NYISO Tariffs --> Market Administration and Control Area Services Tariff (MST) --> 4 MST Market Services: Rights and Obligations --> 4.1 MST Market Services - General Rules
Market Services include all services and functions performed by the ISO under this Tariff related to the sale and purchase of Energy, Capacity or Demand Reductions, and the payment to Suppliers who provide Ancillary Services in the ISO Administered Markets.
The ISO shall provide all Market Services in accordance with the terms of the ISO Services Tariff and the ISO Related Agreements. The ISO shall be the sole point of Application for all Market Services provided in the NYCA. Each Market Participant that sells or purchases Energy, including Special Case Resources and Emergency Demand Response Program participants, sells or purchases Capacity, or provides Ancillary Services in the ISO Administered Markets utilizes Market Services and must take service as a Customer under this Tariff and enter into a Service Agreement under the Tariff, as set forth in Attachment A; each entity that withdraws Energy to supply Load within the NYCA or provides Installed Capacity to an LSE serving Load within the NYCA utilizes the Control Area Services provided by the ISO and benefits from the reliability achieved as a result of ISO Control Area Services, must take service as a Customer under this Tariff and enter into a Service Agreement under this Tariff, as set forth in Attachment A; and each entity that has its virtual bids accepted and thereby engages in Virtual Transactions and each entity that purchases Transmission Congestion Contracts, excluding Transmission Congestion Contracts that are created prior to January 1, 2010, utilizes Market Services and must take service as a Customer under this Tariff and enter into a Services Agreement under this Tariff, as set forth in Attachment A. Each Customer that utilizes Market Services also utilizes Transmission Service and shall obtain Transmission Service under the ISO OATT.
4.1.3.1The ISO shall operate and maintain an OASIS, including a Bid/Post System that will facilitate the posting of Bids to supply Energy and Ancillary Services by Suppliers for use by the ISO and the posting of Locational Based Marginal Prices (“LBMP”) and schedules for accepted Bids for Energy and Ancillary Services. The Bid/Post System will be used to post schedules for Bilateral Transactions. The ISO will provide historical data regarding Energy and Capacity market clearing prices in addition to Congestion Costs on a publicly accessible portion of its OASIS.
4.1.3.2Zonal Uplift Report. The ISO shall post on a publicly accessible portion of its website, in machine-readable format, a report on total daily uplift dollars paid to (a) Generators and Demand Side Resources located in Load Zones H, I and J collectively, (b) Generators and Demand Side Resources located in each of the other NYCA Load Zones, and (c) Suppliers scheduling Imports at a Proxy Generator Bus, no more than 20 calendar days after the conclusion of each month. The report shall be updated at the time the Resource-Specific Uplift Report is posted, and again approximately 120 days after an initial invoice was issued for a month, to incorporate updated information. The report shall provide the uplift paid for each month, by day and by billing category.
Costs that the ISO will report as uplift include: (1) Day-Ahead and real-time Bid Production Cost guarantee payments to Generators and to Demand Side Resource aggregations; (2) Day-Ahead Bid Production Cost guarantee payments to Suppliers that schedule Imports; (3) Day-Ahead Margin Assurance Payments; (4) cost recovery for units responding to Local Reliability Rules addressing loss of Generator gas supply; (5) Import Curtailment Guarantee Payments to Suppliers that schedule Imports in real-time; and (6) Lost Opportunity Cost payments to Suppliers of Voltage Support Service.
4.1.3.3Resource-Specific Uplift Report. The ISO shall post on a publicly accessible portion of its website, in machine-readable format, a report on total uplift paid to Generators, Demand Side Ancillary Service Program Resources, Day-Ahead Demand Response Program resources or aggregations, and to Special Case Resource aggregations, on a monthly basis. The report shall provide the total uplift payment across all uplift categories paid to each Generator or aggregation of Demand Side Resources. The report shall be posted no more than 90 calendar days after the conclusion of each month and shall be updated approximately 120 days after an initial invoice was issued for the month, to incorporate updated information.
4.1.3.4Operator-Initiated Commitment Report. The ISO shall post on a publicly accessible portion of its website, in machine-readable format, commitments made after the Day-Ahead Market for a reason other than minimizing the total production cost of serving load.
