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  • 00:00:54Good morning. Good morning, members of the ERCOT board of directors and to
  • 00:00:58our guests that are here today. My name is Bill Flores. I'm the ERCOT
  • 00:01:01board chair. Welcome to the October 10, 2024 Board of Directors meeting.
  • 00:01:06I have confirmed that a quorum is present in person and hereby call this
  • 00:01:09meeting to order. Board member Carlos Aguilar is attending
  • 00:01:13virtually and will be on in a few moments.
  • 00:01:17I will also note that the board is without two voting
  • 00:01:20members today. The vacant seat of OPEC until the designation
  • 00:01:24is made by the governor and the vacant seat created by Foster's
  • 00:01:28resignation in June. This meeting is being webcast live to
  • 00:01:32the public on ERCOT's website. At this time, I would like
  • 00:01:35to ask if PUC chair Thomas Gleason would
  • 00:01:38like to call an open meeting of the Public Utility Commission of Texas.
  • Clip 1 - Call General Session to Order - Chair
    00:01:41I would. Thank you, mister Chairman. This meeting of the Public Utility Commission
  • 00:01:45of Texas will come to order to consider matters that have been duly posted
  • 00:01:49with the Secretary of State for October 10,
  • 00:01:512024. Thank you, chair Gleason. Members of the public who may be
  • 00:01:55participating today via telecast may not already be aware that
  • 00:01:59the ERCOT board selection committee appointed me as board chair and Peggy
  • 00:02:02he as board vice chair. Effective September 30,
  • 00:02:062024, Peggy and I will complete our first three year
  • 00:02:09terms as ERCOT board members on November 1 and December 31,
  • 00:02:13respectively, and begin our second three year terms the following day,
  • 00:02:17which was also confirmed by the board selection committee. I'd like to
  • 00:02:21thank the board selection committee for the reappointment of a second term
  • 00:02:24and the selection as board chair and picking Peggy
  • 00:02:28as vice chair. Furthermore, I'm also happy to announce that the
  • 00:02:31board selection committee selected directors Aguilar,
  • 00:02:34Swainson and England to complete second three
  • 00:02:38year terms, and the details of their second term effective dates are contained in
  • 00:02:41the board selection committee letter and ERCOT press release that
  • 00:02:45was released a few days ago. It is great that the board selection committee
  • 00:02:49has recognized all of our commitments and qualifications to continue
  • 00:02:53to serve this board and to serve the people of Texas. Peggy, would you
  • 00:02:56like to add anything? Yes,
  • 00:03:00Bill, thank you. I too would like to thank the selection committee and
  • 00:03:05want to let everyone know that it's my honor to serve as the
  • 00:03:08vice chair of the ERCOT board. I look forward to working with
  • 00:03:12the PUC, the ERCOT staff and
  • 00:03:16the stakeholders to improve the reliability and resiliency
  • 00:03:20of the ERCOT grid. Thank you. Thank you,
  • 00:03:23Peggy. So, I'd like to congratulate all the members who have been reappointed.
  • 00:03:26And we all look forward to working together with our stakeholders
  • 00:03:30and with our members. On behalf of the
  • 00:03:33people of Texas, I want to turn it over to Bob Flexen for
  • 00:03:37an announcement that he has regarding his future.
  • 00:03:41Thank you, Bill. So I'd like to inform the board and the public that I
  • 00:03:44do not intend to seek a second term as I plan to pursue new opportunities
  • 00:03:48in which I would no longer be eligible to be on a director, to be
  • 00:03:51a director going forward. So today will likely be my last meeting as a 2024
  • 00:03:56as a board of director. I appreciate the selection by the board selection
  • 00:03:59committee in 2021 to join this board and the great opportunity
  • 00:04:03and experience in having served at such a critical time. So thank you to
  • 00:04:07everyone for that. Thank you,
  • 00:04:09Bob. I will say from a personal perspective, it's having
  • 00:04:13you leave us is going to be, is going to leave a huge gap
  • 00:04:16to fill. And we appreciate your service to the board, to the state of Texas,
  • 00:04:21and particularly your leadership on the R&M committee.
  • 00:04:25We really appreciate that. Thank you.
  • 00:04:29Bob's term is set to expire December 1,
  • 00:04:322024. Bob joined the board on December 2, 2021,
  • 00:04:36and this will conclude his three year term. Bob has served as reliability
  • 00:04:40and markets committee chair. As I said earlier, he's done a great job in that.
  • 00:04:44After his term expires,
  • 00:04:48we are hoping that the board selection committee will have another person
  • 00:04:53selected and ready to go to begin service
  • 00:04:56soon. With those announcements out of the way, and before we
  • 00:05:00get going into the agenda, I'd like to highlight that the antitrust admonition and
  • 00:05:04security map are included with the posted meeting materials.
  • 00:05:08The first item of business today on today's agenda is item two,
  • Clip 2 - Notice of Public Comment, if Any - Discussion - Chair
    00:05:11notice of public comment, if any. Today's meeting agenda was
  • 00:05:15posted publicly on October 3, 2024, and it provided instructions
  • 00:05:19to the public for commenting in person. To date that
  • 00:05:22I'm aware of, nobody has expressed an interest in commenting. Is that still correct,
  • 00:05:26Chad? That is correct for public comment. I will note for planning
  • 00:05:30purposes when we get to item six, which is an update on the CPS
  • 00:05:33energy, RMR and MRA process that will ask
  • 00:05:37a representative for CPS energy to come up and
  • 00:05:40provide their perspective on where they're at with ironic resources as well.
  • 00:05:44Okay, we'll look forward to hearing that commentary.
  • Clip 3 - Consent Agenda - Vote - Chair
    00:05:49The next is agenda item three, the consent agenda. I will turn it over to
  • 00:05:52Chad to provide the budget impacts of the revision request.
  • Clip 3.1 - Unopposed Revision Requests Recommended by TAC for Approval - Vote
    00:05:56 Okay, there are eleven revision requests on the consent agenda.
  • 00:05:59None of the revision requests have an ERCOT staff impact.
  • Clip 3.1.7 - NPRR1244, Related to NOGRR263, Clarification of Controllable Load Resource Primary Frequency Response Responsibilities - Vote
    00:06:03Two of the revision requests have an ERCOT budget impact. So NPRR1244
  • 00:06:08has a budget impact between 70,000 to 100,000.
  • Clip 3.1.1 - NPRR1188, Implement Nodal Dispatch and Energy Settlement for Controllable Load Resources - Vote
    00:06:12 And NPRR1188 has a budget impact
  • 00:06:16between 1.8 million and 2.5 million.
  • 00:06:20This NPRR is about changing the dispatch and pricing
  • 00:06:24of controllable load resources to settle them at the nodal
  • 00:06:27price. This was an initiative that initially started at
  • 00:06:31the commission as part of their blueprint, and it's now in front of the board
  • 00:06:34on the consent agenda.
  • 00:06:37Thank you, Chad. With that, does any board member
  • 00:06:41have any comments or wish to remove any item from the consent
  • 00:06:44agenda? If there's no further discussion?
  • 00:06:48I entertained a motion to approve the consent agenda as it was presented.
  • 00:06:56Second. Who beat John? Okay, thank you.
  • 00:06:59In a second, Julie. Okay. All in
  • 00:07:02favor? Aye. Aye. Any opposed? Any abstentions?
  • 00:07:06The consent agenda is approved. The next agenda
  • Clip 4 - NPRR1188, August 20, 2024 General Session Meeting Minutes Vote - Chair
    00:07:10item is item four, the August 20, 2024 General
  • 00:07:14session meeting minutes. There's a draft of the meeting materials. Does anyone have
  • 00:07:17any comments or wish to make a motion? I moved.
