ISO New England undertakes many projects and initiatives in collaboration with stakeholders for the continued development of the region’s wholesale electricity markets. Listed below are upcoming major projects that may affect your organization over the next 12 months. Projects are added as they are scheduled; in some cases projects are scheduled and implemented in a shorter timeframe and may be added to the list close to their target launch. This page is generally updated on a monthly basis, though more frequent updates may be made in response to a significant change in the project plan.
Click the names of near-term projects to see details on the project and actions required, as well as links to training materials and other resources.
Price-Responsive Demand (PRD) Project
Fully integrate demand response resources (DRRs) to participate in the energy and reserve markets and to be eligible for Forward Capacity Market (FCM) shortage event penalties or credits, as well as peak energy rents
Market participants and demand-designated entities (DDEs) with demand response (DR) assets
Customer and Asset Management System (CAMS)
DR entities will be assigned new asset and resource IDs to be converted to the three-level PRD entity model:
Demand response assets (DRAs)
Demand response resources (DRRs)
Active-demand capacity resources (ADCRs)
The concept of DRR aggregation zone pnodes will be introduced.
Scheduled and forced curtailments for DRAs will be submitted in CAMS
The new DRR IDs and the converted DRA IDs will automatically be assigned to the default subaccount. Participants that choose to use subaccount reporting for these entities will assign subaccounts at go-live.
New displays specific to DRRs will be available in the user interface (UI).
Using the eMarket UI, DR market participants will:
Create portfolios, day-ahead (DA) schedules and real-time (RT) schedules
Submit DA and RT transactions
Be able to enter hourly overrides of physical parameters
Remote terminal unit (RTU)
RTUs will be upgraded and tested prior to go-live.
The desired dispatch point (DDP) for each DRR will be included in the data to convey the requested consumption reduction below the DRR’s adjusted baseline.
DR Audit and Testing Tool (DRATT)
Beginning in early May 2018, DR audits will be put on hold but requests will continue to be accepted for audits commencing June 1, 2018, or later.
ISO New England SMD Applications
Real-time demand response (RTDR) and real-time emergency generation (RTEG) will be removed from the Meter Reader UI.
Demand Response Market User Interface (DRMUI)
The DRMUI will allow download of three baseline types (weekday, Saturday, Sunday/Holiday), baselines for prior days, interval performance data by asset, and interval performance data by resource.
Baseline calculations for Saturdays and Sunday/DR holidays will use the five most recent uninterrupted like-days during the past 42 days rather than non-holiday weekdays as implemented June 1, 2017.
Forward Capacity Tracking System (FCTS)
Existing DR field labels in the UI will be updated to new PRD terms which will also display in historical views with the old DR data model.
DR will be settled via the established two-settlement process where RT market quantities are used to determine participants’ actual operation deviations from their day-ahead (DA) energy positions.
Real-time Net Commitment-Period Compensation hourly shortfall will be introduced.
Market Information Server (MIS)
New reports will be introduced as well as others being retired.
Web services and web publishing
New eMarket WebServices upload/download and XML functionality for DRRs will utilize new DRR terminology.
The potential for resources with capacity supply obligations (CSOs) to have negative capacity payments under the new PFP rules will be collateralized by adding a financial assurance requirement for Forward Capacity Market delivery.
Performance deviations during a reserve deficiency will be settled using the two-settlement approach in which over-performing resources are credited and underperforming resources are charged at a pre-specified rate.
A stop-loss mechanism will be introduced to ensure resource owners do not face unlimited losses for non-performance.
Every resource will be eligible for performance payments, whether or not it has a CSO.
Forward Capacity Tracking System (FCTS)
Lead participants of passive resources will submit a show of interest (SOI) to be eligible for capacity performance payments (CPPs) when performing during a scarcity condition. (The eligibility for CPPs to be paid for external transactions, generators, and demand response resources that are not mapped to a resource will be determined through the settlement process.)
Enhanced Energy Scheduler (EES)
Flex reservations will no longer be an option.
ISO New England SMD Applications
The supplemental availability designation user interface will be retired.
The supplemental availability bilateral option will be replaced with a capacity performance bilateral option within the internal transactions user interface.
The Submit Meter Reading user interface will require all 24 hours to be reported, CSV and XML formats will change, terminology will be updated.
A new scarcity conditions report will be available.
Market Information Server (MIS)
New reports will be introduced and others will be retired.
