ERCOT TAC Meeting Summary: Batch Zero Approval, RPG Projects, and Large Load Interconnection Updates

ERCOT TAC Meeting 05/19/2026 Summary

The ERCOT Technical Advisory Committee (TAC) meeting held on May 19, 2026 primarily focused on transmission reliability planning (RPGs), market rule revisions, ERCOT operational updates, and the proposed Batch Zero framework for Large Load Interconnections under PGRR145 and NPRR1325.  

Regional Planning Group (RPG) Projects 

A major portion of the meeting was dedicated to reviewing and voting on several transmission expansion projects submitted through the RPG process. These projects were aimed at improving reliability, supporting anticipated load growth, and addressing long-term transmission constraints across different regions of Texas. 

(1.) CPS Energy Reactive Power and Helotes Projects (25RPG013 & 25RPG017) 

• ERCOT reviewed the combined CPS Energy Reactive Power Planning Project and Helotes 345/138-kV project for Bexar County reliability concerns. 
• Addresses thermal overloads, voltage violations, and reactive power deficiencies in the Bexar County/San Antonio area while improving long-term load-serving capability. 
• The recommended upgrades include:  
  • New autotransformers  
  • 600 MVAr of STATCOM additions  
  • New 345-kV transmission lines  
  • Rebuilds of several 138-kV facilities  
• ERCOT noted that the original combined project estimate of approximately $235 million increased to approximately $477.7 million after additional reliability-driven upgrades were identified during the EIR process. 

(2.) Muscovy and Voss Lake Project (25RPG009) 

• Resolves thermal and voltage reliability concerns across Bell, Milam, Williamson, Bastrop, Travis, Hays, Caldwell, and Robertson counties while improving long-term transmission capability. 
• Estimated cost of recommended solution is $1.457 billion after ERCOT incorporated RTP-related and additional reliability-driven upgrades. 
• The recommended option includes: 
  • Approximately 159 circuit-miles of new 345-kV lines  
  • New substations and autotransformers  
  • Rebuilt 345-kV and 138-kV facilities  
  • Additional capacitor installations. 

(3.) Oncor Set 1 & Set 2 North and Central Texas Reliability Projects (25RPG040 & 25RPG042) 

• Addresses reliability concerns and transmission constraints across the North, North Central, and East Weather Zones while supporting rapid large load growth. 
• Estimated cost: 
  • Approximately $2.363 billion total:  
  • ~$2.307 billion for Group 2 upgrades  
  • ~$56.4 million for Group 3 upgrades.  
• Load difference from RTP assumptions: 
  • EIR study load reached approximately 71.9 GW compared to:  
    • 55.4 GW in the 2025 RTP  
    • 58.3 GW in the 2024 RTP 
• Recommended upgrades/solution: 
  • ERCOT recommended Group 2 and Group 3 upgrades including:  
    • New 345-kV and 138-kV transmission lines  
    • Reconductoring work  
    • Rebuilt substations  
    • Additional autotransformers.  

(4.) Oncor Set 1 & Set 2 North Central and South Central Texas Reliability Projects (25RPG041 & 25RPG043) 

• Addresses reliability needs and supports long-term transmission capability across North Central and South Central Texas under rapidly increasing load conditions. 
• Estimated cost: 
  • Approximately $381 million for the recommended Group 2 upgrades. 
• Load difference from RTP assumptions: 
  • EIR study load reached approximately 89.9 GW compared to: 
    • 70.8 GW in the 2025 RTP  
    • 71.4 GW in the 2024 RTP 
• Recommended upgrades/solution: 
  • Approximately 13.8 miles of new 345-kV lines  
  • Rebuilt 138-kV facilities  
  • Substation rebuilds  
  • Autotransformer upgrades. 

(5.) Euclid 765-kV Project (26RPG001) 

• Improves import capability, voltage support, and long-term reliability in Central Texas while supporting future large load growth. 
• Estimated cost: 
  • Approximately $1.831 billion with expected in-service date in 2031. 
• Load difference from RTP assumptions: 
  • EIR study load reached approximately 89.9 GW compared to: 
    • 70.8 GW in the 2025 RTP  
    • 71.4 GW in the 2024 RTP 
• Recommended upgrades/solution: 
  • Approximately 131 miles of new 765-kV transmission line  
  • New 765-kV substation  
  • Two new 765/345-kV transformers  
  • Associated breaker and reactor upgrades. 

Note: All the above RPG projects were endorsed by the TAC. 

Revisions and Market Rule Changes

• TAC reviewed and approved several market rule revisions related to ERCOT system access modernization and administrative updates. 
• NPRR1302, which establishes a Market Participant Service Portal within the MIS Certified Area and revises associated forms, was approved. TAC also approved NPRR1306, which removes outdated digital certificate references for Market Participants with ERCOT MIS access. 
• Related revisions including RMGRR184, COPMGRR052, and VCMRR045 were also approved to align supporting market documents with the updated MIS access framework. 

ERCOT Reports

ERCOT provided several operational and market-related updates during the meeting. 