  • 00:07:21Approved. Okay. Second. Thank you, Peggy. Thank you, Bob. All in
  • 00:07:25favor? Aye. Any opposed? Any abstentions?
  • 00:07:29The minutes are approved as written. I'd like to now invite
  • 00:07:33ERCOT CEO Pablo Vegas to present agenda item five,
  • 00:07:37the CEO's update. Pablo, the floor is yours.
  • 00:07:42Thank you very much. And good morning, everybody. I want to thank everybody
  • 00:07:45here for being here today and for your engagement in the, the important work
  • Clip 5 - CEO Update - Discussion - Pablo Vegas
    00:07:49that we do here at ERCOT. In today's update,
  • 00:07:53I'm going to want to cover a few key operational topics.
  • 00:07:57I'm going to talk a little bit about the RTC+B project where we
  • 00:08:00are with that. We've made some significant announcements with regards to its planned implementation.
  • 00:08:04It's an important step in the future of the operations of ERCOT. I'm excited about
  • 00:08:08where we're headed with this project and how it is progressing.
  • 00:08:12I also want to give a brief update on the progress of the Permian Basin
  • 00:08:15reliability plan that's been filed with the public utility commission and is in its next
  • 00:08:19stage of development. We also
  • 00:08:22have launched recently a new application, a new mobile
  • 00:08:27application for ERCOT. I'm going to talk a little bit about what that brings to
  • 00:08:30the table. It's got some great new functionality and I think is going to help
  • 00:08:34with communicating some of the key information that is helpful to
  • 00:08:37consumers and to market participants. And I'm also going
  • 00:08:41to touch briefly on the Southern Spirit HVDC
  • 00:08:45project that's recently been in the news, as there's been a DoE
  • 00:08:49announcement related to it regarding funding.
  • 00:08:52And I want to provide a little bit of background on that project. And where
  • 00:08:55that project fits into the ERCOT market.
  • 00:09:02So, with the real time co optimization and battery
  • 00:09:06project, we have announced a targeted go live date
  • 00:09:10of December 5, 2025, which is earlier
  • 00:09:14than the originally projected Go live date, which was sometime in
  • 00:09:18the middle of 2026. Since this
  • 00:09:22initial RTC market design, program requirements have been enhanced
  • 00:09:26to include functionality changes that account for now battery,
  • 00:09:30energy, storage resources, and be able to
  • 00:09:34project the real time co optimization with the co optimization of batteries
  • 00:09:38as well. This is a significant enhancement and something that's going to be
  • 00:09:41somewhat unique in the ERCOT market. The RTC+B
  • 00:09:45program has successfully completed each of the milestones
  • 00:09:49for the business requirements and for the interface specifications,
  • 00:09:52and it's now positioned to begin system testing in
  • 00:09:55early 2025. Market trials for the
  • 00:09:59project are going to begin in May and are going to run through
  • 00:10:02November of 2025 and the cutover is planned for December 5.
  • 00:10:07ERCOT is going to continue to monitor the additional milestones in
  • 00:10:11the coming months and ensure that both ERCOT
  • 00:10:15and the market participants are going to be ready for that go live and to
  • 00:10:18confirm that December 5 go live. A little bit of
  • 00:10:22background and context on the project this goes back quite a ways.
  • 00:10:25In 2017, the Public Utility Commission directed ERCOT
  • 00:10:29and the immigration to assess the potential benefits
  • 00:10:33of real time co optimization. Real time co optimization
  • 00:10:37is the process of dispatching energy and ancillary services
  • 00:10:41interchangeably in the real time market. Under the
  • 00:10:45current market design, ERCOT procures our ancillary services in
  • 00:10:49the day ahead market and typically does not move ancillary services between resources
  • 00:10:53in the real time market. The remaining capacity that is
  • 00:10:57not procured for ancillary services is then used in the real time
  • 00:11:00market to meet customer demand. The RTC+B
  • 00:11:04design change is a key element in the strategic
  • 00:11:08development of the current ERCOT market to provide more flexibility
  • 00:11:12in real time for ERCOT to efficiently procure and deploy
  • 00:11:16ancillary services. And in addition, the new functionality will include
  • 00:11:20improvements to the modeling and the consideration of batteries
  • 00:11:24and their state of charge that they're going to have available to be able to
  • 00:11:27provide ancillary services.
  • 00:11:31Some of the operational benefits that ERCOT has added to the original business
  • 00:11:35case study include a more timely procurement of ancillary
  • 00:11:39services when additional amounts are required or when existing
  • 00:11:42resources are not able to provide those services.
  • 00:11:45It offers more efficient congestion management resulting from the ability
  • 00:11:49to use a wider variety of resources to solve transmission constraints.
  • 00:11:54It offers a reduction in the manual actions by operators,
  • 00:11:57which includes the deployment of ancillary services and swapping ancillary service obligations
  • 00:12:02between resources. It's going to be able to model a battery
  • 00:12:05as a single device, rather than both a generator and a load,
  • 00:12:09to more efficiently dispatch it within the market. It's going
  • 00:12:13to reduce the need for out of market generator commitments by ERCOT,
  • 00:12:16and it's going to replace an inefficient supplemental market with a
  • 00:12:20real time ancillary services procurement capability.
  • 00:12:23So I want to offer my thanks to the market participants and
  • 00:12:27to the ERCOT staff that have enabled the rapid progress. Since we've got
  • 00:12:31the direction to continue with the development of this RTC project,
  • 00:12:35it's really made incredible progress in time, and 2025 will
  • 00:12:39be a critical year as we get through the testing and get ready for our
  • 00:12:42go live,
  • 00:12:47I also want to spend a little bit of time talking about the changes coming
  • 00:12:50up with our ancillary services methodology. We have a
  • 00:12:53requirement in our protocols to review the ancillary services methodology
  • 00:12:57annually, and in addition, those protocols now require public utility
  • 00:13:01commission approval on any changes to that methodology. So we're
  • 00:13:05proposing several changes in 2025 based on operational experience,
  • 00:13:10based on forecasted changes in the resource mix, and taking into
  • 00:13:14consideration some of the initial findings from the work on the ancillary services study
  • 00:13:18that has been mandated by the Public Utility Commission. At a high
  • 00:13:21level, overall quantities of ancillary services are decreasing
  • 00:13:25from 2024 to 2025, and I'll review those
  • 00:13:28details a little bit in this next slide. And this is going to be a
  • 00:13:31voting item for the ERCOT board under the R&M
  • 00:13:35committee recommendations.
  • 00:13:40So, with an increase in the intermittent resources that are currently serving
  • 00:13:44the grid, we have about 10,000 mw more wind
  • 00:13:48and solar since this time last year.
  • 00:13:51Intuitively, we would expect to see an increase potentially in the reserves
  • 00:13:56to manage that increased uncertainty from operating more intermittent resources.
  • 00:14:00However, we have been able to fine tune our risk management models since
  • 00:14:04last year to allow us to better manage the risk in
  • 00:14:08each hour in such a way that drives a more efficient reserve management
  • 00:14:11process and an overall decrease, on average about
  • 00:14:1548 quantities required in 2025
  • 00:14:19as compared to 2024. Absent these
  • 00:14:23methodology changes, the average hourly ancillary service quantities
  • 00:14:27would have increased because of an increase in the net load
  • 00:14:30forecast, errors that are driven by an increase in the amount of wind and
  • 00:14:33solar generation. The proposed changes
  • 00:14:37to the ancillary services methodology are due to better accounting of risks
  • 00:14:41and improvements to the security constrained economic dispatch
  • 00:14:44tool, and these changes do not decrease system
  • 00:14:48reliability. So, looking briefly at the four
  • 00:14:53core ancillary service changes in the reg up and
  • 00:14:56in the reg down service, we're changing the methodology to use a historic
  • 00:15:00five minute net load forecast error instead of a five
  • 00:15:03minute total variability because of improvements in the schedule allow
  • 00:15:07us to better see and manage the generation ramping.