For each reported commitment, the ISO shall provide the following information:
(a)commitment size: provide both the resource’s UOLN and the quantity of MW committed;
(b)location: the Load Zone in which the resource is located;
(c)commitment reason: (i) system-wide capacity need, or (ii) constraint management, or (iii) voltage support; and
(d)commitment start time.
Operator-initiated commitments are ordinarily posted in real-time as they occur. All operator-initiated commitments for a calendar month will be available no more than 30 days after the conclusion of that month. Operator-initiated commitment postings may later be updated to improve accuracy.
Pursuant to ISO Procedures, each Transaction offered in the Energy, Installed Capacity, Ancillary Services or Transmission Congestion Contract market shall be subject to a minimum size of one (1) megawatt (“MW”); provided however, the minimum size of each Transaction offered in the Energy, Installed Capacity or Ancillary Services market on behalf of Energy Storage Resources and Aggregations shall be one tenth (0.1) of one MW. Regulation Service may be offered in tenths of a MW. Pursuant to ISO Procedures, Special Case Resources may offer a minimum of 100 kW of Unforced Capacity in the Installed Capacity Market. Transactions that exceed one (1) megawatt may be scheduled in tenths of a megawatt provided, however, that Bilateral Transactions and External Transactions in the LBMP Market must always be bid and scheduled in increments of one (1) megawatt.
Customers and Transmission Customers shall utilize Internet service providers to access the ISO’s OASIS and bid/post system. Customers shall arrange for and maintain all communications facilities for the purpose of communication of commercial data to the ISO. Each Customer shall be the customer of record for the telecommunications facilities and services its uses and shall assume all duties and responsibilities associated with the procurement, installation and maintenance of the subject equipment and software.
All purchasers in the Day‑Ahead or Real‑Time Markets who withdraw Energy within the NYCA to serve Load or at an NYCA Interconnection with another Control Area must obtain Transmission Service under the ISO OATT. All Customers requesting service under the ISO Services Tariff to engage in Virtual Transactions must obtain Transmission Service under the ISO OATT.
All LSEs serving Load in the NYCA must comply with the Installed Capacity requirements set forth in Article 5 of this ISO Services Tariff.
All Customers taking service under the ISO Services Tariff must pay the Market Administration and Control Area Services Charge, as specified in Rate Schedule 1 of this ISO Services Tariff.
A Supplier with a Generator or Aggregation with a real time physical operating problem that makes it impossible for the Generator or Demand Side Resource (a) to operate in the bidding mode in which it was scheduled, or (b) to provide all of the Energy or Ancillary Services offered in its Bids, or (c) to achieve or comply with applicable operating parameters or other requirements, shall notify the ISO.
All Customers shall comply with all applicable federal, state and local laws, regulations and orders, including orders from the ISO.
4.1.7.1Violations of FERC’s orders, rules and regulations also violate this Section 4.1.7 of the ISO Services Tariff. In particular, if FERC or a court of competent jurisdiction determines there has been a violation of FERC’s regulations related to electric energy market manipulation (see 18 C.F.R. Section 1c.2, or any successor provision thereto), such violation is also a violation of this ISO Services Tariff if such violation affects or is related to the ISO Administered Markets.
4.1.7.2If the ISO becomes aware that a Customer may be engaging in, or might have engaged in, electric energy market manipulation, it shall promptly inform its Market Monitoring Unit.
4.1.7.3This Section 4.1.7 of the ISO Services Tariff does not independently empower the ISO or its Market Monitoring Unit to impose penalties for, or to provide a remedy for, violations of FERC’s prohibition against electric energy market manipulation, or for other violations of the ISO's Tariffs.
