NYISO Tariffs --> Open Access Transmission Tariff (OATT) --> 6 OATT Rate Schedules --> 6.1 OATT Schedule 1 - Scheduling, System Control And Dispatc
This service is required to schedule the purchase, sale and movement of power through, out of, within, or into the NYCA. This service can be provided only by the ISO. The Transmission Customer must purchase this service from the ISO. The ISO Services Charge for Scheduling, System Control and Dispatch Service and any rebillings associated therewith are set forth below.
The ISO shall charge, and Transmission Customers taking service under the ISO OATT, only, including Special Case Resources, Emergency Demand Response Program participants, Transmission Customers that have their virtual bids accepted and thereby engage in Virtual Transactions, and Transmission Customers that purchase Transmission Congestion Contracts, excluding Transmission Congestion Contracts that are created prior to [the date that the Commission issues an Order approving these revisions], shall pay an “ISO Services Charge” as calculated in Section 6.1.2.2 of this Rate Schedule on all Transmission Services provided pursuant to Parts 3, 4 and 5 to this Tariff, provided that Transmission Customers who are retail access customers who are being served by an LSE shall not pay this charge to the ISO; the LSE shall pay these charges. Transmission Customers taking service under both the ISO OATT and the ISO Services Tariff shall pay the applicable ISO Services Charge as calculated (i) in Sections 15.1.3.1 through 15.1.3.3 of Rate Schedule 1 of the ISO Services Tariff, and (ii) in Sections 6.1.2.2.3 and 6.1.2.2.4 of this Rate Schedule.
The ISO shall charge each Transmission Customer based on the product of: (i) the ISO Services Charge rate for Scheduling, System Control and Dispatch Service; and (ii) the Transmission Customer’s applicable injection billing units and/or withdrawal billing units for the month as described in Section 6.1.2.1.
For the ISO Services Charge calculated under Section 6.1.2.2.1 of this Rate Schedule, the Transmission Customer’s injection billing units shall be based on Actual Energy Injections (for all internal injections) or Scheduled Energy Injections (for all Import Energy injections) in the New York Control Area, including injections for wheelthroughs. The Transmission Customer’s withdrawal billing units shall be based on its Actual Energy Withdrawals for all Transmission Service to supply Load in the NYCA, and hourly Energy schedules for all Wheels Through and Exports. For the ISO Services Charge calculated pursuant to Sections 6.1.2.2.2, 6.1.2.2.3, and 6.1.2.2.4 of this Rate Schedule, the Transmission Customer’s billing units shall be based on the Actual Energy Withdrawals for all Transmission Service to supply Load in the NYCA, and hourly Energy schedules for all Wheels Through and Exports. To the extent Schedule 1 charges are associated with meeting the reliability needs of a local system, the billing units for such charges will be based on the Actual Energy Withdrawals in the sub-zone(s) where the Resource needed to meet the reliability need is located. To the extent Schedule 1 charges are associated with payments made for supplemental payments and Demand Reduction Incentive payments to Demand Reduction Providers, the billing units of such charges shall be based on Actual Energy Withdrawals to supply Load in the NYCA according to the methodology described in Attachment R. To the extent that the sum of all Bilateral Schedules, excluding schedules of Bilateral Transactions with Trading Hubs as their POWs, and all Day-Ahead Market purchases to service Load in the Day-Ahead schedule is less than the ISO’s Day-Ahead forecast of Load and the ISO commits Resources in addition to the reserves it normally maintains to enable it to respond to contingencies to meet the ISO’s Day-Ahead forecast of Load, charges associated with the costs of Bid Production Cost Guarantees for the additional Resources committed Day-Ahead to meet the ISO’s Day-Ahead forecast of Load shall be allocated to Transmission Customers who are not bidding as Suppliers according to the Methodology described in Attachment T.
For Transmission Customers participating in the ISO’s Special Case Resource program or in its Emergency Demand Response Program ISO Services Charge calculated under Section 6.1.2.2.1 of this Rate Schedule, shall be the product of: (i) the applicable ISO Services Charge rate; and (ii) the Transmission Customer's applicable billing units for the month. The Transmission Customer’s billing units shall be based on the total compensable injection MWh.