• ERCOT discussed continued growth in the Aggregate Distributed Energy Resource (ADER) Pilot and reviewed proposed updates to the ADER Governing Document, including removal of CIM Load rating cap language and continued development of a long-term Protocol framework.  
• ERCOT also presented the Firm Fuel Supply Service (FFSS) Settlement Report for the 2025–2026 winter season, including updates on FFSS procurement, decertifications, and clawback settlements.  
• Additionally, ERCOT reviewed a potential Real-Time Market price correction associated with a software defect affecting Qualified Facilities between December 2025 and January 2026. ERCOT identified five Operating Days meeting Protocol significance thresholds for possible Board review.  
• ERCOT also initiated discussions on the proposed 2027 Ancillary Services Methodology review timeline and presented preliminary results from the PUC-directed Ancillary Services and Reliability Services cost allocation study.  

Batch Study Items – PGRR145 and NPRR1325

The most significant and heavily discussed portion of the TAC meeting involved the proposed Batch Zero framework for Large Load Interconnections under PGRR145 and the related NPRR1325. 

• ERCOT emphasized that the current Batch Zero scope is already aggressive with approximately 220 GW of potential modeled 2032 load, including nearly 113 GW of base forecast load, and cautioned that expanding the study scope further could result in unreliable or non-actionable study outcomes because of growing uncertainty related to generation availability and transmission capability. 
• A major focus of discussion involved ERCOT’s May comments to PGRR145. ERCOT explained that the revisions primarily clarified implementation details, study validity requirements, and eligibility criteria for Batch Zero participation. Key revisions discussed during the meeting included: 
• Clarification that ERCOT may verify an Interconnecting Large Load Entity’s (ILLE’s) eligibility status through April 9, 2027 while allowing entities an opportunity to explain inconsistencies before ERCOT determines whether submitted information is materially false.  
• Addition of Fitch Ratings as an acceptable rating agency option for financial qualification requirements.  
• Clarification that direct interconnection cost obligations may be satisfied through existing agreements.  
• Requirement that all discretionary approvals, including zoning and special use permits, be obtained at the proposed interconnection location.  
• Allowing ERCOT to coordinate with Transmission Service Providers (TSPs) regarding project timing assumptions when projects are not included in Transmission Project Information Tracking (TPIT).  
• Addition of a cure period for deficient dynamic data submissions.  
• Clarification regarding treatment of RPG-based study validity and MW withdrawal limits.  
• Addition of a dispute resolution process for ILLE classification disputes.  
• Inclusion of additional references to the Interconnecting Transmission Service Provider within implementation language.  

Another major topic of discussion involved the treatment of existing LLIS studies and RPG-related projects. ERCOT noted that modifications to automatically valid RPG study treatment could require reassessment or restudies for several ongoing LLIS projects. Stakeholders also discussed concerns regarding transmission project assumptions, study validity timelines, and prioritization methodologies for projects already deep into the interconnection process. 

• TAC additionally heard extensive stakeholder comments from Reliant, Wise Energy, Cholla, TEBA, Sailfish, Eolic, Vistra, Data Center Coalition, BKV, Agentic Infrastructure, and Luminary Strategies. 
• Several stakeholders, including Reliant, Wise, Sailfish, Agentic, and Eolic, supported broader treatment of Withdrawal-Limited Private Use Networks (WLPUNs) and Provisional Controllable Load Resources (PCLRs), arguing that these structures provide additional grid flexibility and reduce transmission impacts while supporting more efficient large load integration.  
• Cholla Petroleum requested additional validation reporting for several major Oncor reliability projects and sought further visibility into original studied loads, approved additional loads, and remaining unserved transmission capacity.  
• Vistra, BKV, and the Data Center Coalition largely focused on treatment of net-metered and co-located generation projects under PURA Section 39.169, emphasizing that these projects provide operational flexibility, lower transmission impacts, and additional reliability benefits.  
• TEBA and Luminary Strategies emphasized that the Batch Zero framework should avoid creating arbitrary barriers for viable large load projects and argued that inclusion of additional studied load could support future transmission cost recovery and generation investment.  
• Following extensive discussion, TAC voted to approve PGRR145 as recommended by ROS and amended by ERCOT’s May 18 comments. Several stakeholder desk edits and alternative revisions were discussed during the meeting; however, those alternative versions did not pass. 
• NPRR1325, which aligns related Protocol language with the Batch Zero framework established under PGRR145, was also approved by TAC. 

Conclusion

The May 19, 2026 TAC meeting highlighted ERCOT’s continued efforts to address rapid load growth, transmission reliability needs, and increasing interconnection complexity across the ERCOT region. Approval of multiple large-scale RPG projects reflected the growing need for substantial transmission expansion to support projected demand growth and maintain system reliability. 

The meeting was particularly notable for the advancement of the Batch Zero framework under PGRR145 and NPRR1325. Discussions throughout the meeting demonstrated the challenges ERCOT and stakeholders face in balancing reliability, fairness, transmission capability, and project readiness while responding to an unprecedented number of large load interconnection requests. The Batch Zero initiative is expected to significantly shape future large load planning, transmission development, and interconnection processes across ERCOT in the coming years. 

As ERCOT continues advancing large load interconnection reforms, transmission expansion, and reliability-driven planning, project readiness is becoming increasingly tied to technical strategy and regulatory awareness. ZEG helps developers, utilities, and large load customers navigate evolving ERCOT requirements through engineering-led interconnection support, grid modeling, and strategic due diligence. Contact ZEG to better prepare for shifting grid planning and interconnection risks.