Order in which items were taken up: 1, 4, 5, 8, 10, 6, 19, 13, 15, 16, 17, 18, 20, 21 & 22, 23, 32, 34 & 35 and 39
0.1 - Commission Counsel Shelah Cisneros Lays Out Consent Agenda
Recusal Memos Filed in Project No. 52761: Certain members of the Commission filed recusal memos due to conflicts of interest or other reasons. Specifically:
Chairman Gleeson was recused from Item 6.
Commissioner Hjaltman recused from Items 2, 5, 6, and 8.
Consent Agenda Items: The items under the Consent Agenda included Items 2, 3, 7, and 9. Additionally, certain rules and projects under Items 24, 25, and 26 were also included as part of the Consent Agenda.
No Public Speakers on Consent Items.
Motion to Approve Consent Agenda: Chairman Gleeson asked for a motion to approve the items on the Consent Agenda. Motion was m approved unanimously.
1 - Public comment for matters that are under the Commission’s jurisdiction, but not specifically posted on this agenda.
Commission Counsel Shelah Cisneros confirmed that no public comments were signed up for Item 1 or any of the remaining rules and projects on the agenda.
4 - Docket No. 56531 – Petition of Bobbie Williams to Amend City of Royse City’s Certificates of Convenience and Necessity in Collin County by Streamlined Expedited Release.
Proposed Order Presentation
A proposed order was presented to the Commission for consideration. It was noted that no corrections or exceptions had been filed regarding the order.
A memo from Commission Counsel recommended certain changes to the final order. These changes were intended to refine and clarify the proposed order, ensuring that it accurately reflected the facts and legal considerations relevant to the case.
In addition to the Commission Counsel’s memo, Chairman Gleeson also filed a memo suggesting modifications to fact 19 within the proposed order. These modifications were likely aimed at addressing specific concerns or ensuring that the order was as precise as possible.
Unanimous Agreement on Modifications
The members of the Commission present at the meeting reached a unanimous agreement on the modifications proposed in both memos. This consensus indicated that the Commission was aligned in its approach to resolving the issues presented in Docket No. 56531.
Motion to approve the proposed order consistent with the memos filed by both the Chair and Commission Counsel on August 22 was made, and passed unanimously.
5 - Docket No. 55991 – Application of Lone Star Transmission, LLC to Amend Its Certificate of Convenience and Necessity and Notice of PURA § 14.101 TransactionThreshold Issues and Briefing Order.
A significant portion of the discussion focused on an order requesting briefing on certain threshold issues. The parties involved in the docket had previously filed briefs and reply briefs on these threshold issues, providing the Commission with a foundation for its deliberations.
Chairman Gleeson filed a memo that specifically addressed question one of the threshold issues. This memo was a focal point of the discussion, as it provided insights and recommendations on how the Commission should approach the key questions in the case.
Need for ERCOT Review
The need for a review by ERCOT was discussed during the meeting. The Commission agreed that an ERCOT review was prudent and necessary to ensure that the implications of the proposed CCN amendment were fully understood and properly addressed.
General Agreement on Memo Conclusions
There was a general agreement among the Commission members on the conclusions outlined in Chairman Gleeson’s memo. However, one participant raised concerns about the framing of the questions, suggesting that they might be misguided or incomplete.
Commissioner Glotfelty provided his thoughts on the memo filed in Docket No. 55991. He referenced precedent set in Docket No. 48212, emphasizing the importance of adhering to these precedents in the current case. Commissioner Glotfelty also addressed the historical challenges related to the transmission line in question and its significance within the Competitive Renewable Energy Zones (CREZ) process.
Importance of Understanding the Line’s Value: Commissioner Glotfelty highlighted the necessity of understanding the value that the transmission line brings to the overall system. He pointed out the potential negative impact of a prolonged process on consumers and stressed that the Right of First Refusal (ROFR) statute should not apply in this context.
Expedited Review Process: Commissioner Glotfelty recommended an expedited review process by the Regional Planning Group (RPG) for the existing facility. He also emphasized the need for ERCOT to understand the system impacts, including interconnection effects and loop flows.
Horse Hollow Case: The Commissioner discussed the importance of the Horse Hollow case in relation to the West Texas Generic Transmission Constraint (GTC) and other areas, suggesting that it should inform the Commission’s approach to the current docket.
Concerns About RPG Process Efficiency: Concerns were raised about the efficiency and necessity of the RPG process for certain lines that had been exempted by the legislature. Suggestions were made to provide additional economic planning criteria analysis to the Commission.
Debate on RPG Process: There was a debate on whether the Commission should follow the standard RPG process or seek an alternative approach. The need to work with ERCOT’s planning department to incorporate new comments and return with a full study was discussed.
Kristi Hobbs from ERCOT discussed the timelines for the RPG process. She indicated that the current process takes approximately 150 days, but there is potential to reduce this timeline by 30 to 60 days by eliminating the initial comment period.
