Meeting Summary – 08/19/24 Reliability and Markets Committee Meeting

1 – Call General Session to Order Chair

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

• No public comment

3 – June 17, 2024 General Session Meeting Minutes Vote – Chair

• Motion to approve June 17, 2024 Meeting Minutes passed.

4 – Staff Response to Independent Market Monitor IMM 2023 State of the Market Report for the ERCOT Electricity Markets Discussion – Keith Collins

Key Discussions:

• Review of 2023 IMM State of the Markets report; overall positive assessment with useful market performance insights.
• Focus on IMM recommendations: ERCOT’s response includes ongoing, completed, and future discussions for the recommendations.
• Three primary areas for market improvement identified by IMM: real-time co-optimization (RTC+B), uncertainty reserve product, and multi-interval real-time optimization.
• Four new recommendations from the IMM: Increase shadow price cap in real-time, modify proxy offer cap for renewables, improve requirements for firm fuel supply service, and improve procurement and deployment of ECRS.
• Increase in shadow price cap in real-time has significant alignment between ERCOT and IMM position.
• Firm fuel supply service concerns involve whether resources are generating and cost considerations which may require further stakeholder discussion.
• Existing recommendations: Certain NPRRs already address some recommendations, others require further consideration or fall under PUC purview.
• IMM’s concerns with RTC: Concerned with demand curve values, fundamental issues with AS design, and the linked versus nested/cascading approach for ancillary services.
• Ongoing engagement with IMM and stakeholders to address these concerns and potential implications for project timelines.

Actions and Next Steps:

• Continue full steam ahead with RTC implementation while addressing IMM’s concerns.
• Stakeholder discussions to refine ancillary service demand curves.
• Potential policy decisions to update Emergency Condition/Resource Strategies (ECRS).
• Further analysis by IMM expected within a month to evaluate linked versus nested approach impacts and provide more tangible recommendations.

Stakeholder Process:

• IMM involvement in the stakeholder process is confirmed and ongoing.
• Additional public and stakeholder discussions of IMM’s concerns are anticipated soon.

5 – Board-Tabled Revision Request Vote – Chair

5.1 – NOGRR245, Inverter-Based Resource IBR Ride-Through Requirements – URGENT Vote – Chair

• Motion made to recommended approval of NOGRR245 as recommended by TAC in the 6/7/24 TAC report as amended by ERCOT 8/16/24 comments with recommended priority of 2025 and rank of 3515
• Motion passed unanimously.

5.1.1 – ERCOT Comments on NOGRR245 Discussion – Chad V. Seely / Woody Rickerson

• ERCOT filed two sets of comments on August 12 and August 16.
• A PowerPoint presentation was used to explain the developments.
• Joint commenters who raised concerns are now supportive of the comments.
• Two major differences between the versions filed on the 12th and the 16th.
• Recommendation to move forward with the August 16 version.
• Since June, ERCOT worked extensively with joint commenters.
• Revised NOGRR version submitted on August 16 includes non-objection from joint commenters.
• ERCOT aims to retain the benefits and remove certain exemption criteria for subsequent discussion.
• Clarifications, removal of redundancy, and typo fixes were made.
• Proposal to bifurcate NOGRR into phase one and phase two.
• New inverter-based resources must meet IEEE 2800 requirements post-August 2024.
• Legacy IBRs must maximize software settings by December 31, 2025.
• Requirement to submit notice of intent for exemption under phase two.
• Changes between August 12 and 16 versions include memory card clarification and notice of intent terminology.
• Tracking of compliance and exemptions to be reported quantitatively to the board.
• Impact assessment update: FTE potential increase from 7-8 to 7-10.
• Project priority year suggested as 2025 with a rank of 3515.

5.1.2 – Other Comments on NOGRR245, if any Discussion – Commenters

Other Comments on NOGRR245, if any Discussion – Commenters

• Discussed the need for the board to designate NOGRR245 as a priority for February.
• Mentioned the challenges in policy discussions among stakeholders regarding exemption processes and hardware.
• Emphasized the importance of keeping the committee and board updated on the NOGRR process.
• Suggested that such updates would help identify key issues between ERCOT staff and stakeholders.
• Expressed satisfaction with agreement and implementation of discussed items.

5.2 – TAC Report regarding R&M Committee-Charter Revision Requests Discussion – TAC Chair

The transcript summary is as follows:

• Caitlin Smith, the TAC Chair, presented the TAC report.

