understanding of
Seller and the other parties thereto with respect to the transactions
contemplated thereby.
(f) Legal Proceedings, etc. Except as set forth in Schedule 7, there are
no claims, actions, proceedings or investigations pending or, to Seller's
knowledge, threatened against or relating to Seller before any court,
governmental or regulatory authority or body acting in an adjudicative
capacity relating to the transactions contemplated hereby or that could
otherwise have a Material Adverse Effect on the transactions contemplated
hereby.
(g) Regulation as a Utility. Seller is an "electric company" under
Massachusetts law and subject to regulation by the MDTE and is also subject to
regulation by FERC and the SEC. Seller is subject to the jurisdiction for
certain limited purposes of the New Hampshire Public Utility Commission, the
Maine Public Utilities Commission and the Connecticut Department of Public
Utility Control.
(h) Disclosure. No representation or warranty by Seller in this
Agreement, and no document (including, without limitation, the Commitments)
furnished or to be furnished to Purchaser pursuant to this Agreement or in
connection herewith or with the transactions contemplated hereby, contains or
will contain any untrue or misleading statement or omits or will omit any
material fact necessary to make the statements contained herein or therein, in
light of the circumstances under which ma de, not misleading. All facts of
material importance to the business, operations, prospects, condition
(financial or otherwise), commitments or liabilities of Seller relevant to the
transactions contemplated hereby have been truthfully and completely disclosed
to Purchaser in this Agreement.
8.2 Representations and Warranties of Purchaser. Purchaser represents and
warrants to Seller as follows:
(a) Organization. Purchaser is a corporation duly organized, validly
existing and in good standing under the laws of the State of Delaware and has
all requisite corporate power and authority to own, lease and operate its
properties and t o carry on its business as is now being conducted.
Purchaser is duly qualified or licensed to do business as a foreign
corporation and is in good standing in each jurisdiction in which the property
owned, leased or operated by it or the nature of the business conducted by it
makes such qualification necessary, except in each case in those jurisdictions
where the failure to be so duly qualified or licensed and in good standing
would not have a Material Adverse Effect. Purchaser has heretofore delivered
to Seller complete and correct copies of its Certificate of Incorporation and
Bylaws (or other similar governing documents), as currently in effect.
(b) Authority Relative to this Agreement. Purchaser has full corporate
power and authority to execute and deliver this Agreement and to consummate
the transactions contemplated hereby. The execution and delivery of this
Agreement and the consummation of the transactions contemplated hereby have
been duly and validly authorized by the Board of Directors of Purchaser and no
other corporate proceedings on the part of Purchaser are necessary to
authorize this Agreement or to consummate the transactions contemplated
hereby.
This Agreement has been duly and validly executed and delivered by Purchaser,
and assuming that this Agreement constitutes a valid and binding agreement of
Seller, subject to the receipt of Purchaser Required Regulatory Approvals and
Seller Required Regulatory Approvals, constitutes a valid and binding
agreement of Purchaser, enforceable against Purchaser in accordance with its
terms, except that such enforceability may be limited by applicable
bankruptcy, insolvency, moratorium or other similar laws affecting or relating
to enforcement of creditors' rights generally or general principles of equity.
(c) Consents and Approvals; No Violation.
(i) Except as set forth in Schedule 4, and other than obtaining Purchaser
Required Regulatory Approvals and Seller Required Regulatory Approvals, either
the execution and delivery of this Agreement by Purchaser nor the performance
by Purchaser of its obligations under this Agreement will (A) conflict with or
result in any breach of any provision of the Certificate of Incorporation or
Bylaws (or other similar governing documents) of Purchaser, (B) require any
consent, approval, authorization or permit of, or filing with or notification
to, any governmental or regulatory authority, except where the failure to
obtain such consent, approval, authorization or permit, or to make such filing
or notification, would not have a Material Adverse Effect, (C) result in a
default (or give rise to any right of termination, cancellation or
acceleration) under any of the terms, conditions or provisions of any note,
bond, mortgage, indenture, agreement, lease or other instrument or obligation
to which Purchaser or any of its Subsidiaries is a party or by which any of
their respective assets may be bound, except for such defaults (or rights of
termination, cancellation or acceleration) as to which requisite waivers or
consents h ave been obtained, or (D) violate any order, writ, injunction,
decree, statute, rule or regulation applicable to Purchaser, or any of its
assets.
(ii) Except as set forth in Schedule 4 (the filings and approvals referred
to in Schedule 4 are collectively referred to as the "Purchaser Required
Regulatory Approvals"), no declaration, filing or registration with, or notice
to, or authorization, consent or approval of any governmental or regulatory
body or authority is necessary for the consummation by Purchaser of the
transactions contemplated hereby.
(d) Regulation as a Utility. Purchaser is a power marketer authorized by
the FERC to engage in the wholesale sale and brokering of electric energy and
capacity at market-based rates pursuant to FERC Order 79 FERC 61,167, dated
May 15, 1 997.
ARTICLE 9 INDEMNIFICATION
9.1 Indemnification.
(a) Seller will indemnify, defend and hold harmless Purchaser from and
against any and all claims, demands or suits (by any Person), losses,
liabilities, damages, obligations, payments, costs and expenses (including,
without limitation, t he costs and expenses of any and all actions, suits,
proceedings, assessments, judgments, settlements and compromises relating
thereto and reasonable attorneys' fees and reasonable disbursements in
connection therewith) to the extent the foregoing are not covered by insurance
(each, an "Indemnifiable Loss"), asserted against or suffered by Purchaser
relating to, resulting from or arising out of (i) any breach or alleged breach
by Seller of any covenant or agreement of Seller contained in this Agreement
or the Commitments (ii) any claim of a Power Seller or any third party to the
extent arising from the acts or omissions of Seller or any of its agents or
employees or (iii) any material breach by Seller of any representation or
warranty set forth in Section 8.1 hereof.
(b) Purchaser will indemnify, defend and hold harmless Seller from and
against any and all Indemnifiable Losses asserted against or suffered by
Seller relating to, resulting from or arising out of (i) any breach by
Purchaser of any covenant or agreement of Purchaser contained in this
Agreement, (ii) any claim of a Power Seller or any third party to the extent
arising from the acts or omissions of Purchaser or any of its agents or
employees or (iii) any material breach by Purchaser of any representation or
warranty set forth in Section 8.2 hereof.
(c) Any Person entitled to receive indemnification under this Agreement
(an "Indemnitee") having a claim under these indemnification provisions shall
make a good faith effort to recover all losses, damages, costs and expenses
from insurer s of such Indemnitee under applicable insurance policies, if any
exist, so as to reduce the amount of any Indemnifiable Loss hereunder. The
amount of any Indemnifiable Loss shall be reduced (i) to the extent that
Indemnitee receives any insurance proceeds with respect to an Indemnifiable
Loss and (ii) to take into account any net Tax benefit recognized by the
Indemnitee arising from the recognition of the Indemnifiable Loss and any
payment actually received with respect to an Indemnifiable Loss .
(d) The expiration, termination or extinguishment of any covenant or
agreement shall not affect the parties' obligations under this Section 9.1 if
the Indemnitee provided the Person required to provide indemnification under
this Agreement (the "Indemnifying Party") with proper notice of the claim or
event for which indemnification is sought prior to such expiration,
termination or extinguishment.
(e)Purchaser and Seller each agree that notwithstanding any provisions in this
Agreement to the contrary, all parties to this Agreement retain their remedies
at law or in equity with respect to willful or intentional breaches of this
Agreement.
9.2 Defense of Claims.
(a) If any Indemnitee receives notice of the assertion of any claim or of
the commencement of any claim, action, or proceeding made or brought by any
Person who is not a party to this Agreement or any Affiliate of a party to
this Agreement (a "Third Party Claim") with respect to which indemnification
is to be sought from an Indemnifying Party, the Indemnitee will give such
Indemnifying Party reasonably prompt written notice thereof, but in any event
not later than ten (10) calendar days after the Indemnitee's receipt of notice
of such Third Party Claim. Such notice shall describe the nature of the Third
Party Claim in reasonable detail and will indicate the estimated amount, if
practicable, of the Indemnifiable Loss that has be en or may be sustained by
the Indemnitee. The Indemnifying Party will have the right to participate in
or, by giving written notice to the Indemnitee, to elect to assume the defense
of any Third Party Claim at such Indemnifying Party's own expense a nd by such
Indemnifying Party's own counsel, and the Indemnitee will cooperate in good
faith in such defense at the Indemnifying Party's expense.
(b) If within ten (10) calendar days after an Indemnitee provides written
notice to the Indemnifying Party of any Third Party Claim the Indemnitee
receives written notice from the Indemnifying Party that such Indemnifying
Party has elected to assume the defense of such Third Party Claim as provided
in the last sentence of Section 9.2(a), the Indemnifying Party will not be
liable for any legal expenses subsequently incurred by the Indemnitee in
connection with the defense thereof; provided, however, that if the
Indemnifying Party fails to take reasonable steps necessary to defend
diligently such Third Party Claim within twenty (20) calendar days after
receiving notice from the Indemnitee that the Indemnitee believes the
Indemnifying Party has failed to take such steps, the Indemnitee may assume
its own defense, and the Indemnifying Party will be liable for all reasonable
expenses thereof. Without the prior written consent of the Indemnitee, the
Indemnifying Party will not enter into any settlement of any Third Party Claim
which would lead to liability or create any financial or other obligation on
the part of the Indemnitee for which the Indemnitee is not entitled to
indemnification hereunder. If a firm offer is made to settle a Third Party
Claim without leading to liability or the creation of a financial or other
obligation on the part of the Indemnitee for which the Indemnitee is not
entitled to indemnification hereunder and the Indemnifying Party desires to
accept and agree to such offer, the Indemnifying Party will give written
notice to the Indemnitee to that effect. If the Indemnitee fails to consent
to such firm offer within ten (10) calendar days after its receipt of such
notice, the Indemnitee may continue to contest or defend such Third Party
Claim and, in such event, the maximum liability of the Indemnifying Party as
to such Third Party Claim will be the amount of such settlement offer, plus
reasonable costs and expenses paid or incurred by the Indemnitee up to the
date of such notice.
(c) Any claim by an Indemnitee on account of an Indemnifiable Loss which
does not result from a Third Party Claim (a "Direct Claim") will be asserted
by giving the Indemnifying Party reasonably prompt written notice thereof,
stating the nature of such claim in reasonable detail and indicating the
estimated amount, if practicable, but in any event not later than ten (10)
calendar days after the Indemnitee becomes aware of such Direct Claim, and the
Indemnifying Party will have a period of thirty (30) calendar days within
which to respond to such Direct Claim. If the Indemnifying Party does not
respond within such thirty (30) calendar day period, the Indemnifying Party
will be deemed to have accepted such claim. If the Indemnifying Party rejects
such claim, the Indemnitee will be free to seek enforcement of its rights to
indemnification under this Agreement.
(d)If the amount of any Indemnifiable Loss, at any time subsequent to the
making of an indemnity payment in respect thereof, is reduced by recovery,
settlement or otherwise under or pursuant to any insurance coverage, or
pursuant to any claim, recovery, settlement or payment by or against any other
entity, the amount of such reduction, less any costs, expenses or premiums
incurred in connection therewith (together with interest thereon from the date
of payment thereof at the prime r ate then in effect of the Bank of Boston,
N.A.), will promptly be repaid by the Indemnitee to the Indemnifying Party.
Upon making any indemnity payment, the Indemnifying Party will, to the
extent of such indemnity payment, be subrogated to all right s of the
Indemnitee against any third party in respect of the Indemnifiable Loss to
which the indemnity payment relates; provided, however, that (i) the
Indemnifying Party will then be in compliance with its obligations under this
Agreement in respect of such Indemnifiable Loss and (ii) until the Indemnitee
recovers full payment of its Indemnifiable Loss, any and all claims of the
Indemnifying Party against any such third party on account of said indemnity
payment is hereby made expressly subordinated and subjected in right of
payment to the Indemnitee's rights against such third party. Without limiting
the generality or effect of any other provision hereof, each such Indemnitee
and Indemnifying Party will duly execute upon request all instruments
reasonably necessary to evidence and perfect the above-described subrogation
and subordination rights. Nothing in this Section 9.2(d) shall be construed
to require any party hereto to obtain or maintain any insurance coverage.
(e) A failure to give timely notice as provided in this Section 9.2 will
not affect the rights or obligations of any party hereunder except if, and
only to the extent that, as a result of such failure, the Party which was
entitled to receive such notice was actually prejudiced as a result of such
failure.
ARTICLE 10 DISPUTE RESOLUTION
10.1 Arbitration Proceedings.
Any dispute or need of interpretation arising out of this Agreement
pertaining to the calculation of a termination payment pursuant to Article 7
or a payment required pursuant to Article 4 may be submitted upon request of
either Party to binding arbitration by one arbitrator who has not previously
been employed by either Party, and does not have a direct or indirect interest
in either Party or the subject matter of the arbitration. Such arbitrator
shall either be as mutually agreed by t he Parties within thirty (30) days
after written notice from either Party requesting arbitration, or failing
agreement, shall be selected under the expedited rules of the American
Arbitration Association (the "AAA"). Such arbitration shall be held in
alternating locations of the home offices of the Parties, commencing with
Purchaser's home office, or in any other mutually agreed upon location. The
rules of the AAA shall apply to the extent not inconsistent with the rules
herein specified. Either Party may initiate arbitration by written notice to
the other Party and the arbitration shall be conducted according to the
following: (a) not later than seven (7) days prior to the hearing date set by
the arbitrator each Party shall submit a brief with a single proposal for
settlement, (b) the hearing shall be conducted on a confidential basis without
continuance or adjournment, (c) the arbitrator shall be limited to selecting
only one of the two proposals submitted by the Parties, (d) each Party shall
divide equally the cost of the arbitrator and the hearing and each Party shall
be responsible for its own expenses and those of its counsel and
representatives and (e) evidence concerning the financial position or
organizational make-up of the Parties, any offer made or the details of any
negotiation prior to arbitration and the cost to the Parties of their
representatives and counsel shall not be permissible. Each Party agrees that
it will not bring a lawsuit concerning any dispute covered by this arbitration
provision. Any monetary award of the arbitrator may be enforced by the Party
in whose favor such monetary award is made in any court of competent
jurisdiction.
ARTICLE 11 MISCELLANEOUS
11.1 Entire Agreement.
This Agreement, together with all Schedules hereto and the Ancillary
Agreements constitute the entire agreement between the Parties and supersede
all previous offers, negotiations, discussions, communications and
correspondence with respect t o the transactions contemplated hereby.
11.2 Amendment.
This Agreement may be amended only by a written agreement signed by
the Parties.
11.3 Assignment.
Unless mutually agreed to by the Parties, no assignment, pledge, or
transfer of this Agreement shall be made by any Party without the prior
written consent of the other Party, which shall not be unreasonably withheld,
provided, however, that no prior written consent shall be required for (i) the
assignment, pledge or other transfer to another company or Affiliate in the
same holding company system as the assignor, pledgor or transferor, or (ii)
the transfer, incident to a merger or consolidation with, or transfer of all
(or substantially all) of the assets of the transferor, to another Person or
business entity; provided, however, that such assignee, pledgee, transferee or
acquirer of such assets or the Person with which it merges or into which it
consolidates assumes in writing all of the obligations of such Party
hereunder, and satisfies the Seller Credit Support obligations pursuant to
Section 5.9 or the Purchaser Credit Support obligations pursuant to Section
5.8, as the case may be; and provided, further, that either Party may, without
the consent of the other Party (and without relieving itself from liability
hereunder), transfer, sell, pledge, encumber or assign such Party's rights to
the accounts, revenues or proceeds hereof in connection with any financing or
other financial arrangements.
11.4 Governing Law.
The interpretation and performance of this Agreement shall be
according to and controlled by the laws of The Commonwealth of Massachusetts
(regardless of the laws that might otherwise govern under applicable
Massachusetts principles of conflicts of laws).
11.5 Counterparts.
This Agreement may be executed in two or more counterparts and each
such counterpart shall constitute one and the same instrument.
11.6 Waiver.
No waiver by a Party of any default by the other Party shall be
construed as a waiver of any other default. Any waiver shall be effective
only for the particular event for which it is issued and shall not be deemed a
waiver with respect to any subsequent performance, default or matter.