For Transmission Customers purchasing Transmission Congestion Contracts or engaged in Virtual Transactions, the ISO Services Charge calculated under Section 6.1.2.2.1 of this Rate schedule shall be the product of: (i) the applicable ISO Services Charge rate; and (ii) the Transmission Customer's applicable billing units for the month.
For Transmission Customers purchasing Transmission Congestion Contracts, the Transmission Customer’s billing units shall be based on the settled Transmission Congestion Contract MWh. For Transmission Customers engaging in Virtual Transactions, the Transmission Customer’s billing units shall be based on total cleared virtual bid MWh.
The ISO Services Charge for Scheduling, System Control and Dispatch Service shall consist of six components and shall be recovered on a monthly basis (except for Section 6.1.2.2.5 which shall be billed quarterly) in accordance with the following processes:
6.1.2.2.1.1The responsibility for the sum of (a) those costs listed in Section 6.1.3.1 of this Rate Schedule that are included in the ISO’s annual budget and (b) the ISO’s FERC regulatory fees, shall be allocated 20% to all injection billing units and 80% to all withdrawal billing units. The current 80%/20% cost allocation shall remain unchanged through at least December 31, 2011 and shall continue to remain unchanged until such point in time that a study is conducted and the results of the study warrant changing the 80%/20% cost allocation. The following provisions prescribe the process and timeline for the review and, if warranted by the results of a future study, modification of the 80%/20% cost allocation on a going forward basis:
6.1.2.2.1.1.1A vote of the Management Committee will be taken in the third calendar quarter of 2010 on whether a new study should be conducted during late-2010 and 2011 to allow modification of the 80%/20% cost allocation, if warranted by the results of the study, to be implemented by January 1, 2012. A positive vote by 58% of the Management Committee will be required to go forward with the study, but there will no longer be a “material change” standard as was historically applied to the determination of whether a study should be conducted.
6.1.2.2.1.1.2If the Management Committee vote discussed in (i) above determines that a study should not be conducted, the 80%/20% cost allocation between withdrawal billing units and injection billing units shall be extended through at least December 31, 2012. In the third calendar quarter of 2011, a vote will be taken on whether a new study should be conducted during late-2011 and 2012 to allow modification of the percentage allocation, if warranted by the results of the study, to be implemented by January 1, 2013. Unless a 58% vote of the Management Committee is registered in favor of declining to go forward with the study, the study will be conducted.
6.1.2.2.1.1.3If the Management Committee vote in the third calendar quarter of 2011 discussed in (ii) above determines that a study should not be conducted, the current 80%/20% cost allocation shall remain unchanged until such point in time as the Management Committee determines that a study shall be conducted and the results of that study warrant changing the percentage allocation between withdrawal billing units and injection billing units. If the Management Committee vote in the third calendar quarter of 2011 discussed in (ii) above determines that a study should not be conducted, the Management Committee will revisit the issue of conducting a study annually in the third calendar quarter of each year using the same voting standard (i.e. the study gets performed unless 58% of the Management Committee votes not to commission the study) that was applied to the Management Committee vote in the third calendar quarter of 2011 discussed in (ii) above.
6.1.2.2.1.1.4If, and when, the Management Committee determines a study shall be conducted:
(a)Such study shall be completed, and the results thereof shared with Market Participants, before the end of the second calendar quarter of the year prior to the date on which a possible change to the then current allocation may become effective; and
(b)The ISO will present a draft study scope to Market Participants for consideration and comment before the ISO issues the study scope as part of its Request For Proposal process to retain a consultant to perform the study. A meeting shall be held with Market Participants to discuss the components (e.g., categories of costs considered, allocation of benefits, unbundling, etc.) that should be included in the draft study scope before the draft is issued by the ISO.
6.1.2.2.1.2The rate to be applied to injection billing units shall be the quotient of 20% of the sum of the ISO’s annual budget and FERC regulatory fees divided by the total annual estimated injection billing units as described in Section 6.1.2.1 of this Rate Schedule. The rate to be applied to withdrawal billing units shall be the quotient of 80% of the sum of the ISO’s annual budget and FERC regulatory fees divided by the total annual estimated withdrawal billing units as described in Section 6.1.2.1 of this Rate Schedule.
6.1.2.2.1.3The rates derived in Section 6.1.2.2.1 of this Rate Schedule shall then be multiplied by each Transmission Customer’s injection billing units and withdrawal billing units, as appropriate, for the month.
