Participant Readiness Project Outlook

Last update: 01/25/2023

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 selected projects that may affect your organization in the coming months. Projects are added to the outlook after the solution is designed and participant impacts are identified. Project pages are published as the projects unfold and more detailed materials and resources are developed; these pages provide details on the project and actions required, as well as links to training materials and other resources.

Click the names of projects with hyperlinks to see the related project page.
Click here to subscribe to the Participant Readiness mailing list to receive notifications when this page or the project pages are updated. Click send when the subscription email opens up.
Refer to the Wholesale Markets Project Plan page and Key Project pages to follow the course of proposed projects and initiatives from introduction to implementation.

Upcoming Projects

Project	Target Launch	Participants Affected	System Affected	Scope of Change
Do Not Exceed (DNE) Dispatch Wind, intermittent hydro, and solar resources may operate up to a do not exceed limit and will be dispatchable in real time.	Implemented May 24, 2016: wind DNE required, intermittent hydro DNE optional Implemented April 29, 2017: intermittent hydro DNE required December 4, 2023: solar DNE required	Lead market participants and designated entities with wind and, intermittent hydro, and solar resources	RTU	Remote terminals units (RTUs) must be installed or upgraded for all do-not-exceed dispatchable generators (DDGs).
	Implemented May 25, 2016: wind DNE required, intermittent hydro DNE optional Implemented April 30, 2017: intermittent hydro DNE required December 5, 2023: solar DNE required	Lead market participants and designated entities with wind and, intermittent hydro, and solar resources	MIS	Affected participants will see DNE-specific values and column heading updates added to MIS reports.
	May 31, 2019: Day-Ahead Energy Market participation required for wind and intermittent hydro for operating day June 1, 2019 December 4, 2023: Day-Ahead Energy Market participation required for solar for operating day December 5, 2023	Lead market participants of wind, intermittent hydro, and solar DNE dispatchable generators (DDGs) with CSOs	eMarket	Day-Ahead Energy Market participation required 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.