11.7 Notices.
All notices, requests, statements or payments shall be made as
specified below. Notices required to be in writing shall be delivered by
letter, facsimile or other documentary form. Notice by facsimile or hand
delivery shall be deemed to have been received by the close of the Business
Day on which it was transmitted or hand delivered (unless transmitted or hand
delivered after close in which case it shall be deemed received at the close
of the next Business Day). Notice by overnight mail or courier shall be
deemed to have been received two Business Days after it was sent. A Party may
change its addresses by providing notice of same in accordance herewith:
to Purchaser:
NOTICES & CORRESPONDENCE:
Constellation Power Source, Inc.
David M. Perlman, Esq.
111 Market Place, Suite 500
Baltimore, Maryland 21202
FAX No.: (410) 468-3540
Phone No.: (410) 468-3490
PAYMENTS:
Federal Wire Transfer
First National Bank of Maryland
ABA Routing #052000113
Account: Constellation Power Source, Inc.
Account #: 191-9007-8
INVOICES:
Attn.: Stuart Rubenstein
FAX No.: (410) 468-3540
Phone No.: (410) 468-3430
CREDIT AND COLLECTIONS:
John R. Collins
FAX No. (410) 468-3540
Phone No.: (410) 468-3410
SCHEDULING:
Attn: Stuart Rubenstein
FAX No.: (410) 468-3540
Phone No.: (410) 468-3430
To Seller:
NOTICES & CORRESPONDENCE:
Montaup Electric Company
Manager, Power Supply Administration
750 West Center Street
West Bridgewater, MA 02379
Fax: 508/559-6125
Phone: 508/559-2000 x3809
INVOICES:
Richard Davis, Accounting Supervisor
c/o EUA Service Corporation
750 West Center Street
West Bridgewater, MA 02379
Fax: 508/559-6125
Phone: 508/559-2000 x3554
PAYMENTS:
Federal Wire Transfer
Fleet Bank
ABA #011-000-206
Montaup Electric Company regular account
Account #028-610-808-5 00101
Contact:
Richard Davis, Accounting Supervisor
Fax: 508/427-6493
Phone: 508/559-2000 x3554
11.8 No Third Party Beneficiaries.
This Agreement shall not impart any rights enforceable by any third
party (other than a permitted successor or assignee bound to this Agreement).
11.9 Severability.
Any provision declared or rendered unlawful by any applicable court of
law or regulatory agency or deemed unlawful because of a statutory change will
not otherwise affect the remaining lawful obligations that arise under this
Agreement.
11.10 Construction.
The term "including" when used in this Agreement shall be by way of
example only and shall not be considered in any way to be in limitation. The
headings used herein are for convenience and reference purposes only.
11.11 Advisor.
Goldman Sachs Power LLC ("GSP") is the exclusive advisor to Purchaser
and not a principal of Purchaser. From time to time, Purchaser may designate
one or more employees of GSP as Purchaser's agent for purposes of performing
its obligations under this Agreement. Purchaser shall be solely responsible
for any and all obligations and liabilities associated with this Agreement.
Neither GSP, Goldman, Sachs & Co. nor J. Aron & Company, nor any of their
affiliates, has any responsibility for, or liability with respect to the
obligations of Purchaser under this Agreement or otherwise.
11.12 Audit.
Each Party has the right, at its sole expense and during normal
working hours, to examine the records of the other Party to the extent
reasonably necessary to verify the accuracy of any statement, charge or
computation made pursuant to this Agreement. If requested, a Party shall
provide to the other Party statements evidencing the quantities of Power
delivered at the Delivery Point. If any such examination reveals any
inaccuracy in any statement, the necessary adjustments in such statement and
the payments thereof will be made promptly and shall bear interest calculated
at the Interest Rate from the date the overpayment or underpayment was made
until paid; provided, however, that no adjustment for any statement or payment
will be made unless objection to the accuracy thereof was made prior to the
lapse of twelve (12) months from the rendition thereof.
IN WITNESS WHEREOF, the parties have caused their duly authorized
representatives to execute this Agreement on their behalf as of the date first
above written.
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Name: Kevin A. Kirby
Title: Vice President
CONSTELLATION POWER SOURCE, INC.
By: /s/ John R. Collins
Name: John R. Collins
Title: Vice President & Treasurer
SCHEDULE 1 to POWER PURCHASE AND SALE AGREEMENT
COMMITMENTS
1. Amended and Restated Power Sales Contract, dated December 18, 1998,
between Montaup Electric Company and Southern Energy Canal, L.L.C. (the "Canal
PPA").
2. Power Purchase Agreement, dated October 17, 1986, between Northeast
Energy Associates and Montaup Electric Company, as amended on June 28, 1989
and supplemented by Letter Agreement dated May 11, 1992.(the "Northeast PPA").
3. Purchase Power Agreement, dated January 3, 1989, between Blackstone
Hydro, Inc. ("BHI") and Montaup Electric Company, as assignee of Blackstone
Valley Electric Company (the "BHI PPA").
4. Power Supply Agreement, dated December 19, 1984, by and between City
of Burlington Electric Department and Montaup Electric Company, as assignee of
Newport Electric Corp., as amended by Letter Agreement on July 15, 1986 and on
December 29 , 1989 (the "McNeil PPA").
5. The Firm Energy Contract among Hydro-Quebec and the New England
Utilities (as defined therein) dated October 14, 1985 (the "Firm Energy
Contract").
A Commitment shall be automatically deleted from the above Commitment list
without further action by the parties: (i) on the effective date of any
amendment and assignment of the Commitment pursuant to Section 3.4 of the
Agreement, (ii) upon the expiration of such Commitment pursuant to its terms,
or (iii) upon the termination of such Commitment pursuant to the written
agreement of the parties thereto with the written consent of Purchaser.
SCHEDULE 1-A to POWER PURCHASE AND SALE AGREEMENT
AGREEMENTS RELATED TO HYDRO-QUEBEC INTERCONNECTION
1. Agreement with Respect to Use of the Quebec Interconnection, dated
December 1, 1981, as amended and restated as of September 1, 1985, and as
further amended and restated as of November 19, 1997, and as further amended
as of April 8, 1998 ("Use Agreement").
2. Phase I Vermont Transmission Line Support Agreement, dated December 1,
1981, as amended on June 1, 1982, November 1, 1982, and January 1, 1986.
3. Phase I Terminal Facility Support Agreement, dated December 1, 1981,
as amended June 1, 1982, November 1, 1982, and January 1, 1986.
4. Phase I New Hampshire Transmission Facilities Support Agreement, dated
December 1, 1981.
5. Phase II Boston Edison AC Facilities Support Agreement, dated June 1,
1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1,
1987, and August 1, 1988.
6. Phase II New England Power AC Facilities Support Agreement, dated June
1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987, September 1,
1987, and August 1, 1988.
7. Phase II Massachusetts Transmission Facilities Support Agreement,
dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987,
September 1, 1987, October 1, 1987, August 1, 1988, and January 1, 1989.
8. Phase II New Hampshire Transmission Facilities Support Agreement,
dated June 1, 1985, as amended May 1, 1986, February 1, 1987, June 1, 1987,
September 1, 1987, October 1, 1987, August 1, 1988, January 1, 1989, and
January 1, 1990.
SCHEDULE 2 to POWER PURCHASE AND SALE AGREEMENT
SELLER PAYMENTS
Monthly amounts
SCHEDULE 3 to POWER PURCHASE AND SALE AGREEMENT
SELLER REQUIRED REGULATORY APPROVALS
(i) Any required approvals under the Federal Power Act;
(ii) (A) notice by Seller to, and an order by, the MDTE approving the
Seller Guaranty;
(B) a finding by the MDTE that Eastern's actions in regard to the
Wholesale Standard Offer Service Agreement are in accordance with G.L.c. 164,
94A and 1(B)(b) and that the Wholesale Standard Offer Service Agreement may
become effective; and
(iii) the approval of the Seller Guaranty by the SEC pursuant to the Holding
Company Act.
SCHEDULE 4 to POWER PURCHASE AND SALE AGREEMENT
PURCHASER REQUIRED REGULATORY APPROVALS
The Purchaser requires no regulatory approvals prior to the Effective
Date. However, from time to time during the Term of this Agreement, Purchaser
must file quarterly transaction reports with the FERC reporting the execution
of this Agreement and detailing purchases hereunder that occurred in the prior
quarter.
SCHEDULE 5 to POWER PURCHASE AND SALE AGREEMENT
EXCEPTIONS TO SELLER'S TITLE TO THE COMMITMENTS
Nothing to Disclose
SCHEDULE 6 to POWER PURCHASE AND SALE AGREEMENT
DEFAULTS UNDER THE COMMITMENTS
Nothing to Disclose
SCHEDULE 7 to POWER PURCHASE AND SALE AGREEMENT
LEGAL PROCEEDINGS
Nothing to Disclose
SCHEDULE 8 to POWER PURCHASE AND SALE AGREEMENT
EXHIBIT 10(bb)(ix)
PPA TRANSFER AGREEMENT
This PPA TRANSFER AGREEMENT ("Agreement") is dated as of April 7, 1998
and is made by and between MONTAUP ELECTRIC COMPANY, a Massachusetts
corporation ("Seller"), and TRANSCANADA POWER MARKETING LTD., a Delaware
corporation ("Asset Purchaser"). This Agreement set forth the terms and
conditions under which Seller transfers to Asset Purchaser the economic
benefits and performance obligations, subject to Seller's continuing
obligations to make certain payments, associated with the power purchase
agreements herein after described ("the Power Purchase Agreement") between
seller and third party power supplier ("the Power Seller"), to Asset Purchaser
pursuant to the Asset Purchase Agreement dated as of April 7, 1998 ("the
APA"), by and between Seller and Asset Purchaser.
1. The following Power Purchase Agreement (as amended or supplemented, a
"Commitment") is attached as an exhibit hereto and is incorporated into this
Agreement by reference.
Date Power Supplier
5/14/86 Ocean State Power (Montaup)
9/28/88 Ocean State Power II (Montaup)
5/14/86 Ocean State Power (Montaup
7/12/88 Ocean State Power II (Montaup)
A Commitment shall be automatically deleted from the above Commitment
list (the "Commitment List"} without further action by the parties: (i) on the
effective date of any amendment and assignment of the Commitment pursuant to
Section 7, below, (ii) upon the expiration of such Commitment pursuant to its
terms, or (iii) upon the termination of such Commitment pursuant to the
written agreement of the parties thereto.
2. This Agreement shall become effective on the Effective Date (as
defined in Section 12) and shall remain in effect until Asset Purchaser has
made payment to Seller of amounts owed pursuant to Section 4, below, for the
last month in which a Commitment is listed on the Commitment List, and Seller
has made payment to Asset Purchaser of amounts owned pursuant to Section 8
below, for the last month in which such a payment is due.
3. Commencing as of the Effective Date, each month Seller agrees to
provide to Asset Purchaser all capacity, energy and any other benefits it
receives under each Conunitment as of the first day of the month. All
electric energy shall be deliver ed to Asset Purchaser at the point at which
the Power Seller makes delivery to Seller as established under such
Commitment. Asset Purchase shall be responsible for making all arrangements
necessary for the further transmission of such energy.
4. (a) Commencing as of the month following the Effective Date, Asset
Purchaser agrees to Pay to Seller each month all amounts properly due from
Seller to the Power Seller for the preceding month associated with capacity,
energy and any other benefits made available to it by Seller from each
Commitment on the preceding month's Commitment List, less the amount of
Seller's payment obligation specified in Section 8 below. In turn, each
month, Seller shall timely pay the Power Seller an amount equal to all amounts
properly due to the Power Seller for the preceding month under each
Commitment. For purposes of the first monthly payment due from Asset
Purchaser to Seller under this Agreement in connection with each Commitment,
energy payments shall be based on meter readings taken on the first day for
which Asset Purchaser has a payment obligation under this Agreement and
capacity payments shall be based on the ratio of the number of days in the
month for which Asset Purchaser has a payment obligation under this Agreement
to the total number of days in the month. Asset Purchaser shall make such
payment sufficiently in advance of the time that such payment is due by Seller
to the Power Seller as to allow Seller to make timely payment under such
Commitment, which includes the amount Seller receives from Asset Purchaser in
connection with such Commitment and the amount of Seller's payment obligation
specified in Section 8 below.
(b) Upon the -Effective Date, Seller shall irrevocably and unconditionally
assign and thereafter hold for the benefit of and/or credit to Asset Purchaser
against payments due from it to Seller under Section 4(a) hereof or, at the
termination of t his Agreement pay to Asset Purchaser, any and all amounts
which are then or thereafter received by Seller from the Power Sellers under
the Commitments, including, without limitation, any aggregate differential
balances under any Commitment and the benefit of and proceeds from any
security deposits, letters of credit or other similar instruments or accounts
established for the benefit of Seller by the Power Seller, but excluding any
credits or refunds received by Seller after the Effective Date which relate to
billing errors or reconciliations of pre-Effective Date bills, and any amounts
paid by the Power Sellers to Seller with respect to disputes arising before
the Effective Date that are attributable to a period prior to the Effective
Date .
5. (a) Effective as of the Effective Date, Seller hereby irrevocably and
unconditionally appoints Asset Purchaser as its agent for all purposes under
each Commitment. Asset Purchaser is authorized to take all actions that
Seller may lawfully take under such Commitment without further approval by
Seller, except that Seller's prior written consent shall be required for (i)
actions that materially increase the costs to be incurred or the quantity of
power to be purchased by Seller under such Commitment (such as the approval of
facility expansions or fuel supply arrangements) and (ii) Commitment option
exercises, term extensions or amendments. Seller shall not unreasonably
withold such consent.
(b) Seller shall not agree to any amendment to or waiver of rights under a
Commitment without Asset Purchaser's consent, which Asset Purchaser may grant
or withhold in its sole discretion, and will not take any actions inconsistent
with the provisions of this Section 5.
6. Each party shall be entitled to indemnification under this Agreement
to the extent and in the manner set forth in Article 9 of the APA which is
hereby incorporated herein by reference.
7. (a) Seller and Asset Purchaser agree to work cooperatively and use
all reasonable efforts to amend each Commitment and assign the amended
Commitment to Asset Purchaser so that Seller will be released of all further
liabilities and obligations under each Commitment and Asset Purchaser will be
directly in contract with the Power Seller (a "Novation"). Any such amendment
shall include all modifications necessary to reflect the substitution of Asset
Purchaser for Seller as the purchasing party under such Commitment (including
modifications to Commitment price indices, where appropriate) and to properly
describe interconnection, delivery point and transmission system references in
such Commitment. It is intended by the parties that such Commitment amendment
and assignment preserve the economic benefit of a Commitment to the Asset
Purchaser while continuing to afford to Seller the protections for its or its
Affiliates transmission system embodied in the Commitment, provided that
nothing in this Agreement is intended to limit the ability of Asset Purchaser
to direct the dispatch, availability, quantity of timing of capacity or
electrical output of a facility that is the subject of a Commitment in
accordance with the terms of such Commitment. Seller and Asset Purchaser
agree to execute all agreements and documents reasonably requested by the
other in connection with a Novation. The provisions of Section 8(d) shall
apply in respect of a Novation.
(b) Notwithstanding the provisions of 7(a) the Seller and Asset Purchaser
agree that, as a condition of any Novation, the Asset Purchaser will require
Seller to provide, either (i) payment of a lump sum pursuant to the provisions
of Section 8(d) which reduces the Seller's continuing obligation to zero ($0);
or, if Seller and Buyer do not mutually agree to payment of a lump sum, (ii) a
security interest to the Asset Purchaser in a portion of the Seller's Contract
Termination Charge revenues a nd related service agreements with Eastern
Edison Company, Blackstone Valley Electric Company and Newport Electric
Corporation which is equal to the continuing obligation of the Seller under
8(b) and is acceptable to the Asset Purchaser acting reasonably.