Suppliers with generating units committed by the ISO for service to ensure NYCA reliability or local system reliability, that are eligible to submit start-up and minimum generation Bids, will recover startup and minimum generation costs that were not bid, that were not known before the close of the Real-Time Scheduling Window, and that were not recovered in the Dispatch Day, provided however, eligibility to recover such additional costs shall not be available for megawatts scheduled Day-Ahead. Payment for such costs shall be determined, as if bid, pursuant to the provisions of Attachment C of this Tariff. Energy Storage Resources, Aggregations that include Withdrawal-Eligible Generator(s), and Behind-the-Meter Net Generation Resources dispatched by the ISO for service to ensure NYCA reliability or local system reliability will recover incremental energy costs that were not bid, that were not known before the close of the Real-Time Scheduling Window, and that were not recovered in the Dispatch Day, provided however, eligibility to recover such additional costs shall not be available for megawatts scheduled Day-Ahead. Payments for securing NYCA reliability and local system reliability shall be recovered by the ISO in accordance with Rate Schedule 1 of the ISO OATT.
External Installed Capacity Suppliers that respond to an SRE request are eligible to recover the ISO-verified costs they incur to respond to the SRE request to the extent such costs exceed the ISO-verified market revenues the External Installed Capacity Supplier receives. It is the obligation of the External Installed Capacity Supplier to demonstrate its costs and revenues to the ISO’s satisfaction. In verifying the costs of External Installed Capacity Suppliers that respond to an SRE, the ISO will consider the incremental net costs the Market Party incurred to respond to the SRE. Recoverable costs could include, but are not limited to, incremental costs of generating to supply Energy using the requested Installed Capacity, and the incremental costs incurred by the Market Party to transmit Energy from the External Installed Capacity Supplier’s resource to the NYCA, including the opportunity cost associated with lost expected revenue. However, losses resulting from the difference in External Transaction settlement prices between an External Control Area and the NYCA will only be recoverable if and to the extent the following conditions are satisfied: (a) the losses are demonstrated to be reasonably related to responding to the SRE request; and (b)(i) a counterflow Export from the NYCA offered by the Market Party at the External Interface where the Capacity delivery obligation applies is not scheduled due to NYCA reliability concerns or is curtailed to address NYCA reliability concerns, or (ii) no opportunity exists to schedule a counterflow Export from the NYCA at the External Interface where the Capacity delivery obligation applies. Payments for securing NYCA reliability and local system reliability shall be recovered by the ISO as DisputeResolutionCosts in accordance with Section 6.1.13 of Rate Schedule 1 of the ISO OATT.
Re-dispatching costs incurred as a result of reductions in Transfer Capability caused by Storm Watch (“Storm Watch Costs”) shall be aggregated and recovered on a monthly basis by the ISO exclusively from Transmission Customers in Load Zone J. The ISO shall calculate Storm Watch Costs by multiplying the real-time Shadow Price of any binding constraint associated with a Storm Watch, by the higher of (a) zero; or (b) the scheduled Day-Ahead flow across the constraint minus the actual real-time flow across the constraint.
Generating units designated pursuant to the New York State Reliability Council’s Local Reliability Rule addressing the Loss of Generator Gas Supply for Generators located in New York City or the Local Reliability Rule addressing the Loss of Generator Gas Supply for Generators located on Long Island, as being required either to burn an alternate fuel at designated minimum levels, or to activate their auto-swap capability, based on forecast Load levels in Load Zones J and K (for purposes of this Section 4.1.9, “Eligible Units”), shall be eligible to recover costs associated with burning the required alternate fuel when one of the specified Local Reliability Rules is invoked. For purposes of this Section 4.1.9, the periods of time in which the Eligible Unit burns the alternate fuel only because one of the Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island has been invoked, including that period of time required for an Eligible Unit to move into and out of compliance with a Local Reliability Rule addressing the Loss of Generator Gas Supply, shall be referred to as the “Eligibility Period.”
4.1.9.1.1 Obligation to Test Automatic Fuel Swap Capability and Eligibility to Recover Costs of Performing Fuel Swap Tests
Combined cycle Generating units designated pursuant to the New York State Reliability Council’s Local Reliability Rules addressing the Loss of Generator Gas Supply for Generators located in New York City, which have the ability to automatically swap from natural gas to a liquid fuel source in the event of the sudden interruption of gas fuel supply or loss of gas pressure or the unavailability of gas supply to the Generator, shall:
(a) develop test procedures that are consistent with the requirements of the applicable Local Reliability Rule and ISO Procedures; and
(b) successfully test to demonstrate that the designated combined cycle units are able to automatically swap from natural gas to a liquid fuel source each Capability Period.