6.1.2.2.1.4For Transmission Customers that purchase Transmission Congestion Contracts and/or engage in Virtual Transactions their portion of the sum of (a) those costs listed in Section 6.1.3.1 of this Rate Schedule that are included in the ISO’s annual budget and (b) the ISO’s FERC regulatory fees, attributable to Transmission Congestion Contracts or Virtual Transactions, shall be calculated and billed as follows:
6.1.2.2.1.4.1For Calendar Year 2010:
(a)$0.020 per MWh for Transmission Congestion Contracts for calendar year 2010, based on a $6.7 million projected 2010 annual revenue requirement.
(b)$0.065 per cleared MWh for Virtual Trading transactions for calendar year 2010 based on a $2.0 million projected 2010 annual revenue requirement.
6.1.2.2.1.4.2For Subsequent Calendar Years
Each Transmission Customer shall be charged a rate computed annually based on the product of the annual revenue requirement adjusted for the over or under collection of the prior year’s annual revenue requirement, divided by the three year rolling average of the billing units, where:
(a)the annual revenue requirement is determined using an escalation factor calculated as the percentage change in the originally-approved ISO budget between the calendar year two years prior to the current calendar year (“Calendar Year Minus 2”) and the calendar year one year prior the current calendar year (“Calendar Year Minus 1”);
(b)the over/under collection of the prior year’s annual revenue requirement is calculated for the period between July of Calendar Year Minus 2 and June of Calendar Year Minus 1. For the purpose of this calculation the annual revenue requirement will be converted to a monthly requirement and then aggregated across the 12 months;
(c)the three year rolling average of billing units is calculated using an annual average of the billing units for the period between July of the calendar year four years prior to the current calendar year (“Calendar Year Minus 4”) and June of Calendar Year Minus 1.
However, the annual rate computed will be subject to a 25% maximum increase or decrease for each year. Revenue collected pursuant to this Section 6.1.2.2.1.4 will be disbursed monthly to all injection billing units as described in Section 6.1.2.1 of this Rate Schedule and to all withdrawal billing units as described in Section 6.1.2.1 of this Rate Schedule on the same basis described in Section 6.1.2.2.1.1 of this Rate Schedule.
6.1.2.2.1.5For Customers that participate in the ISO’s Special Case Resources program or its Emergency Demand Response Program their portion of the sum of (i) the ISO’s annual budget including the costs listed in Section 6.1.3.1 of this Rate Schedule; and (ii) the ISO’s FERC Regulatory fees, shall be billed at the same rate charged to injection billing units as described in Section 6.1.2.1 of this Rate Schedule. The rate will be reset annually to match the current calendar year’s rate for injections. Revenue collected pursuant to this Section 6.1.2.2.1.5 will be disbursed monthly to all injection billing units as described in Section 6.1.2.1 of this Rate Schedule and to all withdrawal billing units as described in Section 6.1.2.1 of this Rate Schedule on the same basis described in Section 6.1.2.2.1.1 of this Rate Schedule.
Except with respect to bad debt loss and working capital contribution costs, the responsibility for those costs listed in Section 6.1.3.1 of this Rate Schedule that are neither (i) included in the ISO’s annual budget, nor (ii) FERC-assessed regulatory fees, shall be allocated 100% to all withdrawal billing units. The rate to be applied to withdrawal billing units in each month shall be the quotient of the amount of these costs to be included in the month, as determined by the ISO, divided by the total estimated withdrawal billing units for the month, as described in Section 6.1.2.1 of this Rate Schedule. This rate shall then be multiplied by each Transmission Customer’s withdrawal billing units for the month. The responsibility for costs associated with bad debt losses and working capital contributions shall be allocated pursuant to Attachments U and V to this Tariff, respectively.
