Meeting Summary – 09/25/24 RPG Meeting

1 – Antitrust Admonition

2 – Miscellaneous Updates – ERCOT

• Caleb Holland is leaving the regional planning group.
• This will be Caleb’s last presentation as a member of the regional planning group.
• Caleb received thanks for his years of hard work and dedication.
• Caleb’s final update involves the Brownsville project.

3 – EIR Status Update – Brownsville Area Improvements Transmission Project – ERCOT – Caleb Holland

EIR – AEPSC Brownsville Area Improvement_Status Update_Sept 2024

Overview: Final status update on the AEP Brownsville Improvements transmission project.

• Project Recap: Submit by AEP in March 2024, estimated cost $388M, service date May 2027.
• Project Scope: Addressed thermal overloads and voltage violations in Brownsville area with new load additions.
• Status: Provided regular updates, project under ERCOT independent review.
• Geographical Focus: South weather zone, particularly Brownsville area in Cameron County.
• Shortlisted Options and Details: Explained technical specs and differences of options 2a, 5a, 7, and 8.
• Evaluation Results: Detailed the voltage violations and thermal overloads for various options.
• Preferred Option Selection: ERCOT selected option 2a – least cost, met all criteria, required less CCN mileage, improves operational flexibility.
• Sensitivity Analyses: Generation addition and load scaling sensitivities showed no material impact on project.
• Congestion Analysis: Identified one newly congested line, not recommended for upgrade.
• Next Steps: EIR report posting, TAC recommendation in October, ERCOT board endorsement in December.
• Q&A Highlights: Discussion on load coverage, decision making between options, concerns about confirmed vs. officer letter loads.
• Additional Comments: Need for external discussions between AEP and Sharylandto resolve differing views surrounding project.

4 – EIR Status Update – Rand Area Loop Project – ERCOT

Rand_Area_Loop_Project_RPG_09252024.pdf

• Presenter: Abhishek Penti
• Rayburn Electric Cooperative (REC) submitted the Rand Area Loop project for RPG review in May 2024, a tier two project estimated at $32.2 million requiring a CCN.
• Estimated in-service date is April 2027.
• Purpose: Limit radial load to less than 20 MW and provide “looped service” to REC Rand substation.
• Project is currently under ERCOT independent review.
• ERCOT conducted a steady-state load flow analysis based on TPL-001-5.1 and planning criteria with no voltage, thermal, or unsolved power flow violations found.
• Seven options evaluated with three proposed by REC and four by ERCOT.
• Options 1 and 2 had thermal violations for N-1 contingency scenarios.
• Options 3, 4, 4a, 5, and 6 selected for further evaluation.
• Option 5 deemed infeasible due to Explorer switching station constraints; remaining options require a CCN and are feasible.
• Plant maintenance outage evaluation showed no voltage violations, thermal overloads, or unsolved power flow violations for shortlisted options.
• Long-term load serving capability analysis performed; Options 3, 4, and 4a performed similarly, while Option 6 had less capability.
• All four shortlisted options (3, 4, 4a, 6) meet reliability criteria, REC planning criteria, and improve long-term load serving capability.
• Option 3 is the preferred option: least expensive, fully addresses REC planning criteria, no reliability issues, improves operational flexibility, and enhances long-term load serving capability.
• Congestion analysis (using 2023 RTP 2028 economic case) showed no new congestion within the study area.
• Option 3 details:
  • Estimated cost $32.2 million
  • Service date April 2027
  • Involves new 138-kV switch yard between Explorer and Glen Pine 138-kV line with a new 138-kV line from Rand to the new switchyard, approximately 12.35 miles.
• ERCOT protocol section 3.11..4.9(4) endorses this project to meet REC planning criteria.
• EIR will be posted to MIS in October.
• No audience questions; next presentation: Oncor Delaware basin stages 3 and 4, under ERCOT independent review.

5 – EIR Status Update – Delaware Basin Stages 3 and 4 Project – ERCOT – Tanzila Ahmed

Oncor_Delaware_Basin_Stages3and4_Project_Status_Update_RPG_09252024_18l1p7kw06lrb.pdf

• Project submitted by ERCOT in March 2024 with an estimated cost of $202.2 million.
• Estimated in-service date is summer 2027.
• Project aims to address reliability issues in Delaware Basin area due to significant load growth primarily for oil and gas.
• Previous studies: 2019 Delaware Basin Load Integration and 2024 Permian Basin Reliability Plan.
• Stage 1 upgrade completed in 2023, Stage 2 upgrade expected in 2026, Stage 5 upgrade under review.
• Stage 3 involves a new 345-kV substation, double circuit 345-kV line from Riverton to Drill Hole, and transformer upgrades.
• Stage 4 involves a double circuit 345-kV line from Sand Lake to Riverton.
• Reliability analysis includes sensitivity analysis and planned maintenance outage evaluation.
• Total of 20 voltage violations including 2 generation violations and 2 transformer violations, and 4 unsolved power flow issues identified. All solved by the proposed project.
• Upcoming tasks: conducting congestion analysis, updating cost estimates, and providing further status updates.