The requirement to perform a test each Capability Period can be met by performing a real-time automatic fuel swap, if that fuel swap was successful and occurred during the relevant Capability Period. The scheduling of a test to demonstrate that a designated combined cycle unit is able to automatically swap from natural gas to a liquid fuel source in real-time operations shall be coordinated with the ISO and with the Transmission Owner in whose subzone the Generator is located, consistent with ISO Procedures.
The period during which combined cycle Eligible Units are performing scheduled automatic fuel swap testing, including that period of time required for an Eligible Unit to move into and out of compliance with a Local Reliability Rule addressing the Loss of Generator Gas Supply, is an “Eligibility Period.”
For Eligibility Periods, Eligible Units burning an alternate fuel that would not have been burned but for Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island being invoked and Eligible Units burning an alternate fuel because they activated their auto-swap capability and experienced a swap to the alternate fuel that would not have occurred but for the operation of the auto-swap capability in accordance with the implementation of the Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island shall recover costs that vary with the amount of alternate fuel burned (“variable operating costs”) if: (i) such costs are not reflected in the reference level for that Eligible Unit for the hours included in the Eligibility Period, pursuant to ISO Procedures, and (ii) the hour is one for which the commodity cost of the alternate fuel including taxes and emission allowance costs is greater than the commodity cost for natural gas, including taxes and emission allowance costs, as determined by the ISO. These relative commodity cost determinations shall use the same indices used by the ISO to establish daily Reference Levels. Variable operating costs shall include the commodity cost, associated taxes and emission allowance costs, of the required alternate fuel burned during an Eligibility Period pursuant to Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island. The owner or bidder of an Eligible Unit shall notify the ISO when variable operating costs change due to a change in tax rates.
An Eligible Unit that seeks to recover costs incurred in connection with its compliance with Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island, in addition to the commodity cost, associated taxes and emission allowance cost recovery specified in Section 4.1.9.2, shall negotiate an Implementation Agreement with the ISO. The Eligible Unit and the ISO shall consult with and consider the input of the New York State Public Service Commission, and the Transmission Owner designated by the applicable Local Reliability Rule addressing the loss of gas supply for Generators located in New York City or on Long Island. Such Implementation Agreements shall specify, among other terms and conditions, the facilities (or portions of facilities) used to meet obligations under the Local Reliability Rule addressing the loss of gas supply for Generators located in New York City or on Long Island. The Implementation Agreement shall indicate the rate to be charged during the period of the Implementation Agreement to recover such additional costs.
The Implementation Agreement may also include costs in addition to commodity cost, associated taxes and emission allowance costs of the alternate fuel incurred in connection with compliance with Local Reliability Rules addressing the loss of gas supply for Generators located in New York City or on Long Island that vary with the amount of alternate fuel burned because a Local Reliability Rule addressing the loss of gas supply was invoked. These variable costs shall be paid pursuant to Section 4.1.9.2 as variable operating costs so as to not duplicate payments.
Each such Implementation Agreement shall have a duration of one or more Capability Periods and shall commence at the beginning of a Capability Period unless another date is approved by the Commission. If the Eligible Unit and the ISO reach agreement on the terms and conditions of the Implementation Agreement, the ISO shall file it with the Commission for its review and acceptance.
In the event that the Eligible Unit and the ISO have not come to an agreement six months prior to the beginning of the Capability Period that the Implementation Agreement is intended to govern, then either one of them may request the assistance of the Commission’s Dispute Resolution Service. If the Dispute Resolution Service agrees to provide its assistance the Eligible Unit and the ISO shall participate in whatever dispute resolution process the Dispute Resolution Service may recommend. The Commission’s Dispute Resolution Service may include other stakeholders to the extent confidentiality protections are in place. If, however, there is no agreement four months prior to the beginning of the relevant Capability Period then the Eligible Unit and the ISO may each file an unexecuted Implementation Agreement for the Commission’s review and acceptance.
In the event that any provisions of this Section 4.1.9 are modified prior to the termination date of any Commission-accepted Implementation Agreement, such Implementation Agreement will remain in full force and effect until it expires in accordance with its contractual terms and conditions.