Shortening the Process: The goal was to shorten the process to 90 days if possible. Kristi asked if an update filing should be brought to the next open meeting or if they should proceed with the expectation of completing it within 90 days.
Consensus on 90-Day Expectation: The consensus was to move forward with the 90-day expectation. There was a discussion on whether to leave the issue unresolved or issue an order based on the Commission’s decision on briefing issues.
A motion to direct docket management to draft an order on the briefing issues was approved without opposition.
6 - Docket No. 56125 – Commission Staff’s Petition for Declaratory Order Regarding Opt Out of Securitization Uplift Charges by Transmission-Voltage Customers
Proposed Declaratory Order Presentation
The Commission staff presented a proposed declaratory order to address the request for declaratory relief in this proceeding. The petition sought to clarify whether certain transmission-voltage customers could opt out of securitization uplift charges.
Commissioner Cobos had previously filed a memo related to this issue. In her memo, she recommended approving the declaratory order and emphasized addressing only the specific questions raised in the petition.
Risks of Setting Precedents: Commissioner Cobos warned against setting a dangerous precedent by answering additional questions that were not specifically asked in the petition. She expressed concerns about parties not having the opportunity to fully understand the impacts of related questions not asked in the petition.
Opposition to Opt-Out Transfer Language: Commissioner Cobos opposed including language in the order that would allow opt-out transfer under a corporate umbrella. She argued that this was outside the scope of the current petition and could create tracking challenges for staff in confirming the entities under the same corporate umbrella.
Legal and Practical Challenges: While Commissioner Cobos practically supported the point, she noted the legal and practical challenges for staff in managing the process of opt-out transfers. She acknowledged the legal stance to stay within the boundaries of what is legally required.
A motion made to approve the proposed declaratory order with changes or direction as per Cobos’ memo passed unanimously.
8 - Docket No. 56429 – Application of Texas-New Mexico Power Company for an Extension of Rate Filing Requirement Under 16 TAC § 25.247
Chairman Gleeson filed a memo expressing support for granting the extension request.
Expectations for Future Filings: Chairman Gleeson suggested that while there might be legitimate reasons to delay, barring unforeseen circumstances, TNMP should be expected to file next year. He indicated that future requests for extensions may not be viewed favorably.
Historical Test Year: There was a discussion about the potential benefits of TNMP’s next filing incorporating a historical test year of 2024, capturing significant events like Hurricane Beryl. This would allow for a more accurate reflection of TNMP’s investments and expenditures.
Review of Prudency: The importance of reviewing the prudency of TNMP’s investments in the distribution network was highlighted, especially since TNMP had been able to file Distribution Cost Recovery Factors (DCRFs) for eight years without a prudency review.
System Resiliency Focus Areas: Commissioner Cobos highlighted the need for companies to focus on distribution lines, poles, vegetation management, and transmission lines in their resiliency plans. These areas were identified as critical for ensuring the reliability of the system in the face of extreme weather events.
Infrastructure Wind Ratings: The importance of understanding the wind ratings used for infrastructure was emphasized. Commissioner Cobos suggested that these ratings should be considered in the evaluation of companies’ resiliency plans.
Supplementing Preliminary Orders: Commissioner Cobos proposed supplementing the preliminary order to include more hurricane-specific questions. This would allow the Commission to adequately evaluate the companies' plans and ensure that they were prepared for future hurricanes.
Incorporating Resiliency Questions: It was suggested that all utilities in the Gulf Coast region should incorporate these resiliency questions into their preliminary orders. This would create a more comprehensive approach to evaluating system resilience across the region.
Shelah Cisneros discussed the authority previously delegated to the OPDM that needed Commission approval for preliminary orders. A standard list of questions was proposed to facilitate quick submission to SOAH, ensuring that the process would not be delayed.
Plan to Incorporate Issues: There was a consensus that the plan to incorporate resiliency issues into preliminary orders would not delay the process. Entergy was noted to have relevant information available on their website, and it was important to set forth the necessary information to process the plan by the end of the year.
Motion made to direct document management to issue a supplemental preliminary order consistent with Commissioner Cobos’s memo and the discussion prevailed unanimously.
13 - Project No. 55999 – Reports of the Electric Reliability Council of Texas
Chad Seely and Davida Dwyer from ERCOT provided an update on the CPS RMR MRA process and the current status of ongoing projects. The update focused on the complexities and challenges of maintaining grid reliability while balancing cost-effectiveness.
Pre-RMR Inspection for Braunig Unit Three: Recent discussions included a pre-RMR inspection for Braunig unit three. Developments over the weekend influenced the need to change the course regarding certain policy issues. A revised filing was submitted, discussing the reasons for these policy changes.
Commission Cooperation: The update acknowledged the Commission’s, Commission staff’s, and CPS Energy’s cooperation in addressing these dynamic and difficult reliability and cost-effectiveness issues for the grid. The urgency of making quick decisions to change course was highlighted, with communications sent to all commissioners.
Importance of Pre-RMR Inspection: The critical importance of pre-RMR inspections and the reliance on all three CPS units were highlighted. These units are crucial for relieving Interruption Reallocation Load (IRL) overloads until new solutions become available.
