Oncor submitted the Delaware Basin stage 5 project for review estimated to cost $744.6 million, targeting a December 2029 in-service date, addressing reliability issues in the Delaware Basin due to load growth.
WETT proposed an alternative, estimated at $305.5 million, with potential cost savings and a December 2028 target date.
ERCOT conducted a combined independent review for both Oncor's and WETT's options.
Preliminary results showed both options met reliability criteria with similar long-term load serving capabilities and no violations during maintenance outage analysis.
Updated feasibility and cost assessments indicated Oncor's project at $855.3 million and WETT’s at $871 million.
ERCOT selected Oncor’s option as it met criteria, improved long-term capability, required less CCN mileage, and was the least cost option.
Further analyses including congestion, generation addition sensitivity, load scaling, and SSR assessment showed no significant impacts favoring the Oncor proposal.
Future steps involve formal reports and recommendations proceeding through ERCOT's governance structures.
Yang Zhang from WETT questioned the decision-making process, specifically highlighting load serving capability, CCN mileage, and cost differences.
ERCOT emphasized the primary focus is on meeting reliability needs and economic solutions, indicating cost was a significant factor between the two similar options.
▶️4 - EIR Status Update – Hartring to Upland 138-kV Line and Benedum Autotransformer Addition Project
Addressed 13 thermal overloads and multiple voltage violations using planning guide methodologies.
Options evaluated for addressing violations include different combinations of transmission line upgrades and substation enhancements across various regions of Houston.
Option 1 focuses on Midtown with upgrades in Grant to Herman line and specific substation enhancements.
Option 2 involves broader upgrades across Midtown, Baytown, Southeast Houston, and North Houston.
Option 3 mirrors Option 2 except for Baytown differences, focusing on extending double circuit 345-kV lines.
Timeline anticipates final recommendation by Q2 and readiness for board consideration in June.
No questions or concerns were raised by attendees.
▶️6 - EIR Status Update – Texas A&M University System RELLIS Campus Reliability Project
The RELLIS Campus Reliability Project is a tier one project with a cost estimate of $271.5 million, requiring a CCN. The estimated in-service date is May 2029.
ERCOT conducted a reliability need analysis driven by a new confirmed load of 378 MW in 2030. The analysis revealed multiple reliability violations in various competency conditions including low voltage and thermal overloads.
Four options were studied to resolve the reliability violations. Option 1 involves expanding the existing RELLIS substation and adding a 345 kV double circuit line from TNP One to RELLIS. Other options involved different configurations of lines from TNP One, Sandow, and Salem to RELLIS.
Options 1, 2, and 4 resolved all reliability violations under particular conditions, making them shortlisted for further evaluation. Option 3 had remaining overloads.
Further evaluations will continue including long-term load serving capability assessments, cost estimates, and feasibility assessments. Final recommendations are expected by the end of the year.
No questions were raised during the meeting.
▶️7 - EIR Status Update – Aransas Pass to Rincon 69-kV Line Rebuild Project
The project was submitted in November 2024 as a tier two project, estimated at $33 million, requiring a CCN, with an in-service date of June 2026.
The project addresses post-contingency thermal overloads in San Patricio County.
ERCOT provided updates in previous RPG meetings, and the project is under independent review.
Three options were presented to address thermal violations identified from Gregory to Aransas Pass.
Option 1 involves rebuilding the existing Aransas Pass to Gregory 69-kV line to a 138-kV standard, with ratings of 239 MVA for 8.5 miles, including a 0.03-mile segment from Gregory to Rincon.
Option 2 includes building a new Gregory to Gibbs 138-kV line, costing $52 million and requiring 1.36 miles of CCN.
Option 3 involves building a new Ingleside - DuPont switch to Ingleside 138-kV double circuit line, costing $48 million and requiring 3.25 miles.
All options were feasible and met ERCOT's reliability criteria, improving long-term load-serving capability.
Option 1, costing $34 million and requiring one mile of CCN, is ERCOT's preferred option due to its cost-effectiveness and minimal CCN mileage.
A congestion analysis showed no new congestion for the preferred option within the study area.
The preferred option is to be completed by June 2026, with an EIR report to be posted in May.
Oncor submitted the Roscoe area upgrades project for RPG review in December 2024 with an estimated cost of $83 million and expected in-service date of June 2028.
The project's main purpose is to address voltage violations observed by Oncor in the West weather zone, Nolan County.
Project upgrades include enhancing the path from Eskota to Oak Creek, Oak Creek to Nolan, and Nolan to Sweetwater from 69-kV to 138-kV and constructing a new 138-kV line from Sweetwater Creek to Kilgore.
