Interregional Transfer Study: Discussion on the ERCOT interregional study, cost-benefit analysis for consumers, resource adequacy, and resiliency. RFP was posted, responses received, and proposals are being evaluated. Updates will be provided to stakeholders once available.
Load Review Update: ERCOT did not present the monthly load review as usual due to ongoing work on the official long-term load forecast. It is expected to be published in a few months, and RTP process will await finalized numbers for stakeholder discussion.
Load Forecast Completion: Target date for completion is around April, but this is subject to change. Stakeholders are advised to contact Sam Morris for updates.
TSP Review Period: Discussion on potential impact of forecast delays on TSP review periods, aiming to provide opportunities for comments despite a hard deadline of December 31st.
Impact on ERCOT Publications: Possible delay in ERCOT publications like CDR due to the delay in the official forecast. Uncertain impact and stakeholders are advised to contact appropriate personnel for confirmation.
Pricing and Interconnection Queries: Discussion on metering, interconnection processes, assumptions regarding generation facilities, and related tariffs and contracts, emphasizing the importance of location and provider-specific tariff sheets.
Oncor submitted the project for RPG review in May 2024, with an estimated cost of $744.6 million and an in-service date of December 2029.
Project addresses reliability issues due to significant load growth in the Delaware Basin.
WETT submitted an alternative project for RPG review in June 2024, with estimated cost of $305.5 million and potential cost savings of approximately $67 million.
Single EIR conducted by combining both projects and overview presented at the September 2024 RPG meeting.
Details of Oncor's proposed project include various upgrades and new constructions like new lines and transformers between substations.
WETT's proposed project has differences including new lines from Clear Fork and Lamesa to Long Draw, and other upgrades.
Specific study assumptions were discussed using 2023 RTP 2029 summer peak load case, and several transmission and generation upgrades were added to study cases.
Reliability analysis and state load flow analysis indicated the Oncor option did not show any issues while WETT had four voltage violations.
Long-term load serving capability was evaluated showing different megawatt capabilities for Oncor and WETT options.
Further evaluations and analysis to be conducted including cost estimate, feasibility assessment, and congestion analysis.
Final recommendation expected in Q1 of 2025 with status updates at future RPG meetings.
Questions from Kevin Hanson (Invenergy) and Yang Zhang (WETT) about load additions, study results, and study methodologies, which were addressed.
Clarifications on load serving capability study and load adjustments in the La Mesa area provided.
No further questions from the floor, concluding Tanzila Ahmed’s presentation.
▶️ 4 - EIR Status Update – Tredway 138-kV Switch and Expanse to Tredway 138-kV 2nd Circuit Project
The project is classified as a Tier 2 project with an estimated cost of $33 million and requires a CCN.
The estimated in-service date is June 2026.
The project addresses post contingency thermal overloads in San Patricio County.
Proposal involves rebuilding the Aransas Pass to Gregory transmission line and the Gregory to Rincon line to 138-kV capable levels, but operated at 69-kV.
Upgrades include the Gregory substation and related transmission line terminals to 2,000 amp capability.
Reliability analysis will be performed, considering contingencies, NERC, and ERCOT reliability requirements.
Long-term load serving capability assessment will be conducted.
Possible congestion analysis might be done to ensure no further congestion in the area.
Updates on the project will be provided in RPG meetings with final recommendations expected in Q1 of 2025.
A clarification was provided regarding the long-term load serving assessment being similar to a transfer analysis.
2024 RTP was deemed memorable due to significant large load additions, including data centers (both crypto and non-crypto), hydrogen ammonia, industrial manufacturing, and oil and gas.
Analysis included a heat map of large loads, concentrated primarily in Dallas and Corpus Christi areas.
Discussion of heavy load flows into the Dallas-Fort Worth area and challenges in handling those flows.
Introduction of the Texas 765-kV strategic transmission expansion plan as an alternative to accommodate increased load growth.