Completed Projects

Project	Launched	Participants Affected	System Affected	Scope of Change
Forward Capacity Market (FCM) Cost Allocation & Accelerated Billing Effective June 1, 2022, most monthly FCM settlements and bills will be settled daily and billed twice weekly, and the net regional clearing price (NRCP) calculation will be replaced with a new FCM cost allocation to improve transparency by reporting each pricing component separately.	June 1, 2022	Participants with resources participating in the FCM	Internal Transactions	Capacity load obligation bilateral confirmations will be due at noon on the first business day of the settlement month.
			Submit Peak Contribution	Future dates will be allowed in the user interface and the file upload.
			Financial Assurance Management (FAM)	A Daily FCM Requirements section and its sub-components will be added to FAM.
			Market Information Server (MIS)	Several reports are being retired and added.
			Billing / Settlements	Daily settlement and twice-weekly billing will result in the following: Financial assurance will not increase during the time when monthly capacity load obligation is calculated and the previous month is still unbilled. The time that capacity resources have to wait for payment will decrease. A preliminary month-ahead settlement will be run five business days prior to the start of the operating month.
Forward Capacity Market (FCM) Non-Commercial Capacity (NCC) Trading Financial Assurance (FA) Effective with the 13th capacity commitment period (CCP) beginning June 1, 2022, a new “NCC Trading FA” obligation will be introduced to incentivize participants to notify ISO New England of a resource with non-commercial capacity that will not achieve commercial operation and to withdraw it from CPS monitoring.	ART and CSOB March 29, 2022 FAM May 2022	Participants with capacity supply obligations (CSOs) for resources with non-commercial capacity	Forward Capacity Market Annual Reconfiguration Auction & ARTs and Forward Capacity Market CSO Bilateral Contracts	The market participant of the transferring resource engaged in a CSO Bilateral and/or an Annual Reconfiguration Transaction (ART) will be required to provide responses to the following questions: “Do related side transaction(s) exist?” “Is the acquiring counterparty an affiliate?” The responses to these certifications will determine the amount of NCC Trading FA from a CSO Bilateral or ART. Certifications for confirmed CSO Bilateral Contracts and ARTs for the 13th CCP will be required.
	ART and CSOB March 29, 2022 FAM May 2022		Financial Assurance Management (FAM)	The “Monthly FCM Requirements” section of the “Obligations Detail” display will be modified to include the following: An “NCC Trading FA” line item with the ability to view further details A “Future Effective” NCC Trading FA line item that will provide the NCC Trading value for the next obligation month
Ownership Transfer & External Registration (OTER) The Customer and Asset Management System (CAMS) was enhanced to allow participants to create load assets and SOGs, perform asset lead participant, meter reader, and ownership share transfers, retire assets, and improve asset search capabilities.	Phased implementation completed March 1, 2022	Participants that want to: register load assets and settlement-only generators (SOGs) transfer assets to another Lead Participant transfer ownership share transfer the Meter Reader role retire an asset search for a portfolio of assets and export the results	CAMS	CAMS application group roles for generator asset maintainers and load asset maintainers user interface screens where participants will manage their asset transactions search and export features
Generator Survey System Project (GSS) Create a web-based surveying tool to collect confidential generator data during normal, energy alert, and energy emergency conditions under the requirements defined in Operating Procedure 21 (OP 21) and OP 21 Appendix A	September 14, 2021	Lead market participants and designated entities with generator assets	Ask ISO	Enhance authentication and security Streamline the request and submittal process Automate reminder notifications
Streamline Asset Registration (SAR) Create a new module to submit asset ownership transfer view meter reader and lead market participant asset relationships, and view alternative technology regulation resources (ATRRs), asset-related demand (ARD), tie-lines, and non-energy assets	Phase III January release: Search and view ATRRs Phase III April release: Search and view ARD Phase III June release: Search and view Tie-Line and non-energy assets	All participants registering new generation, load, SOGs, ARD, ATRRs, non-energy assets or tie lines All participants processing asset relationship transfers between owners, meter readers and lead market participants	CAMS	To access asset information in CAMS, affected participants must have an active ISO-NE certificate and at least one asset registration application group roles assigned to their person record in the Customer and Asset Management System (CAMS)
Energy Storage Device (ESD) Allow participants to register a single energy storage asset as an Alternative Technology Regulation Resource (ATRR), a non-regulation capable generator, and a dispatchable-asset-related demand (DARD) asset in order to offer its full range into the regulation market while maintaining its ability to operate as a dispatchable energy market resource	Phase 2, release 2: March 1, 2020 Phase 2: December 1, 2019 Phase 1: April 1, 2019	Participants with grid-sized storage technologies and generators monitoring RTU failure–to-follow data	eMarket	Obtain a day-ahead position that respects the Max Daily Energy and Max Daily Consumption offer parameters Build a real-time offer that will enable the ESD to meet its day-ahead position Add new validations specific to ESD assets