6.1.2.2.3.1The monthly payments the ISO makes to owners of facilities that are needed for the economic and reliable operation of the NYS Transmission System shall be recovered based on withdrawal billing units. Currently, the ISO makes payments to Consolidated Edison Co. of New York, Inc. for the purchase, installation, operation and maintenance of phase angle regulators at the Branchburg-Ramapo Interconnection between the ISO and PJM Interconnection, LLC and to Rochester Gas & Electric Corporation for the installation of a 135 MVAR Capacitor Bank at Rochester Station 80 on the cross-state 345 kV system. The charges to be applied to withdrawal billing units for Transmission Customers, other than those taking service under Section 5 of the OATT to supply Station Power as third party providers, shall be the product of (A) the sum of the monthly bills for such facilities from: (i) Consolidated Edison Co. of New York (less the one-half of such bill paid by PJM Interconnection, LLC) and (ii) Rochester Gas and Electric Corporation, divided by the total number of hours in the month, and (B) the ratio of (i) the Transmission Customer’s withdrawal billing units for that hour as described in Section 6.1.2.1 of this Rate Schedule to (ii) the sum of all ISO Transmission Customers’ withdrawal billing units for that hour (other than withdrawal billing units for those taking services under Part 5 of the OATT) as described in Section 6.1.2.1 of this Rate Schedule. Charges to be paid by Transmission Customers for this service shall be aggregated to render a monthly charge.
6.1.2.2.3.2Transmission Customers taking service under Section 5 of the OATT to supply Station Power as third-party providers shall pay to the ISO a daily charge for this service equal to the product of (A) the sum of the daily bills for such facilities as described in subparagraph (a) above and (B) the ratio of the Transmission Customer’s Station Power supplied under Section 5 of the OATT for the day to the sum of all withdrawal billing units for the day.
6.1.2.2.3.3The ISO shall credit charges paid for this service by Transmission Customers and LSEs taking service under Section 5 of the OATT to supply Station Power as third-party providers for the day on a Load Ratio Share basis to Transmission Customers serving Load in the NYCA for the day.
6.1.2.2.4.1The ISO shall calculate, and Transmission Customers, other than Transmission Customers taking service under Section 5 of the OATT to supply Station Power as third party providers, shall pay an hourly charge equal to the product of (A) the residual adjustment costs listed in Section 6.1.4.1 of this Rate Schedule for each hour and (B) the ratio of (i) the Transmission Customer’s withdrawal billing units for that hour as described in Section 6.1.2.1 of this Rate Schedule to (ii) the sum of all ISO Transmission Customers’ withdrawal billing units for that hour as described in Section 6.1.2.1 of this Rate Schedule.
6.1.2.2.4.2The ISO shall calculate, and each Transmission Customer taking service under Part 5 of the OATT to supply Station Power as a third party provider shall pay a daily charge equal to the product of (A) the residual adjustment costs listed in Section 6.1.4.1 of this Rate Schedule for each day and (B) the ratio of (i) the withdrawal units of the Transmission Customer taking service under Part 5 of the OATT to supply Station Power as a third party provider for that day to (ii) the sum of all ISO Transmission Customers’ withdrawal billing units for that day as described in Section 6.1.2.1 of this Rate Schedule. The ISO shall credit revenue collected by application of this charge, on a Load ratio share basis, to all ISO Transmission Customers’ withdrawal billing units as described in Section 6.1.2.1 of this rate Schedule 1 summed for the day.
6.1.2.2.4.3The ISO shall calculate, and each Transmission Customer shall pay, a daily charge equal to the product of (A) the bid production guarantee costs listed in Section 6.1.4.2 of this Rate Schedule for each day and (B) the ratio of (i) the Transmission Customer’s withdrawal billing units for that day as described in Section 6.1.2.1 of this Rate Schedule to (ii) the sum of all ISO Transmission Customers’ withdrawal billing units for that day as described in Section 6.1.2.1 of this Rate Schedule, provided, however, that the costs of supplemental payments and Demand Reduction Incentive Payments made to Demand Reduction Providers shall be allocated to Transmission Customers according to the methodology described in Attachment R. To the extent that the sum of all Bilateral Schedules, excluding schedules of Bilateral Transactions with Trading Hubs as their POWs, and all Day-Ahead Market purchases to serve Load in the Day-Ahead schedule is less than the ISO’s Day-Ahead forecast of Load and the ISO commits Resources in addition to the reserves it normally maintains to enable it to respond to contingencies to meet the ISO’s Day-Ahead forecast of Load, charges associated with the costs of Bid Production Cost Guarantees for the additional Resources committed Day-Ahead to meet the ISO’s Day-Ahead forecast of Load shall be allocated to Transmission Customers who are not bidding as Suppliers according to the Methodology described in Attachment T.
