▶️0.1 - Commission Counsel Shelah Cisneros lays out Consent Agenda
Commissioners placed Items 4, 8, 10, 11, 12, 13, 14, 15 on the consent agenda.
Chairman Gleeson called for a motion to approve the consent agenda.
The motion to approve the consent agenda was passed unanimously.
No one signed up for public comment.
The decision was made to proceed out of order and discuss ERCOT matters first.
▶️2 - Docket No. 56954; SOAH Docket No. 473-24-25125 – Application of Texas-New Mexico Power Company for Approval of a System Resiliency Plan
An unopposed agreement was addressed within the docket.
The Chairman filed a memo similar to those for previous resiliency plans.
Consideration for taking additional time to brief, think through responses, and decide on approval, denial, or modification of the plan.
▶️2 - Stacy Whitehurst – VP of Regulatory Affairs - overview of System Resiliency Plan - 56954
TNMP covers diverse geographic areas in Texas, each with unique resiliency challenges, such as severe weather conditions like thunderstorms, tornadoes, and hurricanes.
The system resiliency plan (SRP) for TNMP is tailored to each service area's specific needs.
The development of the SRP involved hardening, modernization, vegetation management, operational technology enhancements, and flood mitigation components.
TNMP collaborated with 1898 and company, utilizing major event data, covering 170 years for tropical cyclones and 25 years for other extreme weather events.
The SRP includes eight key resiliency measures: distribution system resiliency, distribution system protection modernization, vegetation management, wildfire mitigation, flood mitigation, enhanced operation system technology, cybersecurity, and physical security.
▶️2 - Chris Gerety – VP of Technical Services & System Reliability - Distribution System Resiliency Measure - 56954
Introduction of four programs aimed at improving system resiliency, including hardening full circuits or protection zones backed by a benefit cost analysis.
Circuit overhead inspections and hardening program focusing on critical elements of circuits not meeting BCR thresholds.
Mention of a strategic undergrounding pilot program to gather data for informed decisions on future SRP filings.
Discussion on the distribution system protection and modernization programs, including mainline automated reclosing deployment and lateral recloser deployment.
Mainline automated reclosing deployment involves modern reclosers for advanced and remote switching during resiliency events.
Lateral recloser deployment entails installation of reclosing fuse devices to minimize outages and restore service more quickly without the need for truck deployment.
▶️2 - Keith Nix – VP of Operations - Vegetation Management - 56954
Keith Nix discussed TNMP's transition from reactive to cycle-based vegetation management, with faster cycles in the Gulf Coast area.
TNMP is enhancing its tree risk assessment by adopting an advanced level two assessment focusing on tree health and the impact of trees outside the right of way.
The implementation of remote sensing technologies such as LIDAR and aerial enhancements will be used for data collection and program development.
Under wildfire mitigation, TNMP is focusing on asset hardening, including replacing wooden cross arms and retrofitting poles, and fuels management by clearing defensible space.
Situational awareness program includes gathering real-time data from weather stations and cameras, shared with first responders to improve fire response.
Ignition mitigation efforts include replacing spark-emitting equipment and installing fast tripping reclosing to prevent sparks.
Flood mitigation focuses on enhancing substations to prevent flood damage and ensure quick recovery.
Enhanced operations systems technology will deploy new technology for a fully functioning outage management system and field area network.
Project and portfolio management strategies are in place to ensure effective execution of the plan.
Cybersecurity enhancements include centralizing monitoring capabilities with five dedicated programs.
Physical security plans involve strengthening fencing and deploying surveillance technology at critical substations.
▶️2 - Commissioner Hjaltman's questions for TNMP - 56954
Commissioner Hjaltman questioned the pilot project for undergrounding, asking why it's still in the pilot phase and what lessons are expected.
TNMP has some underground portions mainly in subdivisions, where developers paid for the undergrounding.
Challenges in undergrounding projects include potential increases in time and costs.
TNMP seeks experience in undergrounding before establishing firm guidelines for when to justify such projects.
Future reporting to the Commission will focus on understanding costs, difficulties, and benefit-to-cost analysis.
Discussion shifted to vegetation management, highlighting the need for proactivity.
The proposed amount for vegetation management is a third of what a study suggested, intended to cover a shorter timeframe.
The plan involves a 3-year timeline, with a future filing for additional resources required to complete the work in 5 to 6 years across service territories.
The discrepancy between a suggested 20-year budget and the planned 3-year execution was questioned.
▶️2 - Jason De Stigter - 1898 - Benefit Cost Analysis - 56954
The benefit cost analysis considers a 20-year time horizon.
