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.
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
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.
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.
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