Scope of Change
Customer Contact Center Solution (CCCS)
Replace the current Ask ISO platform to improve customer-issue management and contact identification by integrating voice, email, and case-tracking systems, as well as to address business continuity goals
All customers and stakeholders submitting inquiries to ISO New England via phone, email, or Ask ISO
Users submitting inquiries directly to the Ask ISO application will be able to access the system with their unique email and password, instead of with the existing digital certificate access process.
A self-service support community will be available to allow users to search knowledge articles for frequently asked questions, to submit inquiries, and to categorize issues to expedite system access and issue routing.
Phone, email, and other contact data will be shared between the Customer and Asset Management System (CAMS) and Ask ISO to create user accounts and update contact information. Security Administrators are encouraged to review CAMS Persons records ahead of this release, particularly phone numbers and e-mail addresses.
Market participants eligible to bid in the Financial Transmission Rights market
Financial Assurance Management (FAM)
FTRs that have the same path, class, and month but were awarded in different auctions may be netted for financial assurance calculations to avoid “double-margining”; unsettled FTR financial assurance will be introduced; and the pre-awarded/award auction obligation will be removed.
Financial Transmission Rights UI (eFTR)
The eFTR sandbox will be updated prior to go-live. Upload and download processes may be tested using formatted CSV files, and add, modify, and delete processes may be tested in the user interface.
All Enhanced Energy Scheduling (EES) software users
Enhanced Energy Scheduling (EES)
The new customer interface will be named New England External Transaction Tool and will be referred to using the acronym “NEXTT.”
Retire the use of EES Java Applet architecture and replace the current EES user interface with a new customer submittal platform.
New file formats for data uploads and downloads will be available.
Subaccounts created in CAMS will be available for assignment in the NEXTT user interface. (See the Divisional Accounting project for more information on subaccounts).
Participants will be able to utilize existing informational Market Information Server (MIS) reporting by subaccount. (See the Divisional Accounting project for more information on subaccounts).
Scope of Change
Subhourly Settlements (SHS)
Transition the settlement interval from hourly to every five minutes to align with the real-time dispatch instruction and pricing intervals for the Real-Time Energy Market, Regulation Market, Net Commitment-Period Compensation (NCPC), and reserve markets for generators, load resources, and external transactions
March 1, 2017: transition to five-minute settlement interval
August 1, 2017: five-minute meter reading submittal allowed as an optional feature
December 1, 2017: implement five-minute interval settlement for regulation capacity and regulation service
Lead market participants submitting Roseton node external transactions, owners of resources that can respond quickly to dispatch instructions, data-scrapers using HTML client programs, and meter reading submitters
Meter reading CSV and XML upload and download files
Affected participants will continue to submit hourly data values to the ISO at the project go-live.
The ISO offered the option to accept five-minute revenue Quality (RQM) data from meter readers beginning August 1, 2017.
The five-minute meter reading submittal option MUST be authorized by the host participant meter reader.
The decision to submit five-minute meter readings is final. There is no option to convert back to hourly submittals.
New “profiling” methods will be used to calculate five-minute interval generation and load megawatt-hour (MWh).
A new FCM Demand Assets tab will be available in the UI for submittals.
Meter readers may choose to submit compressed GZIP files written in or compressed with a GZIP tool.
CSV formats for five-minute data and XML code will be updated to use Greenwich Mean Time (GMT).
Meter reading HTML client programs
Meter reading HTML client programs used for data-scraping must be upgraded to use XML RESTful web services.
Market Information Server (MIS)
MIS reports will be updated to provide settlement details with five-minute granularity for real-time energy, reserves, regulation capacity, regulation service, and real-time NCPC. A new energy quantity report will be developed.
New end point URLs will be available to download preliminary of final:
five-minute regulation clearing prices
Revised pricing reports and preliminary and final grid reports will be downloadable in a CSV format for:
Regulation Clearing Prices
The new dispatch lost-opportunity cost (dispatch LOC) NCPC calculation will be introduced for resources that are not providing regulation or postured during the interval.
Beginning December 1, 2017 introduce five-minute interval settlement for regulation capacity and regulation service.
Implemented July 11, 2017: allow participants to view Meter Reader and Lead Market Participant asset relationships
Implemented June 28, 2016: add Asset Registration tab and allow participants to submit ownership transfers
All customers processing asset relationship transfers between owners, meter readers and lead market participants
To use the new application, affected participants must have an active ISO-NE certificate and arrange to have the application role assigned in the Customer and Asset Management System (CAMS).