Vegetation management requires ongoing attention and investment.
Investments in projects like overhead hardening can provide benefits for up to 40 years.
The analysis assumes continued operation and maintenance over the entire time horizon to justify the overall program.
The analysis aims to determine if investment in such projects is worthwhile.
▶️2 - Commissioner Hjaltman's questions on vegetation for TNMP - 56954
Hiring for vegetation management. Combination of outsourcing labor and hiring internal experts; collaboration with a third party for systems development.
Wildfire mitigation measures. Collection of data on wildfires originating from and potentially affecting TNMP facilities, including ignitions from outside TNMP's area.
Safety and regional data management. Need for separating and tracking safety data regionally to provide clear data for consumers.
Clarification on metric inclusion. Confusion over which metrics were included in the report and if they aligned with the settlement agreement; clarification needed.
▶️2 - Commissioner Jackson's questions for TNMP - 56954
Discussion on whether wildfire mitigation metrics should include wildfires not started by TNMP facilities.
TNMP focuses on fires they are responsible for to measure asset protection and ignition mitigation.
Post-fire analysis for outside ignition sources will track impacts on TNMP facilities.
Consideration of adding metrics for external ignition sources in the future.
Variable ability to monitor all wildfires across TNMP service territory.
Initial plans had higher costs for a situational awareness program within wildfire mitigation.
Cost reduction achieved by finding alternate suppliers for situational awareness technology.
Potential to add common metrics like customer minutes interrupted and avoided system restoration costs.
TNMP's current metrics are tailored to their specific plan costs and capabilities.
Discussion of financial implications to add system restoration cost modeling.
Impact of proposed application on residential ratepayers estimated at around $10, down from $13.51 initially.
Main driver for residential rate impact is O&M costs, specifically vegetation management.
Rate allocation changes are anticipated due to system growth, possibly shifting more cost to other customer classes.
▶️2 - Chairman Gleeson's questions for TNMP - 56954
Settlement reached on a benefit-cost ratio of 0.9 for a program; TIEC argued for 1.2.
Qualitative benefits not included in initial calculation, settled on 0.9 considering these.
Discussion on programs without performance metrics or cost-benefit analysis.
Challenges in cost-benefit analysis for low frequency, high impact events.
Difficulty in quantifying safety and public safety elements in benefits analysis.
Argument for 0.9 ratio as a prudent investment threshold due to qualitative benefits.
Consideration of efficiency by completing all necessary investment in a circuit at once.
Acknowledgment of potentially justifying lower thresholds for specific safety risks.
TNMP discussed uniqueness of their service territory in resiliency planning.
3 & 5
Not Discussed
▶️6 - Project No. 55999 – Reports of the Electric Reliability Council of Texas
Focus on the CDR (Capacity, Demand, and Reserves) report.
▶️6 - Pablo Vegas – ERCOT President & CEO - CDR Cycle - 55999
Presented significant changes in the structure of the CDR cycle due to legislative impacts and market trends.
CDR is published biannually in May and December but was delayed to review substantive changes.
Observed a trend of downward pressure on planning reserves due to rapid load growth.
Incorporated a larger load forecast and effective load carrying capabilities for wind and solar in the report.
For the first time, included battery storage contributions in planning reserve margins.
Introduced reporting of peak net loads and updated criteria for resource inclusion and planned retirements.
Explained construction of load forecasts using existing loads, customer agreements, and anticipated growth factors.
Showed a range of scenarios in the CDR to reflect uncertainties in load and supply projections.
Discussed potential legislative changes affecting large load flexibility requirements.
Highlighted importance of demand response and policy changes for large load flexibility for immediate reliability benefits.
Outlined longer-term focus on infrastructure investment and battery optimization.
Provided insights on potential impacts of market operations not modeled in the CDR economic forecast.
▶️6 - Commissioner Hjaltman's Questions for Pablo Vegas - 55999
Discussion on federal policies impacting resource adequacy in Texas, including EPA rules affecting the coal and gas fleet and potential future restrictions on building new gas resources.
Mention of tariffs affecting supply chains and electric power exchanges, potentially increasing costs and slowing down infrastructure development.
Consideration of modeling different types of load, such as firm and flexible, for better forecasting and reliability benefit to the grid.
Modeling currently includes loads with an obligation to respond, such as participation in ancillary services.
Discussion of adding new load classes with defined operating parameters to improve grid reliability and forecasting.
▶️6 - Commissioner Jackson's questions for Pablo Vegas - 55999
ERCOT is not only an operational entity but also provides crucial data for managing change.