Rules for establishing Eligibility Periods shall be specified in ISO Procedures.
Payments made by the ISO to the Eligible Unit to pay variable operating costs and to pay the rate established by the Implementation Agreement pursuant to this Section 4.1.9 shall be in addition to any LBMP, Ancillary Service or other revenues received as a result of the Eligible Unit’s Day-Ahead or Real-Time dispatch for that day. Payment by the ISO of variable operating costs pursuant to Section 4.1.9.2 shall be based on the Eligibility Period, quantity of alternate fuel burned, and relative costs of alternate fuel compared to natural gas. Payment by the ISO of the rate established in the Implementation Agreement for costs incurred other than variable operating costs shall be made as part of the ISO billing cycle regardless of which Local Reliability Rule addressing the loss of gas supply an alternate fuel is burned pursuant to, and regardless of the relative cost of the alternate fuel compared to natural gas reflected in reference levels.
The ISO shall make available for the Transmission Owner in whose subzone the Generator is located: (i) the identity of Generators determined by the ISO to be eligible to recover the costs associated with burning the required alternate fuel pursuant to the provisions of this Section 4.1.9; (ii) the start and stop hours for each claimed Eligibility Period and (iii) the amount of alternate fuel for which the Generator has sought to recover variable operating costs.
Suppliers may aggregate individual Resources electrically located in the NYCA to provide Energy, Capacity and Ancillary Services. Demand Side Resources participating in the Emergency Demand Response Program and Aggregations of Special Case Resources shall follow the rules set forth in Services Tariff Sections 22 (Att. G) and 5.12.11, respectively. Each Aggregation shall be offered as a single unit and all bidding and offer obligations under the ISO Tariffs apply to the Aggregation, or to the Aggregator, where appropriate, not to the individual Resources that comprise the Aggregation. An Aggregation that offers a combination of Energy injections, Energy withdrawals and/or Demand Reduction must be able to offer at least 100 kW of each.
Each Aggregation must meet the minimum eligibility and performance requirements to participate in the ISO Administered Markets. Unless otherwise noted, Resources within an Aggregation are not individually required to meet the minimum eligibility and performance requirements to participate in the ISO Administered Markets. Generators with PURPA contracts, Limited Control Run of River Resources, Behind-the-Meter Net Generation Resources, Municipally-owned Generation, System Resources and Control Area System Resources are ineligible to participate in an Aggregation. One Aggregation cannot participate in another Aggregation, however, the individual Resources within an Aggregation may switch to a new Aggregation in accordance with Services Tariff Section 4.1.10.3.
An individual Resource that is a customer of a Load Serving Entity that distributed less than or equal to four million MWh in the ISO’s immediately prior and completed fiscal year (which runs January 1 through December 31) shall not be enrolled in an Aggregation, unless the Relevant Electric Retail Regulatory Authority affirmatively authorizes the customers of that Load Serving Entity to participate in the ISO-administered markets in an Aggregation. For the purposes of this Services Tariff Section 4.1.10, et seq., “Relevant Electric Retail Regulatory Authority” shall mean “the entity that establishes the retail electric prices and competition policies for retail electric customers.”
An Aggregator shall, upon enrollment of each individual Resource and annually thereafter, (i) determine whether each Resource is a customer of a Load Serving Entity meeting the annual MWh threshold identified above, and (ii) for each Resource that is a customer of a Load Serving Entity that meets such threshold, accurately attest that the Relevant Electric Retail Regulatory Authority has authorized the Load Serving Entity’s customers to participate in an Aggregation. An attestation completed upon an individual Resource’s initial enrollment shall be effective until the end of the Capability Year in which the Resource was first enrolled. Each annual attestation shall be completed by April 1, and will be effective for the Capability Year beginning May 1 of that year. If the ISO does not receive an updated attestation by April 1, the previously submitted attestation shall remain in effect, and the Aggregator shall be responsible for its accuracy.