8.(a) In the month during which this Agreement is executed, Seller shall pay
the Power Seller an aggregate amount equal to the amount as set out in
Schedule "A" attached hereto (the "Monthly Support Payment"), multiplied by a
fraction, the numerator of which is the total number of days in the month in
which this Agreement is executed, less the number of days in such month up to
and including the date of the execution of this Agreement, and the denominator
of which is the total number of days in the month in which this Agreement is
executed, and such amount shall be deducted by Asset Purchaser from the amount
due Seller under Section 4 above for such month.
(b) Commencing as of the month following the Effective Date of this
Agreement and continuing for each succeeding month through and including
January 2008, Seller shall pay to the Power Seller each month an aggregate
amount equal to the Monthly Support Payment, and such amount shall be deducted
by Asset Purchaser from the amount due Seller under Section 4 above.
(c) n the event that the amount of the Monthly Support Payment set forth
is Section 8(b) (as adjusted to reflect any increase pursuant to this Section
8(c)) shall in any month exceed the amount due Seller from Asset Purchaser
under Section 4, Seller shall increase the amount of its Monthly Support
Payment in the next month (in addition to its obligation set forth in Section
8(b)) by the amount of such excess and Asset Purchaser shall also be allowed
to deduct such excess from the amount due Seller under Section 4 for such
month.
(d) To the extent that a Novation is executed with respect to a Commitment
pursuant to Section 7 and Asset Purchaser and Seller agree to a lump-sum
payment, Seller and Asset Purchaser agree to amend this Agreement to
equitability provide for a lump-sum payment to either Asset Purchaser or the
Power Seller to reduce the amount of Seller's retained obligation set forth in
Section 8(b). Such lump-sum payment and such reduction in the amount of
Seller's retained obligation shall be in amounts to b e negotiated in good
faith by Asset Purchaser and Seller. It is the intention of the parties that
the lump-sum payment shall be based on the net present value of the amounts
set out in Schedule "A" calculated using a discount rate acceptable to Asset
Purchaser and Seller acting reasonably and which is reasonable given the
remaining term of the amounts payable by the Seller to the Asset Purchaser as
set out in Schedule "A", prevailing interest rates for similar financings done
at the time of payment of the lump sum and the creditworthiness of Seller at
the time of payment of the lump sum.
9. This Agreement and all rights, obligations, and performances of the
parties hereunder, are subject to all applicable Federal and state laws, and
to all promulgated orders and other duly authorized action of governmental
authority having jurisdiction.
10. This Agreement, the APA and any other agreement entered into by the
parties pursuant to the APA constitute the entire agreement between the
parties, and supersede all previous offers, negotiations, discussions,
communications and correspondence. This Agreement may be amended only a
written agreement signed by the parties. Except as otherwise set forth in
Section 5 hereof, this Agreement and all of the provisions hereof shall be
binding upon and inure to the benefit of the parties hereto and their
respective successors and permitted assigns, but neither this Agreement nor
any of the rights, interests or obligations hereunder shall be assigned by any
party hereto, including by operation of law without the prior written consent
of the other party, nor is this Agreement intended to confer upon any other
person except the parties hereto any rights or remedies hereunder.
Notwithstanding the foregoing,
(i) the Asset Purchaser may assign all of its rights and obligations
hereunder to any wholly owned subsidiary (direct or indirect) of TransCanada
Pipelines Limited ("TransCanada") and upon Seller's receipt of notice from
Asset Purchaser of any such assignment, the Asset Purchaser will be released
from all liabilities and obligations hereunder, accrued and unaccrued, such
assignee will be deemed to have assumed, ratified, agreed to be bound by and
perform all such liabilities and obligations, and all references herein to
Asset Purchaser shall thereafter by deemed references to such assignee, in
each case without the necessity for further act or evidence by the parties
hereto or such assignee; provided, however, that no such assignment an d
assumption shall release the Asset Purchaser from its liabilities and
obligations hereunder unless the assignee shall have acquired all or
substantially all of the Asset Purchaser's assets; provided, further, however,
that no such assignment and assumption shall relieve or in any way discharge
TransCanada from the performance of its duties and obligations under the
Guaranty dated as of the date of this Agreement executed by TransCanada; and
(ii) the Asset Purchaser or its permitted assignee ma y assign, transfer,
pledge or otherwise dispose of its rights and interests hereunder to a trustee
or lending institutions) for the purpose of financing or refinancing the
Commitment including upon or pursuant to the exercise of remedies under a
financing or refinancing, or by way of assignments, transfers, conveyances or
dispositions in lieu thereof, provided, however, the no such assignment or
disposition shall relieve or in any way discharge the Asset Purchaser or such
assignee from the performance of its duties and obligations under this
Agreement. Seller agrees to execute and deliver such documents as may be
reasonably necessary to accomplish any such assignment, transfer, conveyances,
pledge or disposition of rights hereunder so long as Sellers rights under this
Agreement are not thereby otherwise altered, amended, diminished or otherwise
impaired. The interpretation and performance of this Agreement shall be
according to and controlled by the laws of The Commonwealth of Massachusetts
(regardless of the laws that might otherwise govern under applicable
Massachusetts principles of conflicts of laws). This Agreement may be
executed in one or more counterparts and each such counterpart shall
constitute one and the same instrument.
11. All payments required under this Agreement shall be paid in cash by
federal or other wire transfer of immediately available funds to an account
designated by the party to receive such such payment.
12. This Agreement shall be of no force and effect until the Effective
Date. If the APA shall have been terminated before the occurrence of the
Closing Date (as defined in the APA), this Agreement shall, without any action
of the parties hereto, terminate as of the time of the termination of the APA.
As used in this Agreement, "Effective Date" shall mean the Effective Date (as
defined in the APA).
13. In the event that TransCanada Power Marketing, Ltd. or successor is in
default of the Wholesale Standard Offer Agreement between TransCanada Power
Marketing, Ltd. and Eastern Edison Company, Blackstone Valley Electric Company
and Newport Electric Corporation and, having been given notice has failed to
cure such default within the time specified in the Wholesale Standard Offer
Agreement, Seller's obligation to make support payments under Section 8(a)
will be suspended until such default i s fully cured.
IN WITNESS WHEREOF, the parties have caused their duly authorized
representatives to execute this Agreement on their behalf as of the date first
above written.
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Name: Kevin A. Kirby
Title: Vice President
TRANSCANADA POWER MARKETING LTD.
By: /s/ Alex Pourbaix
Name: Alex Pourbaix
Title: Vice President
By: /s/ Russ Girling
Name: Russ Girling
Title: Senior Vice President
EXHIBIT 10 (bb)(x)
REINSTATEMENT AGREEMENT
This Reinstatement Agreement (the "Agreement") is dated as of July 6,
1999 by and among Southern Energy Canal, L.L.C. ("Southern Canal') and Montaup
Electric Company ("Montaup"). The parties hereto are referred to herein
individually as a "Party" and collectively as the "Parties."
RECITALS
A. In connection with Southern Canal's acquisition of the Canal Station,
Southern Canal assumed certain Power Contracts with Montaup, New England Power
Company ("NEPCO"), Commonwealth Electric Company and Cambridge Electric Light
Company (collectively "COM/Elec") and Boston Edison Company ("BECO')
(collectively the "Original Purchasers") dated December 1, 1965 (the "Original
Contracts") for the sale of 25% of the capacity and energy from Canal Unit I
to each of the Original Purchasers.
B. Pursuant to that certain PPA Transfer Agreement dated October 29, 1997
between USGen New England, Inc. ("USGenNE") and NEPCO, USGenNE was entitled to
certain rights and benefits and was required to perform certain obligations
under NEPCO's Original Contract.
C. Southern Canal entered into Amended and Restated Power Sales Contracts
dated December 18, 1998 with COM/Elec, BECO, and Montaup (the "Amended
Agreements") and submitted the Amended Agreements to the Federal Energy
Regulatory Commission ("FERC') for filing under Southern Canal's market rate
authority.
D. NEPCO and USGenNE filed a protest with FERC regarding the Amended
Agreements on the grounds that the consent of NEPCO was required for the
amendment of the Original Contracts.
E. FERC rejected Southern Canal's filing of the Amended Agreements, and
Southern Canal withdrew its filing and then refiled the Original Contracts
under cost of service rate authority.
F. Southern Canal has obtained the consent of NEPCO and USGenNE to the
Amended Agreements and has entered into a new Amended and Restated Power Sales
Contract with NEPCO which then assigned the contract to USGenNE and which in
turn will assign the contract to Southern Energy New England, L.L.C. effective
August 1, 1999.
G. The Parties desire to reinstate the Amended Agreement between them
(the "Montaup Agreement") in accordance with the terms hereof.
H. Montaup has entered into a Power Purchase and Sale Agreement dated as
of December 21, 1998 with Constellation Power Source, Inc. ("Constellation")
pursuant to which Montaup has agreed to sell the products it receives under
the Montaup Agreement to Constellation.
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements hereinafter set forth, the Parties hereto mutually
covenant and agree as follows:
1. Southern Canal and Montaup hereby reinstate the Montaup Agreement,
effective as of July 1, 1999 (the "Effective Date").
2. Southern Canal consents to any future assignment by Montaup of the
Montaup Agreement to Constellation; provided, however, that at the time of
such assignment Constellation meets the Creditworthiness Criteria asset forth
in the Montaup Agreement or delivers to Southern Canal a duly executed
Guarantee in form and substance satisfactory to Southern Canal from
Constellation's parent company which meets the Creditworthiness Criteria.
3. Southern Canal shall file this Agreement with FERC and the Parties
agree that the rates set forth in the Montaup Agreement apply for the period
from January 1, 1999 through the Effective Date. Within 30 days after a final
order from FERC approving this Agreement, Southern Canal shall pay Montaup the
amount, if any, by which the sum of the demand charges for January 1, 1999
through the Effective Date billed to and paid by Montaup under the Original
Agreement is greater than the amount that would have been payable if the
Montaup Agreement were effective as of January 1, 1999; provided that such
payment shall be made with interest computed in accordance with the FERC
regulations.
4. In connection with this Agreement and the transactions contemplated
hereby, each Party shall execute and deliver any additional documents and
instruments and perform any additional acts that may be necessary or
appropriate to effectuate and perform the provisions of this Agreement.
5. This Agreement shall inure to the benefit of and be binding upon the
Parties and their respective successors and assigns.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by
their officers duly authorized thereunto and have duly caused their corporate
or company seals to be affixed hereto.
SOUTHERN ENERGY CANAL, L.L.C.
By: /s/Henry T. E. Coolidale, Jr.
Name: Henry T. E. Coolidale, Jr
Title: President
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Name: Kevin A. Kirby
Title: Vice President
Exhibit (13)
Annual Report 2001
New England Power Company
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 all these states
(except Connecticut), 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
facilities are part of National Grid USA's transmission operations,
which are represented under the name National Grid Transmission
USA.
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 of cash flows
present fairly, in all material respects, the financial position of
New England Power Company at March 31, 2001 and 2000, and the
results of its operations and its cash flows for the year ended
March 31, 2001, the three month period ended March 31, 2000, and
the years ended December 31, 1999 and 1998, in conformity with
accounting principles generally accepted in the United States of
America. 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 of America, 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 our opinion.
s/PricewaterhouseCoopers LLP
Boston, Massachusetts
April 25, 2001, except for the last paragraph
of the Seabrook 1 section of Note D,
as to which the date is May 22, 2001,
and the fourth paragraph of Note C,
as to which the date is June 8, 2001
New England Power Company
Financial Review
Merger with National Grid
On March 22, 2000, the merger of New England Electric System (NEES)
and 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) maintained its
existing name and remained a wholly owned subsidiary of National Grid
USA. The merger was accounted for by the purchase method, the application
of which, including the recognition of goodwill, was pushed down and
reflected on the financial statements of the National Grid USA
subsidiaries, including the Company. Total goodwill amounted to $1.7
billion, of which the Company was allocated approximately $348 million.
This amount was determined pursuant to a study conducted by an
independent third party and is being amortized over 20 years.
Amortization expense is approximately $17.4 million annually.
The purchase accounting method requires the revaluation of assets and
liabilities to their fair value. This revaluation resulted in an
adjustment to the Company's pension and postretirement benefit accounts
in the amount of approximately $61 million, with an offsetting net credit
to a regulatory liability account (see Note E).
Acquisition of EUA
The acquisition of Eastern Utilities Associates (EUA) by National
Grid USA was completed on April 19, 2000 for $642 million. On May 1,
2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA,
was merged into the Company.
The acquisition of EUA was accounted for by the purchase method, the
application of which, including the recognition of goodwill, has been
pushed down and reflected on the financial statements of the National
Grid USA subsidiaries, including the Company. Total goodwill recognized
in this transaction was approximately $402 million, of which the Company
was allocated approximately $8 million. This amount was determined
pursuant to a study conducted by an independent third party and is being
amortized over 20 years. Amortization expense is approximately $0.4
million annually.
The purchase accounting method requires the revaluation of assets and
liabilities to their fair value. This revaluation resulted in an
adjustment to the Company's pension and postretirement benefit accounts
in the amount of approximately $3 million, with an offsetting net credit
to a regulatory liability account (see Note E).
As a result of the acquisition, Montaup's balance sheet accounts were
incorporated into the financial statements of the Company as of May 1,
2000. Listed below are the significant account balances incorporated.
May 1, 2000 balance
(In thousands)
Assets
Utility plant, at original cost $227,114
Accumulated provisions for depreciation
and amortization $(92,093)
Regulatory assets (current and long-term) $547,412
Liabilities
Other paid-in capital $135,444
Deferred federal and state income taxes $104,860
Accrued Yankee nuclear plant costs $ 46,030
Purchased power obligations
(current and long-term) $176,257
Other reserves and deferred credits $174,942
The accompanying statements of operations do not include any
revenues or expenses related to Montaup prior to the companies' merger on
May 1, 2000.
Regulatory Environment and Accounting Implications
Under 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 with which it has settlement agreements
through contract termination charges (CTC). The Company's retail
distribution affiliates recover CTC-related costs through delivery
charges to distribution customers. The recovery of the Company's stranded
costs (including the Montaup share) is divided into several categories.
The Company's unrecovered costs associated with generating plants
(nuclear and nonnuclear) and most regulatory assets were fully recovered
through the CTC by the end of 2000 and earned a return on equity (ROE)
averaging 9.7 percent. The Montaup share of unrecovered costs associated
with generating plants and most regulatory assets will be fully recovered
through the CTC by the end of 2009. 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 ROE. Until such time as the Company divests its operating
nuclear interests, 80 percent of the revenues and operating costs related
to the units will be allocated to customers through the CTC, with
shareholders being allocated the balance.
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. Similar to the Company, Montaup
also transferred its purchased power obligations as part of the
divestiture and in return agreed to make fixed monthly payments. The
aggregate fixed monthly payments, including the Montaup share, average
$11.3 million per month through December 2009 toward the above-market
cost of those contracts. The liability relating to purchased power
obligations, which is also reflected in regulatory assets, represents the
net present value of these fixed monthly payments. At March 31, 2001, the
net present value is approximately $786 million. 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 $453 million), which were
separate from the $786 million figure referred to above.
Prior to divesting substantially all of its nonnuclear generation
business in 1998, the Company was the wholesale supplier of the electric
energy requirements to its retail distribution affiliates as well as
unaffiliated customers. The Company's all-requirements contracts with its
affiliated distribution companies, as well as with some unaffiliated
customers, were generally terminated pursuant to settlement agreements
and tariff provisions in 1998. However, the Company remains obligated to
provide transition power supply service to new customer load in Rhode
Island at the standard offer price, but does not have a regulatory
agreement that necessarily allows full recovery of the costs of such
standard offer power. Consequently, the Company is at risk for the
difference between the actual cost of serving this load and the revenue
received from this obligation. The standard offer rate that the Company
charges for continuing to meet this obligation increased from 3.5 cents
per kilowatthour (kWh) in 1999 to 3.8 cents per kWh effective January 1,
2000. The standard offer rate is also subject to a rolling twelve-month
fuel index adjustment factor, which increased the rate by an additional
0.121 cents per kWh beginning in April 2000 up to 2.404 cents per kWh by
March 2001. The Company meets this obligation through a combination of
generation from some of its remaining generation sources, as well as by
periodically procuring power at market prices. Over time, the Company
cannot predict whether the resulting revenues will be sufficient to cover
the costs of procuring such power. For the year ended March 31, 2001, the
Company's losses from this obligation were approximately $5 million.
