Meeting Summary – 10/09/24 Reliability and Markets Committee Meeting

1 – Call General Session to Order Chair

2 – Notice of Public Comment, if Any Discussion – Chair

• No public interest was expressed for comments specifically under this item.

• A corporate member signed up to speak under NPRR1190.

3 – August 19, 2024 General Session Meeting Minutes Vote – Chair

3 August 19, 2024 RM General Session Meeting Minutes

• Draft of the meeting minutes for August 19, 2024, was presented.
• Request for comments or motions on the draft.
• A motion was made and seconded.
• Both parties in favor; no opposition or abstentions.
• Meeting minutes considered approved.

4 – Notice of Annual Committee Self-Evaluation Questionnaire Discussion – Chair

4 Notice of Annual Committee Self-Evaluation Questionnaire

• Purpose is to discuss the 2024 annual committee self-evaluation questionnaire.
• Contents and format were reviewed by the Human Resources and Governance Committee on August 19, 2024.
• ERCOT staff will administer the questionnaire electronically after the meeting.
• Review of results is scheduled for the December 2, 2024 meeting.
• Committee members are requested to submit survey responses by November 1.
• Call for final feedback on the content of the questionnaire.

5 – Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements Vote – Chair

5 Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements

• Agenda item 5.1 involves a recommendation for 2025 ERCOT methodologies on minimum ancillary service requirements.
• Jeff Billow is set to present the ERCOT recommendation.
• Following Jeff’s presentation, Caitlin Smith, the Technical Advisory Committee chair, will address agenda item 5.2 concerning TAC’s endorsement of the recommendation.
• This marks the first official approval of the ancillary service methodology by the Public Utility Commission (PUC).
• Feedback is anticipated from board directors chair Gleason or commissioner Kobos before submission to the full PUC later this year.

5.1 – ERCOT Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements Discussion – Jeff Billo

5.1 ERCOT Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements

• Presentation of the 2025 ancillary services methodology.
• Annual update involves studies and analysis to determine next year’s ancillary service quantities.
• Changes in methodology due to NPRR1222 protocol: Board recommends changes; PUC approves them.
• Overall decrease in ancillary services quantities for 2025 following methodology updates.
• Influence of increased wind and solar on the grid affecting forecast errors.
• Regulation up and down adjusted to better account for wind and solar variability through improved intelligence in scheduling.
• ECRS methodology change: Low likelihood of simultaneous outage and forecast error, using greater of the two needs for each hour.
• Minor parameter changes impacting RRS quantities.
• Non-spin methodology update: Reflecting four-hour forecast error coverage at night due to faster generation start.
• Overall 48 MW decrease in ancillary services for 2025.
• Batteries treated as other resources; potential risk if longer events exhaust battery charge.
• Intent is to align procurement with actual system needs without compromising reliability, resulting in reduced consumer costs.
• Positive feedback and appreciation for a granular approach in updating methodologies.

5.2 – TAC Endorsement of ERCOT Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements Discussion – TAC Chair

5.2 TAC Endorsement of ERCOT Recommendation regarding 2025 ERCOT

• TAC Chair Caitlin Smith presented the endorsement of ERCOT’s recommendation for 2025 ancillary service methodologies.
• Mentioned NPRR1222 approval which added PUC involvement in ancillary service methodologies.
• Stakeholders and multiple working groups reviewed and provided input on methodologies between June and August.
• Endorsements were made by the Wholesale Market Subcommittee and the Reliability and Operations Subcommittee with some abstentions.
• Robust discussions were held; one opposing vote due to concerns about ERCOT’s methods, particularly relating to the independent generator segment.
• IMMs did not oppose the methodologies.
• Key discussion points included reduced regulation in certain hours and its risks, interaction with RUC, and broader policy concerns.
• Concerns with ECRS and non-spin reduction included impacts on future investment signals and reliability standards.
• Abstentions were influenced by concerns over potential shifts in market signals and increased out-of-market costs.
• A motion was passed for the board to recommend PUC approve the ERCOT methodologies effective January 1, 2025.

6 – Board-Tabled Revision Request Vote – Chair

6.1 – NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs Vote – Chair

6.1 NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs

• Board tabled revision request NPRR1190 for voting.
• Caitlin presented recommendation to approve NPRR1190 during August Reliability and Markets Committee meeting.
• Committee recommended tabling NPRR1190 to consider quantitative data from ERCOT comments before October board meeting.
• ERCOT staff filed additional comments on September 19, 2024.
• Keith Collins to present ERCOT comments in agenda item 6.1.1.
• New stakeholder comments on NPRR1190 to be discussed.