Deliberation on Policy Issues: The update stressed the importance of being deliberative in tackling policy issues related to grid reliability. The Commission was urged to take a thoughtful approach in considering the implications of these policies.
Concerns About Timing and Costs: Concerns were raised about the potential for large payments if settlements occurred during the outage period. The risks of extensive repairs during the fall, which could affect availability for the winter peak load, were also discussed.
Preferred Timing: Davida suggested delaying the opening of the unit to mid-February or early March for better timing. While this might provide less information for board decision-making, there is flexibility in the RMR process to cancel contracts if necessary.
Balance Between Reliability and Cost-Effectiveness: The update emphasized the critical policy issues balancing reliability and consumer cost-effectiveness. The discussions with Commission staff aimed to develop a policy framework within the extended timeframe.
High Costs and Alternative Options: The update highlighted the high costs associated with a 60-day period for repairs and considered alternative cost options for consumers. An extended timeline for the Request for Proposal (RFP) for must-run alternatives was proposed, with offers due in the second week of October.
Commissioner Cobos stressed the importance of thoughtfully amending the RMR rule without rushing, considering the existing heavy agenda. The timeline for the MRA process offers was discussed, with offers due around October 7 or 8.
Data on Offers: There will be a board meeting shortly after the offer due date to discuss the aggregate results of the offers. Initial results will provide data on the number of megawatts offered, pending due diligence and eligibility verification.
Outlook for MRA: Previous feedback indicated a bleak outlook for the MRA. Inquiries were made about any potential improvement in the outlook. The RFP was amended based on stakeholder feedback to allow more flexibility, particularly focusing on different hours to help with demand response and battery solutions.
Questions were raised about the duration of RMR contracts, specifically whether they would be one-year or multi-year. The discussion also touched on CPS’s announcement of securing an additional 350 MW on the north side of the constraint.
Focus on Two-Year Challenge: The current focus of the RFP is on a two-year challenge. Contracts have a termination clause when the risk is mitigated. The debate centered on the higher cost of a one-year solution versus solving the issue in the second year.
Importance of Grid Stability: The importance of grid stability for the state’s economic viability was emphasized. Uncertainty about meeting the timeline led to consideration of pushing forward with the contract request.
Ongoing Policy Development: Plans to continue developing policy issues and consulting with Commission staff for options and feedback were discussed. The potential for a rulemaking by the end of the year or alternative methods for Commission input and market transparency was considered.
Stakeholder Input: The need to communicate and get feedback from stakeholders on the process was acknowledged. The update emphasized the importance of engaging with stakeholders to avoid making RMR the norm and to rely on market control and investment decisions.
Pre-RMR Inspection Process: The update also discussed the importance of having a process for pre-RMR inspection work and RMR for the future without making it the new norm.
Approval of Generation: The approval of 9,700 MW worth of generation moving forward was highlighted as a critical step in maintaining grid stability.
Motion to Withdraw Request for Good Cause Exception
ERCOT withdrew the request for a good cause exception, allowing more time for decision-making. The flexibility in timing was considered essential, especially around mid-February, to avoid winter peak issues.
Approval of Motion: The motion to withdraw the request was approved.
15 - Project No. 55837 – Review of Value of Lost Load in the ERCOT Market
Key Findings from VOLL Study: The VOLL study produced key findings, including that advance warning can lower VOLL values, potentially influencing future policy analysis. Estimated VOLL values by customer class were calculated, with an ERCOT-wide VOLL value estimate around $35,000 per megawatt-hour.
Recommendation for VOLL Value: The recommendation was to adopt a more conservative VOLL value of $30,000 per megawatt-hour due to higher estimates for small commercial and industrial customers. This value would be used for cost-benefit analysis and planning models but would not impact the current market.
Chairman Gleeson laid out his memo related to the VOLL study. He acknowledged vacillating on the issue but ultimately felt comfortable with the analysis conducted by Brattle.
Comfort with $35,000 VOLL Value: Chairman Gleeson stated that he was comfortable with the $35,000 VOLL value and was open to discussion if there were any questions. He thanked ERCOT for their work on the literature review and survey, noting that this was the first time such a study had been done and that it was critically important.
Commissioner Cobos shared her thoughts on the VOLL study update. She agreed that the difference between $35,000 and $30,000 was not significant according to staff feedback. Commissioner Cobos supported starting with $35,000 as a good starting point and adjusting if necessary as the process moves forward.
Importance of Study for Future Policy: The Commissioner emphasized the importance of the study in informing future policy decisions and ensuring that the Commission had accurate data for planning and cost-benefit analysis.
Commissioner Hjaltman inquired about the implications of high versus low VOLL values. The public may not fully understand the meaning or significance of high versus low VOLL values, so the report needed to clarify the economic implications of varying VOLL levels.
Comparison to Other Regions: The report indicated that the VOLL in the current context was comparable to other regions. The discussion centered on using VOLL values in planning studies to assess costs related to unserved energy during outages.