In a December 15, 2000 Order, the Federal Energy Regulatory
Commission (FERC) rejected the Independent System Operator-New England's
(ISO New England) proposed $0.17 per kW-month Installed Capacity (ICAP)
deficiency charge and reinstated an administratively-determined
deficiency charge of $8.75 per kW-month, retroactive to August 1, 2000.
Several parties, including the Company, filed motions requesting
rehearing and stay of the FERC's order. On January 10, 2001, the FERC
granted these motions. On March 6, 2001, the FERC reversed its earlier
order by allowing ISO New England's previously proposed ICAP rate of
$0.17 per kW-month to be effective from August 1, 2000 through March 31,
2001. Effective April 1, 2001, the FERC ordered an ICAP rate of $8.75 per
kW-month. On March 16, 2001, National Grid and others filed a motion to
stay the FERC Order with the United States Court of Appeals for the First
Circuit (First Circuit). The First Circuit stayed the ICAP rate of $8.75
per kW-month on March 30, 2001. On June 4, 2001, ISO New England made a
filing to comply with the March FERC order that proposed a maximum charge
of $4.87 per kW-month. On June 8, 2001, the First Circuit, ruling on the
merits of the appeal to the FERC's imposing the $8.75 per kW-month
charge, remanded the case to the FERC for further consideration. The
First Circuit order allows the FERC to reinstate its initial order on a
prospective basis, but asks the FERC to answer several questions to
support its order. National Grid and others have asked the FERC to
consider the June 4th ISO filing while it is reconsidering its initial
order on remand. At this time, the Company cannot predict how ICAP
charges will affect its forward looking power supply costs.
National Grid USA presented to the FERC in January 2001 a joint
proposal, with ISO New England and other utilities in New England, for a
Regional Transmission Organization (RTO) in the northeastern US. The RTO
would consist of an ISO with responsibility for administering a
competitive wholesale market in electricity and an Independent
Transmission Company offering transmission services and undertaking
transmission network development and the provision of connections for new
generation. The proposal responds to the FERC's objective set out in
"Order 2000", of separating transmission operations from market
participation and would give the Independent Transmission Company, of
which National Grid USA would be a member, the opportunity to propose
financial incentives to deliver greater value for customers and
shareholders. The proposal is subject to FERC approval and the ability of
the utility group to reach agreement on a number of additional issues.
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 or liabilities, 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.
The Company has 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 March 31, 2001, this amounted to approximately $1.7
billion, including $1.1 billion related to the above-market costs of
purchased power contracts, $0.2 billion related to accrued Yankee nuclear
plant costs, and $0.4 billion related to other net CTC regulatory assets.
Overview of Financial Results
Net income for the twelve months ended March 31, 2001 decreased $13
million compared with the twelve months ended December 31, 1999. The
decrease is primarily due to goodwill amortization from the mergers with
National Grid and EUA, increased purchased power costs, increased
interest expense, and decreased mitigation incentives, partially offset
by increased income due to the May 1, 2000 merger with Montaup, and
increased earnings from nuclear operations.
Net income for the three months ended March 31, 2000 decreased $6
million compared with the same period in 1999 primarily due to the
elimination of certain liabilities related to open access transmission
tariffs of approximately $5 million in the first quarter of 1999.
Net income for the year ended December 31, 1999 decreased $52
million compared with the same period in 1998 as a result of the
continuing impacts of the divestiture and the restructuring of the
utility business. Partially offsetting the decrease was 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.
Operating Revenue
Operating revenue for the twelve months ended March 31, 2001
increased approximately $60 million compared with the twelve months ended
December 31, 1999. The increase is due to increased sales and rates
related to obligations to new customer load in Rhode Island, and
increased unit contract sales from partially owned nuclear units that
experienced refueling outages in 1999. These increases are also affected
by the merger with Montaup, effective May 1, 2000. Partially offsetting
these increases are decreased CTC revenues due to fully reconciling true-
up mechanisms that allow the Company to adjust revenues proportionately
with correlating expenses, and decreased transmission revenues. The
transmission charge is a formula rate that recovers the Company's actual
costs plus a return on actual investment.
Operating revenue for the three months ended March 31, 2000
decreased $33 million compared with the same period in 1999, largely due
to CTC revenue of approximately $21 million from The Narragansett
Electric Company (Narragansett Electric) in 1999 related to its access
charge overcollections. This payment reduced Narragansett Electric's
future CTC obligations. This additional revenue in 1999 had a
corresponding impact to the amortization of CTC, discussed in "Operating
Expenses" below. The decrease was also due to the elimination of certain
liabilities related to open access transmission tariffs of $5 million in
1999. This decrease was partially offset by the impacts of increased
standard offer rates effective January 1, 2000 and increased kWh sales in
the three months ended March 31, 2000 compared with the same period in
1999.
Operating revenue for the year ended December 31, 1999 decreased
$622 million compared with 1998 due to the divestiture and reduced CTC
charges. Partially offsetting this decrease was an increase in
transmission revenues associated with the elimination of certain
liabilities related to open access transmission tariffs discussed above.
Operating Expenses
Operating expenses for the twelve months ended March 31, 2001
increased approximately $51 million compared with the twelve months ended
December 31, 1999.
Fuel for generation increased approximately $2 million primarily
related to charges at the Wyman 4 generating plant. Purchased power
expense for the twelve months ended March 31, 2001 increased
approximately $62 million compared with the twelve months ended December
31, 1999. This increase is primarily attributed to the inclusion of
Montaup's purchased power costs effective May 1, 2000, increased fuel
prices, and an increase in standard offer purchases related to
obligations to supply new customer load in Rhode Island, partially offset
by decreased purchased power charges from the Yankee Nuclear Power
Companies (Yankees). Charges from Maine Yankee decreased due to a refund
for the termination of excess nuclear insurance coverage. Vermont Yankee
purchased power charges decreased due to the effect of a refueling outage
during the quarter ended December 31, 1999. In addition, purchased power
charges from the Yankee Atomic nuclear power plant decreased as a result
of the completion of the purchased power contract and final billing in
June 2000.
Nuclear operation and maintenance expenses increased approximately
$7 million primarily due to the merger of Montaup's ownership percentage
of Millstone 3 with the Company's effective as of the merger date, as
well as the effects of increased expenses related to refueling outages
and other maintenance at Millstone 3 and Seabrook 1.
Other nonnuclear operation and maintenance expenses decreased
approximately $5 million compared with the twelve months ended December
31, 1999 primarily due to reduced pension and postretirement healthcare
expenses and reduced transmission costs. These decreases are partially
offset by the receipt of a transmission wheeling refund that reduced
expense in June 1999.
Depreciation and amortization expenses decreased approximately $24
million for the twelve months ended March 31, 2001 compared with the
twelve months ended December 31, 1999. This decrease is primarily related
to decreased CTC amortization as a result of the full recovery of the
Company's CTC-related costs associated with its generating plants and
regulatory assets (excluding Montaup's) at the end of 2000. This decrease
is partially offset by the Company's payments to increase the Millstone 3
decommissioning trust fund to the level prescribed in the Release and
Settlement Agreement with Northeast Utilities (NU) (see the "Millstone 3"
disclosure in the "Nuclear units" section), as well as the effect of the
addition of Montaup's ownership percentage of Millstone 3 effective as of
the merger date.
Operating expenses for the three months ended March 31, 2000
decreased $27 million compared with the same period in 1999.
The increase in fuel and purchased power expense of approximately $5
million reflected increased purchased power expenses for standard offer
requirements and increased kWh purchased.
Other operating expenses in the three months ended March 31, 2000
decreased approximately $3 million compared with the same period in 1999
due to the reimbursement of start-up costs from 1999 of the ISO New
England in 2000. Maintenance expenses decreased approximately $1 million
as a result of reduced expenses at the partially owned Millstone 3 and
Seabrook 1 nuclear generating facilities.
Depreciation and amortization expenses in the three months ended
March 31, 2000 decreased $23 million compared with the same period in
1999. This decrease was due to additional CTC amortization in 1999
related to the additional payment of approximately $21 million by
Narragansett Electric to the Company, discussed above.
Operating expenses for the year ended December 31, 1999 decreased
$543 million compared with 1998. The divestiture reduced all categories
of operating expenses in 1999, with the exception of depreciation and
amortization expense.
The decrease in fuel expense and purchased power costs reflected 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 Yankees, 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 reflected
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 ISO 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 that experienced refueling outages in the second quarter of
1999.
Depreciation and amortization expenses increased $3 million for the
year ended December 31, 1999, due to the recovery and amortization of
generation-related stranded costs being greater than the depreciation and
amortization of generation-related plant in the prior year. The increase
was also due to new transmission plant expenditures.
Other Income and Expense
Other income for the twelve months ended March 31, 2001 increased
compared with the twelve months ended December 31, 1999 primarily due to
increased earnings from the Yankees, partially offset by a decrease in
allowance for equity funds used during construction.
The amortization of goodwill of approximately $18 million resulted
from the mergers with National Grid and EUA.
Other income for the three months ended March 31, 2000 increased
compared with the same period in 1999 as a result of decreased expenses
related to employee incentive plans from workforce reductions following
the divestiture, partially offset by merger related expenses in 2000.
For the year ended December 31, 1999, other income increased
compared with the year ended December 31, 1998 primarily due to increased
interest income resulting from the reinvestment of the proceeds from the
divestiture. In 1999, this was 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.
Interest Expense
Interest expense increased for the twelve months ended March 31,
2001 compared with the twelve months ended December 31, 1999, primarily
due to higher interest rates on variable rate long-term debt and
increased short-term debt borrowings, as well as interest related to
Montaup's CTC settlement.
Interest expense for the three months ended March 31, 2000 increased
compared with the same period in 1999 primarily due to increased interest
rates on variable rate long-term debt and interest on short-term debt
borrowings not present in 1999.
Interest expense for the year ended December 31, 1999 decreased
compared with the year ended December 31, 1998 principally due to reduced
long-term and short-term debt as a result of the divestiture.
Nuclear Units
Nuclear Units Permanently Shut Down
Three of the Yankees 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
The Company's Estimated
Investment Billings to
as of 3/31/01 Date the Company
Unit % $(millions) Retired $(millions)
- -----------------------------------------------------------------
Yankee Atomic 34.5 2 Feb 1992 0
Connecticut Yankee 19.5 15 Dec 1996 50
Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a
liability and a 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 and Connecticut Yankee recover their costs,
including a return, in accordance with settlement agreements approved by
the FERC in May 1999 and July 2000, respectively. Prospectively, under
the FERC settlement agreement, Connecticut Yankee agreed to reduce annual
collections for decommissioning through the use of its pre-1983 spent
fuel trust funds and to limit its ROE to 6 percent. In addition,
Connecticut Yankee, Yankee Atomic, and Maine Yankee continue to pursue
litigation against the Department of Energy (DOE) to assume financial
responsibility for storage of spent nuclear fuel. Under rate provisions
approved by the FERC for Connecticut Yankee and Yankee Atomic, any
recovery from the DOE proceedings after litigation expenses and taxes
will be returned to customers.
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.
Maine Yankee had hired Stone & Webster, Inc. (S&W), an engineering,
construction, and consulting company, as the principal contractor to
decommission the unit. In May 2000, Maine Yankee terminated its long-term
contract with S&W and negotiated an arrangement with S&W to continue work
through June 2000. In June 2000, S&W filed for Chapter 11 bankruptcy
protection. Subsequently, Maine Yankee decided to self-manage the unit's
decommissioning process. In June 2000, Federal Insurance Company
(Federal) filed a complaint in S&W's bankruptcy proceeding which alleges
that Maine Yankee improperly terminated its contract with S&W. If the
court were to make such a finding, Federal would be excused from a $37
million performance bond liability to Maine Yankee. Federal's complaint
has been removed to the US Federal District Court in Maine for jury
trial. In August 2000, Maine Yankee filed a $78.2 million (later
increased to $86 million) damage claim against S&W in the bankruptcy
proceeding. At this time, the Company is unable to determine the
potential impact, if any, of these developments.
Under the provisions of the Company's industry restructuring
settlement agreements approved by state and federal regulators in 1998,
the Company recovers all costs, including shutdown costs, that the FERC
allows these Yankee companies to bill to the Company.
Operating Nuclear Units
The Company currently has minority interests in two operating
nuclear generating units that the Company is engaged in efforts to
divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its
16.2 percent interest in Millstone 3 to Dominion Resources, Inc.
(Dominion) on March 31, 2001. Until such time as the Company divests its
operating nuclear interests, 80 percent of the revenues and operating
costs related to the units will be allocated to customers through the
CTC, with shareholders being allocated the balance.
Vermont Yankee
The following table summarizes the Company's interest in the Vermont
Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest
(millions of dollars)
---------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 2000$) Balance Expiration
------------ ---------- ------ --------------- ------- ----------
22.5 $12 $36 $102 $57 2012
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. Several other parties, including Entergy Corporation
(Entergy), indicated to the Vermont Public Service Board (VPSB) that they
were prepared to make an offer for Vermont Yankee.
On February 14, 2001, the VPSB rejected Vermont Yankee's sale
agreement with AmerGen and formally terminated the AmerGen proceeding on
March 15, 2001. The VPSB also required Entergy to post a $26 million bond
payable in the event that Entergy withdraws its offer. In addition, the
VPSB stated that if the Entergy bond were redeemed, the proceeds would go
exclusively to Vermont customers. The Vermont Yankee Board of Directors
is presently considering its options with respect to that part of the
order.
On March 15, 2001, Vermont Yankee terminated its agreement with
AmerGen. After considering the pros and cons of shutting the plant down,
continuing to operate it, or sell it, Vermont Yankee decided to proceed
with a formal auction of the plant. The auction was officially launched
on April 16, 2001. The Company expects that the winning bidder of the
plant will be named in the fall of 2001. Any sale of the plant is
contingent upon the receipt of regulatory approvals by the Securities and
Exchange Commission, under the Public Utility Holding Company Act of
1935, the FERC, the Nuclear Regulatory Commission, the VPSB, and other
state regulatory commissions with jurisdiction over other equity owners
of Vermont Yankee.
Under the terms of the original AmerGen agreement, the existing
power purchasers (including the Company) were required 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 would be recovered
through the Company's CTC. At that time, the Company recorded a 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. With Vermont Yankee's termination of the agreement with
AmerGen in March 2001, the Company was relieved of this obligation and
accordingly reversed the liability and offsetting regulatory asset of $80
million. To date, the Company has not determined if it will enter into a
purchased power agreement with a proposed new owner of Vermont Yankee.
Seabrook 1
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), committed to seek
New Hampshire Public Utilities Commission (NHPUC) approval of a
definitive plan to sell, via public auction administered by the NHPUC,
its share of Seabrook 1, with such sale to occur no later than December
31, 2003. NAEC owns the largest percentage of the plant with a 35.98
percent interest, and its affiliate, North Atlantic Energy Service
Corporation, is the plant operator. As part of its settlement, PSNH has
also agreed to make all reasonable efforts to bundle its interests with
those of other owners (including the Company) seeking to sell their
interests so that a controlling interest may be offered in the auction.
In December 2000, NU filed its divestiture plan before the NHPUC,
requesting an expeditious process in order to permit a prompt sale of the
plant. Under the terms of the PSNH Settlement and enabling legislation,
the NHPUC will administer the sale of the plant with the assistance of an
asset sale specialist.
On April 12, 2001, the Company filed a Seabrook Divestiture Plan
with the NHPUC as directed by its 1998 restructuring settlement
agreement. Under the Divestiture Plan, the Company has indicated its
interest in selling its share of Seabrook 1 and has requested that the
NHPUC administer an auction on the Company's behalf under certain
guidelines and conditions.
On May 22, 2001, legislation was enacted in New Hampshire to provide
New Hampshire residents additional protections against the restructuring
problems encountered in California. Although the legislation includes
provisions to delay the sale of PSNH fossil and hydro generation assets,
it directs the NHPUC to expedite the auction of the Seabrook Station in a
manner that benefits customers of all New Hampshire utilities, including
the Company.