  • 00:15:10So the regulation now only needs to cover the risk of forecast errors instead
  • 00:15:14of covering all variabilities. The regulation up
  • 00:15:17average quantities are increasing 34 mw,
  • 00:15:20but that would have been otherwise 77 without this methodology change and
  • 00:15:24the reg down services are increasing by 23 mw, but that would
  • 00:15:28have been a 68 megawatt change without the methodology changes,
  • 00:15:32the responsive reserve service, those hourly
  • 00:15:36quantities are increasing by around 9 mw, so it's relatively unchanged compared
  • 00:15:40to 2024. This methodology change is limited
  • 00:15:43because there's a NIRC requirement that dictates how we measure responsive reserve
  • 00:15:47service and how we need to acquire it. And so there's really not
  • 00:15:50too much of a change. Based on that NIRC reliability standard with
  • 00:15:55ECRS, we are now computing. The change is we're
  • 00:15:58computing quantities as either the higher of the quantity
  • 00:16:02needed to restore frequency following a large generator trip,
  • 00:16:07or the quantity needed to respond to an intra hour net load forecast
  • 00:16:11error. Prior to this methodology change, we summed
  • 00:16:15both of those factors together in order to come up with the required quantities.
  • 00:16:20Based on analysis we've done since we implemented ECRS,
  • 00:16:23we see that it's unlikely that both risk factors would occur simultaneously.
  • 00:16:28And if they did, the control room does have manual tools that they can
  • 00:16:31use to maintain reliability in real time, should both of them occur
  • 00:16:35at the same time. So the result of that is that the average
  • 00:16:38hourly quantities for ECRS are decreasing by about 271
  • 00:16:43MW, but those would have otherwise increased
  • 00:16:47246 MW absent the changes that we're making.
  • 00:16:52And then finally, for Non-Spin, the methodology change that
  • 00:16:55we're putting in place is a change to the overnight compute quantities,
  • 00:17:00which are the hours between 10:00 p.m. and 06:00 a.m.
  • 00:17:04and what we are doing is we are using a historic
  • 00:17:08four hour ahead look, the net load forecast instead of a
  • 00:17:11six hour ahead look, during the daytime hours,
  • 00:17:15on higher risk days, we would need to rely on offline generators that have a
  • 00:17:18startup time of around 6 hours. However, during the nighttime, ERCOT can
  • 00:17:22rely on offline generators that have a startup time of 4 hours or less.
  • 00:17:26And so the forecast error risk is different at night than what we see during
  • 00:17:29the day. So based on this, the amount of Non-Spin is increasing
  • 00:17:33158 mw in 2025. But that
  • 00:17:37would have been otherwise a 246 megawatt increase had we not made
  • 00:17:40that methodology change so overall this is
  • 00:17:44an opportunity to improve efficiency on the leveraging of the
  • 00:17:47ancillary services, continue to maintain the reliability,
  • 00:17:51and continue to refine our methodology to get more risk tuned to
  • 00:17:54the actual risk in each hour. So a good change overall
  • 00:17:58for the market and consumers.
  • 00:18:06A brief update on where we are with the Permian Basin reliability plan.
  • 00:18:10We produced that plan per the direction of House Bill 5066
  • 00:18:14to identify the needs of the transmission system for the Permian Basin region
  • 00:18:19and the transmission upgrades that are needed to meet the forecasted demand in that area.
  • 00:18:24At the September 26 open meeting with the Public Utility
  • 00:18:27Commission, the PUC approved the plan and authorized transmission
  • 00:18:32service providers to begin preparing certificates of convenience and
  • 00:18:36necessity for eight import paths into the permian
  • 00:18:39region, five of those defined as 345
  • 00:18:42kv paths and three of those defined as 765 kv
  • 00:18:46paths. The tsps can begin submitting the ccns
  • 00:18:50for these critical import paths as of May 1 of next year.
  • 00:18:54Concurrently, ERCOT has been working with the 2024
  • 00:18:57Regional Transmission plan on the regional transmission plan,
  • 00:19:00which is the statewide plan that is scheduled to be released in December of this
  • 00:19:04year. Between now and May 1, 2025,
  • 00:19:08there's going to be continued study and analysis on the
  • 00:19:11appropriate voltage levels to use for the import paths in
  • 00:19:15the permian basin plan, as well as looking at what
  • 00:19:18is the optimal voltage system for the larger statewide
  • 00:19:21regional transmission plan.
  • 00:19:25An evolving generation mix has resulted in increased distance
  • 00:19:29between generator sites and demand centers,
  • 00:19:32and in addition, we've seen that with the significant increase in
  • 00:19:36forecasted load that it justifies the consideration
  • 00:19:40of using extra high voltage transmission infrastructure
  • 00:19:44operated at a level like 765 kv for
  • 00:19:47import path options and for transmission.
  • 00:19:51Ehv facilities are generally known to provide benefits
  • 00:19:55such as reducing losses for long distance power transportation.
  • 00:19:59They increase short circuit strength, they reduce
  • 00:20:02congestion, they can increase grid reliability and stability,
  • 00:20:07and they can address the uncertainty of future generation changes
  • 00:20:10and location and improve voltage stability compared with
  • 00:20:14a transmission system operated at a lower voltage.
  • 00:20:18So the final 2024 RTP plan, which will have a statewide
  • 00:20:21view and will also present the considerations of both an extra
  • 00:20:25high voltage plan versus an existing 345 kv system,
  • 00:20:29will be completed no later than December of this year.
  • 00:20:40So there's been in the late last week and into the weekend,
  • 00:20:43there were several articles published that followed a recent
  • 00:20:47DoE announcement regarding the
  • 00:20:51Southern Spirit DC tie project that
  • 00:20:54had been awarded approximately $360 million
  • 00:20:58in a capacity payment funding to help continue
  • 00:21:02support the financing for this project. The news
  • 00:21:05stories made it sound like there had been some substantive
  • 00:21:09change in the policy around interconnecting the ERCOT
  • 00:21:12grid to other grids in the United States,
  • 00:21:16effectively making a policy decision
  • 00:21:20around interconnecting the ERCOT grid to the us grids.
  • 00:21:23And that's not the case. That is not what has occurred with this
  • 00:21:27recent announcement, nor with the underlying drivers for this project today.
  • 00:21:31ERCOT has four asynchronous ties that connect
  • 00:21:35the ERCOT grid to other grids outside of ERCOT. Two of them
  • 00:21:39connect us to the eastern interconnect. They add up
  • 00:21:42to 820 mw that do so. And we also have two
  • 00:21:46ties that connects us to the Mexican electric grid synase.
  • 00:21:50Those add up to about 400.
  • 00:21:54Those is a DC tie, and the other one is a variable frequency
  • 00:21:58transformer that operates like a generator with
  • 00:22:02a control system, but it is not a synchronous tie to
  • 00:22:06that grid. So the southern spirit transmission
  • 00:22:09line that was in the news and in question would be a fifth tie.