6 – EIR Status Update – Venus Switch to Sam Switch 345-kV Line Project – ERCOT

ONCOR_Venus_Switch_to_Sam_Switch_Project_Update_09252024.pdf

Discussions:

Presenter: Sarah Gunasekera

• Oncor submitted the project RFP in June, estimated cost is $118.9 million and will not require a CCN.
• Project to be completed by May 2026.
• Addresses post contingency thermal overloads on the Venus switch to Sam switch double circuit 345-kV line.
• Project is currently under ERCOT independent review.

Study Assumptions

Using 2023 RTP for 2026 summer case, adding 730 confirmed load, maintaining 2023 RTP reserve levels.

Preliminary Results

• Three voltage violations under N-1 conditions, seen also under G-1 and X-1.
• Four thermal overloads under P1 and one under P7 conditions.

Options

• Option 1: Oncor proposed project, upgrading various 345-kV lines totaling about 76 miles.
• Option 2: Includes upgrades in Option 1 plus Venus switch to Navarro 345-kV line upgrade of 33.2 miles.

Preliminary Results for Options

• No thermal or voltage violations in N-1 study for Options 1 and 2.
• Thermal and voltage violations observed under G-1 and X-1 conditions.
• Decrease in thermal violations seen, especially in Option 2.

Next Steps

• Study additional project alternatives to satisfy ERCOT reliability criteria.
• Perform evaluations on plan maintenance outage, long term load serving capability, generation addition and load scaling sensitivity, subsynchronous resonance assessment, and congestion analysis.

Timeline: Final recommendation expected in Q4 of this year.

Q&A:

• Questioner: Sunil Dhakal, Lone Star Transmission
  • Question: Are there plans to look into 345-kV  in the area?
  • Response: Potentially, evaluation ongoing.
• Questioner: Harsh, Oncor
  • Question: Clarification on treating 345-kV overloads and 69-kV voltage issues separately.
  • Response: Evaluating solutions for Waxahachie area, particularly Wilmer project, considering additional generation resources and load in northern Dallas. Conclusions not yet solidified.

7 – ERCOT Independent Review Scope: Connell 345/138-kV Switch and Connell to Rockhound 345-kV Double-Circuit Line Project

Oncor_Connell_to_Rockhound_RPG_Project_SCOPE_09252024_RPG_1.pdf

• Ben was unavailable to present; Robert Golan took over.
• Project submitted by Oncor in June 2024.
• Tier one project costing $110.62 million, requiring a Certificate of Convenience and Necessity (CCN).
• Estimated in-service date: December 2026.
• Addresses low voltages and thermal overloads expected by summer 2025 due to significant load growth in the western portion of Texas, primarily from the oil and gas industry.
• Project includes various constructions and installations:
  • New Connell 345/138-kV switching station.
  • Two new Connell to Rockhound 345-kV lines (13 miles).
  • New circuitry and breakers at multiple existing switches.
  • Reconfiguration of existing connections within the studied areas.
• Scope and study area: Western Texas counties focusing on Midland and Martin.
• Will follow NERC TPL-001-5.1 and ERCOT planning criteria.
• Timeline for final recommendation: Q4 of 2024, with status updates at future RPG meetings.
• No questions from the audience; the presentation moved to the next agenda item on the Forty 345/138-kV switch rebuild project.

