A presentation was given on the analysis updates regarding Non-Spin resources, specifically online Non-Spin resources, and how they were being deployed.
It was noted that the analysis did not change the initial recommendation to recommend that Non-Spin duration lasts at least 4 hours.
Online Non-Spin capacity must be offered at a minimum of $75 per megawatt hour as per the protocols, with this capacity being available to SCED for deployment as needed.
An estimation was conducted to evaluate the deployment of online Non-Spin resources by SCED.
Historical data from 06/01/2018 to 03/27/2025 was analyzed, showing that 81% of events had a duration of four hours or more.
Questions were raised regarding the impact of different price floors on the event patterns and on the reliability determination.
A discussion was held on a specific date's analysis where forecast errors led to extended deployment of Non-Spin capacity.
Nitika Mago presented that the deployment patterns are driven by weather events and forced outages, which are difficult to forecast accurately.
Clarifications were made regarding the adjustments to battery state of charge calculations and their implications for the reliability need analyses.
It was concluded that the information shared did not change the existing recommendation but highlighted the usage of Non-Spin capacity during system demands.
The draft NPRR includes additional sections for clarity on qualification and monitoring criteria.
Key changes introduced include adjusting durations in various sections with acronyms established for consistency.
In reliability unit commitment, a new paragraph includes a 60-minute duration for energy and ancillary services, excluding RRS provided using fast frequency response with a 15-minute duration.
Changes include replacing a 15-minute duration with 30 minutes in regulation and responsive reserve.
Adjustments also seen in monitoring criteria, replacing 15 minutes with 30, and ECRS criteria changed from two hours to one hour.
Discussion on the impact of Non-Spin resource qualification and ECRS.
Nitika Mago addressed the revisions focusing on regulation updates and ERCOT’s intention to file the NPRR.
Stakeholder comments emphasized the importance of ensuring market stability and considerations for evolving reserve durability.
Concerns raised regarding state of charge (SOC) limits and how language applies to breakdown scenarios.
Further inquiries included how the NPRR aligns with security constraints and socioeconomic dispatch parameters, ensuring it doesn’t violate max/min SOC limits.
Clarification provided that adjustments are needed when transitioning from a combo model to a single model concerning ESR registration.
Queries about the impact of the NPRR changes on day-ahead market ancillary services.
Stakeholders invited to provide further comments or proposals before the next session, with potential for additional sessions based on feedback.
Specific sections of the handbook are marked in green to indicate completion by ERCOT; this helps to show what the QSE needs to accomplish.
Section three of the handbook is crucial and has been discussed in past meetings.
ERCOT will run RTC SCED in the market trials environment using market submissions and telemetry, with published prices and dispatch information.
Introduction of 'non-monitored operating days' where QSEs submit real-time offers with 80%-120% cost representation. Participation is not enforced but expected to improve market results.
NPRR1058 allows all resources to update offers during the operating hour, with a mandatory reason in the text field for changes.
SCED-generated capacity prices will be published by interval on ERCOT.com; reports must be downloaded as no dashboards or specific displays will be provided.
SCED operations will occur on business days, specifically Tuesdays and Thursdays from 9 to 5, which provides a regular schedule for participants.
The handbook is being finalized and flagged as complete, but changes can be made if necessary.
There was a question about schema changes for recent code requirements; it was clarified that the reason field is already part of submissions and will be validated during the operating period.
The same update logic for energy offer changes will apply to AS offer submissions, pending confirmation.
Introduction of a new frequency control test from September to October, described as challenging.
Proposal of a two-hour test with QSE participation, ensuring reliable RTC SCED dispatch and frequency control without significant operational disruption.
ERCOT to provide a minimum of ten business days advanced notice before test dates, with tests conducted to prevent frequency issues.
Details on managing transition risk through parallel production systems and binding RTC SCED during tests.
Minimizing the risk of significant redispatch through guardrails requiring QSEs to enter identical energy offer curves for both current and RTC systems.
Specific instructions for AS responsibilities: $0 offers for resources carrying responsibilities and $2,000/megawatt for others.
Consideration of current duration requirements over RTC during LFC tests for ESRs with response AS responsibility.
Telecom assumptions for QSEs and possible test run LFC to ensure QSE offers and telemetry are functioning prior to main tests.
Detailed test execution phases involving gradual QSE transition to RTC control, minimizing frequency swings during the test’s two-hour window.
Clarification on AS trades or changes within the test window, ensuring QSE can update offers as needed.
Financial settlements during tests based on current system prices, exempting base point deviation charges to prevent penalties.
Dispute conditions limited to financial harm instances, with criteria based on protocol 6.6.9(4)
Discussion on potential repeat of the test twice if needed, with adjustments based on findings.
Key Participants
ERCOT representatives introducing and explaining the test process.
Q&A from attendees like Ned Bonskowski, Dave Maggio, and Chris Espinosa providing additional inquiries on operational details.
Questions addressing specific scenarios like AS responsibility shifts and telemetry requirements.
Next Steps
Take feedback back to respective teams and provide additional questions or concerns in the next round of discussions.
Refine clarifications on AS offer protocols and test logistics prior to next meeting.
Overview of the progress and future integration of battery energy storage systems into the ERCOT system.
Increase in battery energy storage capacity from less than 200 megawatts in 2019 to over 11,000 megawatts today, with expectations of reaching 18,000 by the end of the year.
Duration of batteries in the system mainly consists of one-hour duration batteries, with a future trend towards longer duration batteries.
Implementation of real-time co-optimization where more ancillary services are expected to be provided by batteries.
Introduction to new NPRRs that support the transition such as NPRR1014, NPRR1204, NPRR1236 and the cleanup NPRR1246.
Details about the single model approach which includes registration, qualification, modeling, and telemetry as a single resource.
Modification of setpoint deviation calculation with tighter tolerance requirements being implemented.
Procedures for submission of energy bid offer curves and real-time management in the day-ahead and real-time markets.
RUC processes including DRUC and HRUC will be used to ensure enough capacity in future hours and how state of charge information will be utilized.
Deployment factors will simulate potential AS deployment used for future RUC calculations.
Discussion on how deployment factors are determined and how they can impact the market participants' operations.
Multiple questions were raised and answered about deployment factors, tolerances, and operating procedures.
Discussion on the timing and phases of report deliveries.
Reports will be delivered in multiple phases: no new reports on May 5, but introduction of wave one and wave two groups.
Group One involves open loop testing reports including RTC energy prices, binding constraints, adders, and market clearing prices for ancillary services.
Group Two involves closed loop testing, with seven additional reports and 11 new CDR reports available in September.
Some reports could be moved up to July for integration testing.
Reports are categorized as existing, modified, or new, with some changes not affecting the data itself.
The complete inventory includes around 95 reports, detailing when each will be released and any associated changes.
Dashboards and XSD files also discussed; XSDs available by October 15 for integration building.
The ERCOT reporting inventory tool, EMIL, was mentioned as a resource for tracking reports.
No significant changes in graphic/dashboard elements except for a few modifications.