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

• NPRR1190 discussed provisions for recovery of financial loss from a manual high dispatch limit (HDL) override, focusing on issues when real power output is reduced but intended to meet QSC load obligations.
• Current protocol allows compensation for losses on day-ahead market obligations and bilateral contracts affected by HDL override, but doesn’t account for losses within service territory obligations.
• The revised language in NPRR1190 permits compensation for concrete realized loss, not merely opportunity cost.
• TAC voted on June 24 with six opposing votes from the consumer segment and one abstention from the independent retailer segment.
• Opponents argued the proposal contradicts nodal market design, rewards overscheduling of undeliverable power, and disrupts proper dispatching incentives and new generation siting.
• ERCOT supported NPRR1190 as approved by TAC and provided data and historical context on HDL override payments.
• Motion to approve NPRR1190 as recommended by TAC faced a hurdle due to the six opposing votes, resulting in further discussion without immediate approval.

5.2.2 – NPRR1215, Clarifications to the Day-Ahead Market DAM Energy-Only Offer Calculation Vote – Chair

• NPRR1215 clarifies the day-ahead market energy-only offer credit calculation.
• It zeros out negative values in the exposure calculation.
• It uses the absolute value of negative prices to increase exposure when prices are negative.
• Motion made for RNM Committee to recommend the board remand NPPRR1215 back to TAC
• Motion passed unanimously.

5.2.2.1 – ERCOT Comments on NPRR1215 Discussion – Austin Rosel

• ERCOT filed comments on August 1 to correct a formula error.
• ERCOT discussed their plan to file comments on July 31 during the TAC meeting, with no concerns raised by TAC members.
• Austin Rosel reiterated that the NPRR version aimed to capture an “as built” and not introduce any policy change.
• A formula error inadvertently caused a policy change, discovered after TAC voted.

5.2.3 – NPRR1219, Methodology Revisions and New Definitions for the Report on Capacity, Demand and Reserves in the ERCOT Region CDR – URGENT Vote – Chair

• NPRR1219 changes the methodologies for preparing the CDR report.
• Incorporates a report release schedule and requires switchable generation resource owners to provide information on unavailable units for all seasons, not just summer and winter.
• Efforts to update the CDR are in response to Winter Storm Uri.
• Switch to ELCCs and reporting loads/resources during the forecasted peak net load hour instead of just peak load.
• At the 7/31 meeting there were two opposing votes from the consumer segment, and four abstentions from the consumer, independent generator, and independent power marketer segments.
• Opposition was due to the need for more time to review ELCC calculations and policy implications with the Public Utility Commission and Legislature.
• Support from stakeholders for implementing changes in the December CDR due to associated urgency.
• Debate over ELCC application to renewables but not thermal generation, and the complexity of calculations.
• Continued collaboration with stakeholders to improve CDR processes.
• Capturing the availability of switchable generation in CDR reports is viewed as crucial, particularly for understanding seasonal availability.
• Account for battery energy storage in CDR, as its current contribution is listed as zero despite increasing megawatts added.
• Motion made to recommend approval of NPRR1219 as recommended by TAC passed unanimously. 

5.2.4 – NPRR1230, Methodology for Setting Transmission Shadow Price Caps for an IROL in SCED – URGENT Vote – Chair

• Discussed methodology for setting transmission shadow price caps for interconnection reliability operating limits (IROLs) and security constrained economic dispatch, deemed urgent.
• NPRR1230 will allow ERCOT to manage power flows within IROLs using existing tools instead of manual intervention, reducing operational risk during stress conditions.
• Mentioned the issue that occurred during the September 6 EEA event.
• Implementation was delayed initially to avoid market uncertainty; now planned for next summer.
• At the 7/31 TAC meeting there were two opposing votes (cooperative and municipal segments) and four abstentions (cooperative and independent retail provider segments) due to cost concerns.
• Opposing vote cited increased market costs shown in ERCOT’s analysis, ranging from $0.5 to $1.6 billion over 20 days.
• ERCOT’s South Texas export GTC exit strategy indicates resolution by 2027, reducing the need for the NPRR.
• Discussion on how NPRR1230 mitigates high dispatch limit overrides in NPRR1190, improving market process by automating dispatch limits.
• Motion made for the RNM committee to recommend approval of NPRR1230 as recommended by TAC passed unanimously.
• Discussion then shifted back to NPRR1190 regarding concerns about the increased eligibility for makehold payments and the broader issue of out-of-market payments.
• Acknowledged the small number of instances vs. potential impacts.
• Clarified the ERCOT comments on NPRR1190 and provided quantification of impacted resources and historical data.
• Decision to table NPRR1190 for more information, to be revisited in October.
• Motion to table NPRR1190 made and seconded; approved unanimously.