4.1.10.1 Aggregation Composition
Aggregations must contain at least twoone or more Resources, except that a single Demand Side Resource may participate as a single-Resource Aggregation. The maximum physical injection capability for a Resource participating in an Aggregation is 20 MW. Resources with a nameplate capability greater than 20 MW may participate in an Aggregation if the ISO determines sufficient physical protection and control schemes exist to limit the injection capability of the Resource to 20 MW or less. There is no maximum Demand Reduction capability for Demand Side Resources participating in an Aggregation. An Aggregator must identify each individual facility in an Aggregation in accordance with the ISO Procedures.
Aggregations may be comprised of a single Resource type or multiple Resource types. Except as otherwise provided in the ISO Tariffs and the ISO Procedures, Aggregations that are comprised of a single Resource type shall follow the rules associated with that Resource type (e.g., an Aggregation of Energy Storage Resources shall follow the rules applicable to Energy Storage Resources). Aggregated (i) Intermittent Power Resources, (ii) Energy Limited Resources, (iii) Capacity Limited Resources, or (iv) Limited Energy Storage Resources shall constitute a single Resource type Aggregation only when the individual Resources in the Aggregation have the same Intermittent, energy limiting, or capacity limiting characteristic (e.g., an Aggregation of only solar Resources, or an Aggregation of only pumped storage Resources). Provided, however, that Aggregations with multiple, different types of Intermittent Power Resources, Energy Limited Resources, Capacity Limited Resources, and Limited Energy Storage Resources shall follow the rules associated with DER Aggregations.
Aggregations that are comprised of more than one Resource type, and Aggregations comprised of only Demand Side Resources shall follow the rules associated with DER Aggregations.
Aggregations that include at least one Withdrawal-Eligible Generator may submit Bids to withdraw Energy. For the purpose of measuring Aggregation compliance with Base Point Signals, Aggregations that include at least one Withdrawal-Eligible Generator will be measured based on their net performance; that is, Energy injections and Demand Reductions will be reduced by Energy withdrawals.
Aggregators shall not offer any Resource as part of an Aggregation that is participating in the ISO Administered Markets in a different Aggregation or as an individual Resource.
4.1.10.2 Aggregation Electrical Location
The ISO shall establish a set of Transmission Nodes in the New York Control Area at which individual Resources may aggregate. Each Transmission Node shall be identified in the ISO Procedures. The ISO shall consult with the appropriate Member System prior to identifying a Transmission Node in accordance with ISO Procedures. Aggregators shall identify, after consultation with the interconnecting utility, the Transmission Node for each Aggregation. All Resources in an Aggregation must be electrically located in the New York Control Area, and electrically connected to the same ISO-identified Transmission Node. Multiple Aggregators may each enroll one or more Aggregations at a Transmission Node.
The ISO may modify the set of Transmission Nodes from time to time due to conditions on the New York State Transmission System and the underlying distribution systems changing over time. The ISO shall also review and update (if needed) the identified Transmission Nodes on an annual basis, and will post a notice of any changes to the identified Transmission Nodes at least ninety (90) days prior to the beginning of the Capability Year. Changes to the set of Transmission Nodes shall take effect on the first day of the Capability Year. Aggregators shall certify, in accordance with ISO Procedures, that Aggregations affected by changes to Transmission Nodes meet all requirements of this Section pursuant to ISO Procedures.
4.1.10.3 Resources Changing Aggregations
Subject to the requirement that all of the Resources in an Aggregation must be electrically connected to the same ISO-identified Transmission Node, an individual Resource may leave its current Aggregation and/or join a new Aggregation to be effective at the start of a calendar month, but must provide at least thirty (30) ninety (90) calendar days notice of its intent to change Aggregations. Registration of Resources that leave or join an Aggregation shall be completed in accordance with ISO Procedures. The ISO must approve all Resource registrations before the Resource is allowed to participate in an Aggregation.
Additional rules for Resources changing Aggregations, that participate in the ICAP market are located in Services Tariff Section 5.12.13.1.
4.1.10.4 Aggregation Metering
Each Aggregation must meet the applicable metering standards identified in the ISO’s Tariffs and in ISO Procedures. Aggregators may choose to have an ISO-authorized Meter Services Entity or the applicable Member System provide Aggregation metering services for wholesale market participation. See Services Tariff § 13.