Agreement on $35,000 VOLL: There was general agreement on using the VOLL value of $35,000 based on research and consumer feedback. The $35,000 value was considered an adequate starting point for current purposes.
Motion to Approve VOLL Value
Motion to approve the VOLL value of $35,000 per megawatt-hour, consistent with the findings of the study and Chairman Gleeson’s memo passed unanimously.
16 - Project No. 54584 – Reliability Standard for the ERCOT Market. (Proposal for Adoption) Werner Roth, Chris Brown, and Allison Fink
David Smeltzer from the Commission staff presented the proposal for adoption of the reliability standard. The content of the proposal largely reflected the decision points from the previous meeting, with a few notable changes.
Assessment and Review Timeline: The most significant change was the shift in the assessment and review of options from every two years to every three years. This change was made to align with the forward-looking nature of the staff’s recommendation.
Fleshed-Out Processes: While other processes were fleshed out more, there were no significant changes from the last open meeting. The proposal was designed to ensure that the ERCOT market remained reliable and that the standards were both realistic and achievable.
Commissioner Cobos acknowledged the importance of the role and expressed appreciation for the amendments made from the proposal for publication to adoption. She provided several clarifications in her memo:
EEA3 Event Specification: Commissioner Cobos clarified that the term “during an EEA3 event” should be used to specify minimum required operating reserves, emphasizing that load shedding happens at 1,500 megawatts.
Expected Loss of Load Events: She clarified that the expected loss of load events for the ERCOT region should be “equal to or less than one event per ten years.”
Annual Filings: Commissioner Cobos proposed that ERCOT submit annual filings on the maximum megawatts of load that could be safely rotated during a loss load event, starting December 1, 2024. These filings would be based on surveys, with a two-month process anticipated for staff review.
Market Equilibrium Reserve Margin Analysis: Concerns were raised about the market equilibrium reserve margin analysis due to its economic hypothetical nature and potential to inject skewed data. The focus should be on planning based on ERCOT’s load forecasts and announced and retired generation.
Stakeholder Feedback: Commissioner Cobos emphasized the critical roles of ERCOT, the Independent Market Monitor (IMM), and staff in recommendation processes. Stakeholders would have a 30-day period to provide comments on reliability assessments showing deficiencies.
The Commission staff sought clarification on several points raised in Commissioner Cobos’s memos. They focused on the intent of the structural reorganization for the flow of ERCOT assessment, comments, IMM analysis, and staff recommendations.
Stakeholder Input Process: Staff confirmed that stakeholders should be able to provide feedback on both the assessment and recommendations simultaneously. They also discussed the need for ERCOT to provide a menu of options, including a primary recommendation, rather than only a list of choices.
ERCOT’s Recommendation Flexibility: The staff discussed the flexibility in providing their own recommendations outside of ERCOT’s suggestions. They also addressed handling steps during an Energy Emergency Alert (EEA) 3 event, even if some steps were skipped.
Market Equilibrium Reserve Margin: There was consideration of whether the market equilibrium reserve margin component was necessary in the assessment process. Stakeholders would be given the opportunity to provide feedback on all parts of the process, including ERCOT’s recommendations.
Kristi Hobbs clarified that ERCOT was not the only entity doing the work and that Requests for Information (RFIs) were sent to Transmission Service Providers (TSPs) to gather their information.
RFI Process Timeline: Historically, the RFI process is conducted before the summer and winter to obtain updated information. The summer 2024 RFI had already been completed, but additional information would be gathered for the upcoming winter.
Coordination with Commission Staff: RFIs would be sent to TSPs, and coordination with Commission staff and TSPs would take place before December 1st to form a recommendation. The goal was to ensure the gathered information met the standards of effective and safe operation.
Quick Timeline and Flexibility: A quick timeline was expected, but the coordination and data analysis were considered doable. Flexibility was built into the process to allow time for surveying, data collection, and analysis.
Barksdale English from Commission staff recommended that ERCOT develop protocols or processes for calculating load shed. The focus was on ensuring stakeholders understood the process of calculating load shed safely and effectively.
Future Transparency Processes: The expectation was that the number calculated in December would follow current processes, though there might be changes in the future. New transparency processes would likely not be developed until next year.
Reliability Standard Review Process Timeline: Questions were raised about the timeframe for ERCOT’s reliability standard review process, which was initially every five years but changed to three years. The process of assessment and recommendations by ERCOT could take one to two years.
Exceedance Tolerance Flexibility: The staff considered extending the review period to every three years instead of every two years to avoid continuous updates. The plan was to wait for three years of data before making new recommendations on reliability standards.
Stakeholder Requests and Load Shed Terminology: Potential issues with adding undefined terms like "effectively" and the varying interpretations from a transmission perspective were discussed. New technologies impacting load rotation patterns were also considered.
Safe and Reliable Load Rotation: The goal was to safely and reliably rotate loads, minimizing the hours any individual load is without power during a load shed event.
