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

  1. 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.