6 – Recommendation regarding Oncor Temple Area Regional Planning Group RPG Project Vote – Kristi Hobbs

• ERCOT Staff is endorsing the Oncor Temple Area project and seeking board endorsement.
• Projects over $100 million require board endorsement.
• The Oncor Temple Area project addresses reliability needs including thermal overloads on 18 miles of transmission lines and 31 voltage violations in Bell County.
• Option 5A was unanimously endorsed by TAC.
• Two main criteria for the recommendation: loss of a transformer followed by a single transmission element, and contingency loss of a single transformer followed by a single transmission element or a common tower outage.
• Option 5A was the least costly solution, required the least amount of new right-of-ways, and improved long-term load carrying capacity compared to other options.
• Motion made for the board to endorse the need for the Tier 1 Oncor Temple Area project, option 5A, passed unanimously. 

7 – Independent Market Monitor IMM Report Discussion – IMM

• Market activity report covers June and July.
• Aside from electrical issues from the July hurricane, the period was uneventful.
• Wholesale energy prices were low in June and July.
• Lower prices driven by mild temperatures and a 14% decrease in natural gas prices compared to 2023.
• Wholesale electricity prices dropped by 53% compared to last year.
• Last summer saw high prices due to reserve deployment issues, now modified.
• Very low congestion between zones, indicated by comparable monthly average prices across zones.
• July 2024 had much lower load due to mild temperatures compared to 2022 and 2023.
• Ancillary service costs were lower in June and July due to lower energy costs.
• Resource mix showed a slight increase in wind generation, with otherwise stable production mix.
• Congestion costs followed energy prices, with lower costs due to reduced energy prices and congestion compared to prior years.

8.1 – System Planning and Weatherization Update Discussion – Kristi Hobbs

• Kristi Hobbs presented the System Planning and Weatherization update.
• Transmission Project Options
  • Several options considered; shortlisted to three.
  • One option not meeting NERC and ERCOT criteria was discarded.
  • Selected option cost: $272 million, another option: $329 million.
• Summer Inspection Program
  • Goal: 300 generation resources and 300 transmission facilities.
  • Achieved: 288 resources and 247 transmission facilities inspected as of mid-August.
• Permian Basin Reliability Plan
  • Plan filed with PUC includes a $4.02 billion subset of projects for local transmission needs.
  • Options considered for power import paths: 345kV, higher voltage (EHV).
  • Total cost varies: $13 billion to just under $14 billion.
• EHV Transmission Planning
  • Ongoing study to be completed by the end of the year.
  • Stakeholder feedback will be incorporated through monthly RPG meetings and additional workshops.
• Large Load Growth
  • Significant increase in large load interconnection requests.
  • Current projection: over 49,000.
• Resource Adequacy for Upcoming Months
  • Highest risk period: evening hours as solar sets.
  • September risk less than August; October higher due to maintenance outages.
• Reliability Standard and Cost Studies
  • Commission to take action on the reliability standard by the end of the month.
  • Value of lost load survey results to be published soon.
  • Cost of new entry study updated; commission approved a cone of 140 kilowatt-hours per year.

