Motion to recommend approval of NPRR1282 as recommended by PRS in the 5/14/25 PRS Report passed with 93% in favor, two opposed, and one abstention.
Discussion on NPRR1282 centered on the evolving reliability needs and AS products required for grid stability.
ERCOT emphasized the need for longer duration ancillary services to manage variability and uncertainty on the grid.
A primary point was the recommendation to increase duration for regulation and RRS due to historical events like SCED failure.
ERCOT suggested maintaining a four-hour duration for Non-Spin Reserve to ensure grid reliability under forecast errors or outages.
There was significant debate on the appropriate duration for Non-Spin and ECRS, with differing views between ERCOT, IMM, and stakeholders.
ERCOT stated that Non-Spin with a four-hour duration is necessary based on operational experience and historical deployment events.
Stakeholders expressed concerns about market certainty, investment impacts, and the practicality of new duration requirements.
Several stakeholders argued for a one-hour product for Non-Spin in real-time to optimize flexibility and efficiency.
A motion was proposed but failed to pass, recommending a compromise that maintained four-hour qualifications but suggested one-hour procurement in real-time.
Another motion passed to approve NPRR1282 as recommended by PRS, with the understanding of potential revisits post-RTC go live.
▶️ 6 - Revision Requests Tabled at TAC (Possible Vote)
▶️ 6.1 - NOGRR264, Related to NPRR1235, Dispatchable Reliability Reserve Service as a Stand-Alone Ancillary Service
NOGRR264 remains tabled with no action required this month.
Motion to approve the RMS Strategic Objectives as presented added to the combo ballot.
2025 RMS strategic objectives approved and consolidated into 6 easy-to-understand goals that align with the RMS scope.
RMS Working Group and task force are progressing with key activities including the annual validation and an in-depth review of the load profiling guide.
Upcoming retail market training sessions: Retail 101 on June 18 and Texas SET 5.0 on June 25. Hosted by Vistra in Irving with some seats still available.
Texas data transport MarkeTrak system continues analysis for inadvertent gains, showing progress due to automation improvements in Texas SET 5.0.
Ongoing work on MarkeTrak application, quarterly reports, and retail system service level compliance.
In-depth review of Texas market test plan is underway, expected to take several meetings.
Next RMS meeting scheduled for Thursday, June 12 at 09:30am
Two voting items proposed for approval: RMS strategic objectives and recommendations related to OBDRR054 and the RMS report.
Motion to recommend approval of OBDRR054 as recommended by RMS in the 5/13/25 RMS Report added to the combo ballot.
The request is for revising the Texas market test plan to include pre-production testing requirements for market participants.
Currently, there's no requirement for market participants to complete pre-production testing if they were qualified on past versions.
Historical incidents occurred with Oncor, CenterPoint, and another case 16 years ago due to outdated qualifications.
An example was given of a market participant who was certified 16 years ago but faced issues when entering production as they used past versions of Texas SET transactions and NAESB EDM.
There was a lack of awareness about system changes required for the new versions among market participants.
Clarification was provided stating that all market participants must undergo qualification testing with any changes or when new Texas SET versions are released.
The current issue highlights the need for a language update in the Texas market test plan to prevent similar incidents.
Connectivity testing and billing/payment processes are part of these requirements, with retesting required if any system changes occur after initial qualification.
The first two items discussed were already covered under the PRS report for voting.
Both items received unanimous approval, indicating readiness for a combined ballot for TAC.
The DWG procedural manual was reviewed, with a separate ballot conducted due to generator segment extensions preferring to delay approval for advanced grid support testing.
Approval is contingent upon the passage of a protocol that would necessitate such testing.
Considerations were made regarding the potential for confusion with the current proceedings.
▶️ 8.1 - NOGRR265, Related to NPRR1238, Registration of Loads with Curtailable Load Capabilities
Completed work on NPRR1238 and NOGRR265.
Proposal to remove NPRR1238 and NOGRR265 from the TAC assignment, pending any confusion.
No objections were raised regarding the removal from the ROS action item list.
NPRR1238 and NOGRR265 will still remain on the TAC action item list for future meetings.
Next meeting is scheduled for June 5 and will be conducted via Webex.