Millstone 3
In November 1999, the Company entered into an agreement with NU and
certain of NU's subsidiaries to settle claims made by the Company
relative to the operation of Millstone 3. Among other things, the
settlement provided for NU to include the Company's share of Millstone 3
in an auction of NU's share of the unit. Upon the closing of the sale, NU
would pay the Company a total of $25 million, regardless of the actual
sale price, with adjustments for certain capital and fuel procurement
expenditures. The settlement also required NU to indemnify the Company
and assume any residual liabilities resulting from the sale, including
any requirements that the sellers continue to purchase output from the
unit.
In August 2000, Dominion agreed to purchase the Millstone units,
including the Company's 16.2 percent interest in Millstone 3, for $1.3
billion in cash.
In November 2000, the Rhode Island Attorney General and the Rhode
Island Division of Public Utilities and Carriers filed a protest at the
FERC contending that the payment the Company would receive from the sale
of Millstone 3, as established by its agreement with NU, was
insufficient. In December 2000, the Company and other parties to the
Millstone sale submitted answers opposing Rhode Island's position and
arguing, among other things, that Rhode Island's contention was well
beyond the scope of the FERC proceeding. The Company further stated that
concerns over the customer rate impact of the Company's agreement with NU
would be more appropriately addressed under the terms of its
restructuring settlements. On January 25, 2001, the FERC found that Rhode
Island's objection was beyond the scope of the proceeding and approved
the sale.
On March 31, 2001, the Company completed the sale of its 16.2
percent interest in Millstone 3 for approximately $27.9 million. In
addition, the Company paid approximately $5.8 million to increase the
decommissioning trust fund to the level prescribed in its settlement
agreement with NU. The amounts received pursuant to the sale will, after
reimbursement of the Company's transaction costs and net investment in
Millstone 3, be credited to customers. The Company cannot predict whether
the Rhode Island regulators will reassert their claims in connection with
the recovery of stranded costs, or the financial consequences if they do
reassert their claims.
As a result of the sale, certain balance sheet accounts related to the
Company's investment in Millstone 3 were adjusted at March 31, 2001.
Listed below are the significant adjustments recorded.
Increase (Decrease)
(In thousands)
Utility plant $(679,345)
Construction work in process $ (6,684)
Nuclear fuel $ (10,974)
Materials and supplies $ (6,107)
Decommissioning $ (34,141)
Accumulated provisions for depreciation $ 597,851
Regulatory assets - net book value and
transaction costs $ 94,501
NSTAR Settlement
On March 30, 2001, the Company reached a settlement in principal
with NSTAR, formerly known as Boston Edison Company (BECO), resolving
issues surrounding a $3 million refund to Montaup ordered by the FERC in
January 2000. The order stemmed from an earlier proceeding initiated by
the FERC where it required BECO to reduce its ROE under a life of unit
purchased power agreement (PPA) with Montaup for 11 percent of the output
from the Pilgrim plant. BECO subsequently divested its ownership in the
Pilgrim plant in July 1999, and Montaup terminated its life of unit PPA
in favor of a PPA that expires in 2004. BECO appealed the FERC Order to
the First Circuit which, in turn, has remanded the case to the FERC for
further proceedings. Proceeds from the refund have already been credited
to customers through Montaup's CTC reconciliation mechanism. Under the
terms of the settlement, the Company will return to BECO 75 percent of
the refund amount, plus interest through March 31, 2001. The settlement
is conditioned on consent from the parties to Montaup's restructuring
settlement to recover this amount from customers through the CTC.
Wyman 4 Settlement
On April 23, 2001, Central Maine Power (CMP) and the Wyman 4
minority owners reached a settlement under which CMP will pay a total of
$12 million to the minority owners. The Company's pro rata share of the
settlement proceeds will be $2.9 million. The proceeds of the settlement,
less legal costs, will be returned to customers via the CTC. The
settlement is the result of arbitration brought by the Company and others
against CMP regarding the sharing of CMP's proceeds from its sale of the
Wyman 4 unit and site in Yarmouth, Maine in 1999. The Company is a 9
percent minority owner of the Wyman 4 generating unit.
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 March 31, 2001, the Company's tax exempt variable
rate long-term debt had a carrying value and fair value of approximately
$410 million. While the ultimate maturity dates of the underlying loan
agreements range from 2015 through 2022, this debt is issued in tax
exempt commercial paper mode. The various components that comprise this
debt are issued for periods ranging from one day to 270 days, and are
remarketed through remarketing agents at the conclusion of each period.
The weighted average variable interest rate for the year ended March 31,
2001, was approximately 3.4 percent.
As discussed in the "Regulatory Environment" section, the Company
remains obligated to provide transition power supply service to new
customer load in Rhode Island at the standard offer price, but does not
have a regulatory agreement that allows full recovery of the costs of
such standard offer power. The Company meets this obligation through a
combination of generation from some of its remaining generation sources,
as well as by periodically procuring power at market prices. Over time,
the Company cannot predict whether the resulting revenues will be
sufficient to cover the costs of procuring such power. For the year ended
March 31, 2001, the Company's losses from this obligation were
approximately $5 million.
Utility Plant Expenditures and Financing
Cash expenditures for the Company for utility plant totaled $57
million for the twelve months ended March 31, 2001 and were primarily
transmission-related. The funds necessary for utility plant expenditures
during the period were primarily provided by internal funds. Cash
expenditures for fiscal year 2002 are estimated to be approximately $45
million, principally related to transmission functions. Internally
generated funds are expected to fully cover capital expenditures in
fiscal year 2002.
In September 2000, the Company repurchased 961 shares of its 6
percent $100 par value preferred stock for $79,766. Approximately $17,000
of this transaction was credited to retained earnings. In October 2000,
the Company repurchased 350 shares of its 6 percent $100 par value
preferred stock for $30,455. Approximately $4,000 of this transaction was
credited to retained earnings.
In February 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.
Dividends payable at March 31, 2000, in the amount of $256 million
were paid on June 27, 2000.
The Company has regulatory approval to issue up to $375 million of
short-term debt. In October 2000, the Company received the necessary
regulatory approvals to allow approximately $39 million of variable rate
debt to remain outstanding through 2015. This results in classifying that
debt as long-term rather than short-term.
At March 31, 2001, the Company had lines of credit and standby bond
purchase facilities with banks totaling $456 million which are available
to provide liquidity support for $410 million of the Company's long-term
bonds in tax-exempt commercial paper mode, and for other corporate
purposes. There were no borrowings under these lines of credit at March
31, 2001.
New England Power Company
Statements of Income
Year ended 3 Months ended Year ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- ------------------------------------------------------------------------------------------
Operating revenue, principally
from affiliates $656,272 $134,564 $167,177 $596,341 $1,218,340
Operating expenses:
Fuel for generation 14,342 3,548 3,058 12,803 223,828
Purchased electric energy:
Contract termination and nuclear
unit shutdown charges 214,948 47,405 46,873 187,777 97,469
Other 91,844 14,682 11,111 56,731 302,367
Other operation 69,624 15,760 19,210 70,936 155,065
Maintenance 31,748 4,320 5,766 28,536 60,239
Depreciation and amortization 78,762 16,962 40,367 103,080 99,924
Taxes, other than income taxes 22,343 5,561 5,634 20,282 48,492
Income taxes 44,946 9,641 13,100 37,633 73,594
-------- -------- -------- -------- ----------
Total operating expenses 568,557 117,879 145,119 517,778 1,060,978
-------- -------- -------- -------- ----------
Operating income 87,715 16,685 22,058 78,563 157,362
Other income:
Allowance for equity funds
used during construction 276 (393) 588 1,958 633
Equity in income of nuclear
power companies 6,703 862 515 2,939 5,284
Amortization of goodwill (17,905) (366) - - -
Other income (expense), net 3,559 1,850 434 2,087 118
-------- -------- -------- -------- ----------
Operating and other income 80,348 18,638 23,595 85,547 163,397
-------- -------- -------- -------- ----------
Interest:
Interest on long-term debt 17,834 3,749 3,143 14,052 30,775
Other interest 4,883 853 240 1,003 10,688
Allowance for borrowed funds
used during construction (669) (426) (133) (522) (961)
-------- -------- -------- -------- ----------
Total interest 22,048 4,176 3,250 14,533 40,502
-------- -------- -------- -------- ----------
Net income $ 58,300 $ 14,462 $ 20,345 $ 71,014 $ 122,895
======== ======== ======== ======== ==========
Statements of Retained Earnings Year ended 3 Months ended Year ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- -------------------------------------------------------------------------------------------
Retained earnings at beginning
of period $ 1,415 $ 27,287 $204,603 $ 204,603 $ 407,630
Net income 58,300 14,462 20,345 71,014 122,895
Dividends declared on cumulative
preferred stock (91) (24) (24) (94) (1,230)
Dividends declared on common stock,
$-0-, $6.66, $-0-, $66.69, and $20.25,
per share, respectively - (24,098) - (241,415) (130,610)
Gain on redemption of preferred stock 21 - - 264 (264)
Repurchase of common stock - - (7,085) (7,085) (193,818)
Purchase accounting adjustment - (16,212) - - -
Acquisition adjustment 465 - - - -
------- -------- -------- --------- ---------
Retained earnings at end of period $60,110 $ 1,415 $217,839 $ 27,287 $ 204,603
======= ======== ======== ========= =========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
At March 31, At March 31,
(In thousands) 2001 2000
- -------------------------------------------------------------------------------------
Assets
Utility plant, at original cost $ 846,935 $1,318,026
Less accumulated provisions
for depreciation and amortization 320,238 854,309
---------- ----------
526,697 463,717
Construction work in progress 34,946 35,730
---------- ----------
Net utility plant 561,643 499,447
---------- ----------
Goodwill, net of amortization 338,188 333,771
Investments:
Nuclear power companies,
at equity (Note D-1) 46,474 45,966
Decommissioning trust funds (Note D-2) 16,331 36,279
Nonutility property and other investments 14,374 7,490
---------- ----------
Total investments 77,179 89,735
---------- ----------
Current assets:
Cash and temporary cash investments (including
$22,075 and $37,820 with affiliates) 22,360 226,921
Accounts receivable:
Affiliated companies 61,191 72,780
Others 89,483 48,139
Fuel, materials, and supplies, at average cost 6,289 10,345
Prepaid and other current assets 2,051 25,377
Regulatory assets - purchased power obligations and
accrued Yankee nuclear plant costs 158,578 82,698
---------- ----------
Total current assets 339,952 466,260
---------- ----------
Regulatory assets (Note C) 1,522,089 1,203,090
Deferred charges and other assets 50,170 37,271
---------- ----------
$2,889,221 $2,629,574
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized - 6,449,896 shares
Outstanding - 3,619,896 shares $ 72,398 $ 72,398
Other paid-in capital (Note J) 731,974 582,983
Retained earnings 60,110 1,415
Unrealized gain (loss) on securities, net (145) -
---------- ----------
Total common equity 864,337 656,796
Cumulative preferred stock, par value
$100 per share (Note H) 1,436 1,567
Long-term debt 410,279 371,773
---------- ----------
Total capitalization 1,276,052 1,030,136
---------- ----------
Current liabilities:
Short-term debt - 38,500
Accounts payable (including $25,287 and
$26,993 to affiliates) 66,017 51,584
Accrued liabilities:
Taxes 39,451 2,394
Interest 1,489 1,900
Purchased power obligations and accrued
Yankee nuclear plant costs 158,578 82,698
Other accrued expenses (Note G) 7,621 10,879
Dividends payable 22 256,487
---------- ----------
Total current liabilities 273,178 444,442
---------- ----------
Deferred federal and state income taxes 272,304 176,351
Unamortized investment tax credits 9,312 16,733
Accrued Yankee nuclear plant costs (Note D-2) 172,340 261,145
Purchased power obligations 636,848 611,802
Other reserves and deferred credits 249,187 88,965
Commitments and contingencies (Note D)
---------- ----------
$2,889,221 $2,629,574
========== ==========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows
Year ended 3 Months ended Year ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- -----------------------------------------------------------------------------------------
Operating activities:
Net income $ 58,300 $ 14,462 $ 20,345 $ 71,014 $ 122,895
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 85,123 18,799 42,170 108,789 104,331
Amortization of goodwill 17,905 366 - - -
Deferred income taxes and
investment tax credits, net (11,480) (2,908) 5,726 14,111 (226,722)
Allowance for funds used
during construction (945) (33) (720) (2,480) (1,594)
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)
Changes in assets and liabilities,
net of effects of acquisition:
Decrease (increase) in
accounts receivable, net (7,914) (3,174) 37,890 22,706 130,914
Decrease (increase) in fuel,
materials, and supplies 4,160 (874) 648 (251) (10,270)
Decrease (increase) in
regulatory assets 152,533 60,044 82,801 166,730 (1,071,524)
Decrease (increase) in prepaid
and other current assets 26,501 13,938 6,154 (17,746) (8,778)
Increase (decrease) in
accounts payable (813) (11,628) (81,950) (99,148) (31,761)
Increase (decrease) in purchased
power contract obligations (77,039) (16,947) (36,903) (128,931) 832,668
Increase (decrease) in other
current liabilities 30,822 (7,787) (11,147) (14,575) 5,037
Increase (decrease) in other
non-current liabilities (147,847) 20,349 (5,661) 45,483 (108,896)
Other, net 73,202 (49,869) (40,946) (87,277) 298,141
--------- -------- -------- --------- -----------
Net cash provided by (used in)
operating activities $ 202,508 $ 34,738 $ 18,407 $ 74,953 $ (413,049)
--------- -------- -------- --------- -----------
Investing activities:
Proceeds from sale of generating assets $ - $ - $ - $ - $ 1,688,863
Plant expenditures, excluding allowance
for funds used during construction (56,558) (11,890) (13,739) (56,887) (64,446)
Other investing activities (3,270) (271) (20) (4,411) (5,474)
--------- -------- -------- --------- -----------
Net cash provided by (used in)
investing activities $ (59,828) $(12,161) $(13,759) $ (61,298) $ 1,618,943
--------- -------- -------- --------- -----------
Financing activities:
Capital contribution from parent $ - $ - $ - $ - $ 34,881
Dividends paid on common stock (256,463) - - (9,050) (166,084)
Dividends paid on preferred stock (93) - (24) (118) (1,206)
Changes in short-term debt (38,500) - - 38,500 (111,250)
Long-term debt - issues 38,500 - - - -
Long-term debt - retirements (90,575) - - - (328,000)
Repurchase of common shares - - (18,056) (18,056) (417,960)
Preferred stock - retirements (110) - - - (38,505)
--------- -------- -------- --------- -----------
Net cash provided by (used in)
financing activities $(347,241) $ - $(18,080) $ 11,276 $(1,028,124)
--------- -------- -------- --------- -----------
Net increase (decrease) in
cash and cash equivalents $(204,561) $ 22,577 $(13,432) $ 24,931 $ 177,770
Cash and cash equivalents
at beginning of period 226,921 204,344 179,413 179,413 1,643
--------- -------- -------- --------- -----------
Cash and cash equivalents
at end of period $ 22,360 $226,921 $165,981 $ 204,344 $ 179,413
========= ======== ======== ========= ===========
Supplementary Information:
Interest paid less amounts capitalized $ 18,296 $ 5,322 $ 2,042 $ 11,849 $ 43,419
--------- -------- -------- --------- -----------
Federal and state income taxes
paid (refunded) $ (3,233) $ (15) $ 11,321 $ 55,134 $ 282,076
--------- -------- -------- --------- -----------
Dividends received from
investments at equity $ 13,986 $ 1,129 $ 1,730 $ 5,243 $ 6,571
--------- -------- -------- --------- -----------
The accompanying notes are an integral part of these financial statements.
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 all these states (except Connecticut), 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. The Company's
transmission facilities are part of National Grid USA's transmission
operations, which are represented under the name National Grid
Transmission USA. In addition, the Company also owns a minority interest
in one joint owned nuclear generating unit and one fossil fuel generating
unit, as well as minority equity interests in four nuclear generating
companies, three of which own generating facilities that are permanently
shut down. The output from these generating facilities is sold to third
parties and used to serve the Company's load obligation.
2. System of Accounts and Financial Statement Presentation:
The accounts of the Company are maintained in accordance with the
Uniform System of Accounts prescribed by regulatory bodies having
jurisdiction.