8 – Forney 345/138-kV Switch Rebuild Project Overview – Oncor

Oncor_Forney345-138kV_Switch_Project_RPG_09252024.pdf

• Rebuild project is estimated to cost $103.5 million.
• The project addresses thermal violations, replaces aging infrastructure, and enhances system reliability.
• Existing switching station details: 345-kV double bus double breaker configuration, 138-kV single bus with 345/138-kV auto transformer rated at 750 MVA.
• New switch configuration will be in a breaker-and-a-half layout.
• Installation of a second 750 MVA auto transformer and a 110.4 MVAR capacitor bank at Forney was proposed.
• Main driver of the project is the thermal violations observed at the existing Forney auto transformer.
• Existing infrastructure at Forney was built in the 1960s and lacks modern microprocessor relays.
• Rebuild scope: 345-kV equipment rated at 5,000 AMP, 138-kV equipment rated at 3,200 AMP, new auto transformer rated at 750 MVA, and relocation of the Forney substation.
• Reactive support needs identified by real-time operational data showing low voltages in Dallas and Kaufman County.
• Capacitor banks proposed to address low voltage issues not captured by models but observed in real-time operations.
• Operational feedback prompted the reactive support installations to maintain system voltage around one per unit.
• No further questions from attendees after the presentation.

9 – ERCOT Independent Review Scope: Forney 345/138-kV Switch Rebuild Project – ERCOT

Oncor_Forney_345_138-kV_Switch_Rebuild_Project_RPG_09252024.pdf

• Presentation given by Abishek Penti for Oncor’s NSW project.
• Project submitted to RPG in July 2024, estimated cost of $103.5 million.
• In-service date estimated to be December 1, 2025.
• Purpose: Address post-contingency thermal violations and replace aging infrastructure.
• Project includes installing multiple 345 kV and 138 kV breakers in a breaker and a half arrangement and adding an auto transformer.
• Switch rebuild aims to improve operational flexibility and system reliability in Dallas Fort Worth region.
• ERCOT independent review involves monitoring north and north central weather zones, focusing on Dallas and Kauffman counties.
• Base case to be updated using 2023 RTP for 2026 summer peak.
• Loads consistent with 2023 RTP methodology; newly approved loads added to the base case.
• Contingency analysis to follow specific ERCOT regulations and criteria, monitoring various parameters like thermal and voltage limits.
• Study procedure includes need analysis, project evaluation, sensitivity analysis, subsynchronous resonance (SSR) assessment, and congestion analysis.
• Status updates to be provided in future RPG meetings with a final recommendation by Q4 2024.
• No questions or comments from the attendees after the presentation.

10 – Wilmer 345/138-kV Switch Project Overview – Oncor

Oncor_Wilmer345-138kV_Switch_Project_RPG_09252024.pdf

• Oncor presented an overview of the Wilmer 345/130-kV switch project.
• The project aims to establish a 345/130-kV switch in Dallas County, referred to as Wilmer Switch.
• Projected cost: $158.2 million.
• Purpose: Address large load request of 756 MW at Wilmer 130-kV substation, preventing thermal violations and enhancing network reliability.
• Location selection criteria: Proximity to load request and economic viability.
• Project includes: Establishing a new 345/130-kV switch and two new transformers, terminating certain lines into Wilmer Switch, and rebuilding portions of the existing Watermill 345 kV line.
• Rebuild and convert existing 69 kV line from Wilmer to Ferris to 130 kV operation.
• Confusion addressed on how interconnection agreements are signed: Explained that agreements are contingent on approval and customers are informed of required upgrades. Load does not come online until 2026.
• End use classification of the load: Data center, non-crypto.

11 – ERCOT Independent Review Scope – Wilmer 345/138-kV Switch Project – ERCOT

Oncor_Wilmer_345138-kV_Switch_Project_Scope_RPG_09252024.pdf

• ERCOT independent review study scope for the Wilmer 345/138 kV switch project presented by Yin Li.
• Described overload issues in the Wilmer area due to new load, including Wilmer, Watermill, Seagoville, Forney, Kaufman, and the south area.
• Oncor’s proposed solution: Wilmer 345/138 kV project with two transformers and transmission upgrades.
• Study assumptions, including region focus (North Central weather zone), use of 2033 RTP and 2028 thermal peak case for data.
• Transmission projects with in-service dates before summer 2028 and relevant additions and removals detailed in appendices A and B.
• Generation projects included based on August GIS report and adhering to 2023 RTP methodology.
• Load assumptions include an additional 756 MW new confirmed load at Wilmer.
• Contingency and criteria adherence, including techniques like need analysis, sensitivity analysis, SSR assessment, and congestion analysis.
• Timeline goal to complete the study by December.
• Question raised about performing dynamic stability studies for the large new load. Oncor confirmed no stability issues were found.
• Clarified that ERCOT relies on TSP’s stability study results unless specific stability issues are identified.
• Confirmation that necessary stability studies were performed by Oncor, with a request to specify dynamic models used.
• Yang Zhang (WETT) highlighted the importance of naming and organizational clarity for meeting minutes.
• Further comment from another participant emphasized the need to reassess if the RPG study results match TSP studies, regarding the need for dynamic stability studies.
• Conclusion with an acknowledgment of no more questions, and the next item handed back to Oncor for the Delaware Basin stage five project overview.