  • 00:22:13It would be another one to the eastern interconnect, where we already have two
  • 00:22:16today. And it has been proposed at a level of about 3000
  • 00:22:20mw. We have had DC
  • 00:22:24ties interconnecting to other parts of the us grid, going back to
  • 00:22:27as far as 1984. The Southern
  • 00:22:31Spirit project is an independently developed project that is going to initiate
  • 00:22:35and Texas, and is going to transmit through Louisiana and
  • 00:22:38terminate in Mississippi. It's going to allow for the scheduled
  • 00:22:42exchange of power for both reliability as well as for
  • 00:22:45economic purposes. Even though the Southern Spirit
  • 00:22:49project is proposed at up to 3000 transmission
  • 00:22:53capability, it's currently under study to determine if
  • 00:22:56the current system's import and export limits would allow
  • 00:23:00that level of transport across the tie.
  • 00:23:03Under the current planning rules and under current system capabilities,
  • 00:23:06it doesn't look like that full 3000 capability would
  • 00:23:10be enabled without some substantial investment to enable that.
  • 00:23:13There is a policy discussion that is underway at the Public Utility Commission
  • 00:23:17now as to whether the transmission system around the
  • 00:23:21interconnection point should be upgraded and invested in in
  • 00:23:25order to allow for 100% transmissibility at all times of
  • 00:23:29the power across the line like this.
  • 00:23:32DC ties that have been approved by FERC pursuant to
  • 00:23:36sections 210 and 211 of the Federal Power act
  • 00:23:40do not pose a risk to the independent jurisdiction that
  • 00:23:44ERCOT has over its wholesale power and transmission markets.
  • 00:23:48It is how the existing DC ties that exist in ERCOT today
  • 00:23:52were developed, and its also how the Southern Spirit
  • 00:23:56transmission project was approved back when it was approved.
  • 00:24:00This project was approved back in late 20,
  • 00:24:04I think, 2017, and had several conditions
  • 00:24:07that needed to be met and directives that were set forth by the Public Utility
  • 00:24:11Commission. All of those directives, except for a couple,
  • 00:24:14have been met at this point. And in 2022, that was acknowledged by
  • 00:24:18the Public Utility Commission as having met those directives.
  • 00:24:21And there's still two that are remaining to be done as the engineering
  • 00:24:25and the design process for the project continues. This project
  • 00:24:29is still awaiting approval in other states. We believe that. We understand
  • 00:24:33that it's recently been approved by the Louisiana Public Utility Commission,
  • 00:24:37but that there is still an open window around appeals available there
  • 00:24:40and it's still waiting for approval in Mississippi. And one of
  • 00:24:44the conditions, part of the conditions for the approval of this project here in ERCOT
  • 00:24:48was that the cost to develop the project, the majority of the costs were going
  • 00:24:52to be borne by the developers, not by ERCOT consumers.
  • 00:24:56So I'll pause there before I wrap up on our mobile application
  • 00:25:01launch, if there's any questions related to either this project or to any of the
  • 00:25:05updates operation that I've offered earlier. Chair Gleason Pablo,
  • 00:25:09I just want to say thank you for providing an update on this slide.
  • 00:25:12I know after this story came out, you all responded
  • 00:25:16to inquiries by the media and the legislature
  • 00:25:20as, as did the PUC, and it necessitated me having
  • 00:25:23to put out a statement on this. So appreciate this clarification
  • 00:25:27so that everyone fully understands what the southern spirit line
  • 00:25:30actually means for the state. Thank you. Thanks, Tom. Thank you, chair Pablo
  • 00:25:36I want to thank the ERCOT team again for their
  • 00:25:40work on the Permian Basin reliability plan. Christie Hobbs
  • 00:25:43and her team worked really hard on getting us a plan in a very short
  • 00:25:47amount of time, and we worked together
  • 00:25:50until the last second on this thing. And so I'm very
  • 00:25:54appreciative of all the hard work that's gone into it and the
  • 00:25:59promise of this plan to help the western part
  • 00:26:02of our state in the Permian Basin in
  • 00:26:06the future. So I wanted to say that again. Thank you. Thank you,
  • 00:26:10Commissioner. And I'm really excited about the potential this represents as well,
  • 00:26:13that there's a tremendous growth opportunity economically for the western
  • 00:26:17portion of the state. And this investment that we're going to make is
  • 00:26:20going to be able to serve customers and consumers for decades
  • 00:26:24to come. And appreciate the support and leadership that you've provided to this effort
  • 00:26:28as well. Commissioner Kobos thank you, Pablo. I'd just like to add
  • 00:26:32one more comment on the permian basin. And that is one of the benefits of
  • 00:26:35765, as I understand it, is that it just requires a smaller
  • 00:26:39footprint to actually implement for the same amount of transmission capacity.
  • 00:26:43And I don't know if that was clear to people from your slide,
  • 00:26:46but you just don't have to build as many power lines.
  • 00:26:50That's right. It's a significant benefit. You would
  • 00:26:53intuitively think that roughly doubling of the voltage would potentially mean
  • 00:26:57a doubling of the capacity. But in reality, a 765
  • 00:27:01line can carry four to five times the capacity
  • 00:27:05of a equivalent 345 circuit. And so
  • 00:27:09it's a tremendous asset in terms of being able to move power efficiently
  • 00:27:12around the state, and does so much more efficiently from a
  • 00:27:15land utilization because of that fact. So thank you for calling
  • 00:27:19that out, John.
  • 00:27:23Any other comments or questions for Pablo?
  • 00:27:28One more comment and you've got it on your slide. But I'd just like to
  • 00:27:31emphasize that, you know, the fact that there is a power line,
  • 00:27:35the DC tie doesn't actually guarantee that there's any power.
  • 00:27:39And so there's a little bit of magical thinking that goes on.
  • 00:27:42That's saying, just because we run a power line from eastern
  • 00:27:47Texas to somewhere in Mississippi, that somehow that's
  • 00:27:51going to guarantee that there's 3000 power available.
  • 00:27:55Not necessarily. Yeah, and I've
  • 00:27:58addressed the question as to the strategy of
  • 00:28:02further connecting the ERCOT grid to the other
  • 00:28:06us grids and the benefits that would need to be really fully evaluated.
  • 00:28:11The reliability issue that you bring up is a critical one, because depending
  • 00:28:15on where a line would terminate,
  • 00:28:19the further away that it is geographically from the
  • 00:28:22ERCOT system, the better opportunity there would be for reliability benefits
  • 00:28:27during periods of extreme weather. But that's a significant
  • 00:28:30consideration to understand.
  • 00:28:34But that's just one piece of it. And as I've noted before, the actual
  • 00:28:38cost to consumers for the infrastructure to enable
  • 00:28:42this can be very significant. The lines in and of themselves are
  • 00:28:45very expensive. HVDC lines are expensive. But the underlying
  • 00:28:49support around the ERCOT system to enable the first full import
  • 00:28:52and export can require significant transmission upgrades. So that's something that
  • 00:28:56has to be considered in the cost profile. The economic impact of
  • 00:29:00bringing power in from other regions and moving power from ERCOT out to other regions
  • 00:29:04also has to be considered. And that's something that I think a
  • 00:29:07lot of the studies have not really fully addressed. What it would mean to the
  • 00:29:11market here in ERCOT, and to the impact to existing transmission operators
  • 00:29:15and generators, and to consumers, what it would mean to be moving
  • 00:29:18power in and out of the state at points in time. And so I think
  • 00:29:21that needs to be studied fully. And something that often gets overlooked
  • 00:29:25when we talk about this is the fact that there are quite a few interconnections
  • 00:29:29actually available through switchable generation units that can serve both
  • 00:29:33the ERCOT market as well as are connected to other
  • 00:29:37portions of the us grid. We have about 4000
  • 00:29:40switchable generation that can serve both ERCOT and other us grids.