Real-time telemetry data and revenue-quality meter data shall be submitted for each Aggregation. Real-time telemetry for DER Aggregations shall consist of three parts: (i) the net of Energy injections and Energy withdrawals by Withdrawal Eligible Generators, (ii) Demand Reductions; and (iii) the sum of both (i) and (ii). Revenue-quality meter data for each DER Aggregation shall consist of three parts: (i) Energy injections; (ii) Energy withdrawals by Withdrawal-Eligible Generators; and (iii) Demand Reductions. Aggregations of other Resource types shall submit meter data in accordance with Services Tariff Section 13 and the ISO Procedures.
4.1.10.5 Qualification Requirements for Aggregators
Aggregators must be Customers. Aggregators must (i) comply with the registration requirements set forth in Services Tariff Section 9, and the ISO Procedures; (ii) designate one or more contact persons to receive ISO communications; and (iii) comply with the metering requirements set forth in Services Tariff Section 13 and the associated ISO Procedures. Prior to an Aggregation’s participation in the wholesale market, and each individual facility’s participation in an Aggregation, the Aggregator shall attest that the individual facility(ies) and Aggregation have been authorized to participate in the ISO-administered markets by the applicable Distribution Utility and Relevant Electric Retail Regulatory Authority. For the purposes of Services Tariff Section 4.1.10, et seq., “Distribution Utility” is defined as “an entity, such as a Transmission Owner or Public Power Entity, that owns and operates facilities used for the retail distribution of electricity and provides retail service(s) under tariffs approved by the applicable Relevant Electric Retail Regulatory Authority.”
4.1.10.6Double Counting of Services
A Resource participating in an Aggregation shall not be eligible to supply Energy, Operating Reserves, Regulation Service, or Installed Capacity in the ISO-administered markets when the Resource provides the same or substantially similar service in a retail market or program.
When a Resource participates in one or more retail markets or programs, an Aggregator may only register that Resource in an Aggregation that does not provide the same or substantially similar service in the ISO-administered markets. For example, if a Resource provides Installed Capacity or a substantially similar service to a retail market or program, the Aggregator shall not enroll the Resource in an Aggregation that also supplies Unforced Capacity in the ISO’s Installed Capacity market. The Aggregator may, however, enroll the Resource in an Aggregation that only supplies Energy and Ancillary Services in the ISO-Administered Markets.
4.1.10.7ISO – Utility Operational Coordination
4.1.10.7.1Utility Review of Distributed Energy Resource Enrollment
A Distribution Utility shall have sixty (60) calendar days to review the reliability and safety impact of each new Distributed Energy Resource connecting to its electric facilities that seeks to participate in the ISO Administered Markets, and any incremental change to an Aggregation. The ISO shall provide to the Distribution Utility the physical and operational data collected for the Distributed Energy Resource upon the Resource’s enrollment in the ISO-Administered markets in order to facilitate review of new facilities. The ISO shall also provide to the Distribution Utility individual Distributed Energy Resource physical and operational data necessary to evaluate incremental changes to an Aggregation. The sixty-day review period shall begin on the date the ISO transmits Distributed Energy Resource’s operating and physical information to the Distribution Utility.
If a Distribution Utility notifies the ISO within sixty days that a Distributed Energy Resource’s participation in the ISO Administered Markets poses a significant threat to the reliability and/or safety of the Distribution Utility’s electric facilities, the ISO shall incorporate such finding(s) its review of the Distributed Energy Resource. The ISO, Distribution Utility, and Aggregator shall evaluate the reliability and/or safety concerns identified by the Distribution Utility, and attempt to implement appropriate measures to mitigate the reliability and/or safety concern(s). The ISO may limit the capacity and/or wholesale market services a Distributed Energy Resource is authorized to supply to address the reliability and/or safety concerns communicated by the Distribution Utility. If the ISO does not receive timely notification from the Distribution Utility pursuant to this Services Tariff Section 4.1.10.7.1, then the ISO will assume that the operation of the Distributed Energy Resource will not have a material reliability and/or safety impact on the applicable distribution system.
The operation of this Section shall not prevent the Distribution Utility from derating or declaring a Resource to be unavailable in accordance with Section 4.1.10.7.2 below.