▶️ 8.2 - NOGRR275, Eliminate Scheduling Center Requirements for QSEs That Are Not WAN Participants
Motion to recommend approval of NOGRR275 as recommended by ROS in the 5/1/25 ROS Report added to the combo ballot.
Discussion focused on NOGRR275 regarding scheduling center requirements.
A motion was suggested to put NOGRR275 on the combo ballot for approval.
ROS had recommended approval in the May 1 ROS report.
No objections or abstentions were noted for the motion.
Action was delegated to Cory to handle the motion.
▶️8.3 - NOGRR277, Related to NPRR1282, Ancillary Service Duration under Real-Time Co-Optimization – URGENT
Motion to recommend approval of NOGRR277 as recommended by ROS in the 5/20/25 ROS Report passed unanimously with 2 abstensions.
NOGRR277 was discussed under the ROS update and was previously approved by ROS via email vote with one abstention.
There were no objections to placing the NOGRR on the combo ballot.
The group voted to recommend approval of NOGRR277 as guided by ROS in the May 2025 ROS report, with one abstinence.
Several representatives provided their votes, with two abstentions from Bob Helton and Caitlin Smith.
Motion passed with approval from various representatives, indicating the motion carried.
Post-vote, the meeting was adjourned for a 20-minute break before resuming with subcommittee updates.
Motion to endorse the ADER Phase 3 Governing Document as presented added to the combo ballot.
The ADER Phase 3 Governing Document was an action item from TAC to WMS and has been closed out by the WMS side.
There was a discussion about tabling the document until the next TAC meeting due to significant edits and lack of detailed discussions at subcommittee or working group levels.
Voltus is interested in exploring options regarding two main issues: the authority given to LSE QSEs over their portfolio in context of the ADER pilot and a provision related to rejecting specific premises from ADER aggregation.
Voltus emphasizes the importance of a deadline for LSE QSEs to respond to third-party QSEs, suggesting possibly a 30-day window.
There is a goal to present the governing document to the board in June, but it is not mandated.
The procedural necessity of a TAC vote for advancing the document was questioned and left for further clarification.
Ned Bonskowski commented that the timing for responses should be worked out between the parties directly and need not be included in the governing document.
ERCOT plans to bring Phase 3 governing document to the board in June.
An associated report covers phase two experience, results, and issues.
The presentation highlighted phase two findings with 3 ADRs qualified at 15 megawatts energy, 8 megawatts Non-Spin reserve service, and 9 additional ADRs in registration.
Phase 3 proposed enhancements include increased pilot participation limits and a new participation model similar to a non-controllable load resource.
Discussion on telemetry validation enhancements and zonal dispatch analysis concerns.
Phase 3 governing document approved by WMS, accommodating 60 megawatts for energy and 84 megawatts for ancillary services.
Immediate increase proposed to 160 megawatts and 80 megawatts for energy and ancillary services due to growing interest.
Clarification requested on ERCOT's discretion in participation limits.
Presentation aims to move pilot to permanent market design.
Discussion on whether to vote on the phase three governing document; voting tabled for board meeting.
Support expressed for WMS governing document compromise, balancing retail and third-party access concerns.
The meeting was held on May 19 and covered several NPRRs and credit updates related to real-time co-optimization plus batteries.
A CRR credit proposal from DC Energy was reviewed, highlighting the need for potential changes to CRR obligation collateral. ERCOT will conduct a gap analysis.
Discussions included credit exposure calculations and potential revisions due to new AS virtual offers.
ERCOT presented a market credit risk corporate standard initiative to assess market participants' risk exposure.
A risk-based assessment of default risk is being introduced to better understand and mitigate potential default scenarios.
ERCOT emphasized this initiative as a market education event, not altering credit calculations or collaterals.
The session included a presentation on stress-testing scenarios similar to industry standards in banking to prepare for extreme volatility.
Credit highlights showed minimal changes with no significant activities or unusual collateral calls.
The large load queue has grown significantly in the past year from mid-40s gigawatt range to 56 gigawatts.
There was a net increase of 19 gigawatts in the queue, including new projects and cancellations.
Breakdown of project statuses includes: Energized, Approved to Energize, Planning Studies Approved, Under ERCOT Review, and Studies Submitted.