			Remote Terminal Unit (RTU)	Add new telemetry values to receive ESD current state of charge Add market data to reliability session for ESDs because they will not receive market data via the normal market session Set failure-to-follow flag for all generators to “always following”; data received via the RTU should be disregarded after implementation
			Settlements	Update Lost Opportunity Cost calculation to accommodate single input telemetry value View failure-to-follow data for all generators in settlements Add to settlements for FCM Payments, Energy, Regulation, Energy Quantity, Annual Peak Load Reserves, DA NCPC, RT Generator/DARD NCPC Settlements, Settlement Funding Tariff 12/1/19 – exempt from Schedule 9 Regional Network Service and Local Service transmission charges when dispatched to charge for service
			MIS Reports	DA/RT NCPC reports Regulation reports
Offer Caps (FERC Order 831) Encourage participants to offer supply when short-run costs exceed existing offers caps by allowing cost-based incremental energy offers and make-whole payments	March 1, 2020	Participants submitting eMarket offers for generators and demand response resources; all other bids and offers	eMarket and related XML	All incremental energy offers submitted on the Schedule Hourly Offers Updates display and its related XML will be accepted and stored, but will be soft capped at $1000/MWh until verified by the new auto-raise function A new auto-raise function will adjust soft capped offers over the $1,000/MWh soft cap up to the lesser of the last submitted value or reference schedule without requiring participant intervention The Schedule Offers Default display will continue to reject energy offers over the existing $1,000/MWh cap Verified cost-based incremental energy offers will be hard capped at $2,000/MWh when calculating LMPs Demand response resource participants will be able to view and download their reference schedules
			Internal market Monitor Asset Characteristics (IMMAC)	Demand Response Resource (DRR) details and change request functionality will be available
			Settlements / NCPC	Incremental energy costs verified after the market was cleared that are above $1,000/MWh will be analyzed to determine if make-whole payments will be granted
Energy Market Opportunity Cost (EMOC) Provide market participants with an estimated daily opportunity cost for use in energy market offer formulation. Will better enable economic commitment and dispatch to make the most cost-effective use of limited fuel supplies during stressed operating conditions.	Phase 2: December 3, 2019 Phase 1 implemented: November 29, 2018	Lead market participants of oil-fired and dual-fuel generators with short-term fuel supply limitations and eMarket users for all Generators and Demand Response Resources	Internal Market Monitor Asset Characteristics (IMMAC) module within the Customer and Asset Management System (CAMS)	Phase 2: calculate a real-time opportunity cost and separately report the carbon permit price; Phase 1: display an estimated opportunity cost on a daily basis before the day-ahead window
			eMarket	The real-time reoffer period for all Generators and Demand Response Resources will open by 8:00 PM
Update Enhanced Energy Scheduling (EES) Technical Architecture Create a new user interface for participants to submit external transactions and assign subaccounts; replace the JAVA Applet architecture to improve system performance	October 23, 2019	All Enhanced Energy Scheduling (EES) software users	Enhanced Energy Scheduling (EES)	The new participant 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 participant submittal platform.
			WebServices	New file formats for data uploads and downloads will be available.
			CAMS Subaccounts	Subaccounts created in CAMS will be available for assignment in the NEXTT user interface. (See the Divisional Accounting project for more information on subaccounts).
			MIS	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).
Balance of Planning Period: Financial Assurance (BOPP FA) Implement a balance-of-planning-period monthly auction structure for Financial Transmission Rights (FTRs) and adjust associated financial assurance calculations	September 17, 2019	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.
			Web Services	New web services to be available for FTR auction results
Annual Reconfiguration Transactions (ARTs) are designed to provide the equivalent of a bilateral transfer of a capacity supply obligation (CSO) at a fixed price. By entering into an ART and participating in an annual reconfiguration auction, a capacity supplier can achieve price-quantity assurance (to the extent the capacity is substitutable) when either acquiring or shedding a CSO.	April 30, 2019	Participants and their counterparties seeking to acquire or shed CSO with price certainty	ISO New England SMD Application: Forward Capacity Market Reconfiguration Auction User Interface	Enhancements to include: Three ART submission windows for a capacity commitment period, each coincident with a submission window for annual reconfiguration auction (ARA) bids and offers Provisional ART windows available prior to the ART submission window; if the provisional ART passes validation, it is converted to an ART when the ART submission window opens
			Financial Assurance Management (FAM)	Financial exposure from ARTs will be included in financial assurance obligations.
			Market Information Server (MIS)	The existing ARA report will be enhanced to include information about each confirmed ART.