12 – Delaware Basin Stage 5 Project Overview – Oncor

Delaware_Basin_Stage5_RPG_Overview_for_ERCOT_09252024.pdf

• ERCOT’s 2019 Delaware Basin Load Integration Study identified 5 stages of transmission upgrades
• Stage 5 necessary when load exceeds 5,422 MW, anticipated by summer 2025
• Load levels based on SSWG cases from October 2023
• Oncor analysis found numerous contingencies causing low voltages and thermal violations
• Proposed upgrades include 220 miles of 345-kV double circuit line
• Project components: expanding 138 kV switchyard at Lamesa, new 138-69 kV switching station at Welch, rebuilding Clearfork 345 kV switch
• Estimated project cost: $744.6 million
• Project impacts eight counties: Andrews, Borden, Culberson, Dawson, Gaines, Loving, Reeves, Winkler
• Significant load growth attributed to oil and gas industry and inverter-based resources
• Expected to enhance reliability and import capability for West Texas
• Detailed scope of transmission upgrades outlined with specific line mileages and terminus points
• Project requires multiple CCN applications, construction from 2025 to December 2029 depending on various factors
• RPG submittal comment period ended May 28, ERCOT Independent review by November 22
• Following the overview, questions from Cyrus and Kevin addressed matters related to potential 765 kV line alternatives and reliability impacts
• Subsequent presentation for Delaware Basin Stage 5 project alternatives

13 – Delaware Basin Stage 5 Project Alternative Overview – WETT

WETT_DB5_Alternative_Overview_RPG.pdf

• Presentation by WETT on Delaware Basin Stage 5 project alternatives.
• Background: Need for system upgrades in the Delaware Basin to serve oil and gas loads identified in 2019. ERCOT 2023 RTP study confirmed this need.
• Oncor submitted its proposal in May; WETT submitted an alternative in June, with a final version in August.
• WETT’s proposal is a Tier 1 project, with a portion to be in service by December 2028.
• Cost for WETT’s portion: $305 million.
• WETT’s proposal vs. Oncor’s: Focus on using local 130 kV facilities to address load-serving needs while avoiding Lamesa area reliability issues.
• Comparison: WETT offers a potentially more cost-effective solution, with similar performance in power flow, stability, and short circuit analyses as Oncor’s proposal.
• Conclusion: Both proposals solve reliability needs; WETT suggests ERCOT compare and review both to decide the best approach.
• No questions were raised after the presentation. The next session will be an independent review scope presentation by ERCOT.

14 – ERCOT Independent Review Scope – Delaware Basin Stage 5 Project – ERCOT

EIR – Oncor – Delaware Basin Stage 5 Project – Scope – RPG September 2024

• Tanzilla Ahmed presented the scope for the ERCOT independent review for the delay air Basin stage five project. 
• ERCOT is conducting a single EIR review for both Delaware Basin Stage 5 alternatives.
• Study region: Far West Weather Zone (Andrews, Borden, Culberson, Dawson, Gaines, Loving, Reeves, and Winkler counties).
• Using 2023 final RTP case for 2029 summer transmission upgrades.
• Including all approved RPG projects and placeholders for Delaware Basin stages 3 and 5 based on previous presentations.
• Updated based on 2024 TPIT published in July.
• Generation analysis using 2024 GIS report and considering new generations with COD before December 2029.
• Consideration of recent retired and indefinitely modball units for status loads.
• Updating oil and gas loads based on 2024 SMP global forecast.
• Ensuring reserve maintenance with 2023 RTP criteria.
• Specific assessment of turning off all five Permian Basin generations and Odessa combined cycle train one for transformer.
• Focus on Riverton, San Lake, and Long Draw transformers.
• Reliability need analysis with contingencies and evaluation against NERC & ERCOT reliability requirements.
• Assessment of long-term load serving capability, congestion analysis, cost, and feasibility.
• Future status updates at RPG meetings and final recommendation tentatively by Q4 2024.
• Robert Golan clarified that the review primarily compares two options but may include upgrades identified during evaluation.