6.1.1 – ERCOT Comments on NPRR1190 Discussion – Keith Collins

6.1.1 ERCOT Comments on NPRR1190

• Keith Collins provided an overview of NPRR1190, a policy extension originally approved in 2017 as NPRR649.
• Currently, if ERCOT directs a resource to reduce its output causing a financial loss, the QSC may be eligible for compensation if they have a day-ahead market obligation or bilateral contract.
• NPRR1190 aims to extend this compensation provision to entities without day-ahead obligations or bilateral contracts, such as municipalities or competitive entities representing both generation and load under a single QSC.
• Historically, there have been limited high dispatch override payments, with only five days of occurrence since the inception of the policy.
• Two of these days were during the February 2021 winter storm, and other minor payments occurred in August and September of 2023, all considered relatively small amounts.
• The presentation provided a historical listing of override payment occurrences, noting very few instances over several years.
• Increased eligibility was noted in 2023 due to a specific constraint, but changes under NPRR1230 are expected to reduce similar instances by increasing the shadow price for congestion.
• Questions were raised about the price cap during the February 2021 events, with clarification that the current cap is significantly lower than past caps, which would reduce the financial impact of similar future events.

6.1.2 – Other Comments on NPRR1190, if any Discussion – Commenters

6.1.2 Other Comments on NPRR1190, if any

• Eric Schubert of Lion Dell Chemical represented joint consumers and opposed NPRR1190, stating it would reward over-scheduling of power and force other consumers to subsidize lack of hedging.
• Eric Schubert highlighted that current PUC Rule 25.501 has been in place for decades and should not be changed to allow subsidies for HDL overrides.
• Eric Schubert recommended that NPRR1190 be rejected and that issues should be remanded to TAC to remove language permitting side payments.
• Barksdale English from the Public Utility Commission advised the board to remand NPRR1190 back to TAC for further consideration, acknowledging the broader scope and potential unintended consequences.
• Commission staff does not align with joint commenters that the revision request violates substantive rules, pointing out ERCOT’s existing process through alternative dispute resolution.
• The board tabled NPRR1190 to consider quantitative data, noting that NPRR1190 lacks an urgent status and does not impact reliability according to ERCOT staff.
• ERCOT staff acknowledged that previously approved NPRR1230 might reduce the need for HDL overrides.
• A recommendation was made for the board to remand NPRR1190 back to TAC to gather more information on the initial market policy framework and reassess the need for the compensation mechanism introduced by NPRR649 in protocols from 2017.
• The committee motioned to remand NPRR1190 back to TAC for further consideration with all in favor.

7 – TAC Report Discussion – TAC Chair

7 TAC Report

• No revision requests with opposing votes presented at this meeting.
• The presentation focused on the stakeholder process for educational purposes.
• Introduced the current ERCOT stakeholder committee structure, emphasizing its efficient and expertise-driven nature.
• Highlighted the intense level of expertise in various subcommittees, especially the reliability and operations subcommittee.
• Explained that all subcommittees, except for protocol revision subcommittee, have working groups under them.
• Mentioned the TAC composition of 30 members and balanced representation among consumer, buyer, and seller voices.
• Working groups are open to all; participation varies by subject.
• TAC has a two-thirds voting threshold, while subcommittees require a simple majority.
• Described the revision request process, emphasizing the role of subcommittees and working groups.
• Encouraged stakeholder comments to be filed during the protocol revision subcommittee process.
• Discussed the intention of the process as obtaining expertise and possibly serving as a substitute rulemaking process.
• Provided examples of process pathways for specific revision requests like NPRR1190 and NPRR1198.
• Emphasized the simultaneous and expertise-focused evaluation by different groups.