National Grid USA and its subsidiaries changed their fiscal year
from a calendar year ending December 31 to a fiscal year ending March 31.
National Grid USA and its subsidiaries made this change in order to align
their fiscal years with that of National Grid Group plc (National
Grid)(see Note B). The Company's first new full fiscal year began on
April 1, 2000 and ended on March 31, 2001. The accompanying financial
information as of March 31, 2001 and 2000, and for the twelve months
ended March 31, 2001, reflects the new basis of accounting established
for the Company's assets and liabilities in connection with the
acquisition of National Grid USA by National Grid on March 22, 2000. The
audited results of operations for the three month period ended March 31,
2000 includes an immaterial amount of goodwill amortization for the ten
day period from March 22 to March 31, 2000. Due to the immateriality of
this effect, this transitional period has not been separated into the
period preceding and the period following the pushdown of goodwill.
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 2001 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 3.2 percent for
the year ended March 31, 2001, 3.7 percent for the three month period
ended March 31, 2000, 8.1 percent for the three month period ended March
31, 1999, and 7.6 percent and 6.1 percent for the years ended December
31, 1999 and 1998, respectively.
4. Depreciation and Amortization:
The depreciation and amortization expense included in the statements
of income is composed of the following:
Three Months
Year Ended Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- ---------------------------------------------------------------------------------
Depreciation - transmission related $15,055 $ 3,269 $ 3,440 $ 13,222 $12,553
Depreciation - all other 5,477 (15) 354 1,286 46,256
Nuclear decommissioning costs (Note D-2) 9,901 923 699 3,637 2,719
Amortization:
Millstone 3 additional amortization,
pursuant to 1995 rate settlement - - - - 22,040
Regulatory assets covered by contract
termination charges (Note C) 48,329 12,785 35,874 84,935 16,356
------- ------- -------- ------- -------
Total depreciation and
amortization expense $78,762 $16,962 $40,367 $103,080 $99,924
======= ======= ======= ======== =======
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 for all periods
presented. Amortization of Millstone 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 at
purchase date of 90 days or less as cash.
6. Property, Plant, and Equipment:
The Company's integrated system of transmission property consists of
approximately 2,800 circuit miles of transmission lines and 116
substations.
7. Income Taxes:
Income taxes have been computed utilizing the asset and liability
approach which requires the recognition of deferred tax assets and
liabilities for the tax consequences of temporary differences by applying
enacted statutory tax rates applicable to future years to differences
between the financial statement carrying amounts and the tax basis of
existing assets and liabilities.
8. New Accounting Standards:
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (FAS 133). FAS 133
requires that an entity recognize all derivative instruments as either
assets or liabilities in the statement of financial position and the
measure of those instruments at fair value. In June 1999, the FASB issued
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date," which amends FAS 133 to be
effective for all fiscal quarters of fiscal years beginning after June
15, 2000. FAS 133 was subsequently amended by SFAS No. 138, "Accounting
for Certain Derivative Instruments and Certain Hedging Activities." The
Company expects the adoption of the new standard during fiscal 2002 will
not have a material impact on its financial position or results of
operations.
In September 1999, the FASB issued an exposure draft of a proposed
SFAS titled "Business Combinations and Intangible Assets - Accounting for
Goodwill." A limited revision of the draft was issued on February 14,
2001. The proposed SFAS would continue recognition of goodwill as an
asset but would not permit amortization as currently required by
Accounting Principles Board Opinion No. 17, "Intangible Assets." In
addition, goodwill would be tested periodically for impairment when
events and circumstances occur indicating that it might be impaired. The
proposed SFAS would be effective for fiscal years beginning after
December 15, 2001. Early adoption would be permitted for companies with a
fiscal year beginning after March 15, 2001. Currently, the Company is
unable to determine the potential impact of the proposed accounting
standard on its financial position or results of operations.
Note B - Mergers and Acquisitions
Merger with National Grid
On March 22, 2000, the merger of NEES and National Grid was
completed, with NEES (renamed National Grid USA) becoming a wholly owned
subsidiary of National Grid. The Company maintained its existing name and
remained a wholly owned subsidiary of National Grid USA. The merger was
accounted for by the purchase method, the application of which, including
the recognition of goodwill, was pushed down and reflected on the
financial statements of the National Grid USA subsidiaries, including the
Company. Total goodwill amounted to $1.7 billion, of which the Company
was allocated approximately $348 million. This amount was determined
pursuant to a study conducted by an independent third party and is being
amortized over 20 years. Amortization expense is approximately $17.4
million annually.
The purchase accounting method requires revaluation of assets and
liabilities to their fair value. This revaluation resulted in an
adjustment to the Company's pension and postretirement benefit accounts
in the amount of approximately $61 million, with an offsetting net credit
to a regulatory liability account (see Note E).
Acquisition of EUA
The acquisition of Eastern Utilities Associates (EUA) by National
Grid USA was completed on April 19, 2000 for $642 million. On May 1,
2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA,
was merged into the Company.
The acquisition of EUA was accounted for by the purchase method, the
application of which, including the recognition of goodwill, has been
pushed down and reflected on the financial statements of the National
Grid USA subsidiaries, including the Company. Total goodwill amounted to
approximately $402 million, of which the Company was allocated
approximately $8 million. This amount was determined pursuant to a study
conducted by an independent third party and is being amortized over 20
years. Amortization expense is approximately $0.4 million annually.
The purchase accounting method requires revaluation of assets and
liabilities to their fair value. This revaluation resulted in an
adjustment to the Company's pension and postretirement benefit accounts
in the amount of approximately $3 million, with an offsetting net credit
to a regulatory liability account (see Note E).
As a result of the acquisition, Montaup's balance sheet accounts were
incorporated into the financial statements of the Company as of May 1,
2000. Listed below are the significant account balances incorporated.
May 1, 2000 balance
(In thousands)
Assets
Utility plant, at original cost $227,114
Accumulated provisions for depreciation
and amortization $(92,093)
Regulatory assets (current and long-term) $547,412
Liabilities
Other paid-in capital $135,444
Deferred federal and state income taxes $104,860
Accrued Yankee nuclear plant costs $ 46,030
Purchased power obligations
(current and long-term) $176,257
Other reserves and deferred credits $174,942
The accompanying statements of operations do not include any
revenues or expenses related to Montaup prior to the companies' merger on
May 1, 2000.
Note C - Regulatory Environment and Accounting Implications
Under 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 with which it has settlement agreements
through CTCs. The Company's retail distribution affiliates recover CTC-
related costs through delivery charges to distribution customers. The
recovery of the Company's stranded costs (including the Montaup share) is
divided into several categories. The Company's unrecovered costs
associated with generating plants (nuclear and nonnuclear) and most
regulatory assets were fully recovered through the CTC by the end of 2000
and earned a return on equity (ROE) averaging 9.7 percent. The Montaup
share of unrecovered costs associated with generating plants and most
regulatory assets will be fully recovered through the CTC by the end of
2009. 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 ROE. Until such time as the Company
divests its operating nuclear interests, 80 percent of the revenues and
operating costs related to the units will be allocated to customers
through the CTC, with shareholders being allocated the balance.
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. Similar to the Company, Montaup
also transferred its purchased power obligations as part of the
divestiture and in return agreed to make fixed monthly payments. The
aggregate fixed monthly payments, including the Montaup share, average
$11.3 million per month through December 2009 toward the above-market
cost of those contracts. The liability relating to purchased power
obligations, which is also reflected in regulatory assets, represents the
net present value of these fixed monthly payments. At March 31, 2001, the
net present value is approximately $786 million. 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 $453 million), which were
separate from the $786 million figure referred to above.
Prior to divesting substantially all of its nonnuclear generation
business in 1998, the Company was the wholesale supplier of the electric
energy requirements to its retail distribution affiliates as well as
unaffiliated customers. The Company's all-requirements contracts with its
affiliated distribution companies, as well as with some unaffiliated
customers, were generally terminated pursuant to settlement agreements
and tariff provisions in 1998. However, the Company remains obligated to
provide transition power supply service to new customer load in Rhode
Island at the standard offer price, but does not have a regulatory
agreement that necessarily allows full recovery of the costs of such
standard offer power. Consequently, the Company is at risk for the
difference between the actual cost of serving this load and the revenue
received from this obligation. The standard offer rate that the Company
charges for continuing to meet this obligation increased from 3.5 cents
per kilowatthour (kWh) in 1999 to 3.8 cents per kWh effective January 1,
2000. The standard offer rate is also subject to a rolling twelve-month
fuel index adjustment factor, which increased the rate by an additional
0.121 cents per kWh beginning in April 2000 up to 2.404 cents per kWh by
March 2001. The Company meets this obligation through a combination of
generation from some of its remaining generation sources, as well as by
periodically procuring power at market prices. Over time, the Company
cannot predict whether the resulting revenues will be sufficient to cover
the costs of procuring such power. For the year ended March 31, 2001, the
Company's losses from this obligation were approximately $5 million.
In a December 15, 2000 Order, the FERC rejected the Independent
System Operator's (ISO New England) proposed $0.17 per kW-month Installed
Capacity (ICAP) deficiency charge and reinstated an administratively-
determined deficiency charge of $8.75 per kW-month, retroactive to August
1, 2000. Several parties, including the Company, filed motions requesting
rehearing and stay of the FERC's order. On January 10, 2001, the FERC
granted these motions. On March 6, 2001, the FERC reversed its earlier
order by allowing ISO New England's previously proposed ICAP rate of
$0.17 per kW-month to be effective from August 1, 2000 through March 31,
2001. Effective April 1, 2001, the FERC ordered an ICAP rate of $8.75 per
kW-month. On March 16, 2001, National Grid and others filed a motion to
stay the FERC Order with the United States Court of Appeals for the First
Circuit (First Circuit). The First Circuit stayed the ICAP rate of $8.75
per kW-month on March 30, 2001. On June 4, 2001, ISO New England made a
filing to comply with the March FERC order that proposed a maximum charge
of $4.87 per kW-month. On June 8, 2001, the First Circuit, ruling on the
merits of the appeal to the FERC's orders imposing the $8.75 per kW-month
charge, remanded the case to the FERC for further consideration. The
First Circuit order allows the FERC to reinstate its initial order on a
prospective basis, but asks the FERC to answer several questions to
support its order. National Grid and others have asked the FERC to
consider the June 4th ISO filing while it is reconsidering its initial
order on remand. At this time, the Company cannot predict how ICAP
charges will affect its forward looking power supply costs.
National Grid USA presented to the FERC in January 2001 a joint
proposal, with ISO New England and other utilities in New England, for a
Regional Transmission Organization (RTO) in the northeastern US. The RTO
would consist of an ISO with responsibility for administering a
competitive wholesale market in electricity and an Independent
Transmission Company offering transmission services and undertaking
transmission network development and the provision of connections for new
generation. The proposal responds to the FERC's objective set out in
"Order 2000", of separating transmission operations from market
participation and would give the Independent Transmission Company, of
which National Grid USA would be a member, the opportunity to propose
financial incentives to deliver greater value for customers and
shareholders. The proposal is subject to FERC approval and the ability of
the utility group to reach agreement on a number of additional issues.
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 SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation" (FAS 71), which requires
regulated entities, in appropriate circumstances, to establish regulatory
assets or liabilities, 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 FASB 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.
The Company has 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 March 31, 2001, this amounted to approximately $1.7
billion, including $1.1 billion related to the above-market costs of
purchased power contracts, $0.2 billion related to accrued Yankee nuclear
plant costs, and $0.4 billion related to other net CTC regulatory assets.
Note D - Commitments and Contingencies
1. Yankee Nuclear Power Companies
The Company has minority interests in four Yankee Nuclear Power
Companies (Yankees). 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:
Year Ended Three Months Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- ----------------------------------------------------------------------------------------
Operating revenue $ 291,628 $ 81,225 $ 89,244 $ 377,039 $ 439,046
=========== =========== =========== =========== ===========
Net income $ 29,589 $ 5,310 $ 5,138 $ 13,890 $ 23,218
=========== =========== =========== =========== ===========
Company's equity in
net income $ 6,703 $ 862 $ 515 $ 2,939 $ 5,284
=========== =========== =========== =========== ===========
Net plant 160,701 167,317 166,062 172,100 171,582
Other assets 1,893,733 2,520,887 2,798,948 2,631,750 2,810,613
Liabilities and debt (1,855,775) (2,437,609) (2,707,749) (2,554,261) (2,723,454)
----------- ----------- ----------- ----------- -----------
Net assets $ 198,659 $ 250,595 $ 257,261 $ 249,589 $ 258,741
=========== =========== =========== =========== ===========
Company's equity in
net assets $ 46,474 $ 45,966 $ 47,323 $ 46,233 $ 48,538
=========== =========== =========== =========== ===========
Company's purchased electric energy:
Vermont Yankee $ 31,899 $ 7,761 $ 7,874 $ 37,551 $ 35,108
All other Yankees $ 21,616 $ 9,324 $ 9,370 $ 37,765 $ 48,543
=========== =========== =========== =========== ===========
At March 31, 2001, approximately $7 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 of the Yankees 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
The Company's Estimated
Investment Billings to
as of 3/31/01 Date the Company
Unit % $(millions) Retired $(millions)
- -----------------------------------------------------------------
Yankee Atomic 34.5 2 Feb 1992 0
Connecticut Yankee 19.5 15 Dec 1996 50
Maine Yankee 24.0 17 Aug 1997 129
In the case of each of these units, the Company has recorded a
liability and a 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 and Connecticut Yankee recover their costs,
including a return, in accordance with settlement agreements approved by
the FERC in May 1999 and July 2000, respectively. Prospectively, under
the FERC settlement agreement, Connecticut Yankee agreed to reduce annual
collections for decommissioning through the use of its pre-1983 spent
fuel trust funds and to limit its ROE to 6 percent. In addition,
Connecticut Yankee, Yankee Atomic, and Maine Yankee continue to pursue
litigation against the Department of Energy (DOE) to assume financial
responsibility for storage of spent nuclear fuel. Under rate provisions
approved by the FERC for Connecticut Yankee and Yankee Atomic, any
recovery from the DOE proceedings after litigation expenses and taxes
will be returned to customers.
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.
Maine Yankee had hired Stone & Webster, Inc. (S&W), an engineering,
construction, and consulting company, as the principal contractor to
decommission the unit. In May 2000, Maine Yankee terminated its long-term
contract with S&W and negotiated an arrangement with S&W to continue work
through June 2000. In June 2000, S&W filed for Chapter 11 bankruptcy
protection. Subsequently, Maine Yankee decided to self-manage the unit's
decommissioning process. In June 2000, Federal Insurance Company
(Federal) filed a complaint in S&W's bankruptcy proceeding which alleges
that Maine Yankee improperly terminated its contract with S&W. If the
court were to make such a finding, Federal would be excused from a $37
million performance bond liability to Maine Yankee. Federal's complaint
has been removed to the US Federal District Court in Maine for jury
trial. In August 2000, Maine Yankee filed a $78.2 million (later
increased to $86 million) damage claim against S&W in the bankruptcy
proceeding. At this time, the Company is unable to determine the
potential impact, if any, of these developments.
Under the provisions of the Company's industry restructuring
settlement agreements approved by state and federal regulators in 1998,
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 currently has minority interests in two operating
nuclear generating units that the Company is engaged in efforts to
divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its
16.2 percent interest in Millstone 3 to Dominion Resources, Inc.
(Dominion) on March 31, 2001. Until such time as the Company divests its
operating nuclear interests, 80 percent of the revenues and operating
costs related to the units will be allocated to customers through the
CTC, with shareholders being allocated the balance.
Vermont Yankee
The following table summarizes the Company's interest in the Vermont
Yankee Nuclear Power Corporation as of March 31, 2001:
The Company's Interest
(millions of dollars)
----------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 2000 $) Balance Expiration
------------- ----------------------------------------------------------------
22.5 $12 $36 $102 $57 2012
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. Several other parties, Including Entergy Corporation
(Entergy), indicated to the Vermont Public Service Board (VPSB) that they
were prepared to make an offer for Vermont Yankee.