Comparison between traditional 345-kV plan and new 765-kV plan which showed 765-kV plan mitigates some local issues.
Introduction of new scenarios such as fall peak maintenance outage scenario.
Use of sensitivity analysis by lowering announced load and turning off generation not in queue to see impact on system reliability.
Cost comparisons made between 345-kV and 765-kV plans; the latter potentially cost-effective considering future needs.
Discussion of tracking and implementation of projects, and the potential role of ERCOT’s public reporting.
Questions and Responses:
From: Monica Jha, Vistra Question: Understanding future RPG approval process for large loads. Response: Will depend on TSP and their scheduling with Robert Golen's RPG team.
From: Komal Shetye, Scout Clean Energy Question: Whether RTP load models are included in final ERCOT power flow models. Response: Yes, large loads are included in final RTP cases.
From: Ken Donohoo, Advanced Power Alliance Question: If ERCOT will monitor projects as they get built. Response: TPIT spreadsheet tracks projects, but ERCOT open to further suggestions.
From: Shirley Mathew, Texas RE Question: Tracking materialization of large load additions. Response: Handled by ERCOT's large load interconnection group with confidentiality considerations.
From: Various Participants Questions: Clarifications on project specifics, cost estimates, and models. Responses: Provided details on station plans, transformer types, projects not needed under reduced load conditions, and general clarifications.
▶️ 8 - 2024 Grid Reliability and Resiliency Assessment Final Update
The 2024 Grid Reliability and Resiliency Assessment is mandated by 87R-SB1281 and adopted into the 16 Texas Administrative Code § 25.101.
The assessment considered two scenarios: a winter extreme scenario and a summer hurricane scenario.
Resiliency projects meeting the criteria were identified for both scenarios to prevent cascading failures, instability, and reduce outage impacts like loss of service.
For the winter scenario, reinforcement of 345-kV pathways from the coast into central and north-south of Dallas into central was identified as beneficial.
For the hurricane scenario, substation hardening was a key improvement, alongside line upgrades and additions.
Distribution hardening, although out of ERCOT's immediate scope, was noted as beneficial for transmission system resiliency.
A formal process to determine project benefits through protocol revision is intended to be proposed by ERCOT.
The summer hurricane scenario used a Category 5 storm model based on an Argonne National Labs study.
Damages were categorized into slight, moderate, substantial, and severe; complete damage was noted as non-existent.
Winter scenario used load forecasts based on historical analysis accounting for weather events like Winter Storm Uri, Elliott, and Heather.
A resource adequacy issue was identified in the winter scenario, resolved by reducing crypto and industrial load.
Generation capacity losses due to weatherization were considered, leading to identification of resource adequacy issues.
Questions from attendees addressed aspects like generation resource adequacy, transmission constraints, and reserve margins.
The 2024 Long-Term System Assessment (LTSA) is a biannual study analyzing future scenarios for system planning over the next six years, supplementing the RTP.
The study includes three scenarios: Current Trends, High Large Load Adoption, and High Load Growth with Environmental Regulations.
Key findings include the replacement of coal and natural gas with wind, solar, and battery storage; renewable resources representing more of the generation capacity; importance of energy storage; and transmission challenges between resource-rich areas and demand centers.
Transmission improvements and four new projects are required for future economic savings.
LTSA analyses indicate a significant increase in required generation capacity by 2039, especially under high load growth scenarios.
The impact of potential policy changes, such as the pause on wind contracts by President Trump, is currently unclear but will be assessed in future LTSA processes.
Questions from participants raised issues like emission credits for combustion turbines and the need for detailed environmental regulations in the analyses.
Discussion Points:
Curtis Tarwater brings up the impact of the pause on wind contracts and ERCOT's lack of immediate information on it.
Bob Wittmeyer seeks clarification about the generation capacity required and its feasibility for future scenarios.
Kevin Hansen asks about the presence of sufficient emission credits to support combustion turbines in the market.
Environmental regulation assumptions and their documentation are discussed following a question.