Commissioner Cobos clarified that the intent was not to cause issues but to create flexibility for ERCOT. She supported the change from 0.25% to 1% exceedance probability as a positive step.
1% as Starting Point: Commissioner Cobos suggested that 1% be used as a starting point and a floor, not an absolute limit. She emphasized that the magnitude, or the amount of megawatts from TSPs, is a key metric that will change over time.
Flexibility for Future Adjustments: The Commissioner highlighted that investments by transmission distribution companies and changing load characteristics would necessitate flexibility. Setting 1% as a floor aimed to give ERCOT and the Commission flexibility for future adjustments based on analysis.
Werner Roth from the Commission staff explained that ERCOT’s initial recommendation lacked exceedance tolerances for frequency, duration, and magnitude.
Cost Savings and Feasibility: Adding exceedance tolerances was necessary for cost savings and system feasibility. Planning a system to avoid all events completely was costly and unrealistic.
Tolerance Levels: Original exceedance tolerances were set at 1 in 400 for magnitude and 1 in 100 for duration. Implementation of these tolerances reduced costs and improved system reliability.
Flexibility Consideration: After discussions, there was consideration for flexibility in these numbers. The IMM’s comments noted the susceptibility of the magnitude metric to modeling assumptions, and an alternative of accepting a 1.0% magnitude tolerance was proposed.
Final Threshold: From a policy perspective, the Commission considered high magnitude and duration events to be acceptable at a 1 in 100 event threshold. The final threshold was established based on achieving a balance between reliability and cost.
The Chairman and Commissioners emphasized the importance of flexibility and optionality but also highlighted the need for certainty. There was a consensus on the need for a "bright line" for the first reliability standard, with flexibility for future adjustments.
1% Threshold as a Starting Point: The 1% threshold for both duration and magnitude was considered an appropriate starting point. The legislative intent of SB3 was to set a measurable reliability standard, and 1% was seen as a middle ground that provided a firm line for reliability measurement.
Three-Legged Stool Approach: The importance of leading with a three-legged stool approach—frequency, duration, and magnitude—was emphasized. The Commission expressed general support for the 1% threshold, acknowledging its potential for future adjustments based on feedback.
Finalizing Changes: The Commission planned a recess to finalize the changes and review the rule draft before final voting. The Chairman and Commissioners agreed on leaving the 1% threshold for duration and magnitude, with the opportunity for feedback from stakeholders in the future.
Staff Recommendation: The hours chosen for performance credits should be when dispatchable generation is most needed. This approach ensures that the PCM incentivizes the availability of generation during critical periods of grid stress.
Design Parameter 6: Duration-Based Cap for Consecutive PC Hours
Staff Recommendation: The staff recommended that no duration-based cap should be applied to consecutive performance credit hours. This recommendation allows the PCM to remain flexible and responsive to actual grid conditions without arbitrary limits.
Design Parameter 20: Cost Cap Compliance Framework
Staff Recommendation: A firm $1 billion gross cap was recommended for the PCM. This cap would help manage the overall cost impact of the PCM on the market and consumers, ensuring that the mechanism remains financially sustainable.
Design Parameter 26: Penalties for Non-Performance
Staff Recommendation: No penalty should be applied for resources that did not clear the forward market. This recommendation was made to avoid discouraging participation in the forward market and to ensure that the PCM remains attractive to a broad range of resources.
Commissioner Glotfelty raised a question regarding the metric used to determine performance credit hours, specifically whether net load or the lowest surplus available generation should be the focus.
Overlapping Risks: The discussion acknowledged that net load and lowest surplus available generation capture overlapping but distinct risks. Commissioner Glotfelty expressed concern that focusing solely on the highest net load might miss risks associated with high thermal outages.
Importance of Dispatchable Generation: The Commissioner emphasized the importance of ensuring that dispatchable generation is available during periods of highest net load, as this is when it is most needed to maintain grid stability.
Compensation for All Available Megawatts: There was consideration for compensating all available megawatts, including intermittent resources, during critical hours. This approach would ensure that the PCM incentivizes the full range of resources necessary to meet demand.
Consensus on Current Approach: There was a consensus to maintain the current approach, which aligns with the January 19, 2023, blueprint. This blueprint focuses on ensuring enough dispatchable generation during periods of low renewable output.
Acknowledgment of Staff Efforts: The staff’s efforts in developing these recommendations were acknowledged, and the Commission agreed to move forward with notifying ERCOT, E3, and the Independent Market Monitor (IMM) to begin benefit-cost assessments based on the identified recommendations.
Matt Arth from ERCOT discussed the challenges in establishing the magnitude for the cost-benefit analysis due to the absence of a finalized rule. Both ERCOT and the IMM need to initiate the analysis promptly, targeting completion by December 1.
Baseline for Study: The proposal was to use 19 gigawatts as the baseline for the study, as referenced in the proposed white paper from April. This figure represents the megawatts of load that can be safely rotated during grid stress periods.
