EX-10.23.5 14 y58564i.txt 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. -2- 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; -3- 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 -4- 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 -5- 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 Chester 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. -6-