Do Not Exceed (DNE) Dispatch
Wind and intermittent hydro resources may operate up to a do not exceed limit and will be dispatchable in real time; project excludes solar resources at this time
Implemented April 30, 2017: intermittent hydro required
Implemented May 25, 2016: wind required, intermittent hydro optional
Lead market participants of wind and intermittent hydro units with a capacity supply obligation (CSO) or that are qualified generator reactive resources
Affected market participant must begin submitting outage requests into the Control Room Operations Window (CROW) Outage Scheduler application when an outage will reduce the real-time high operating limit (RTHOL) below its CSO or the available voltage amperes reactive (VAR) will be below qualified VAR.
Lead market participants and designated entities with wind and intermittent hydro resources
Remote terminals units (RTUs) must be installed or upgraded for all do-not-exceed dispatchable generators (DDGs).
Affected participants will see DNE-specific values and column heading updates added to MIS reports
Lead market participants of wind and intermittent hydro units with CSOs
Because Day-Ahead Energy Market participation will be required for DDGs with CSOs, affected market participants must arrange access to eMarket, the software platform used to submit required data and retrieve the day-ahead clearing results.
Lead market participants with fast start generators or demand-response resources, flexible DNE dispatchable generators, and certain dispatchable-asset-related demand resources
A new lost-opportunity cost calculated in real-time will be paid to units that are moved out of merit due to fast-start resources.
Market Enhancements for DARD Pumps
New modeling practices and bidding parameters to better reflect dispatchable-asset-related demand (DARD) operating characteristics in offer data and economic dispatch
March 1, 2017
Lead market participants with pump storage hydro-generating resources
Transmission owners of substations with a rating of 69 kV or higher, or as required per ISO Operating Procedure No. 16 (OP 16), Transmission System Data, and lead market participants with generators participating in the Real-Time Energy Market
Current participant schematics and overviews will be required for initial load prior to production releases.
New roles will be available in the Customer and Asset Management System (CAMS) for access to view and submit to the sandbox and production environments.
Generator Dynamics Data Management A new system for uploading and updating detailed technical information about the physical and operational characteristics of power system equipment
May 14, 2016
Lead market participants and nonparticipants required to report and certify generator dynamics data
Affected market participants and nonparticipants must access the Dynamics Data Management System (DDMS) section of the Customer Ticket Management (CTM) application to report and certify generator dynamics data.
In the Customer and Asset Management System (CAMS), the company security administrator must assign the contact type Generation Compliance Contact Primary and grant access to the Customer Ticket
Management/DDMS Compliance Officer role to the proper users.
Divisional Accounting (Subaccounts)
User-defined subaccounts were enabled to allow customers to segregate their settlement reporting by assigning assets and resources directly to a subaccount and assigning other activity-based transactions to subaccounts in various applications
Market participants who are interested in using divisional accounting to segregate the reporting of their market activity by specific settlement subaccounts
Participants can create subaccounts, assign assets and resources, and add subaccount reporting in the Customer and Asset Management System (CAMS).
Participants can assign subaccounts to transactions in the eMarket application.
Internal Transactions UI
Participants can assign subaccounts to transactions in the Internal Transactions user interface.
Participants can assign subaccounts to self-supply requests in the Forward Capacity Tracking System (FCTS).
Participants can create new informational Market Information Server (MIS) reporting by subaccount.
Coordinated Transaction Scheduling (CTS)
Enhanced scheduling procedures were enabled for external transactions at the Roseton interface, which allow market participant to submit a unified real-time bid to simultaneously purchase and sell energy on each side of the interface, with the bid price indicating the price difference between the two regions that the participant is willing to accept
December 15, 2015
Market participants transacting at the Roseton interface between ISO New England and the New York ISO
Affected participants must follow the process to get access to and create a password for the New York ISO Joint Energy Scheduling System (JESS) in order to submit external transactions at this interface.
All Enhanced Energy Scheduler (EES) software users
Affected participants can now select an eTag ID and link it to the EES schedule.
All market participants using pricing data
Affected participants can now access Market Information Server (MIS) reporting that include 15-minute pricing and constraints.
Market participants using pricing data for Roseton pricing node 4011