Target Completion Date: The analysis, essential for assessing the PCM’s impact, should be completed by December 1 to inform future decisions and potential adjustments to the mechanism.
18 - Project No. 55845 – Review of Ancillary Services in the ERCOT Market. (Discussion and possible action) Harika Basaran and Julie Gauldin Review of Ancillary Services in the ERCOT Market
Collaboration on the Study: The study has involved continued collaboration between staff, ERCOT, and the IMM. A recent workshop at ERCOT presented draft study results and provided stakeholders with the opportunity to ask questions and offer input.
Draft Recommendations: Both ERCOT and the IMM presented their draft recommendations during the workshop. These recommendations addressed several technical and policy issues that are critical to the future of ancillary services in the ERCOT market.
Robust Discussion: A robust discussion took place during the workshop, covering various aspects of the proposed changes. Stakeholders were engaged in the process, ensuring that diverse perspectives were considered in the development of final recommendations.
Next Steps: Filing a Draft Study Report: The next step in the process is to file a draft study report by the end of September. This report will outline the findings and proposed changes to ancillary services, based on the input gathered during the workshop.
Stakeholder Comments: Following the filing of the draft report, questions for stakeholders to provide comments on will be released shortly after. This feedback will be critical in refining the final recommendations.
Staff-Led Workshop at the Commission: A staff-led workshop at the Commission is scheduled for October 31, with the agenda informed by stakeholder comments. Workshop details have already been posted on the public website, ensuring transparency and broad participation.
Discussion in Open Meetings: The study will be discussed during at least two open meetings in November and December before finalizing and submitting the report to the legislature. These discussions will provide additional opportunities for public input and Commission deliberation on the proposed changes to ancillary services.
19 - Project No. 56896 – Texas Energy Fund In-ERCOT Loan Program Reports and Filings. (Discussion and possible action, including loan application advancement and delegation of authority to Executive Director) Barksdale English and David Gordon
Commission Staff’s David Gordon lays out the Commission Staff’s memo
David Gordon from the Commission staff laid out a memo recommending a set of applications to advance to due diligence for the TEF in the ERCOT loan program.
Set of Applications: The memo’s attachment one included a list of projects and applications that had been discussed in detail with each office. The memo requested delegation of authority to the executive director to enter into loan agreements with applicants after due diligence review.
No Guarantee of Loan Award: It was noted that advancing a project to due diligence did not guarantee that it would be awarded a loan. Companies would have to prove their worthiness through the due diligence process.
Characteristics of Recommended Portfolio: Attachment two in the memorandum provided information on the characteristics of the recommended portfolio set compared to the full application set for review.
Tracie Tolle from the Commission staff provided an overview of the evaluation methodology used for TEF applications.
Review Process: A total of 72 applications were reviewed using data from over 60 application questions. Applications were ranked in four categories: project technical attributes, sponsor history, sponsor financials, and project financials.
Policy Priorities: Two quantifiable policy priorities were speed to market and addressing transmission constraints and load growth. Rankings were assigned based on these priorities.
Portfolio Selection: An iterative process was used to build the portfolio, selecting top-ranking projects and ensuring diversity in resource types, applicant types, and locations. Only one application per applicant was included in the recommended portfolio.
Acknowledgment of Efforts: The process involved significant work, acknowledged by various speakers, including contributions from Deloitte and extensive efforts by Tracie Tolle and her team. The recommendation received positive feedback, particularly for its diversity and alignment with the goals of replacing aging combined cycle units.
Commissioner Hjaltman asked about the due diligence process after TEF application approval and the role of the Executive Director if issues are found.
Authority Delegation: The request was for the delegation of authority to the Executive Director to enter into contracts with companies that satisfied due diligence requirements. If due diligence revealed material issues that could not be resolved, the application would not advance.
Future Actions: Future actions would depend on funding availability, timing constraints, and continued interest, with a possibility of additional applications being recommended before March 2025. Any additional applications approved for due diligence would be presented in subsequent open meetings for consideration.
Support for Evaluation Process: The structured process developed to evaluate applications and the tools built to collect and assess them were commended. The criteria for addressing transmission congestion through generation projects were highlighted as valuable.
Locational Diversity: Support was expressed for the group’s efforts, specifically in addressing locational diversity to benefit the system. Tracy Tolle was acknowledged for her pivotal role in the project’s success.
A motion was made to advance the set of TEF applications to due diligence review. The motion included the delegation of authority to the executive director to approve and enter into a loan agreement with any applicant that satisfied due diligence. The motion also delegated authority to the executive director to deny any application that failed to meet due diligence requirements. The motion was unanimously approved, allowing the TEF process to move forward.
20 - Project No. 56966 – Goal for Reducing Average Total Residential Load in the ERCOT Region. (Proposal for Publication) Ramya Ramaswamy and Mackenzie Arthur.
Comprehensive Information Gathering: The memo encouraged Commissioners to ensure that they gathered all necessary information to make informed decisions on residential load reduction. No major points were outlined beyond this directive.