8.2 – System Operations Update Discussion – Dan Woodfin

• Dan Woodfin presented the System Operation update.
• Hurricane Beryl
  • Initial forecasts predicted the hurricane would hit south of Brownsville, Mexico; it eventually hit Matagorda County, South of Houston.
  • Caused significant load loss in Houston due to distribution outages.
  • ERCOT managed transmission and generation well, with high online reserves throughout the event.
  • Adjustments to load forecasts were necessary.
  • RFIs will be sent to entities with outages for continuous improvement insights.
• Ancillary Services
  • ERCOT Contingency Reserve Service updates rejected by Commission but operational procedures have been adjusted since August 1.
  • Changes to ancillary services quantities for 2025 have been approved; will be endorsed in October and implemented after further workshops.
  • Legislature-required, 87R-SB3, ancillary service study in progress; recommendations to be discussed on August 28.
• DRRS Dispatchable Reliability Reserve Service
  • NPRR1235 proposal will be implemented post-RTC (Real-Time Co-optimization for Ancillary Services and Local Congestion Management), anticipated at a later date.
• PUC Ancillary Service Study
  • Two main areas for potential changes: frequency response bucket and resource commitment adequacy.
  • Recommendations include adopting probabilistic analysis methods and setting ancillary service quantities closer to real time.
• NPRR1149 Implementation
  • Tracking QSE capacity shortages monthly, finding a low shortage percentage in July.
  • Tracking the ability of energy storage resources to maintain ancillary service provision throughout their deployment duration.
• Survey on Inverter-Based Resources (IBRs)
  • Survey found that about 30 gigawatts of IBRs plan to maximize ride-through capability improvements, with others still assessing or awaiting more guidance.
• Questions from Julie
  • Requirements to compare ancillary service costs and reliability for summer 2023 versus summer 2022 will be addressed in the next meeting.

8.3 – Commercial Markets Update Discussion – Gordon Drake

• Gordon Drake presented the commercial markets update.
• Objectives: Highlight notable market trends, discuss market evolution work, and key stakeholder conversations.
• Hurricane Beryl impact: Mild pricing outcomes system-wide, localized price separations, price oscillations between $0 and $75, and peak demand reduction of approximately 15.5-16GW.
• Observed localized effects included significant price separation between the Houston zone and south load zones, with Houston prices occasionally reaching negative values.
• Discussed current market initiatives including the Performance Credit Mechanism (PCM), Dispatchable Reliability Reserve Service (DRRS), and the ADER pilot.
• PCM: Workshop held on July 25, next steps include publishing a ‘straw man’ and a cost and market effects analysis in the next few days.
• DRRS: Multi-stage approach focusing first on offline resources, with future steps involving energy storage resources and controllable load resources.
• ADER Pilot: Evaluating current performance and new participation models, working closely with stakeholders and the PUC.
• Questions raised about the implementation timeline of the PCM, with estimates suggesting 2025 following the necessary rulemaking processes.

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

• Matt Mereness presented the RTC update.
• Discussed the ongoing work and collaboration with the vendor on RTC integration points.
• Emphasized planning for testing and going live, interdependencies like system operator training.
• Highlighted market readiness focus with technical deep dives and a market trials plan.
• Explained the process of updating and aligning RTC protocols and the single model.
• Provided status on the queasies’ attestations, including feedback and tracking of submissions.
• Reviewed the preparations for market trials, QSEs engagement, and necessary system changes.
• Addressed the readiness of different QSEs, noting 106 with resources and respective attestations.
• Outlined next steps, including running simulations and stress tests starting in late September.
• Discussed policy constraints related to ORDC curve and possible shifts within the ORDC framework.
• Confirmed that current scope is locked, and any design changes would delay implementation.
• Responded to questions about testing and feedback, confirming iterative scorecards for different testing stages.

8.4 – Market Credit Update Discussion – Austin Rosel

• Austin Rosel provided the update.
• Noted that the NPRR1215 request had already been handled by the committee.
• Due to mild prices, there were no major credit developments to report.
• No defaults or uplifts to the market were observed.
• Total potential exposure remained flat throughout the summer, maintaining around 2 billion dollars.
• Comparison with previous years showed a significant decrease in potential exposure.
• NPRR1205 was approved by the PUC on June 13, which included increased issuer limits for banks and higher quality standards.
• On July 1, the first phase of NPRR1205 was implemented, doubling issuer limits.
• There were no issues with banks breaching their revised limits.
• NPRR1215 had been remanded back to TAC as requested.

8.5 – Revision Request Status Update Discussion – Ann Boren

• Ann Boren provided the Revision Request Status update.
• 14 revision requests for consideration at the board meeting tomorrow
• 5 revision requests already reviewed today
• 9 remaining revision requests on the consent agenda
• 58 revision requests currently in process
• 18 new revision requests submitted since June board meeting
• 12 aging revision requests tabled for over 7 months
• 1 aging revision request (NPRR1188) removed after being tabled for almost a year.
• 45 revision requests approved to date through the stakeholder process

12 – Adjournment Chair

• Meeting was officially adjourned by Chair Gleeson.