Four project options were evaluated for addressing voltage violations, with options one and four shortlisted for further evaluation due to no thermal or power flow violations.
Option one is Oncor's proposal, and option four includes constructing a new substation tapping between the Champion Creek to Oak Spring 345-kV line.
Option three was deemed infeasible, and option two exhibited a thermal violation.
Both shortlisted options showed improved long-term load serving capability and no voltage violations during planned maintenance outage evaluations.
Next steps include further evaluation of options, feasibility assessments, and cost estimates with updates provided in the next RPG meeting and final recommendations reported by May.
No questions were raised from the participants.
▶️9 - Southern DFW Load Interconnection and General Grid Strengthening Project Overview
The focus is on the transmission elements in various counties in the North, Central, and East weather zone, using a base case from the 2024 RTP and 2029 summer peak load case.
Projects within the study area before December 2028 will be included unless they're already in the case; some are listed in appendix A1.
Transmission projects identified as placeholders in the 2024 RTP will be removed, with a list available in appendix A2.
New generation with a service date before December 2028 will be added if not already modeled, as per the 2025 March GIS report.
Generation dispatch will be consistent with the 2024 RTP, and recently retired units will be reviewed.
Study area load adjusted to project submissions while maintaining reserves consistent with the 2024 RTP.
Standard contingencies will follow NERC and ERCOT guidelines, and specific plants and transformers were listed for testing.
Reliability analysis, maintenance outage evaluation, and long-term load capability assessment will be executed.
Project validity will lead to additional analysis like sensitivity, SSR assessment, and congestion analysis.
Updates will be provided in future RPG meetings with final recommendations tentatively scheduled for Q3 2025.
▶️11 - Hamilton County Conversion Project Overview
The project spans across Comanche County, Hamilton County, Coryell County, and into Bell County.
Brazos Electric is responsible for a long 69-kV transmission line in this corridor.
Project begins at Hasse Substation with a 138-kV source and will move south to Gustine-Indian Gap transmission line.
A CCN application required due to limited existing easements, additional easements are being acquired.
Full voltage conversion planned due to a transmission constraint.
Grizzly Ridge site has a generator limited to 70 MW, although capable of 110 MW.
Two official projects are connecting to the grid: Grizzly Ridge and another 100 MW solar farm.
There have been several load inquiries, but many are put off by potential delays for full service capability.
Brazos Electric is concerned about potential future voltage violations due to load growth.
Goal is to perform a full voltage conversion from Hasse to Poage (soon to be replaced by Crusader station).
The project description is submitted and available on the ERCOT MIS site, though not with meeting materials.
No additional comments or questions from the room attendees.
▶️12 - ERCOT Independent Review Scope: Hamilton County Conversion Project
The project is a tier two project estimated to cost $90 million, requiring CCN with an estimated in-service date of fall 2030.
It is recommended as a GTC exit strategy for the Hamilton GTC.
Project involves converting multiple 69-kV to 138-kV pathways in between Hasse and Poage and involves various substations and transmission lines.
They will rebuild certain segments as double circuits with specified MVA ratings.
Study assumptions include focusing on the North Central weather zone, and using the 2024 RTP 2030 summer peak case.
Economic study will also be conducted using the 2024 RTP economic study base case for 2029.
Needed analysis will include both reliability and economic analysis, project evaluation will test alternatives, and planned maintenance and congestion analysis will be conducted.
Final project recommendation expected in Q2 of this year.
Question about additional generation for Brazos interconnecting with the project area will be updated in the April GIS report.
GTC exit strategy option is studied as a project alternative.
▶️13 - Update on Financial Assumptions for ERCOT Economic Planning Criteria
ERCOT performs two required tests for economic projects, namely the congestion cost savings test and the production cost savings test, as per PUCT substantive rules.
A transmission project is considered economically viable if it passes either of these tests.
The congestion cost savings test evaluates if consumer energy cost savings exceed the average of the first three years' annual revenue requirement.
The production cost savings test assesses if annual production cost savings exceed the first year annual revenue requirement.
Nodal protocol sections 3.11.2(5) and 3.11.2(6) necessitate annual reviews of financial assumptions used to determine revenue requirements.
Revenue requirement calculations for TSPs cover the return on rate base (cost of equity and debt and debt to equity ratio), depreciation, O&M costs, and taxes.
The current financial assumptions methodology in use is consistent with that used in 2024.
The methodology employs a generic transmission project with assumed capital cost for each TSP to calculate revenue requirements.
Results show a side-by-side comparison of first year and average first three years' revenue requirements for each TSP.
Weighted first year annual revenue requirement is at 13%, and the average for the first three years is 12.7% for this year.
Questions were addressed regarding the economic criteria tests and the generic baseline project used for calculations.