  • 00:29:45And that's something that is an incredible asset to us and potentially
  • 00:29:49could be an opportunity to make more investment in that which is both
  • 00:29:52supply at that point as well as flexibility and economic opportunity.
  • 00:29:57So there's a lot of different ways, I think, to solve the reliability
  • 00:30:00challenge. DC ties could be one of those,
  • 00:30:04but I think they need to be fairly evaluated from all of these factors
  • 00:30:07to really understand what is the best investment for the
  • 00:30:11ERCOT consumers when it comes to investing in reliability
  • 00:30:15and the economic potential of more infrastructure. And so that
  • 00:30:18I think you bring up an excellent point and we need to go further into
  • 00:30:21this analysis.
  • 00:30:28I'm really proud to highlight this new technology that
  • 00:30:32we have launched. Our new app that is available on both the
  • 00:30:36Apple platform, the iOS platform, as well as on the Google Play store
  • 00:30:40for the Android platforms we launched
  • 00:30:43this last month. It is a new mobile app that gives you a more transparent,
  • 00:30:47reliable, real time information of the grid. If you've already downloaded this
  • 00:30:50app on your device, please update it. You'll see the new refreshed
  • 00:30:54version when you do so. And it was built based on
  • 00:30:57a lot of input from market, participant and public feedback,
  • 00:31:00as well as a lot of testing by both. And some of the key changes
  • 00:31:04include it has a fully redesigned user interface which includes dark mode.
  • 00:31:08It has added and expanded interactive dashboards with videos to
  • 00:31:12explain features. It has personalization, so you can now customize
  • 00:31:15which dashboards appear on your home screen. You can enhance the
  • 00:31:19notifications that you want to receive in order to get alerts from ERCOT.
  • 00:31:23It also has a look ahead to events that are happening and sponsored
  • 00:31:26by ERCOT. So it's got a week ahead look, a week ahead meeting,
  • 00:31:30calendar, view that you can use and it also has an avenue for
  • 00:31:33submitting feedback. So that is an
  • 00:31:36exciting new change. I hope we continue to get feedback and we're going to continue
  • 00:31:39to be focusing on revising the communication channels that we
  • 00:31:43use to reach out to our stakeholders and consumers.
  • 00:31:46And then in addition, I wanted to also note that we are now on Instagram.
  • 00:31:50So ERCOT has been expanding its social
  • 00:31:53media channels and its presence. We are now on X,
  • 00:31:57which is the former Twitter platform. We are on Facebook,
  • 00:32:00we are on LinkedIn, and now we are on Instagram as well.
  • 00:32:04So ERCOT ISO. Please come
  • 00:32:07and follow us. That's how you know you're cool. If you've got a lot of
  • 00:32:10followers, so please follow us. And so
  • 00:32:14as part of this, we're also launching an educational campaign using
  • 00:32:17a lot of the social media content to kind of launch.
  • 00:32:20Here's who ERCOT is, here's what we do, what we're about, things we're
  • 00:32:24not, and helping to educate the public as we show up
  • 00:32:28on these new platforms that we can be reached through and
  • 00:32:32accordingly. With that, as I'd like to conclude my remarks always, I'd like to conclude
  • 00:32:36with thank you and appreciation. And I want to focus this thanks to
  • 00:32:39the teams that really worked on developing this new mobile application and
  • 00:32:43our new launch on the our social media platforms. We had
  • 00:32:46more than 40 employees that worked on this project.
  • 00:32:50Last year brought in a lot of user research into this.
  • 00:32:53The mobile app experience included many, many stakeholder
  • 00:32:57discussions and meetings, and the design work was about
  • 00:33:00six months worth of work. Paired up with our IT organization to
  • 00:33:04set up the underlying APIs in order to support the static and
  • 00:33:07the dynamic content that you can see on the mobile app. So I really
  • 00:33:11want to thank the team for the excellent work in accomplishing this in
  • 00:33:14a short period of time and continuing to progress our brand and our visibility
  • 00:33:18to the stakeholders in Texas that lean on getting information
  • 00:33:22that's accurate and reliable in real time in order to understand
  • 00:33:25what ERCOT does. So thank you for all of you who are part of that.
  • 00:33:29And with that, if there's no more questions, I'll conclude my remarks. Any questions
  • 00:33:33or comments for Pablo? If not
  • 00:33:37Pablo, thank you. I want to thank you for the
  • 00:33:40update on southern spirit. To provide the fulsome analysis and
  • 00:33:44discussion regarding that particular project.
  • 00:33:48It is important that we correct the misinformation that was
  • 00:33:52put out there by the media. It also seems like you and the team have
  • 00:33:55been in full afterburner mode since our August meeting. When you think about the
  • 00:33:59acceleration of RTC+B, the ancillary services study,
  • 00:34:03the mobile app, and the Permian Basin plan.
  • 00:34:06So I want to thank all of ERCOT team for the great work that
  • 00:34:10they've done the last several months.
  • 00:34:14I'd now like to move on for
  • 00:34:17agenda item six, the update on the CPS energy reliability
  • 00:34:21must run, and must run alternative process.
  • 00:34:24Chad Seeley and Woody Rickerson will join Pablo as co presenters.
  • 00:34:28In addition, we've invited the CPS representative to express
  • 00:34:33their comments on this particular issue.
  • 00:34:35Pablo, Chad, Woody okay, I think I'll start it off
  • 00:34:39and then Woody and I will kind of tag team through some of these slides
  • 00:34:42and at some point I'll ask the CPS representative to come up.
  • Clip 6 - Update on CPS Energy Reliability Must-Run RMR and Must-Run Alternative MRA Process - Discussion - Pablo Vegas / Woody Rickerson / Chad V. Seely
    00:34:46 But we obviously had an update at the August board meeting
  • 00:34:49on where we were in the RMR MRA process,
  • 00:34:54and we continue to work very collaboratively with CPS
  • 00:34:57Energy on negotiating the terms of a potential RMR agreement
  • 00:35:01for all three resources. And, you know, a couple
  • 00:35:05of the key takeaways reflected here on the slide is that we're positioned,
  • 00:35:08obviously, to come to the board in December for a full
  • 00:35:12evaluation of whether the board wants to select one or more of these
  • 00:35:15RMR units. If you recall, in August,
  • 00:35:19we talked about the must run alternative timeline,
  • 00:35:22and at that time, ERCOT, on its own
  • 00:35:26through the RFP process, decided to extend the response deadline
  • 00:35:29to give the industry more time to look at the qualification
  • 00:35:34criteria within the RFP and hopefully have
  • 00:35:37an industry response. That deadline was
  • 00:35:41this past Monday, October 7,
  • 00:35:44and we received one MRA offer as
  • 00:35:47a result of extending that. So that's a little disappointing that we
  • 00:35:51weren't able to get more interest from the industry to respond,
  • 00:35:54because ultimately the consumers of Texas will have to
  • 00:35:58pay for any type of solution that the board deems is appropriate.