8 – Recommendations regarding Market Price Corrections Discussion – Gordon Drake

8.1 – Real-Time Market Price Correction – Incorrect Recall of ERCOT Contingency Reserve Service Vote – Chair

8.1 Real-Time Market Price Correction – Incorrect Recall of ERCOT Contingency Reserve Service

• Discussion on two proposed real-time price corrections affecting three operating days.
• Main issue occurred on August 20, 2024, due to an incorrect recall of ERCOT Contingency Reserve Service (ECRS) during an under-generation situation.
• 2000 MW of ECRS was inadvertently recalled instead of the intended 500 MW, leading to a spike in system prices exceeding $5,000/MWh.
• Correction of the issue was applied on August 28, 2024, alongside a market notice about the investigation for potential price correction.
• Investigation confirmed the event met significance criteria for price correction, with impacts identified on 37 counterparties.
• Single largest impact was nearly $600,000 with a total market impact of $3.5 million.
• Recommendation to approve the price corrections and to reclaim excess payments from generators was put forth.
• Motion to approve the recommendation was moved, seconded, and passed.

8.2 – Real-Time Market Price Correction – Incorrect Resource Data Impacting the Real-Time Market Vote – Chair

8.2 Real-Time Market Price Correction – Incorrect Resource Data Impacting the Real-Time Market

• Gordon reviewed the incorrect resource data issue impacting the real-time market for operating days August 9 and 10.
• On August 10, a resource was incorrectly identified due to an erroneous update of the resource’s registration effective date.
• The issue was corrected on August 10, around 01:00 p.m., and a market notice was issued on August 20 to review the price correction.
• The impact analysis met significance criteria, leading to a board approval request for real-time price corrections.
• The issue was caused by the system freezing temporarily and applying the effective date to an incorrect resource.
• A fix is being developed to ensure the correct resource selection and prevent future issues, planned post-implementation of RTC+B.
• Impact to counterparties: on August 9, one counterparty met the significance criteria; on August 10, four counterparties met it.
• Largest impacts to counterparties: approximately $24,000 on August 9 and shy of $5,000 on August 10.
• Total market impact was about $325,000 for both days combined.
• Motion made and approved to recommend board action for price corrections for the affected days.

9 – Independent Market Monitor IMM Report Discussion – IMM

9 Independent Market Monitor (IMM) Report

• Presented by Jeff McDonald, discussing wholesale market performance for June, July, and August.
• Wholesale prices were lower in 2023 due to mild temperatures and lower natural gas prices.
• Resource mix was relatively unchanged, but there was increased solar production.
• Ancillary service costs were historically low, affected by ECRS prices.
• Supply conditions were less tight compared to the previous two summers.
• August 19 and 20th were highlighted due to operational issues and high market prices caused by steep evening ramps.
• IMM recommends reconsidering waiting to deploy until in a scarcity condition to avoid artificially high prices.
• Deployment of ECRS helps preserve regulation and ten-minute reserve levels.
• ECRS shouldn’t be recalled until severe conditions are over, a software issue noted on August 20th.
• ERCOT is working on improving procedures to enhance system operations during tight conditions.
• Energy storage resources are providing reserves and acting as a shortage reserve rather than price arbitrage.

10 – Committee Briefs Discussion – Staff

10.1 – System Planning and Weatherization Update Discussion – Kristi Hobbs

10.1 System Planning and Weatherization Update

• The reliability standard framework has been passed by the commission, setting parameters for loss of load events, with assessments to start in 2026.
• ERCOT is working with transmission service providers to understand rotation capabilities during events and will report recommendations by December 1.
• Transmission project investments have increased significantly, including $2.16 billion in projects energized and $2.5 billion endorsed as of July.
• The Permian Basin transmission plan was approved, with ongoing analysis for import path voltages and a decision required by May 1.
• ERCOT is exploring the benefits of implementing higher voltage lines (765 alternatives) for future planning, targeting plan completion by year-end.
• Generation interconnection requests are predominantly for solar and battery, with a slight increase in natural gas entries.
• Since the start of the large load interconnection process, over 58,000 requests have been reviewed, with 5.7 gigawatts approved for energization.
• Weatherization updates reveal that ERCOT exceeded inspection targets for generation and transmission resources.
• Improvements in energy storage processes have been made, allowing single submissions, with full implementation expected next year.
• Acknowledgement of the collaborative work by ERCOT and commission staff on the Permian transmission study.