Data Gathering and Incentives: Commissioner Jackson stressed the critical nature of data gathering to value demand response properly. He also called for input on making the program successful, particularly in rural areas, and emphasized the need to incentivize participation in demand response programs.
Validation of Anecdotal Evidence: Ramya noted that the data being gathered would help validate anecdotal evidence regarding the current state of demand response. This validated data would facilitate the revision of future goals.
No Additional Questions: There were no additional questions from the Commissioners, indicating general agreement with the approach outlined in the memo.
New Policy Proposal: Commissioner Glotfelty proposed a new and different policy specifically aimed at the transmission level. The policy related to interconnection costs, which was initially proposed at the distribution level.
Stakeholder Comments: The Commission agreed to hold a briefing and to receive comments from stakeholders. A deadline for comments and the location for filing would be provided via memo. There was a recommendation to consolidate everything into a single docket, 54224, to streamline the process.
Comprehensive Briefings: The objective was to provide comprehensive briefings based on stakeholder input, with additional guidance on managing received comments. The memo outlined the creation of an interconnection allowance at the distribution level similar to the transmission level.
Policy Considerations: The policy considerations included implementation in municipal and cooperative areas. The economic impact of who bears the cost at the distribution level, likely consumers, was also discussed.
22 - Project No. 54233 – Technical Requirements and Interconnection Processes for Distributed Energy Resources (DERS). (Discussion and possible action)
Commissioner Glotfelty suggested asking stakeholders for comments before publishing a rule.
Comments and Viability: Stakeholders were encouraged to provide input on the viability of moving forward with the rule. The memo expressed appreciation for staff’s efforts on timelines and preparation.
Policy Issues: The next step involved further discussion on embedded policy issues before finalizing the pathway. Ramya Ramaswamy would begin briefing other offices on the issues over the next month.
Commissioner Hjaltman raised a question about the generation allowance, which was statutorily driven from the legislature.
Jurisdictional Considerations: It was unclear if the Commission could adopt this allowance without legislature-driven directives. The Commission potentially had jurisdiction over some related matters, but further analysis was needed.
ERCOT’s Role: Currently, ERCOT did not have an active role in this particular issue, though its role might develop based on future policy decisions regarding funding and interconnected generating facilities.
Stakeholder Feedback: Distributed resources and their interconnection to ERCOT were part of rule language to be briefed later. Commissioner Glotfelty’s memo raised questions and comments that would be considered, with staff putting reasonable boundaries on topics of interest for further consideration.
23 - Project No. 55718 – Reliability Plan for the Permian Basin Under PURA §39.167. (Discussion and possible action)
August 22 Workshop: Commission Staff’s Therese Harris provided details on the August 22 workshop, which was described as informative with participation from many stakeholders. The information gathered would be used to compose a memo presenting the pros and cons of different ways to proceed.
Ongoing Meetings with ERCOT: The Commission staff had ongoing meetings with ERCOT to discuss the reliability plan and processing of (CCNs). These discussions aimed to ensure that the Permian Basin’s reliability needs were addressed efficiently.
Memo Filing Timeline: The next open meeting was scheduled for September 12, with the goal of filing the memo before the meeting, aiming for no later than September 8. Staff recommendations and pros and cons for options related to the Permian Basin reliability plan would be reviewed before the meeting.
Stakeholder Engagement: The update emphasized the importance of meeting with stakeholders to gather robust feedback from diverse perspectives. Two main issues were identified: the reliability plan and the processing of CCNs and the order.
Acknowledgment of Contributions: The Commission acknowledged the contributions and experience of staff members, including Mark Hobankamp, in addressing these issues.
Commissioner Cobos raised additional points regarding CCNs and House Bill 5066.
ERCOT and TSP Collaboration: ERCOT and Transmission Service Providers (TSPs) needed to collaborate on the number of CCNs to review due to a new 180-day timeline from HB5066. There was a need to determine total CCNs and sequencing per month for efficient processing.
Sufficient Staff Resources: The discussion highlighted the need to ensure sufficient staff resources to handle the processing of CCNs. The focus was on infrastructure resiliency and reliability, involving eight new Full-Time Equivalents (FTEs).
Staffing Increase and Funding Request: A plan was required for sequencing and docket processing to keep up with the influx of CCNs. The update mentioned a staffing increase and funding request for a case management system to streamline workflows.
32 - Discussion and possible action on electric reliability; electric market development; power-to-choose website; ERCOT oversight; transmission planning, construction, and cost recovery; and electric reliability standards and organizations arising under federal law
Confusion Over Previous Comments
The update addressed confusion caused by Chairman Gleeson’s comments at the last ERCOT board meeting. The focus was on the specific issue of NOGRR245 and its appropriate handling.
Acknowledgment of Prior Discussions: The update acknowledged prior discussions between Chairman Gleeson and Barksdale regarding NOGRR245. The discussion centered on ensuring that the policy issue was handled appropriately within the Commission’s framework.
Barksdale English provided an update on the Commission’s progress with rule changes.
