Exhibit 10.23.5
SEVENTY-THIRD AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(SCHEDULE 2 CHANGES)
THIS SEVENTY-THIRD AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT,
dated as of May 9, 2001 ("Seventy-Third Agreement"), amends the New England
Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was
amended and restated by the Thirty-Third Agreement Amending New England Power
Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in
the form of the Restated New England Power Pool Agreement ("Restated NEPOOL
Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the
Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission
Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL
Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have
subsequently been amended numerous times, with such amendments most recently
consolidated, respectively, in FERC Electric Third Revised Rate Schedule No. 5,
submitted in Docket No. ER00-2894-000, and FERC Electric Tariff, Fourth Revised
Volume No. 1, submitted in Docket Nos. EL00-62-000, et al.; and
WHEREAS, the Participants desire to amend the NEPOOL Tariff as
heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Seventy-Third Agreement by the
NEPOOL Participants Committee in accordance with the procedures set forth in the
NEPOOL Agreement, the Participants agree as follows:
SECTION 1
AMENDMENTS TO ANCILLARY SERVICE SCHEDULE 2
1.1 NEPOOL Tariff Ancillary Service Schedule 2 is amended to read as set
forth in Attachment A hereto.
SECTION 2
AMENDMENT OF THE ANCILLARY SERVICE SCHEDULE 2 IMPLEMENTATION RULE
2.1 The Ancillary Service Schedule 2 Implementation Rule, which is a
supplement to the NEPOOL Tariff, is deleted in its entirety.
SECTION 3
MISCELLANEOUS
3.1 This Seventy-Third Agreement shall become effective on August 1, 2001
or on such other date as the Commission shall provide that the
amendments reflected herein shall become effective.
3.2 Terms used in this Seventy-Third Agreement that are not defined herein
shall have the meanings ascribed to them in the NEPOOL Agreement.
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ATTACHMENT A
SEVENTY-THIRD AGREEMENT
SCHEDULE 2
REACTIVE SUPPLY AND VOLTAGE CONTROL FROM
GENERATION SOURCES SERVICE
In order to maintain transmission voltages on the NEPOOL Transmission
System within acceptable limits, generation facilities are operated to produce
(or absorb) reactive power. Thus, Reactive Supply and Voltage Control from
Generation Sources Service must be provided for each transaction on the NEPOOL
Transmission System. The amount of Reactive Supply and Voltage Control from
Generation Sources Service that must be supplied with respect to a Transmission
Customer's transaction will be determined based on the reactive power support
necessary to maintain transmission voltages within limits that are generally
accepted in the region and consistently adhered to by the Participants.
Additional information regarding the processes used to collect data and
calculate amounts due or payable under this Schedule 2 can be found in the
Ancillary Service Schedule 2 Business Procedure posted on the ISO website.
I. DETERMINING THE AMOUNT TO BE PAID FOR SERVICE UNDER THIS SCHEDULE
Reactive Supply and Voltage Control from Generation Sources Service is
to be provided through the System Operator and the Transmission Customer must
purchase through the System Operator service for voltage support capability
provided by Qualified Generators and service when the System Operator (or
applicable satellite dispatching center) determines, in the exercise of its
discretion, that it is necessary to direct a generating unit to alter its
operations in an hour in order to provide such service. The charge for such
service shall be paid by each Participant or Non-Participant which receives
either Regional Network Service or Internal Point-to-Point Service or Through or
Out Service and shall be determined in accordance with the following formula:
CH = (CC + LOC + SCL + PC) (HL1 + RC1) divided by
(HL + RC)
in which
CH = the amount to be paid by the Participant or
Non-Participant for the hour;
CC = the capacity costs for the hour shall be the
VAR Revenue Requirement determined as set
forth herein divided by the number of hours
in the month;
LOC = the lost opportunity costs for the hour to be
paid to Participants who provide VAR support;
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ATTACHMENT A
SEVENTY-THIRD AGREEMENT
PC = the portion of the amount paid to
Participants for the hour for Energy produced
by a generating unit that is considered under
this Schedule 2 to be paid for VAR support;
SCL = the cost of energy used in the hour by
generating facilities, synchronous condensers
or static controlled VAR regulators in order
to provide VAR support to the transmission
system;
HL1 = the Network Load of the Participant or
Non-Participant for the hour;
HL = the aggregate of the Network Loads of all
Participants and Non-Participants for the
hour;
RC1 = the Reserved Capacity for Internal
Point-to-Point Service and/or Through or Out
Service of the Participant or Non-Participant
for the hour; and
RC = the aggregate Reserved Capacity for Internal
Point-to-Point Service and/or Through or Out
Service of all Participants and
Non-Participants for the hour.
II. DETERMINING A GENERATOR'S COMPENSATION FOR PROVIDING SERVICE UNDER THIS
SCHEDULE
The compensation to be paid to generators providing Schedule 2 service
shall be based on the four components set forth below.
1. CAPACITY COST (CC)
1.1. A Qualified Generator shall be eligible to receive compensation for
the capability to deliver VARs to the system (a "VAR Payment") under
the Capacity Cost component of Schedule 2 as provided herein. A
Qualified Generator is any generator that is in the market system and
provides measurable voltage support, as determined from time to time
by the Reliability Committee or such other Committee as the
Participants Committee may designate, to the control area.
1.2. The VAR Payment is not intended to compensate a Qualified Generator
for losses associated with station use and energizing the generator
leads and generator step-up transformer.