Dues, fees, and other charges: (i) of NERC for its service as the Electric Reliability Organization for the United States (“ERO”) recovered pursuant to FERC Docket Nos. RM05-30-000, RR06-1-000 and RR06-3-000 and related dockets, and (ii) of Northeast Power Coordinating Council: Cross-Border Regional Entity, Inc., or its successors, incurred to carry out functions that are delegated by the NERC and that are related to ERO matters pursuant to Section 215 of the FPA, all of which dues, fees, and other charges shall be recovered quarterly. Such recovery shall be based on Actual Energy Withdrawals to supply Load in the NYCA, utilizing the load metering information for the most recent month for which actual load meter data are available for invoices issued through August 31, 2007 and utilizing finalized actual load metering data no longer subject to challenge for invoices issued on or after September 1, 2007. The metering information shall not be subject to correction or adjustment. Notwithstanding any applicable provisions of this Tariff or of the ISO Services Tariff, the ISO may supply to NERC the name of any LSE failing to pay any amounts due to NERC and the amounts not paid.
Amounts paid to Suppliers, pursuant to the Incremental Cost Recovery for Units Responding to Local Reliability Rules I-R3 and I-R5, shall be recovered from Load in the Transmission District of the Supplier being paid, other than Load scheduled by a Transmission Customer taking service under Part 5 of the OATT to supply Station Power as a third party provider, on the basis of each LSE’s contribution to the Load in the day the payment obligation is incurred.
ISO costs to be recovered through the Rate Schedule 1 charge include:
6.1.3.1Costs associated with the operation of the NYS Transmission System by the ISO and administration of this Tariff by the ISO, including without limitation, the following:
The ISO’s payments from Transmission Customers will not equal the ISO’s payments to Suppliers. Part of the difference consists of Day‑Ahead Congestion Rent. The remainder comprises the Residual Adjustment, which will be an adjustment to the costs in Section 6.1.3.1. The most significant components of the Residual Adjustment, which is calculated below, include:
The actual Residual Adjustment for each month shall be the sum of the hourly Residual Adjustments calculated as follows: (A) the ISO’s receipts from Transmission Customers and Primary Holders of TCCs for services which equal the sum of: (i) payments for Energy scheduled in the LBMP Market in that hour in the Day-Ahead commitment; (ii) payments for Energy purchased in the Real‑Time LBMP Market for that hour that was not scheduled Day‑Ahead; (iii) payments for Energy by generating facilities that generated less Energy in the real‑ time dispatch for that hour than they were scheduled Day‑Ahead to generate in that hour for the LBMP Market; (iv) TUC payments made in accordance with Sections 3, 4 and 5 of this Tariff that were scheduled in that hour in the Day‑Ahead commitment; and (v) real‑time TUC payments in accordance with Parts 3, 4 and 5 of this Tariff that were not scheduled in that hour in the Day‑Ahead commitment; (B) less the ISO’s payments to generation facilities, Transmission Owners and Primary Holders of TCCs equal to the sum of the following: (i) payments for Energy to generation facilities that were scheduled to operate in the LBMP Market in that hour in the Day‑Ahead commitment; (ii) payments to generation facilities for Energy provided to the ISO in the real‑time dispatch for that hour that those generation facilities were not scheduled to generate in that hour in the Day‑Ahead commitment; (iii) payments for Energy to LSEs that consumed less Energy in the real‑time dispatch than those LSEs were scheduled Day‑Ahead to consume in that hour; (iv) payments of the real-time TUC to Transmission Customers that reduced their schedules for that hour after the Day‑Ahead commitment; (v) payments of Congestion Rents collected for that hour in the Day‑Ahead schedule to Primary Holders of TCCs; (vi) settlements with Transmission Owners for losses revenue variances; and (vii) positive Net Congestion Rents collected in that hour.
The ISO’s costs also include the costs associated with differences between the amounts bid by generating facilities that have been committed and scheduled by the ISO to provide Energy and certain Ancillary Services, and the actual revenues received by these generating facilities for providing such Energy and Ancillary Services. Where the costs are incurred to compensate a Resource for meeting the reliability needs of a local system, the associated charge shall apply only to Transmission Customers serving Load in the Load Zone(s) or sub-zone where the Resource is located. The ISO’s costs also include the costs associated with payments made for supplemental payments and Demand Reduction Incentive payments to Demand Reduction Providers.
Effective Date: 6/30/2010 - Docket #: ER10-1657-000 - Page 1