Solid Foundation: The Commission had laid a solid foundation with previous executive leadership and staff, developing effective staff and processes. Recent open meetings reviewed seven rule changes, reflecting a high volume of work being done by markets and projects teams.
Workload Sustainability: Barksdale noted that while the workload might not be sustainable in the long term, the staff was capable of handling difficult policy items. Plans were discussed to revisit this topic in mid or late September.
Shifting Responsibilities Back to Commission: The update proposed moving some work back to the Commission that had been previously outsourced. Support was expressed for the idea of bringing tasks back to the Commission as organizational capacity increased.
Commissioner Cobos addressed the significance of NOGRR245 and the importance of ERCOT’s involvement in major policy decisions.
Reliability and Cost Impacts: Issues involved major policy calls on reliability and cost impacts to Texas consumers. Commissioner Cobos stressed that ERCOT should be more involved in both the initial and final stages of these policy decisions.
Settlement Success: NOGRR245’s first part was successful in reaching a settlement. However, the bifurcation and exemption process in NOGRR245 was expected to be more contested.
Appeals and Stakeholder Feedback: If appealed to the Commission, communication between parties, including ERCOT, could become restricted. Commissioner Cobos suggested that the Commission should consider rulemaking to set the process forward, similar to the weatherization framework.
Commissioner Jackson emphasized the importance of effective resource utilization amid Texas’s growth.
Engagement and Involvement: Commissioner Jackson stressed the need for engagement and involvement from both the Commission and ERCOT on state-impacting issues. He emphasized the importance of having a well-defined work plan and clear responsibilities for better risk and change management.
Data-Driven Processes: The update supported data-driven and policy-driven processes for managing change. Commissioner Jackson identified NOGRR245 as a major policy discussion topic for the Commission.
Feedback from ERCOT Committees: The Commissioner discussed collaboration with Caitlin Smith, Chair of the Technical Advisory Committee (TAC), on decision-making processes between ERCOT and the Commission. TAC’s decision to move a scheduled workshop from September 5 to the regular meeting on September 19 was noted.
Stakeholder Engagement: Commissioner Jackson expressed intent to engage with stakeholders and ensure seamless coordination in deliberations. He also mentioned ongoing discussions with Barksdale on resource allocation and coordination.
NERC’s Role: The update noted that the North American Electric Reliability Corporation (NERC) was addressing similar issues nationally, which could impact ERCOT despite the Federal Energy Regulatory Commission’s (FERC) lack of jurisdiction.
34 - Project No. 56793 – Issues Related to the Disaster Resulting from Hurricane Beryl. (Discussion and possible action) Connie CoronaDiscussion on Hurricane Beryl Disaster Response
Houston Workshop Date Announcement
Connie Corona from Commission staff announced the date for the Public Utility Commission’s Houston workshop.
Workshop Details: The workshop was scheduled for 9:00 a.m. on Saturday, October 5, at the Harris County Department of Education, Ronald W. Reagan Building, fifth-floor conference center. The workshop would be led by the Commission and would focus on disaster response and emergency preparedness.
Staff Attendance at CenterPoint Open Houses
Connie Corona also provided an update on staff attendance at CenterPoint’s open houses, which were part of the ongoing response to Hurricane Beryl.
Community Engagement: Staff attended each of CenterPoint’s open houses, which were well received by the community. The update noted that Commissioner Glotfelty was seen at one of the events on social media, though it was not widely known.
Follow-Up Discussions: Follow-up discussions were held with CenterPoint, who planned to respond to outstanding questions from the last open meeting. Gratitude was expressed for the continued effort in addressing action items related to the disaster response.
35 - Project No. 56822 – Investigation of Emergency Preparedness and Response by Utilities in Houston and Surrounding Communities. (Discussion and possible action) Connie Corona and Barksdale EnglishDiscussion on Emergency Preparedness Investigation
Connie Corona provided an update on the investigation’s progress.
RFI Deadlines: Requests for Information (RFIs) in the investigation were due the following day, with several responses already received. Staff was beginning to review the responses in preparation for the next open meeting.
Next Open Meeting: An update on the investigation would be provided at the next open meeting on September 12. The time and location for the Houston workshop had been set, allowing for continued progress in the investigation.
Connie Corona discussed the ongoing collaboration with CenterPoint on their list of commitments related to the disaster response.
Supporting Documentation: The investigation team was working with CenterPoint to determine what should be considered as supporting documentation for the completion of each commitment. The goal was to ensure that all commitments were met and properly documented.
39 - Chairman Gleeson Opens Up Item for Update from Executive Director
Badge Reader Installation: Badge readers installed in elevators would soon restrict access to staff only. This change would complicate access for open and other meetings, and staff would need to badge attendees.
Visitor Assistance: A station would be set up downstairs to help visitors with badges, ensuring smooth access to the meeting rooms.
Reserved Seating: A reminder was given that seats in the commissioner’s hearing room were general admission and not reserved, except for a few seats reserved for guests invited by commissioners, typically for ERCOT matters.