On February 14, 2001, the VPSB rejected Vermont Yankee's sale
agreement with AmerGen and formally terminated the AmerGen proceeding on
March 15, 2001. The VPSB also required Entergy to post a $26 million bond
payable in the event that Entergy withdraws its offer. In addition, the
VPSB stated that if the Entergy bond were redeemed, the proceeds would go
exclusively to Vermont customers. The Vermont Yankee Board of Directors
is presently considering its options with respect to that part of the
order.
On March 15, 2001, Vermont Yankee terminated its agreement with
AmerGen. After considering the pros and cons of shutting the plant down,
continuing to operate it, or sell it, Vermont Yankee decided to proceed
with a formal auction of the plant. The auction was officially launched
on April 16, 2001. The Company expects that the winning bidder of the
plant will be named in the fall of 2001. Any sale of the plant is
contingent upon the receipt of regulatory approvals by the SEC, under the
1935 Act, the FERC, the NRC, the VPSB, and other state regulatory
commissions with jurisdiction over other equity owners of Vermont Yankee.
Under the terms of the original AmerGen agreement, the existing
power purchasers (including the Company) were required 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 would be recovered
through the Company's CTC. At that time, the Company recorded a 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. With Vermont Yankee's termination of the agreement with
AmerGen in March 2001, the Company was relieved of this obligation and
accordingly reversed the liability and offsetting regulatory asset of $80
million. To date, the Company has not determined if it will enter into a
purchased power agreement with a proposed new owner of Vermont Yankee.
Seabrook 1
The following table summarizes the Company's interest in the
Seabrook 1 nuclear generating unit as of March 31, 2001;
The Company's share of (millions of dollars)
---------------------------------------------
The Company's Net Estimated Decommissioning
Ownership Plant Decommissioning Fund License
Interest (%) Assets Cost (in 2000 $) Balances* Expiration
- -------------------------------------------------------------------------------------
10 $17** $61 $16 2026
*Certain additional amounts are anticipated to be available through tax
deductions.
**Represents post-December 1995 spending including nuclear fuel.
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), committed
to seek New Hampshire Public Utilities Commission (NHPUC) approval
of a definitive plan to sell, via public auction administered by
the NHPUC, its share of Seabrook 1, with such sale to occur no
later than December 31, 2003. NAEC owns the largest percentage of
the plant with a 35.98 percent interest, and its affiliate, North
Atlantic Energy Service Corporation, is the plant operator. As part
of its settlement, PSNH has also agreed to make all reasonable
efforts to bundle its interests with those of other owners
(including the Company) seeking to sell their interests so that a
controlling interest may be offered in the auction.
In December 2000, Northeast Utilities (NU) filed its
divestiture plan before the NHPUC, requesting an expeditious
process in order to permit a prompt sale of the plant. Under the
terms of the PSNH Settlement and enabling legislation, the NHPUC
will administer the sale of the plant with the assistance of an
asset sale specialist.
On April 12, 2001, the Company filed a Seabrook Divestiture
Plan with the NHPUC as directed by its 1998 restructuring
settlement agreement. Under the Divestiture Plan, the Company has
indicated its interest in selling its share of Seabrook 1 and has
requested that the NHPUC administer an auction on the Company's
behalf under certain guidelines and conditions.
On May 22, 2001, legislation was enacted in New Hampshire to
provide New Hampshire residents additional protections against the
restructuring problems encountered in California. Although the
legislation includes provisions to delay the sale of PSNH fossil
and hydro generation assets, it directs the NHPUC to expedite the
auction of the Seabrook Station in a manner that benefits customers
of all New Hampshire utilities, including the Company.
Millstone 3
In November 1999, the Company entered into an agreement with
NU and certain of NU's subsidiaries to settle claims made by the
Company relative to the operation of Millstone 3. Among other
things, the settlement provided for NU to include the Company's
share of Millstone 3 in an auction of NU's share of the unit. Upon
the closing of the sale, NU would pay the Company a total of $25
million, regardless of the actual sale price, with adjustments for
certain capital and fuel procurement expenditures. The settlement
also required NU to indemnify the Company and assume any residual
liabilities resulting from the sale, including any requirements
that the sellers continue to purchase output from the unit.
In August 2000, Dominion agreed to purchase the Millstone
units, including the Company's 16.2 percent interest in Millstone
3, for $1.3 billion in cash.
In November 2000, the Rhode Island Attorney General and the
Rhode Island Division of Public Utilities and Carriers filed a
protest at the FERC contending that the payment the Company would
receive from the sale of Millstone 3, as established by its
agreement with NU, was insufficient. In December 2000, the Company
and other parties to the Millstone sale submitted answers opposing
Rhode Island's position and arguing, among other things, that Rhode
Island's contention was well beyond the scope of the FERC
proceeding. The Company further stated that concerns over the
customer rate impact of the Company's agreement with NU would be
more appropriately addressed under the terms of its restructuring
settlements. On January 25, 2001, the FERC found that Rhode
Island's objection was beyond the scope of the proceeding and
approved the sale.
On March 31, 2001, the Company completed the sale of its 16.2
percent interest in Millstone 3 for approximately $27.9 million. In
addition, the Company paid approximately $5.8 million to increase
the decommissioning trust fund to the level prescribed in its
settlement agreement with NU. The amounts received pursuant to the
sale will, after reimbursement of the Company's transaction costs
and net investment in Millstone 3, be credited to customers. The
Company cannot predict whether the Rhode Island regulators will
reassert their claims in connection with the recovery of stranded
costs or the financial consequences if they do reassert their
claims.
As a result of the sale, certain balance sheet accounts related
to the
Company's investment in Millstone 3 were adjusted at March 31,
2001.
Listed below are the significant adjustments recorded.
Increase (Decrease)
(In thousands)
Utility plant $(679,345)
Construction work in process $ (6,684)
Nuclear fuel $ (10,974)
Materials and supplies $ (6,107)
Decommissioning $ (34,141)
Accumulated provisions for depreciation $ 597,851
Regulatory assets - net book value and
transaction costs $ 94,501
Nuclear Decommissioning
The Company is liable for its share of decommissioning costs
for 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 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 Seabrook 1 through depreciation expense.
In addition, the Company is paying its portion of projected
decommissioning costs for Connecticut Yankee and Maine Yankee. The
Company has completed its projected decommissioning obligation for
Yankee Atomic. Such costs reflect estimates of total
decommissioning costs approved by the FERC.
In New Hampshire, legislation was enacted in 1998 that 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, there is a
single owner of an approximate 15 percent share of Seabrook 1 that
is subject to the legislation. The impact of this legislation to
the Company is not considered material to its financial position or
results of operation.
The Company has been working to amend the current nuclear
decommissioning statute to become effective upon the sale of
Seabrook. Decommissioning legislation has passed in the New
Hampshire legislature. This bill, initiated and supported by
Seabrook's joint owners, including the Company and members of the
New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC),
modifies New Hampshire's current decommissioning law and removes
utility owners from the role of proportional guarantor for non-
utility owners. The new legislation also seeks to protect customers
from future decommissioning risks by requiring a buyer to provide
funding assurance even in the event of a premature shutdown at the
plant. The bill also enhances the potential sale price of Seabrook
by allowing the buyer to retain any decommissioning funds in excess
of those contributed by customers of the present utility owners and
by reducing the standard set by the NHNDFC for non-radiological
decommissioning.
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 the
Company to pay a fee based on its share of the net generation from
the Seabrook 1 nuclear generating unit. Prior to 1998, the Company
recovered this fee through its fuel clause. Under 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 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 filed claims for money damages in the U.S.
Court of Federal Claims for the costs associated with the DOE's
failure to begin to take fuel in 1998. As an interim measure until
the DOE meets its contractual obligations to dispose of their spent
fuel, those companies are proceeding with construction of
independent spent fuel storage installations on the plant sites.
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. There is no assurance that decommissioning
costs actually incurred by Seabrook 1 or the Yankees 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, the funds collected for decommissioning to that
point may be insufficient. Under 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
and Seabrook 1 would subject the Company to a $28.6 million maximum
assessment per incident. The Company's payment of any such
assessment would be limited to a maximum of $3.2 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.
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 $3.0 million with respect to the current policy
period.
3. Plant Expenditures
The Company's utility plant expenditures are estimated to be
approximately $45 million for fiscal year 2002. At March 31, 2001,
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. At March 31, 2001, the Company had
guaranteed approximately $18 million of project debt with terms
through 2015. The Company's rights and obligations under its
support agreements were transferred to the purchaser of its
nonnuclear generation. Also, as a result of the National Grid USA
merger with EUA, at March 31, 2001, the Company had guaranteed an
additional amount of approximately $4 million originally guaranteed
by Montaup. The Company remains an obligor under the support
agreements until 2020. Costs associated with these support
agreements are recoverable through the CTCs.
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, intends 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 March 2001, the charges
assessed Norwood amount to approximately $29 million, all of which
remain unpaid. The Company filed a collection action in
Massachusetts Superior Court (Superior Court). The Superior Court
deferred action until the various appeals described below were
decided. On March 14, 2001, the Superior Court ordered Norwood to
pay the Company $27 million including interest. Norwood was ordered
to pay the judgement in monthly installments of $600,000. Norwood
has also entered a consent order to establish a segregated account
for the benefit of the Company in the amount of $14 million and to
make regular additions to the account.
Separately, Norwood filed suit in Federal District Court
(District Court) in April 1997 alleging that the divestiture of the
Company's nonnuclear generating business (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 consolidated appeals Norwood made from FERC's orders
approving the Company's divestiture, the wholesale rate settlement
between the Company and its distribution affiliates, and the CTC
tariff amendment. In February 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
alleged generation market power. In February and March 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. In May 2000, Norwood petitioned the US
Supreme Court for review of the First Circuit decisions. In October
2000, the US Supreme Court refused Norwood's petitions to review
the First Circuit decisions affirming (a) the FERC's approval of
the CTC, the divestiture, and the settlement agreements regarding
termination of the Company's power sales agreements with its
affiliates, and (b) the District Court's dismissal of Norwood's
antitrust and breach of contract claims.
In the District Court action, in April 2000, the Company
renewed its motion to dismiss Norwood's remaining claim. Norwood
amended its complaint to reassert a request for rescission of the
divestiture, which it had earlier dropped. A hearing took place
before the District Court in July 2000.
Norwood has also appealed a June 1999 FERC decision that
rejected Norwood's challenge to the calculation of the CTC based on
the terms of the 1983 power contract, which Norwood contended ended
in October 1998, not October 2008. In June 2000, the First Circuit
rejected Norwood's appeal. Norwood filed a petition for certiorari
to the US Supreme Court for review of the First Circuit's decision.
On April 24, 2001, the US Supreme Court denied Norwood's petition.
7. Settlements
NSTAR Settlement
On March 30, 2001, the Company reached a settlement in
principal with NSTAR, formerly known as Boston Edison Company
(BECO), resolving issues surrounding a $3 million refund to Montaup
ordered by the FERC in January 2000. The order stemmed from an
earlier proceeding initiated by the FERC where it required BECO to
reduce its ROE under a life of unit purchased power agreement (PPA)
with Montaup for 11 percent of the output from the Pilgrim plant.
BECO subsequently divested its ownership in the Pilgrim plant in
July 1999, and Montaup terminated its life of unit PPA in favor of
a PPA that expires in 2004. BECO appealed the FERC Order to the
First Circuit which, in turn, has remanded the case to the FERC for
further proceedings. Proceeds from the refund have already been
credited to customers through Montaup's CTC reconciliation
mechanism. Under the terms of the settlement, the Company will
return to BECO 75 percent of the refund amount, plus interest
through March 31, 2001. The settlement is conditioned on consent
from the parties to Montaup's restructuring settlement to recover
this amount from customers through the CTC.
Wyman 4 Settlement
On April 23, 2001, Central Maine Power (CMP) and the Wyman 4
minority owners reached a settlement under which CMP will pay a
total of $12 million to the minority owners. The Company's pro rata
share of the settlement proceeds will be $2.9 million. The proceeds
of the settlement, less legal costs, will be returned to customers
via the CTC. The settlement is the result of arbitration brought by
the Company and others against CMP regarding the sharing of CMP's
proceeds from its sale of the Wyman 4 unit and site in Yarmouth,
Maine in 1999. The Company is a 9 percent minority owner of the
Wyman 4 generating unit.
Note E - Employee Benefits
1. Pension Plan:
The Company participates with other subsidiaries of National
Grid USA in a noncontributory, defined benefit plan covering
substantially all employees of the Company. The plan provides
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 the year ended March 31, 2001, the three
months ended March 31, 2000, and the years ended December 31, 1999
and 1998 included the following components:
Year Three
Ended Months Ended Year Ended
March 31, March 31, December
31,
- ----------------------------------------------------------------------------------------
- -
(thousands of dollars) 2001 2000 1999 1998
- ----------------------------------------------------------------------------------------
- -
Service cost - benefits earned during the period $ 482 $ 118 $ 527 $ 2,430
Plus (less):
Interest cost on projected benefit obligation 8,381 1,760 7,044 7,435
Return on plan assets at expected long-term rate (12,440) (2,200) (8,090) (8,675)
Amortization of transition obligation - (33) (170) (184)
Amortization of prior service cost - 24 115 161
Amortization of net (gain)/loss - (100) 36 159
Curtailment (gain)/loss - - - (5,680)
- ----------------------------------------------------------------------------------------
- -
Benefit cost/(income) $(3,577) $ (431) $ (538) $(4,354)
- ----------------------------------------------------------------------------------------
- -
Special termination benefits not included above $ - $ - $ - $10,911
- ----------------------------------------------------------------------------------------
- ---
The funded status of the plan cannot be presented separately
for the Company as the Company participates in the plan with other
National Grid USA subsidiaries.
The following provides a reconciliation of benefit
obligations and plan assets for the National Grid USA companies'
plan:
At At
March 31, December 31,
- ----------------------------------------------------------------------------
(millions of dollars) 2001 2000 1999
- ----------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ 800 $ 789 $ 843
Service cost 12 2 11
Interest cost 72 15 56
Actuarial (gain)/loss 47 10 (55)
Benefits paid (90) (16) (66)
Acquisitions 188 - -
Special termination benefits 6 - -
Plan amendments 20 - -
- ----------------------------------------------------------------------------
Benefit obligation end of period 1,055 800 789
- ----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at
beginning of period 991 947 837
Actual return on plan assets during year (59) 59 117
Company contributions 8 1 59
Benefits paid from plan assets (90) (16) (66)
Acquisitions 232 - -
- ---------------------------------------------------------------------------
Fair value of plan assets end of period 1,082 991 947
- ---------------------------------------------------------------------------
Funded status 27 191 158
Unrecognized actuarial (gain)/loss 206 - (206)
Unrecognized prior service cost 20 - 5
Unrecognized transition (asset)/liability - - (3)
- ---------------------------------------------------------------------------
Net amount recognized $ 253 $ 191 $ (46)
- ---------------------------------------------------------------------------
Amounts recognized in the statement of
financial position consist of:
Prepaid benefit cost $ 338 $ 262 $ 14
Accrued benefit liability (90) (71) (66)
Intangible asset - - 2
Accumulated other comprehensive income 5 - 4
- ---------------------------------------------------------------------------
Net amount recognized $ 253 $ 191 $ (46)
- ---------------------------------------------------------------------------
March 31, December 31,
2001 2000 1999 1998
- -------------------------------------------------------------------------------
Assumptions used to determine pension cost:
Discount rate 7.50% 7.75% 7.75% 6.75%
Average rate of increase in
future compensation level 4.61% 5.10% 5.10% 4.13%
Expected long-term rate of
return on assets 8.75% 8.50% 8.50% 8.50%
Plan assets are composed primarily of equity and fixed income
securities. Fair value adjustments of approximately $33 million
are reflected in the Company's financial statements at March 31,
2000.