  • 00:36:02So we'll talk about that MRA offer a little bit later
  • 00:36:06in the slide deck. One of the other issues that we've been
  • 00:36:09focused on for several months with CPS was
  • 00:36:13a recognition by CPS Energy that the state of these units required
  • 00:36:17at least a 60 day inspection for each of those units. And so there'd been
  • 00:36:20a lot of discussion with the board and with the commission about, well, we may
  • 00:36:24want to take one of these units out of service sooner
  • 00:36:28and do what we were characterizing as a pre RMR agreement,
  • 00:36:32which came with this concept that the board talked about in
  • 00:36:35August around loss, opportunity costs, and kind of setting up a new policy
  • 00:36:40paradigm around that issue. Again, continuing to work with CPS
  • 00:36:44energy collaboratively. They ultimately decided to
  • 00:36:48move the notice of suspension of operations date from
  • 00:36:51March 31 up to March 2,
  • 00:36:54because the earliest we were really going to be able to take that unit out
  • 00:36:57was going to be after the winter season. So we were targeting kind of March
  • 00:37:011, and they were able to use our existing processes by changing that
  • 00:37:04date. So greatly appreciate CPS energy and their executive
  • 00:37:08management team for looking at that issue and addressing that kind
  • 00:37:12of difficult policy issue of whether lost opportunity cost is
  • 00:37:15appropriate or not under our current regulatory regime.
  • 00:37:19So that's addressed in the second key takeaway. Again,
  • 00:37:22the deadline for the MRAs was October 2. And I think, most importantly,
  • 00:37:26what we're trying to do today is just kind of set up the board for
  • 00:37:29the expectation of what's coming and December. There's a lot of
  • 00:37:33analysis that ERCOT staff will be doing over the next several weeks
  • 00:37:36now that we have the MRA piece in house
  • 00:37:40to look at that one offer, along with the cost that's been submitted
  • 00:37:43by CPS Energy for those three units, and then the other kind
  • 00:37:46of qualitative and quantitative issues that we need to do as a full assessment
  • 00:37:51to bring that information back to the board for consideration.
  • 00:37:54We had targeted December to make sure that the board
  • 00:37:58had enough time to look at this information. And if somehow the board
  • 00:38:02needed more information, then there's still opportunity to
  • 00:38:06use the February meeting, which is pretty late in the cycle,
  • 00:38:09to make this decision, or potentially have a special meeting between December
  • 00:38:14and the February board meeting, because this is a big decision for the
  • 00:38:17board to evaluate the local reliability impacts
  • 00:38:21that we have identified as a result of these resources. Going away March
  • 00:38:25and making sure that you have a complete set of information to evaluate the
  • 00:38:29cost benefits of what your decision may be. So,
  • 00:38:33on the next slide. Thanks, Penny, for driving that. This is somewhat
  • 00:38:36a familiar slide. It just kind of gives you an overview of the three units.
  • 00:38:40Again, we were originally targeting unit three, which is that 412
  • 00:38:44megawatt unit to do as a pre RMR agreement.
  • 00:38:48But that got resolved last week when CPS
  • 00:38:51Energy revised its NSO and changed that
  • 00:38:54date to March 2. So, again, the issue of lost opportunity
  • 00:38:58cost is no longer at play. We can now kind of focus on our traditional
  • 00:39:02RMR regulatory process. That's in the protocols.
  • 00:39:05I want to turn it over to Woody just to remind the
  • 00:39:09board of the reliability analysis that we conduct when we receive
  • 00:39:13an NSO. Yeah. First of all, we want to thank
  • 00:39:17CPS for giving us the notice of suspension of operations a
  • 00:39:20year early. That was. That really helps with this
  • 00:39:24difficult analysis. Remind everyone
  • 00:39:28that the reliability analysis looks at transmission system impacts.
  • 00:39:32It doesn't look at resource adequacy. So if these units have been located in
  • 00:39:36West Texas or someplace else, they probably wouldn't have met the reliability,
  • 00:39:39the RMR criteria. And that RMR criteria is laid out in the protocols.
  • 00:39:43You'll see those three bullets there that talk about what those criteria are.
  • 00:39:47So reliability analysis was conducted. All three
  • 00:39:51units are needed.
  • 00:39:56On the next slide. Consistent with our process,
  • 00:39:59we went out with the RFP, and we've now completed that
  • 00:40:03process with one possible
  • 00:40:06resource that can be leveraged as part of our analysis.
  • 00:40:10So, again, just making sure that the board's aware we're following the processes and
  • 00:40:13the protocols. Once we identified an RMR. We must go out for an RFP.
  • 00:40:17We've laid out that eligibility criteria that I'll talk about in a few minutes.
  • 00:40:21And we received one must run alternative proposal.
  • 00:40:26So getting back to kind of the core reliability
  • 00:40:29issue with the South Texas export IRL, what do you kind of speak to that?
  • 00:40:33Yeah, so an irol is an
  • 00:40:36interconnection reliability operating limit. So it's a NERC
  • 00:40:40designation. These are especially critical limits that you
  • 00:40:44can't afford to have overload because they could potentially cascade.
  • 00:40:48So using those standards,
  • 00:40:52that IRL from south Texas, which was established earlier
  • 00:40:56this year, that is the transmission criteria
  • 00:41:00that makes these units need to be RMR.
  • 00:41:04So that's what's driving this. It's not
  • 00:41:07a, it's not a resource adequacy issue. It is to protect
  • 00:41:11that irol.
  • 00:41:15So any MRA service that
  • 00:41:18we would use would also reduce the loading.
  • 00:41:22So the RMR or the MRA, either one, would reduce the
  • 00:41:25loading on those lines that are irols. And if
  • 00:41:29you look at the next slide, slide seven. So this is
  • 00:41:33an illustration that shows the impact,
  • 00:41:38the shift, what we call a shift factor from different
  • 00:41:42places across the state on that line. And so that line is
  • 00:41:45going to be just south of San Antonio. So it's on the border between
  • 00:41:50the green and the red dots that you see
  • 00:41:53there. So greenhouse would be places where an
  • 00:41:57injection of power would reduce that south to
  • 00:42:01north loading. And red would be a place
  • 00:42:04where an injection of power would increase the loading. So we want
  • 00:42:08to, the brawny units are just north of
  • 00:42:12that interface. So they have a high shift factor in reducing
  • 00:42:16that loading. So at any MRA, we would
  • 00:42:19look at, if we had gotten any, would have also been a,
  • 00:42:23something that would reduce that loading as well. And so you can,
  • 00:42:27there's some scales on there. You can kind of see where the impact,
  • 00:42:31the most impactful places are for unloading
  • 00:42:34that line. But that's probably the most important thing to keep in mind when you
  • 00:42:38look at this reliability analysis is
  • 00:42:42that everything is focused on unloading that particular
  • 00:42:45line. And that's, that's the, that's the problem
  • 00:42:49that we're dealing with here is that particular line that irol
  • 00:42:52coming south out of San Antonio. And keep in mind that the
  • 00:42:56board has approved a couple different projects that are being worked on
  • 00:43:00now that will fix that. But there is a gap between
  • 00:43:04the time Bronick retires and
  • 00:43:08when those projects are going to be implemented.
  • 00:43:14Okay, on the next slide, just getting to the MRA requirements,
  • 00:43:17you know, we tried to set up the RFP to
  • 00:43:22be as flexible as possible based upon
  • 00:43:25the resource attributes and what we were trying to accomplish as far as the reliability
  • 00:43:29analysis. So in the RFP, we were looking for generation resources, which included
  • 00:43:33batteries, settlement only generators, and distributed generation and demand
  • 00:43:37response. And we're looking across a two year period here.
  • 00:43:41As Woody indicated, those current South Texas reliability
  • 00:43:45projects aren't intended to come into service until the summer of 2027.