Forward Capacity Market (FCM) Delayed Commercial Resource Treatment (DCRT) a.k.a. Capacity Supply Obligation (CSO) Cover Changes Introduce a monthly “failure-to-cover” charge to incentivize participants unable to fulfill their CSO to take action to cover their obligation or assume a charge based on the amount of CSO that is not covered by the capacity a resource has demonstrated its ability to provide	Implemented: February 12, 2019 For CCPs beginning June 1, 2022 (CCP-13), the monthly failure to cover rates will be derived per 13.3.4 (b) of the Market Rule	FCM participants with resources unable to fulfill their CSO for each month within the applicable capacity commitment period (CCP) (Existing import capacity resources will be excluded from maximum demonstrated output and failure to cover charges)*	Forward Capacity Market Reconfiguration Auction	ISO New England will stop its practice of submitting demand bids on behalf of project sponsors with projects that have not achieved their critical path schedule milestones and have not covered their CSO for the applicable portion of the CCP Participants can avoid incurring failure to cover charges by submitting demand bids in the third annual reconfiguration auction (ARA 3) or the June monthly reconfiguration auction The maximum demonstrated output (MDO) calculation will be introduced which is the highest output level of an asset over a defined historical period Participants will compare the sum of the MDOs of all assets mapped to a resource to verify that the CSO does not exceed the MDO total The MDO will be provided to participants prior to ARA 3
			Settlements	The concept of an “unproven CSO quantity test” will be introduced to calculate the difference between a resource’s CSO and its MDO. The monthly charge for each resource with an unproven CSO quantity will be calculated as the product of the monthly failure-to-cover charge rate and the unproven CSO quantity
			MIS	The FCM Settlement Summary report will be updated to include failure–to-cover charges and credits An FCM Failure-to-Cover Detail report will be introduced The FCM Capacity Load Obligation Settlements Detail report will be updated to include failure-to-cover credits The Pre-ARA 3 Maximum Demonstrated Output annual report will be distributed prior to ARA 3
			Forward Capacity Tracking System (FCTS)	Pipeline analysis plans will not be required after the new unproven quantity test and the failure-to-cover charge are implemented. These mechanisms are designed to ensure that participants are covering their obligations without the ISO specifically tracking uncovered obligations. In FCTS, pipeline analysis plans: Assigned to new demand capacity resources for the 11th and 12th forward capacity auctions (FCAs) will be removed from FCTS Will not be assigned new pipeline analysis plans at the conclusion of each FCA effective with the conclusion of FCA 13
Competitive Auctions with Sponsored Policy Resources (CASPR) Implement a substitution auction (SA) to be run after the primary Forward Capacity Auction (FCA) to coordinate the entry of new sponsored policy resources (SPRs) with the exit of older existing capacity resources willing to permanently retire; this pairing of entry and exit minimizes the impact that SPRs have on competitively-based capacity prices, maintains resource adequacy, and reduces over-supply concerns	February 4, 2019	Forward Capacity Auction participants with one of the following: New sponsored policy resource Existing generating capacity resource with either a full or partial retirement delist bid, or qualified capacity seeking to participate in the SA as demand Import resource with an external elective transmission upgrade with either a full or partial retirement delist bid, or qualified capacity seeking to participate in the SA as demand	Forward Capacity Tracking System (FCTS)	Participants requesting to qualify a new resource as an SPR will use FCTS to: Elect to participate in the SA via a show of interest (SOI) Provide documentation in the new capacity qualification package certifying that the new resource is a an SPR Submit final supply offers for the FCA qualified capacity, if qualified as an SPR Participants with an existing generating capacity resource or import capacity resource with an external elective transmission upgrade will use FCTS to: Elect to participate as demand in the SA Submit demand bid quantities
			Financial Assurance Management System (FAM)	FAM will be updated to determine exposure and adjust the FA requirement as necessary for the following: Negative-priced supply offer segments submitted by SPRs Existing resources that elected, in a prior FCA, to have their CSO and capacity clearing price continue to apply after the applicable capacity commitment period, and then submitted a demand bid into the SA at a price greater than the rate-lock price.
			Substitution Auction	Participants with a new SPR will be prevented from electing a multi-year CSO and capacity clearing price for any capacity that clears in the SA Participants with an existing resource that will participate in the SA as demand will be prevented from: Designating it as self-supply Including it on an offer composed of separate resources Automatically matching it to an offer The SA supply offer of an SPR receiving a CSO in the primary FCA will be reduced by the difference between its qualified capacity and its awarded CSO. The demand bid from an existing resource that exceeds the CSO awarded to that resource in the primary FCA will be reduced to equal the awarded CSO.
			MIS	FCA Auction Results MIS Report will be updated to include results from the SA.
Customer Contact Center Solution (CCCS) Replace the current Ask ISO platform to improve participant-issue management and contact identification by integrating voice, email, and case-tracking systems, as well as to address business continuity goals	August 27, 2018	All participants and stakeholders submitting inquiries to ISO New England via phone, email, or Ask ISO	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.
	August 27, 2018		CAMS	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.
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	June 1, 2018	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.
			eMarket	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	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.
			Settlements	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 Morning Report will include DRR capacity.
Forward Capacity Market Pay-for-Performance (FCM PFP) Replace the FCM availability metric with a performance metric based on measurable energy delivered and reserves provided	June 1, 2018	Lead market participants for all resources	Financial Assurance Management (FAM)	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.