Real-time co-optimization is a key upcoming initiative aimed at improving resource dispatch efficiency.
This initiative will help in lowering wholesale costs by optimizing energy dispatch and carrying higher-cost resources in reserve.
For the first time, batteries will be included in the co-optimization to enhance efficiency.
The primary focus is on market efficiency without compromising grid reliability.
Long-term reliability requires attention to load responsiveness and investment incentives in the energy market.
There is a need to balance efficiency improvements with long-term reliability planning.
ERCOT is unique due to Texas's growth and requires tailored solutions for efficiency and reliability.
▶️6 - Chairman Gleeson's questions for Pablo Vegas
ERCOT has limited data for verifying loads provided by TSP officer tested load letters, lacking a standardized process.
Inconsistencies in TSPs' load counting could pose data accuracy issues.
There's a need for consistent and transparent criteria for load data verification.
Load forecasts are key for transmission planning but could benefit from being divided into long-term transmission and reliability views.
Debate on whether to have separate processes for long-range transmission planning and reliability metrics.
Recent legislative changes influenced CDR changes with significant adjustments in wind, solar, and storage contributions.
Increase in reported load forecasts is expected, emphasizing the need for improved understanding of load criteria.
Concerns were raised on timeline discrepancies in forecast reporting, impacting reliability and operational modeling.
Upcoming load forecasts might show significant increases, raising questions on how best to utilize the data for planning and reliability.
Ensuring accurate timing and staging of load activation is critical for quality analysis and reporting.
▶️6 - Matthew Arth - ERCOT - ERCOT's report on proposed magnitude methodology - 55999
The methodology aligns with the reliability standard rule 25.508, focusing on frequency, duration, and magnitude.
Magnitude value is not explicitly defined in the rule; ERCOT is tasked with determining it in consultation with transmission operators and commission staff.
ERCOT issued RFIs in September and November to gather data on load shed rotation programs and determine feasible load shedding magnitudes.
ERCOT proposes a methodology using 20% of the forecasted winter load, based on the 75th percentile, which equates to 16,000 MW for winter 2024-2025.
The proposed magnitude implicitly excludes critical public safety, industrial, and natural gas facilities while ensuring compliance with under-frequency load shed requirements.
Transmission-connected customers not registered as critical are included in the shedtable amount.
The methodology is not a compliance standard; it offers guidance for evaluating ERCOT's regional reliability and load shed rotation considerations.
ERCOT seeks commission agreement to implement the proposed methodology for annual reports starting on December 1.
Overall, the methodology assists in balancing public reliability and health impacts during load shedding.
▶️6 - Werner Roth - Commission Staff - Staff's recommendation on ERCOT's report for proposed magnitude methodology - 55999
Staff recommended ongoing consultation with ERCOT and transmission operators as required by the rule.
A methodology has been established but there is an emphasis on continued discussion to adapt if the system changes.
The methodology is based on the low forecast in the Capacity, Demand, and Reserves (CDR) report, providing more certainty for the upcoming year's values.
▶️6 - Commissioner's Jackson's questions to ERCOT - 55999
The planning purpose is emphasized, not intended for operational purposes.
Revisitation of the methodology is planned through consultation between staff and ERCOT by December 1 every year.
Discussion prior to December 1 will determine if any significant changes require revisiting the methodology.
ERCOT plans to consult with Commission Staff and transmission operators well in advance, at least one to two months before the filing.
Assessment of advancements in segmentation or rotation method technologies will be done to consider different approaches.
Consistent magnitude methodology provides certainty for planning.
Current understanding indicates that the magnitude amount is not the limiting factor, its reliability standard is determined by frequency, the one in ten component.
7
Not Discussed
▶️9 - Project No. 53911 – Aggregate Distributed Energy Resource (ADER) ERCOT Pilot Project
▶️9 - Ramya Ramaswamy - Commission Staff - Moving ADER Pilot Project to ERCOT - 53911
The ADER Pilot Project allows households and commercial customers to participate in ERCOT's real-time and ancillary services market.
Initial skepticism existed, but pilot stakeholders and ERCOT pursued innovative solutions.
Regulatory and policy issues were cleared to support pilot success.
Recommendation made to move the ADER Pilot Project to ERCOT for further growth.
A larger stakeholder group at ERCOT can benefit the pilot's growth.
Continued monitoring of the project will be similar to other ERCOT projects.
ERCOT should report project progress to the Commission every six months.
16-27
Not Discussed
▶️28 - Chairman Gleeson pauses Open Meeting, to hold Closed Session
No action will be taken regarding matters discussed in Closed Session.