  • 00:43:49And so we're looking across a two year horizon here. And we allowed that
  • 00:43:53flexibility of, you could offer in one year, two year,
  • 00:43:56you know, complete flexibility to try to get the industry to
  • 00:44:01really look at what assets could be available to solve
  • 00:44:04some of the reliability issues. And you can see that noted here
  • 00:44:07on the slide, kind of the flexibility that we were offering as far, far as
  • 00:44:11duration for deployment for demand response and esrs
  • 00:44:14recognizing their kind of limitations and whether a demand response provider
  • 00:44:18would really want to be out longer than a certain period of time. So this
  • 00:44:22gives you an overview of some of the flexibility that we tried to accomplish in
  • 00:44:26the RFP. If you recall back in August that
  • 00:44:29Chairman Gleason and I had a discussion about, maybe this is one of the issues
  • 00:44:33we need to be talking about after the lessons learned from this particular
  • 00:44:37RMR MRA analysis is maybe we need to go further.
  • 00:44:41If we're going to continue to see notice of suspensions of
  • 00:44:45operations and we want to leverage must run alternatives as a
  • 00:44:48more cost effective, reliable solution, then we may want
  • 00:44:51to start to talk about this policy issue next year after the board
  • 00:44:55gets through. This specific issue on the next slide is just
  • 00:44:58a high level summary, because we can't go into a lot of specific details right
  • 00:45:01now. But again, we received one proposal which is a
  • 00:45:051200 megawatt, multi hour storage resource by the submission deadline.
  • 00:45:10That actually came in a couple of minutes before the submission deadline. But what's
  • 00:45:14important here is that this proposal is for the summer of
  • 00:45:182026. So we received no offers
  • 00:45:22for anything. For the reliability concerns that we've identified for 2025.
  • 00:45:28This battery is in a location that
  • 00:45:32is helpful from the previous slide that Woody identified as a shift factor.
  • 00:45:36We're not going to get into all those details here today, but it does
  • 00:45:39look like it has a helping shift factor to that constraint.
  • 00:45:43And of course, we just received this on money. So we need to go through
  • 00:45:46our due diligence process and make sure that it's really eligible and
  • 00:45:50qualified under the RFP criteria that we laid out of in
  • 00:45:54the RFP. So we will ultimately, if it is eligible and
  • 00:45:58qualified, this will be part of our overall analysis,
  • 00:46:01looking at that 2026 horizon. But for 2025,
  • 00:46:05with no must run alternatives, we're really looking at
  • 00:46:09the CPS Bronig resources versus
  • 00:46:13the cost to consumers and the unserved energy
  • 00:46:17that could occur if we have to shed load because of
  • 00:46:21the IRL constraints.
  • 00:46:25So on the next slide, I'm not going to go through all this,
  • 00:46:28but this is the point where I'd like to ask CPS energy
  • 00:46:32to come up to the podium, if they don't mind,
  • 00:46:36because I think it's a good opportunity for CPS to give their perspective
  • 00:46:40on the state of these resources, what they've been doing to try
  • 00:46:43to posture at least unit three, which is still,
  • 00:46:47there's no certainty that the board will select unit three, but these
  • 00:46:51are obviously very old units. There are
  • 00:46:55supply chain issues, as we've noted here in the last bullet point,
  • 00:46:59about getting some of the parts that would be necessary to extend
  • 00:47:03the life beyond the March deadline. And I think obviously
  • 00:47:06CPS, being the owner and operator of those assets, are in the best
  • 00:47:10position to kind of give their perspective of how they're
  • 00:47:13managing that issue as we head toward a December decision.
  • 00:47:18So if there's somebody from. Yep, thanks.
  • 00:47:21Good morning, everybody. Rick Yarutia, CPS Energy. I'm vice president
  • 00:47:25of generation operations. I was here last time. So good to see
  • 00:47:28everybody again. So currently we
  • 00:47:33are working through our planning activities for a
  • 00:47:36potential Bronig three outage.
  • 00:47:41This outage will be used to inspect the systems and
  • 00:47:44equipment for that power plant to ensure first
  • 00:47:48that the plant is safe for continued
  • 00:47:51operation because it is approaching end
  • 00:47:55of life, and of course also
  • 00:47:59to ensure that we are doing any
  • 00:48:02reliability improvements that we can do before an RMR
  • 00:48:06contract is established. If that occurs, we have
  • 00:48:10an outage planning team like most, and currently
  • 00:48:14they're in the throes of working through the outage plan,
  • 00:48:18and that includes the establishment of an outage schedule.
  • 00:48:23As Mister Seeley mentioned, we have identified
  • 00:48:28some potential issues with parts lead
  • 00:48:31lead time for some of
  • 00:48:35the major components of that power plant.
  • 00:48:38I'll mention three specifically. The list is not complete yet.
  • 00:48:41We're still, like I said, working through the outage plan.
  • 00:48:45But currently we are seeing extended lead times for some of
  • 00:48:48our steam turbine parts. That includes some of our steam
  • 00:48:52turbine valves and then our steam turbine generator.
  • 00:48:57The steam turbine generator system is critical in
  • 00:49:01unit operation, about an average lead
  • 00:49:05time. If we look at our current list of about twelve weeks,
  • 00:49:10the maximum lead time that we've seen for one of
  • 00:49:13those components is 41 weeks,
  • 00:49:16and there's a
  • 00:49:21very high number of the 20 week lead
  • 00:49:25time range. We are
  • 00:49:29working with several of our vendors
  • 00:49:32to try to mitigate those lead times or improve them,
  • 00:49:37and I think we recognize that there probably is some opportunity
  • 00:49:40for some improvements, but we're still working through that with our vendors.
  • 00:49:44We'll continue to do so through the outage planning process.
  • 00:49:48I mentioned previously that the list isn't complete yet. Again, we're working
  • 00:49:52through the list. Our plan is to continue to update ERCOT with
  • 00:49:55any findings of increased lead times that could jeopardize
  • 00:50:00the outage schedule, and we'll work
  • 00:50:03through those issues as they come up. Currently, the outage is scheduled
  • 00:50:06for 60 days. That's an estimate
  • 00:50:10based on our approach of an open
  • 00:50:13inspect and close, so that schedule can
  • 00:50:17change if we find a, any major, what we
  • 00:50:20call discovery work, in which some of that equipment
  • 00:50:24or systems has to have extensive repairs.
  • 00:50:28I'll give an example. If we inspect a
  • 00:50:31piping system that has longitudinal
  • 00:50:35cracking, which requires us to replace a section of pipe,
  • 00:50:38you know, that could obviously add time to the outage. Weeks,
  • 00:50:42months. It just depends on what type of failure we
  • 00:50:46find. What kind of questions
  • 00:50:49does anybody have? Thank you, Rick. John,
  • 00:50:54is your intent to do the inspection and put it back into service
  • 00:50:57and then schedule the required upgrades to keep it in service
  • 00:51:01for whatever period is necessary? Is that sort of the plan,
  • 00:51:04or. It depends on what we find.
  • 00:51:08Right. So our main focus is safety. So if we find something
  • 00:51:12related to safety, then, of course, we will not be able to
  • 00:51:15restart the unit until that's resolved. If we find other
  • 00:51:19issues that can wait and are tied
  • 00:51:22to reliability and fit inside of that,
  • 00:51:26what we're assuming right now to be a two year RMR window,
  • 00:51:29well, then we'll have to have those discussions with ERCOT,
  • 00:51:33develop a plan and move from there.
  • 00:51:38And is there any of this work that can be done in advance of the
  • 00:51:41actual shutdown, like external
  • 00:51:45inspections and stuff like that? Right now, we haven't
  • 00:51:50discussed any pre outage type work. Right now, our focus is on
  • 00:51:54planning the outage. But if any of those come up, we can
  • 00:51:58have discussion with ERCOT about that situation.