4.1.10.7.2Ongoing Operational Coordination
The ISO, Transmission Owner, Distribution Utility, and Aggregator shall coordinate scheduling and dispatch for all Generators, Demand Side Resources, and Distributed Energy Resources participating in the wholesale markets as part of an Aggregation in accordance with ISO Procedures. Such coordination shall be consistent with the requirements set forth in the ISO’s Business Practice Manuals, including the Day-Ahead Scheduling Manual, Transmission and Dispatch Manual, and Emergency Operations Manual.
An Aggregator shall identify to the applicable Distribution Utility, and, if a different entity, the Transmission Owner, the Generator(s), Demand Side Resource(s), and/or Distributed Energy Resource(s) within its Aggregation that will be operated to meet a NYISO-issued schedule prior to the dispatch of any Generator, Demand Side Resource or Distributed Energy Resource participating in an Aggregation in accordance with the ISO Procedures.
A Distribution Utility shall have the authority to derate, or declare as unavailable for dispatch, a Generator, Demand Side Resource, or Distributed Energy Resource that is interconnected to the Distribution Utility’s electrical facilities when the utility determines that the Generator, Demand Side Resource, or Distributed Energy Resource is reasonably expected to pose a threat to the reliability of the electric facilities under the operational control of the Distribution Utility, and not under ISO operational control. When a Distribution Utility makes such determination, it shall notify the applicable Aggregator as soon as practicable.
When a Distribution Utility notifies an Aggregator that an individual Generator, Demand Side Resource or Distributed Energy Resource participating in its Aggregation must be derated or forced out of service, the Aggregator shall promptly update its Day-Ahead and/or Real-Time Market Bids, if necessary, in accordance with Services Tariff Sections 4.2 and 4.4, and the ISO Procedures. If the Aggregator is not able to update its Day-Ahead and/or Real-Time Market Bids, it shall notify the ISO of a full or partial Forced Outage in accordance with Services Tariff Section 5.12 and Outage Scheduling Manual Section 3. Aggregations that are unable to operate to achieve the ISO’s dispatch due to the direction of the Distribution Utility will remain subject to any charges or penalties that may apply.
4.1.10.7.3Role of the Relevant Electric Retail Regulatory Authority
Each Aggregator shall ensure that its Aggregation and the individual Generators, Demand Side Resources, and Distributed Energy Resources participating in the its Aggregation, comply with all applicable rules and regulations promulgated by the Relevant Electric Retail Regulatory Authority and included in a Distribution Utility’s tariffs that are accepted and/or approved by the Relevant Electric Retail Regulatory Authority.
The ISO shall provide to each Distributed Energy Resource’s Relevant Electric Retail Regulatory Authority the physical and operational data collected for the Distributed Energy Resource upon the Resource’s enrollment in the ISO-Administered markets upon request. The Relevant Electric Retail Regulatory Authority shall have the opportunity to submit information to the ISO that will aid in the ISO’s determination of the capacity and/or wholesale market services a Distributed Energy Resource is authorized to supply. The ISO shall consider information provided by the Relevant Electric Retail Regulatory Authority in its evaluation of a Distributed Energy Resource.
4.1.11Dual Participation
Effective May 1, 2020, Generators and Demand Side Resources, and Distributed Energy Resources electrically located in the NYCA may simultaneously participate in the ISO-administered wholesale markets and in programs or markets operated to meet the needs of distribution systems located in the NYCA. Generators, and Demand Side Resources and Distributed Energy Resources engaged in dual participation must meet all applicable rules and obligations set forth in the ISO Tariffs.
Generators, and Demand Side Resources, and Distributed Energy Resources operating to meet an obligation outside of the ISO-administered wholesale markets must Bid in a manner that ensures they will be dispatched by the ISO for the market intervals consistent with the manner in which the Resource operates to meet such obligation(s). The ISO and Transmission Owners shall coordinate scheduling and dispatch for all Generators, and Demand Side Resources, and Distributed Energy Resources engaged in Dual Participation in accordance with ISO Procedures. The ISO has the authority to determine schedules for these resources.
Effective Date: 12/31/9998 - Docket #: ER21-2460-000 - Page 1