10.2 – System Operations Update Discussion – Dan Woodfin

10.2 System Operations Update

• Highlighted the ancillary service study and future revision requests.
• Discussed Senate Bill 3 which asked the PUC to review ERCOT’s ancillary services.
• PUC staff requested input from ERCOT and IMM. A significant white paper has been posted on ERCOT’s website.
• Upcoming workshop on PUC’s draft report regarding ancillary services recommendations.
• Current ancillary services are deemed sufficient to meet ERCOT’s reliability needs.
• Recommended improvements in commitment purposes of ancillary services using Monte Carlo type probabilistic analysis.
• Suggested determining 50% of ancillary service quantities closer to the operating day based on updated forecasts.
• Outlined a timeline for new processes, with implementation aimed for 2027.
• Discussed criteria for determining sufficient ancillary service quantities, moving from less edge operation.
• Emphasized the need for policy decisions in response to PUC staff questions.
• Addressed reliability standards, emphasizing different criteria for operational reliability compared to planning reliability.
• Mentioned the use and implementation of grid forming inverters to improve stability, with planned rule changes.
• Announced accounting adjustments on system peak demands related to battery storage.

10.3 – Commercial Markets Update Discussion – Gordon Drake

10.3 Commercial Markets Update

• Review of summer 2024 compared to previous years, highlighting lower real-time average hub prices and ancillary service prices.
• Increase in solar and energy storage capacity observed, impacting overall reserves and energy market.
• New peak demand record mentioned, with a notable decrease in hub average prices in 2024.
• Significant increase in capacity from energy storage resources and solar generation participation.
• Marked reduction in ancillary services costs and real-time congestion rents.
• General price convergence between day-ahead and real-time markets.
• Lower reliability unit commitment (RUC) activity, with increased resource diversity in selections.
• Challenges with congestion revenue rights auction performance, particularly in outer years, due to increased participation.
• Considering administrative and market participation changes to address longer auction solving times.

10.3.1 – Real-Time Co-optimization Update Discussion – Matt Mereness

10.3.1 Real-Time Co-optimization Update

• Update on market participant readiness with attestations received from 106 participants; only one delayed response.
• Target go-live date announced for December 5, 2025.
• Milestones set for both internal and external development, with timelines currently being met.
• Market trials plan under review and readiness training outlined for market employees.
• Communication about market notice and go-live date made through press release, trending talk paper, and more.
• Issues list restructured with policy issues separated from readiness issues for stakeholders to evaluate.
• Significant emphasis on the ancillary service proxy offer floor debate.
• Development of an RTC simulator to explore historical data and possible policy decisions.
• Discussion on scarcity pricing mechanisms and their alignment with marginal reliability benefits.
• Shortage pricing issues identified with existing RTC design, suggesting a nested demand curve could resolve concerns.
• Simulation tools developed to compare existing and proposed nested curve approaches, with positive results.
• No anticipated delay in RTC development with the implemented changes.
• Future simulations and evaluations planned for fall and winter to refine pricing and implement readiness activities.
• Emphasis on delivery mechanics, policy analysis, and market trials in preparation for the December 5, 2025 go-live date.

10.4 – Market Credit Update Discussion – Austin Rosel

10.4 Market Credit Update

• Current market credit situation remains stable due to mild summer prices and shoulder months.
• Total potential exposure is relatively flat, with September showing 1.7 billion.
• Discretionary collateral is currently at 4 billion.
• Implementation of NPRR1205 on November 1, resulting in the removal of six banks that do not meet new requirements.
• Credit limits were increased prior to summer and are now being adjusted post-summer.
• NPRR1215 is a clarification with no credit impacts, aiming to align formula and protocols with system functionality.
• Feedback from TAC requested remand of language back to TAC for revision, which was unanimously approved.
• No further questions or issues reported.

10.5 – Revision Request Status Update Discussion – Ann Boren

10.5 Revision Request Status Update

• Anne Boren from ERCOT provided a revision request status update.
• There are twelve revision requests up for October board consideration.
• One revision request, NPRR1190, was previously reviewed during the meeting.
• The remaining eleven requests are unopposed and sourced from TAC, expected to be on the consent agenda.
• Currently, 53 revision requests are in process, which might actually be closer to 57.
• Eight new revision requests have been submitted since the August board meeting.
• Three older requests have moved forward in the stakeholder process, leaving nine on the aging list.
• Year-to-date, 58 revision requests have been approved through the stakeholder process.
• There are no current revision requests impacting RTC+B that require expedited processing.

11 – Future Agenda Items Discussion – Woody Rickerson

11 Future Agenda Items

• No comments were made regarding upcoming agendas.

12 – Other Business Discussion – Chair

• No additional business was brought up for discussion.
• The committee adjourned the general session.
• An executive session was convened.
• No voting items are anticipated from the executive session.
• The general session will not reconvene after the conclusion of the executive session.
• General session adjournment and conclusion of the webcast.