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 the year ended March
31, 2001, the three months ended March 31, 2000, and the years
ended December 31, 1999 and 1998 included the following
components:
Three
Year Ended Months Ended Year Ended
March 31, March 31, December 31,
- --------------------------------------------------------------------------------------
- --
(thousands of dollars) 2001 2000 1999 1998
- --------------------------------------------------------------------------------------
- --
Service cost - benefits earned during the period $ 210 $ 47 $ 193 $ 1,109
Plus (less):
Interest cost on projected benefit obligation 3,337 786 2,816 3,244
Return on plan assets at expected long-term rate (3,537) (803) (2,896) (2,656)
Amortization of transition obligation - 19 85 1,732
Amortization of prior service cost - - - 5
Amortization of net (gain)/loss - (285) (1,252) (1,138)
Curtailment (gain)/loss - - - 27,149
- --------------------------------------------------------------------------------------
- --
Benefit cost/(income) $ 10 $(236) $(1,054) $29,445
- --------------------------------------------------------------------------------------
- --
Special termination benefits not included above $ - $ - $ - $ 439
- --------------------------------------------------------------------------------------
- --
The following provides a reconciliation of benefit obligations and
plan assets including fair value adjustments recorded in March 2000 of
approximately $28 million:
At At
March 31, December 31,
- -------------------------------------------------------------------------------
(millions of dollars) 2001 2000 1999
- -------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $38 $42 $ 41
Service cost - - -
Interest cost 3 1 3
Actuarial (gain)/loss 2 (4) -
Benefits paid (4) (1) (2)
Acquisitions 8 - -
- -------------------------------------------------------------------------------
Benefit obligation end of period 47 38 42
- -------------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period 40 39 36
Actual return on plan assets during year (1) 2 4
Company contributions 2 - 1
Benefits paid from plan assets (4) (1) (2)
Acquisitions 4 - -
- -------------------------------------------------------------------------------
Fair value of plan assets end of period 41 40 39
- -----------------------------------------------------------------------------
Funded status (6) 2 (3)
Unrecognized actuarial (gain)/loss 7 - (25)
Unrecognized prior service cost - - -
Unrecognized transition (asset)/liability - - 1
- -------------------------------------------------------------------------------
Net amount recognized $ 1 $ 2 $(27)
- -------------------------------------------------------------------------------
March 31, December 31,
2001 2000 1999 1998
- ----------------------------------------------------------------------------
Assumptions used to determine
postretirement benefit cost:
Discount rate 7.50% 7.75% 7.75% 6.75%
Expected long-term rate of
return on assets 8.48% 8.40% 8.42% 8.35%
Health care cost rates:
1998 to 1999 5.25%
2000 8.25% 8.25% 8.25% 5.25%
2001 8.00% 6.75% 6.75% 5.25%
2002 6.50% 5.25% 5.25% 5.25%
2003 and beyond 5.00% 5.25% 5.25% 5.25%
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 March 31, 2001 by
approximately $5 million or decrease the APBO by approximately $5
million, and change the net periodic cost for fiscal year 2001 by
approximately $400,000.
The Company generally funds the annual tax-deductible
contributions.
In connection with the mergers referred to in Note B, the Company
adjusted its pension and PBOP accounts in the amount of approximately
$64 million, with an offsetting net credit to a regulatory liability
account. This adjustment eliminated any unrecognized net gain or loss,
unrecognized prior service cost, or unrecognized transition obligation
of the Company. The regulatory liability is being amortized over the
service period to pension and postretirement health care costs.
Note F - Income Taxes
The Company and other subsidiaries intend to elect to participate
with National Grid General Partnership, National Grid USA's parent
company that is wholly owned by National Grid, 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
1996.
Total income taxes in the statements of income are as follows:
Three
Year Ended Months
Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- --------------------------------------------------------------------------------------
Income taxes charged to operations $44,946 $9,641 $13,100 $37,633 $ 73,594
Income taxes charged (credited) to
"Other income" (52) (4) - 1,985 (19,582)
------- ------ ------- ------- --------
Total income taxes $44,894 $9,637 $13,100 $39,618 $ 54,012
======= ====== ======= ======= ========
Total income taxes, as shown above, consist of the following
components:
Three
Year Ended Months Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- --------------------------------------------------------------------------------------
Current income taxes $ 56,374 $12,545 $ 7,374 $ 25,507 $ 280,734
Deferred income taxes (1,111) (581) 10,732 25,921 (204,129)
Investment tax credits, net (10,369) (2,327) (5,006) (11,810) (22,593)
-------- ------- ------- -------- ---------
Total income taxes $ 44,894 $ 9,637 $13,100 $ 39,618 $ 54,012
======== ======= ======= ======== =========
Since 1998, the Company has been amortizing previously
deferred investment tax credits (ITC) related to generation
investments over the CTC recovery period. Unamortized ITC related
to generating units divested in 1998 and 2001 were credited to
other income pursuant to federal tax law.
Previously recognized ITC related to transmission facilities
are amortized over their estimated productive lives.
Total income taxes, as shown above, consist of federal and state
components as follows:
Three
Year Ended Months Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- --------------------------------------------------------------------------
Federal income taxes $38,350 $ 8,035 $10,975 $33,746 $41,255
State income taxes 6,544 1,602 2,125 5,872 12,757
------- ------- ------- ------- -------
Total income taxes $44,894 $ 9,637 $13,100 $39,618 $54,012
======= ======= ======= ======= =======
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:
Three
Year Ended Months Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- ----------------------------------------------------------------------------
Computed tax at statutory rate $36,118 $ 8,435 $11,706 $38,721 $ 61,917
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (7,762) (1,513) (3,254) (7,677) (15,157)
State income taxes, net of
federal income tax benefit 4,254 1,042 1,381 3,817 8,292
Rate recovery of deficiency
in deferred tax reserves 4,339 1,617 3,508 8,207 -
Amortization of goodwill 6,267 - - - -
Prior year tax adjustment 773 - - (2,028) (188)
Millstone 3 sale 1,787 - - - -
All other differences (882) 56 (241) (1,422) (852)
------- ------- ------- ------- --------
Total income taxes $44,894 $ 9,637 $13,100 $39,618 $ 54,012
======= ======= ======= ======= ========
The following table identifies the major components of total deferred
income taxes:
At At
March 31, December 31,
(In millions) 2001 2000 1999
- ----------------------------------------------------------------------------
Deferred tax asset:
Plant related $ 67 $ 67 $ 67
Investment tax credits 4 6 8
All other 30 3 2
----- ----- -----
101 76 77
----- ----- -----
Deferred tax liability:
Plant related (211) (159) (157)
All other, principally regulatory
assets (162) (93) (100)
----- ----- -----
(373) (252) (257)
----- ----- -----
Net deferred tax liability $(272) $(176) $(180)
===== ===== =====
Note G - Short-term Borrowings and Other Accrued Expenses
At March 31, 2001, the Company had no short-term debt outstanding.
The Company has regulatory approval to issue up to $375 million of short-
term debt. In October 2000, the Company received the necessary regulatory
approvals to allow approximately $39 million of variable rate debt to
remain outstanding through 2015. This results in classifying that debt as
long-term rather than short-term. Proceeds from the increase in short-
term debt were utilized to pay Montaup's debt of approximately $91
million and purchased power contract obligations of approximately $60
million. 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 that 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 March 31, 2001, the Company had lines of credit and standby bond
purchase facilities with banks totaling $456 million which are available
to provide liquidity support for $410 million of the Company's long-term
bonds in tax-exempt commercial paper mode, and for other corporate
purposes. There were no borrowings under these lines of credit at March
31, 2001. Fees are paid on the lines and facilities in lieu of
compensating balances.
The components of other accrued expenses are as follows:
At At
March 31, December 31,
(In thousands) 2001 2000 1999
- -----------------------------------------------------------------------------
Accrued wages and benefits $1,191 $ 1,215 $ 1,063
Rate adjustment mechanisms 5,555 9,110 14,550
Other 875 554 80
------ ------- -------
$7,621 $10,879 $15,693
------ ------- -------
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at March 31, 2001, March 31,
2000, and December 31, 1999 is as follows (in thousands of dollars except
for share data):
Shares Dividends Call
Outstanding Amount Declared Price
- ------------------------------------------------------------------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
$100 par value
6.00% Series 14,361 15,672 15,672 $1,436 $1,567 $1,567 $91 $24 $94 (a)
(a) Noncallable.
The annual dividend requirement for cumulative preferred stock was
approximately $86,000 for 2001 and 2000, and $94,000 for 1999. In 2000,
the Company repurchased or redeemed preferred stock with a par value of
approximately $131,000.
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:
(In thousands) At At At
March 31, March 31, December 31,
Series Rate % Maturity 2001 2000 1999
- ---------------------------------------------------------------------------------------
Pollution Control Revenue Bonds:
CDA (a) variable October 15, 2015 $ 38,500 $ - $ -
MIFA 1 (a) variable March 1, 2018 79,250 79,250 79,250
BFA 1 (b) variable November 1, 2020 135,850 135,850 135,850
BFA 2 (b) variable November 1, 2020 50,600 50,600 50,600
MIFA 2 (a) variable October 1, 2022 106,150 106,150 106,150
Unamortized discounts (71) (77) (79)
-------- -------- ------
Total long-term debt $410,279 $371,773 $371,771
======== ======== ========
(a) CDA = Connecticut Development Authority
(b) MIFA = Massachusetts Industrial Finance Authority
(c) BFA = Business Finance Authority of the State of New Hampshire
At March 31, 2001, interest rates on the Company's variable rate
long-term bonds ranged from 3.0 percent to 4.2 percent.
At March 31, 2001, the Company's long-term debt had a carrying value
and fair value of approximately $410,000,000. The fair value of debt that
reprices frequently at market rates approximates carrying value.
Note J - Common Stock
The purchase accounting method was used in the merger of National
Grid and NEES, and in the acquisition of EUA by National Grid USA. This
method resulted in a retained earnings adjustment of approximately $16
million for the National Grid/National Grid USA merger in order to
reflect post-merger earnings. A retained earnings adjustment in the
amount of approximately $0.5 million resulted from the merger of Montaup
into the Company. Both mergers resulted in adjustments to other paid-in
capital to reflect the pushdown of goodwill.
The Company repurchased shares of its common stock in 1999 as
follows (dollar amounts expressed in thousands):
Reductions to:
---------------------------------------
Common stock
Number of Cash and related Other paid- Retained
Year Shares Paid premium in capital earnings
- ----------------------------------------------------------------------------
1999 130,000 $18,056 $4,348 $6,623 $7,085
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 the year
ended March 31, 2001, the three months ended March 31, 2000 or March 31,
1999, and the years ended December 31, 1999 or 1998. Taxes, other than
income taxes, charged to operating expenses are set forth by class as
follows:
Year Ended Three Months Ended Year Ended
March 31, March 31, December 31,
(In thousands) 2001 2000 1999 1999 1998
(unaudited)
- --------------------------------------------------------------------------
Municipal property taxes $19,334 $4,718 $4,618 $17,640 $42,080
Federal and state payroll
and other taxes 3,009 843 1,016 2,642 6,412
------- ------ ------ ------- -------
$22,343 $5,561 $5,634 $20,282 $48,492
======= ====== ====== ======= =======
Transactions between the Company and other affiliated companies for
sales of electric energy and other sales amounted to approximately
$385,982,000, $90,934,000, $120,700,000, $338,295,000, and $1,077,752,000
for the year ended March 31, 2001, the three months ended March 31, 2000,
the three months ended March 31, 1999, and the years ended December 31,
1999 and 1998, respectively.
National Grid USA Service Company, Inc., 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 $44,315,000, $11,514,000, $10,088,000,
$43,584,000, and $74,203,000, including capitalized construction costs of
$19,117,000, $4,597,000, $3,415,000, $17,229,000, and $21,281,000, in the
year ended March 31, 2001, the three months ended March 31, 2000, the
three months ended March 31, 1999, and the years ended December 31, 1999
and 1998, respectively.
Selected Financial Information
Year Three
Ended Months Ended
March 31, March 31, Year Ended December 31,
2001 2000 1999 1999 1998 1997 1996
(In millions) (unaudited)
- -------------------------------------------------------------------------------------
Operating revenue $ 656 $ 135 $ 167 $ 596 $1,218 $1,678 $1,600
Net income $ 58 $ 14 $ 20 $ 71 $ 123 $ 145 $ 152
Total assets $2,889 $2,630 $2,282 $2,303 $2,415 $2,763 $2,648
Capitalization:
Common equity $ 865 $ 657 $ 523 $ 332 $ 521 $ 913 $ 906
Cumulative preferred stock 1 1 1 2 1 40 40
Long-term debt 410 372 372 372 372 648 733
------ ------ ------ ------ ------ ------ ------
Total capitalization $1,276 $1,030 $ 896 $ 706 $ 894 $1,601 $1,679
Preferred dividends declared $ - $ - $ - $ - $ 1 $ 2 $ 3
Common dividends declared $ - $ 24 $ - $ 241 $ 131 $ 135 $ 134
------ ------ ------ ------ ------ ------ ------
Selected Quarterly Financial Information (Unaudited)
Quarter Quarter Quarter Quarter Quarter
Ended Ended Ended Ended Ended
March 31, June 30, Sept. 30, Dec. 31, March 31,
(In thousands) 2000 2000 2000 2000 2001
- ------------------------------------------------------------------------------------
Operating revenue $134,564 $156,190 $175,390 $156,396 $168,296
Operating income $ 16,685 $ 15,908 $ 25,232 $ 22,040 $ 24,535
Net income $ 14,462 $ 14,223 $ 16,460 $ 14,780 $ 12,837
Quarter Quarter Quarter Quarter
Ended Ended Ended Ended
March 31, June 30, Sept. 30, Dec. 31,
1999 1999 1999 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
Per share data is not relevant because the Company's common
stock is wholly owned by National Grid USA, a wholly owned
subsidiary of National Grid Group plc.
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of April 1, 2001)
L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Executive Vice President of
National Grid USA
Lawrence J. Reilly
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
Robert G. Powderly
Vice President of National Grid USA
Terry L. Schwennesen
Vice President of the Company
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 April 1, 2001)
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Executive Vice President of
National Grid USA
Lawrence J. Reilly
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
Marc F. Mahoney
Vice President of the Company and of certain affiliates
John F. Malley
Vice President of the Company
James S. Robinson
Vice President of the Company
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
Terry L. Schwennesen
Vice President of the Company
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, President of
certain affiliates, Vice President of an affiliate, and Vice
President, Chief Financial Officer, and Treasurer of National
Grid USA
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates and
Secretary or Clerk of certain affiliates
Geraldine M. Zipser
Assistant Clerk of the Company and of certain affiliates,
Secretary or Clerk of certain affiliates, and Assistant Secretary
of an affiliate
Patricia C. Easterly
Assistant Treasurer of the Company and Treasurer of an affiliate
Nancy B. Kellogg
Assistant Treasurer of the Company and of certain affiliates
Kwong O. Nuey
Controller of the Company and of certain affiliates and Vice
President of an affiliate
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, Fleet National Bank, 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.
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, Kirk L. Ramsauer, and
Geraldine M. Zipser, individually, as attorney-in-fact to execute on
behalf of the undersigned the Company?s transition report on Form 10-K
for the period ended March 31, 2001 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 25th day of May, 2001.
s/L. Joseph Callan s/Peter G. Flynn
_________________________ _________________________
L. Joseph Callan Peter G. Flynn
s/Michael E. Jesanis s/Robert G. Powderly
_________________________ _________________________
Michael E. Jesanis Robert G. Powderly
s/Lawrence J. Reilly s/Terry L. Schwennesen
_________________________ _________________________
Lawrence J. Reilly Terry L. Schwennesen
s/Richard P. Sergel s/Philip R. Sharp
_________________________ _________________________
Richard P. Sergel Philip R. Sharp
NEP John G. Cochrane
Treasurer
June 28, 2001
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: File No. 1-6564
Ladies and Gentlemen:
New England Power Company is a participant in the Electronic Data
Gathering and Retrieval Program.
Submitted herewith in electronic format for filing with the
Commission is a Transition Report for the transition period ended
March 31, 2001 on Form 10-K for New England Power Company which is
required to file a report pursuant to Section 13 of the Securities
Exchange Act of 1934.
This annual report is filed with you pursuant to Rule 13(a)-1
of the Securities and Exchange Commission under the Securities
Exchange Act of 1934.
Very truly yours,
s/John G. Cochrane
- -iii-
- -41-
- -67-
Issued by: David T. Doot, Secretary Effective: June 28, 2000
Issued on: July 28, 2000 nep2001
Filed to comply with order of the Federal Energy Regulatory Commission,
Docket No. EL00-62-000, issued June 28, 2000, 91 FERC 61,311 (2000).