1.3. The "VAR Rate" will be established each year as of January 1 on a
prospective basis for that calendar year and shall be the Base VAR
Rate * Min (1, (1.2*Forecast Peak Adjusted Reference Load for the
year/SUM (Qualified Generator's Seasonal Claimed
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ATTACHMENT A
SEVENTY-THIRD AGREEMENT
Capability))).
1.4. The "Base VAR Rate" shall be $0.90/kVAR-yr in 2001; $0.95/kVAR-yr in
2002; $1.00/kVAR-yr in 2003 and $1.05/kVAR-yr in 2004 and thereafter.
1.5. The "Forecast Peak Adjustment Reference Load" shall be the value
published in the then-most recently published CELT report at the time
the VAR Rate is established for a year.
1.6. A "Qualified Generator's Seasonal Claimed Capability" shall be the
Seasonal Claimed Capability of each Qualified Generator applicable for
the season in which the NEPOOL Forecast Peak Adjusted Load is forecast
to occur.
1.7. The "VAR Revenue Requirement" shall be the SUM (Qualified Generator's
VAR Payment).
1.8. A Qualified Generator's VAR Payment shall equal the (VAR
Rate*Qualified VARs).
1.8.1. The VAR Rate is determined pursuant to paragraph 1.3 above.
1.8.2. Qualified Generators will be paid their VAR Rate under this
Section for each month of a calendar year starting with the
month in which this Section becomes effective.
1.9. "Qualified VARs" shall be:
1.9.1. Qualified VARs of an untested unit shall be equal to the
Lagging VAR capability at Seasonal Claimed Capability for the
season of forecasted peak as indicated on the Qualified
Generator's NX-12D form that is then in effect adjusted for
losses to station service and energizing the generator leads
and generator step-up transformer.
1.9.2. As soon as practicable, but in no event longer than two years
from the effective date of this Section, the Qualified VARs of
a Qualified Generator shall be determined at its point of
delivery to the system, in accordance with the then-applicable
Operating Procedures. At least every 5 years after that test,
a test of the VAR capability of a Qualified Generator across
its full operating range shall be conducted.
2. LOST OPPORTUNITY COST (LOC)
2.1. The Lost Opportunity Cost for hydro, pumped storage and thermal
generating units that are dispatched down by ISO-NE, a NEPOOL
satellite or a NEPOOL Participant dispatch center for the purpose of
providing reactive supply and voltage control will be calculated in a
manner that is consistent with the rules established in Market Rule
and Procedure No. 6-A - Compensation For Resources Postured For OP-4
Conditions (MRP 6-A). The
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ATTACHMENT A
SEVENTY-THIRD AGREEMENT
LOC calculation shall consist of the "Revenue Shortfall Adjustment" and
the "Emergency Purchase Adjustment," as those terms are defined in the
Schedule 2 Business Procedure. The Revenue Shortfall Adjustment and the
Emergency Purchase Adjustment are calculated on an hourly basis and
then totaled for the entire day in which the posturing occurred. The
value of the Revenue Shortfall Adjustment and the Emergency Purchase
Adjustment are summed for each Participant to create the LOC adjustment
total.
3. COST OF ENERGY CONSUMED (SCL)
3.1. MOTORING HYDRO OR PUMPED STORAGE GENERATING UNITS. The SCL associated
with hydro and pumped storage generating units that are motoring at
the request of ISO-NE, a NEPOOL satellite or a NEPOOL Participant
dispatch center for the purpose of providing reactive supply and
voltage control will equal the cost of energy to motor and will be
calculated in each hour as follows: SCL = (MWhUnit * (ECP or Actual
energy cost), where the MwhUnit are calculated pursuant to the
Schedule 2 Business Procedure. Actual energy cost applies only if
motoring energy is purchased through a bilateral contract.
Documentation of actual energy cost is to be provided to ISO-NE. The
UpliftSched2 component of the SCL no longer applies since the option
of reporting the energy required by a hydro or pumped storage
generating unit that is motoring for the purpose of providing reactive
supply and voltage control under a distinct and unique Load Asset in
the Market System is now available.
3.2. SYNCHRONOUS CONDENSERS AND STATIC CONTROLLED VAR REGULATORS (SC/SCV).
The SCL will be set to zero ($0), and the cost of energy to supply
reactive supply and voltage control from the ▇▇▇▇▇▇▇ SCV will be
treated as losses on the NEPOOL bulk transmission system. This
treatment will be revisited by the Markets Committee and Tariff
Committee on an as needed basis (e.g., upon the addition of a new SC
or SCV within the NEPOOL Control Area).
4. COST OF ENERGY PRODUCED (PC)
4.1. THERMAL GENERATING UNITS. The PC associated with thermal generating
units brought on-line by the ISO, a NEPOOL satellite or a NEPOOL
Participant dispatch center for the purpose of providing reactive
supply and voltage control shall equal the portion of the total uplift
to be paid that resource for a day that is attributed to the hour(s)
during which the resource is run to provide this service in accordance
with applicable Market Rules.
4.2. HYDRO AND PUMPED STORAGE GENERATING UNITS. The PC associated with
hydro or pumped storage generating units that are producing real power
and that have also been brought on-line by the ISO, a NEPOOL satellite
or a NEPOOL Participant dispatch center to provide reactive supply and
voltage control shall equal the portion of the total uplift to be paid
that resource for a day that is attributed to the hour(s) during which
the resource is run to provide this service in accordance with
applicable Market Rules.
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