In the past year, 1,395 MW of load was approved to energize.
Of the 6,874 MW approved to energize, about half are in the Western zone, while the remainder is distributed in other load zones.
Standalone projects comprise 5,609 MW and colocated projects account for 1,265 MW.
ERCOT observed a non-simultaneous monthly peak consumption of 3,489 MW in May, slight decrease from last month.
The simultaneous monthly peak consumption was 3,441 MW in May, showing a slight increase from last month.
Project distribution by size: 93 projects in the 75-250 MW range, 66 in the 250-500 MW range, 53 in the 500-1000 MW range, and 56 projects over 1000 MW.
There were discussions on the need for further breakdown of project details, especially with NPRR1267 requests.
Stakeholders expressed interest in understanding project churn rate and how approvals evolve, considering some approved projects might later opt out.
▶️13.1 - Outage Coordination Outage Capacity Calculation and Process (Possible Vote)
Update on proposed revisions to the MDRPOC methodologies, seeking feedback from stakeholders.
Revisions aim to provide sufficient outage capacity compared to historical levels, applying risk-based methodology for outages more than seven days ahead.
The proposed revision incorporates feedback from stakeholders, presenting a new MDRPOC curve for better thermal generation resource evaluation.
Stakeholders expressed appreciation for accommodating feedback and extending the first-year methodology, which helps with planning scheduled outages.
Discussion about incorporating minimum outage levels in winter and summer to spread outages throughout the year.
Stakeholders raised questions regarding changes in minimum outage levels from previous presentations and whether minimum levels could be included in protocol language for better scheduling certainty.
Consideration of historical outage performance before and after MDRPOC implementation to inform current methodology revisions.
Suggestions were made to consider average over requested time windows instead of individual days impacting outage requests.
Ongoing collaboration with stakeholders and updates planned for approval in June 2025.
The obligation period for the season was from 11/15/2024 to 03/15/2025.
33 generation resources were awarded as primary FFSSRs.
The clearing price was $12,240 per megawatt, with 4,195 megawatts of capacity procured for about $51,300,000.
The standby fee settlement amount was $49,700,000, slightly less due to availability reduction factors.
No fuel replacement costs were incurred.
The estimated standby fee clawback amount was about $7,300,000.
Clawbacks are based on paragraphs 9, 11, and 13 of the protocol, reflecting issues like unavailability during a watch, failure to deliver a 95% average HSL, and mechanical failures.
Six resources incurred clawback charges for various reasons related to availability and performance.
Discussion occurred on cap and budget limits for procurement, with confirmation that the procurement cleared at the cap set this season.
The cap had been lowered by the Commission, which affected the clearing price.
Clarification that settlements are involved only at the end of the process, with procurement details requiring follow-up.
Bryan Sams confirmed the procurement cleared at the new cap and emphasized competitive procurement.
▶️ 13.4 - RPG Project - Combined Delaware Basin Stage 5 Project and Alternative (Possible Vote)
The review was previously conducted annually but now occurs biennially.
Significant developments have occurred since 2023 in the council's procedures or structures.
Emphasis on enhancing transparency, efficiency, and effectiveness in stakeholder processes.
Recognition of the difficulty stakeholders face in attending numerous meetings, necessitates a focus on streamlining processes.
Suggestions to improve coordination among groups and meetings, especially when dealing with similar topics.
Importance of clarity regarding the purpose and objectives of various stakeholder groups.
Proposal for a self-assessment for working group and subcommittee leadership, to evaluate processes.
Kristy Ashley highlighted the robust nature of ERCOT's stakeholder process but noted areas for improvement since Winter Storm Uri, including the steep increase in meetings.
Concerns about timely posting of meeting materials, given the increase in the number of important meetings.
Recommendation for group chairs to evaluate the necessity of meetings and possibly adjust the frequency to every other month.
Introduction of a previously effective rule by Ken Donahue where agenda items without posted materials in advance would not be discussed to maintain meeting efficiency.
Planning to send out self-assessment surveys with feedback expected before July 4, allowing for agenda adjustments before the next board meeting in September.
Future discussions and reviews scheduled after collecting self-assessments, with final recommendations to be presented at the August TAC meeting.
