NPRR1247 was recommended by TAC for board approval with three opposing votes and one abstention.
Incorporates the Consumer Energy Cost Reduction Test as the Congestion Cost Savings test in economic project evaluation.
Addressing amendments by the PUC in Texas Administrative Code § 25.101 and aligned with 87R-SB1281.
ERCOT worked with E3 to develop a suitable congestion cost savings test based on stakeholder feedback.
The NPRR proposes a System Wide Gross Load Cost Test, recommended by E3.
Maintains the Production Cost savings test as a standalone evaluation method.
Faced procedural and substantive challenges during the proposal process, receiving diverse feedback from stakeholders.
Opposition due to concerns over urgency, incompleteness, and lack of stakeholder review for supporting white papers.
ERCOT engaged with stakeholders throughout the process and made necessary revisions based on feedback.
Debate about the appropriateness of some variables in the economic criteria formula and possibility of future updates.
NPRR1247 aims to evaluate projects based on both production and congestion cost savings for recommending approval.
Motion to reccomend that the board approve NPRR1247 approval passed unamiously.
Commitment to review project revenue requirements at least annually and ensure efficient application of the criteria.
6 - Recommendations regarding Regional Planning Group (RPG) Tier 1 Transmission Projects - Julie England
Discussion of two regional planning group projects.
Projects: American Electric Power Service Corporation, Brownsville Area Improvements Transmission Project, and Oncor Delaware Basin Stages 3 and 4 project.
Christy Hobbs to present recommendations for these projects.
Projects have met criteria for board consideration.
Recommendations scheduled for a vote as noted in the agenda.
The AEPSC Brownsville Area Improvements Project is valued at $423 million and requires Tier 1 approval.
The project was first reviewed by ERCOT in March of this year due to specific needs in the Brownsville area.
Analysis aimed at addressing thermal overloads and voltage violations according to NERC and ERCOT planning criteria.
A stakeholder review process was conducted, culminating in unanimous endorsement by the technical advisory committee in October.
Ten different options were evaluated, with the chosen recommendation being the least cost option while offering additional operational flexibility and improved long-term load serving capability.
Recommendation 2A is to be moved forward to the board for endorsement.
No questions or comments were raised by committee members, and a motion was made and seconded to recommend board endorsement of Option 2A.
Jeff McDonald presented the IMM report, reviewing market performance and concerns about ASDC curves.
Energy prices from August to October were lower than a year ago, due to milder summer weather and lower natural gas prices.
Notable was a warmer October, which increased prices and loads that month.
There was a low occurrence of shortage pricing, contributing to lower overall prices.
Ancillary service costs and congestion costs were generally uneventful.
There was an increase in wind and solar energy production in October, attributed to greater installations.
Battery storage was discussed, noting it doesn't appear as supply due to it being a net load.
An analysis of battery storage showed a large capacity offered at varied price ranges, with interests on the optimized charging and discharging strategies.
The report emphasized the challenges for battery storage operators in real-time markets and the use of rule-of-thumb strategies over dynamic price bids.
McDonald acknowledged battery storage as a key future element and promised more detailed future reports.
The IMM worked on developing ASDC curves to address specific concerns while ensuring compatibility with the RTC software and existing ORDC curves.
Recommendations were made for ERCOT to evaluate and potentially refine the proposed ASDC curves.
Upcoming revision requests are being processed; initial discussions held to avoid starting from scratch when finalized.
Growth of large loads, such as data centers and crypto miners, raises concerns: these loads often fail to ride through voltage events, impacting system voltage and causing temporary power consumption dropouts.
ERCOT proposed PGRR122 to limit the loss of load to 1,000 megawatts for any single fault to manage frequency stability.
Timeline and process for getting necessary studies for 8,800 megawatts yet to be completed, dependent on input from transmission service providers.
Second major issue discussed: series capacitors added to some lines to increase power transfer capability. Risk of subsynchronous resonance when generators connect directly, leading to proposal of a new planning guide revision to prevent direct connections.
End of fall outage season; beginning of winter inspections. Outage levels are decreasing compared to mid-November.
Electric vehicle sales growth has slowed. Updated long-term forecasts reflect this trend.
Inertia of the system has overall increased slightly on average, while minimum inertia times are recovering due to increased nighttime loads from data centers.
Winter weather outlook predicts warmer and drier conditions on average, but potential for significant cold outbreaks due to increased variability in temperature.
ERCOT has achieved a budget savings of approximately $15 million by advancing its real-time co-optimization project timeline by seven months, reducing the budget to $35 million.
A beta version of the SCED software, critical for the real-time co-optimization, has been delivered and is undergoing development and testing.
The market trials plan has been approved by TAC, and initial training readiness materials are available online.
Five historical operating days were simulated to show hypothetical market prices if RTC had been in place, and results have been published.
The IMM proposed new ancillary services (AS) demand curves, with discussions planned to evaluate and possibly implement them.
Two NPRRs concerning policy issues will be drafted—an omnibus for market trial parameters and one for AS demand curves.
Significant progress has been made in market readiness training materials and defining market trials activities and criteria.
The implementation of the NPRRs needs board approval by April to proceed with May market trials; this timeline is crucial.
Feedback from the Public Utility Commission emphasizes keeping the implementation deadline on schedule for real-time co-optimization.
Stakeholders support the current implementation plans, with an adherence to the established timeline to prevent delays.