			Settlements	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.
			Web services	A new scarcity conditions report will be available.
			Market Information Server (MIS)	New reports will be introduced and others will be retired.
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	Implemented phases: 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.
			Web services	New end point URLs will be available to download preliminary of final: five-minute LMPs five-minute reserve five-minute constraints five-minute regulation clearing prices
			ISO Express	Revised pricing reports and preliminary and final grid reports will be downloadable in a CSV format for: Binding constraints Energy LMPs Reserve prices NCPC Regulation Clearing Prices
			Settlements	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.
Internal Market Monitor Asset Characteristics (IMMAC) UI Allow participants to submit asset characteristics data directly to the ISO’s Internal Market Monitor (IMM) and view current data on file with the IMM via the Customer and Asset Management System (CAMS)	July 11, 2017	Lead market participants with generator assets, except for settlement only generators	CAMS	To use the new IMMAC module in CAMS, affected participants must have an active ISO-NE certificate and be assigned the maintainer or viewer role.
Real-Time Fast-Start Pricing (FSP) Improve the Real-Time Energy Market’s pricing logic to enable fast-start resources to set price more frequently	March 1, 2017	Lead market participants with fast start generators or demand-response resources, flexible DNE dispatchable generators, and certain dispatchable-asset-related demand resources	Settlements	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	eMarket and related web services	New bidding parameters (submit): Maximum Daily Consumption Limit Maximum Number of Daily Starts New resource modeling parameters (view-only): Minimum-Run Time Minimum-Down Time New NCPC type parameters: Daily NCPC Dispatch Lost Opportunity Cost Daily NCPC Rapid Response Pricing Opportunity Cost
	March 1, 2017		Settlements	Day-ahead and Real-time Net Commitment-Period Compensation (NCPC) settlements will be modified to include NCPC payment calculations for DARD pumps, including NCPC dispatch lost opportunity cost.
Interconnection Request Tracking Tool Elective Transmission Upgrades (IRTT ETU) Replace the Interconnection Request Tracking Tool (IRTT) with an improved version for use by participants to submit interconnection requests	February 17, 2017	Participants and project proponents with new or existing interconnection requests (IRs) for generators or Elective Transmission Upgrades (ETUs)	IRTT	The new version of the IRTT will be improved and enhanced to enable online submittal for ETU IRs. Existing data, user names, and passwords will be migrated to the new application automatically.
Participant One-line Diagram Submissions Modify the NX912D Application (NX-9 and NX-12D) for participants to submit one-line schematic diagrams and area overviews	December 20, 2016	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	NX912D	Current participant schematics and overviews will be required for initial load prior to production releases.
	December 20, 2016		CAMS	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	CTM/DDMS	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.
	May 14, 2016		CAMS	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 participants 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	Multiple Phases	Market participants who are interested in using divisional accounting to segregate the reporting of their market activity by specific settlement subaccounts	CAMS	Participants can create subaccounts, assign assets and resources, and add subaccount reporting in the Customer and Asset Management System (CAMS).
			eMarket	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.
			FCTS	Participants can assign subaccounts to self-supply requests in the Forward Capacity Tracking System (FCTS).
			MIS	Participants can create new informational Market Information Server (MIS) reporting by subaccount.
			NEXTT (to replace EES in Q3 2019)	Participants will be able to assign subaccounts to external transactions using NEXTT user interface
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	JESS	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	EES	Affected participants can now select an eTag ID and link it to the EES schedule.
		All market participants using pricing data	MIS	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	Selectable pricing reports	Affected participants can now choose to see 15-minute pricing and constraints data in selectable ISO Express reports, such as the Selectable Day-Ahead and Real-Time Hourly Demand Report.
		Market participants using pricing data for Roseton pricing node 4011	Web services	Affected participants can now access new endpoints for CTS in the ISO’s web services data.

What We Do

Regional Electricity Outlook

Corporate Governance

Key Grid and Market Stats

Government and Industry Affairs

News and Media

Careers at ISO New England

Contact the ISO

Applications and Status Changes

Participant and Asset Listings

Training

Support

Governing Agreements

Rules and Procedures

Regulatory Filings and Orders

Participants Committee and Working Groups

Markets Committee and Working Groups

Transmission Committee and Working Groups

Reliability Committee and Working Groups

Planning Committees

Industry Collaborations

Inactive Committees

Key Projects

Plans and Studies

System Forecasting

Interconnection Service

Transmission Planning

Key Study Areas

Planning Models and Data

ISO Express

Markets Data and Information

Power System Forecast and Status

Market Performance

Market Monitoring and Mitigation

Market Development

Settlements and Billing

Transmission Operations and Services

Participant Readiness Project Outlook

Upcoming Projects

Completed Projects