15 – 2024 RTP Economic Study Preliminary Results – ERCOT

2024_RTP_Economic_Study_Results_20240925_vs3opiy4w6hb.pdf

• Two base cases for study years 2026 and 2029 created.
• Full study results and report expected by year-end.
• Improvement in battery dispatch model with vendor LCG.
• Evaluation of transmission projects based on economic benefit and efficiency.
• Peak loads: 90,702 MW (2026) and 94,410 MW (2029).
• Energy production: Natural gas (44%-48%), wind & solar (~40%), nuclear and coal fill remaining demand.
• Significant wind and solar capacity modeled for both years, with increases expected by 2029.
• Total congestion cost: $1.1 billion (2026) and $928 million (2029).
• High congestion in areas including West Texas, Panhandle, Houston Interface, and Lubbock region.
• Various questions addressed regarding battery dispatch improvements, load growth impacts, congestion cost reductions, and economic project evaluations.

16 – ERCOT Extra-High Voltage Infrastructure Update – ERCOT

ERCOT_EHV_Infrastructure_Initiative_Update_09252024_RPG.pdf

Presenter Name: Jameson Hessler

• Overview of initial violations from this year’s traditional RTP.
• Introduction and discussion of two-phase EHV plan: Phase One and Phase Two.
• Phase One includes 765kV lines based on Permian Basin study and Eastern Connection.
• Phase Two is a potential future expansion including panhandle and valley components.
• Challenges in quantifying EHV benefits in current RTP analysis.
• ERCOT’s effort to incorporate feedback from TSPs and other stakeholders.
• Testing and analyzing EHV plan under 2030 RTP case.
• Coordination with PUC’s timeline for the Permian Basin study and EHV project.
• Economic analysis considerations and qualitative benefits of 765kV lines.
• Need to quantify qualitative benefits such as increased transfer capability and reduced line losses.
• Clarifications on TSP involvement and the selection process for discussions.
• Plan to manage new and changing load requests in future RTP cases.
• Conversations and feedback sessions with TSPs regarding routing challenges.
• Final proposal and next steps towards a December 2024 conclusion.
• Further discussion with attendees regarding future studies and timing of EHV projects.
  
  

17 – 2024 RTP Sensitivity Study Assumptions – ERCOT

2024_RTP_Sensitivity_Assumptions_09252024_RPG_sndp5rkfazmq.pdf

• RTP sensitivity analysis required by NERC includes an off-peak condition and two system peak conditions.
• The 2024 RTP sensitivity will use the minimum load case for 2027, and peak load sensitivity for 2026 and 2029.
• All officer letter loads will be scaled to 50% of their full value while contract loads remain unchanged.
• Generation changes will focus on generation hubs being turned off; other generation assumptions remain unchanged.
• IA and FIS only generation remains, significant particularly in the 2029 case.
• Reduction in officer letter loads illustrated with specific columns providing total system load and contract load context.
• Q&A highlighted why 50% scaling for officer letter loads was chosen—there’s no perfect number, it’s a starting point for stakeholders.
• Intent is to provide a baseline for stakeholders to conduct their own sensitivity analysis and evaluations.

18 – 2024 Grid Reliability and Resiliency Assessment Assumptions Update – ERCOT 

2024_Reliability_and_Resiliency_Assessment_Assumptions_09252024_RPG.pdf

• Introduction by Tyler Long from ERCOT on reliability and resiliency assessment assumptions.
• Study mandated by Senate Bill1281 and Texas Administrative Code 25. 101.
• Assessment of extreme weather scenarios: extreme winter weather and summer hurricane scenarios.
• Base case: final 2029 summer case, updated with new generation and approved RPG projects.
• Summer hurricane scenario: worst-case scenario with Houston landfall, Category 5, 160 mph winds, 22ft storm surge.
• Wind and solar dispatch based on 2024 RTP methodology.
• Extreme winter scenario: transformed load from summer to winter based on 2021 winter weather year.
• Winter peak forecast: initial 91 GW, final 105 GW after adjustments.
• Capacity loss due to extreme cold weather based on historical analysis of storms Uri, Elliott, and Heather.
• Battery dispatch: based on state of charge during top four load hours of coldest day plus two following days.
• Thermal generation loss capacity: average based on historical outages during top four peak load hours of storms Uri, Elliott, and Heather.
• Identified total thermal loss capacity: 9,400 MW (gas 7,000 MW, coal 2,000 MW).
• Study criteria: p0, p1, p2, and p7 contingencies to prevent cascading events and uncontrolled islanding.
• Final presentation conclusion with no additional questions or concerns raised.

19 – Adjourn – ERCOT