  • 00:52:01These unit just keep in mind that the unit will be available,
  • 00:52:05you know, between now and the start of the outage. So we'll be
  • 00:52:09focused on the ensuring that the unit maintains
  • 00:52:13its availability during that timeframe. Rick, how long
  • 00:52:16do you think it will take to conclude your pre outage study
  • 00:52:20that you're working on right now? Yeah, I think it's
  • 00:52:24going to take us pretty close to the start of the outage. Typically,
  • 00:52:28it's about a one year evolution from
  • 00:52:32start of plan to execution of outage. And so, of course,
  • 00:52:36we're compressing that right now. So we're hopeful
  • 00:52:39to have that plan accelerated and done very soon.
  • 00:52:43But I think there's some risk of us
  • 00:52:47being in the December or January timeframe to be
  • 00:52:50finished. We are also executing other
  • 00:52:54outages right now in our extended fleet.
  • 00:52:58And so we also have to maintain, maintain focus on those plants that
  • 00:53:02are not going to be retired. Right. And maintain availability
  • 00:53:06from now into the future. Right. So got to keep that focus.
  • 00:53:09Okay, thanks, Brie. Have we concluded that units one
  • 00:53:13and two are not going to be inspected at this point?
  • 00:53:16No, I don't think that's the case. We're having discussion with ERCOT about
  • 00:53:20those inspections as well. I'd like to follow
  • 00:53:23on that question. If you look at the slide of notices,
  • 00:53:26suspensions of operations, there's three units listed,
  • 00:53:29and my current understanding is any one of those three could
  • 00:53:33come back in the final proposal for RMR.
  • 00:53:37Is that correct? Yes. We will bring
  • 00:53:41back analysis to support one, two, or three,
  • 00:53:45and or all of the above and the MRA,
  • 00:53:49if it's eligible to. So it's a menu of options
  • 00:53:52for the board to consider based on the cost benefit analysis relative
  • 00:53:56to the reliability risk and the inspection outcome,
  • 00:53:59correct? Yes. Okay. Yes.
  • 00:54:03Okay. Any other questions or comments,
  • 00:54:06Laura? Commissioner Kobo Sherman.
  • 00:54:10Yes. So my question is, and I don't know if you're going to have the
  • 00:54:12answer, but it seems to be an evolving situation. Right.
  • 00:54:15You don't know. I mean, the likelihood of any of these units being available
  • 00:54:19for this summer of 25, we just don't have a very clear idea until
  • 00:54:24the analysis is done and the plant is opened.
  • 00:54:28And so I'm just kind of wondering if,
  • 00:54:33you know, the likelihood of even getting any of these
  • 00:54:36plants this summer, because that's very unclear to me. And we're
  • 00:54:39kind of just spinning our wheels for the summer over and over,
  • 00:54:44and I understand why, but at the same time, are we
  • 00:54:48really just talking about summer 26 in reality?
  • 00:54:51Because it seems to me that,
  • 00:54:54you know, like you're saying, if there's a part that you need, you're not going
  • 00:54:57to get it, potentially or likely, for the summer.
  • 00:55:01So I'm just wondering, as ERCOT looks at the menu of options to present to
  • 00:55:04the board once you get more information, maybe it's
  • 00:55:08really an option of,
  • 00:55:11you know, waiting till the summer of 26 in reality, with an
  • 00:55:15MRA involved,
  • 00:55:18that is definitely a risk with unit three
  • 00:55:22or any of the units that the board ultimately selects.
  • 00:55:26But either way, if the reliability analysis shows
  • 00:55:29that they're needed and the benefits are there,
  • 00:55:32the work has to be done. And so then it just becomes when they're operationally
  • 00:55:36available, because we have identified a two year risk, and it's
  • 00:55:40not just a summer issue, it is a seasonal risk across those
  • 00:55:44two years. So, yes, I think there is
  • 00:55:47a significant risk that unit three could
  • 00:55:51not be available during parts of the summer. And if something, again,
  • 00:55:55depending on what the board does, even selecting some of the other units
  • 00:55:58may result in not having that full capacity available
  • 00:56:02for the summer. Yeah. Okay. So it is important to keep in mind it's a
  • 00:56:06year round risk. So even if it's not
  • 00:56:09there, the full summer, as long as you get it in, if you're able to
  • 00:56:12get it in, that will help mitigate that IRL risk
  • 00:56:16for the next two years. Correct. And what do you want to add? Anything?
  • 00:56:20I think it also leads to the point of if you
  • 00:56:24de risking, this probably requires that you look at more than one unit,
  • 00:56:29because it sounds like there's a reasonable chance that at least one of these units
  • 00:56:32is going to be down for some extended maintenance period, perhaps in a peak load
  • 00:56:36period. So we may, in fact, have to bring more
  • 00:56:39capacity back than we would normally need to take
  • 00:56:43to just account for that. Is that a fair statement?
  • 00:56:48Could you repeat it one more time? I caught the end. I'm just making
  • 00:56:51the point that, given the uncertainty surrounding
  • 00:56:55the repair of a given unit,
  • 00:56:59it may well be that we have to opt for multiple units
  • 00:57:03to be brought back online through the RMR process to
  • 00:57:08ensure that we have at least some capacity available
  • 00:57:11during the peak periods. Yeah, I think that's
  • 00:57:14a. You know, we're working with ERCOT. I think that's more of
  • 00:57:18an ERCOT question. But from our perspective,
  • 00:57:21we do believe there's risk with inspecting units and the findings
  • 00:57:25of the units, and. And certainly these outages could extend,
  • 00:57:29or we could find something that might
  • 00:57:32lead to us not bringing a unit back. That's what I'm sort
  • 00:57:35of anticipating, you might say. Yeah, we need to
  • 00:57:39be.
  • 00:57:43I think it was Carlos, maybe trying to say something. Carlos, did you have a
  • 00:57:46question, if I may? Just one question
  • 00:57:50about what we can expect? I mean,
  • 00:57:54of course, you have your preventative maintenance and maintenance records
  • 00:57:58for these units, so,
  • 00:58:01you know, what kinds of issues is it that you expect to find?
  • 00:58:09Yes. So, for Bronick three, we're really.
  • 00:58:13We really need to inspect the steam turbine,
  • 00:58:16specifically the HP the high pressure and the intermediate
  • 00:58:20pressure steam turbine rotor.
  • 00:58:23That equipment has some
  • 00:58:27repairs that require us to inspect it before it runs more.
  • 00:58:30And we also have some important inspections
  • 00:58:34to do on the low pressure turbine rotor as well. Some of
  • 00:58:38the last stage blades on
  • 00:58:41that rotor have some inspection intervals
  • 00:58:45coming up. I think there's some risk
  • 00:58:48with that system specifically as it
  • 00:58:52relates to meeting the 60 day
  • 00:58:56schedule or not. And so it's really important for us to
  • 00:59:00do those inspections at the beginning of the outage, which will be the plan.
  • 00:59:04We also have, of course, our boilers,
  • 00:59:09again, are approaching end of
  • 00:59:12life. We expect to find some boiler,
  • 00:59:16steam circuit, and water circuit issues that will
  • 00:59:21have to evaluate how we resolve those, if they can be resolved.
  • 00:59:24And then also we have our high energy
  • 00:59:27piping systems. So these are high pressure steam systems.
  • 00:59:31This piping has been in place and in operation for many decades.
  • 00:59:35And although we've done preventative maintenance over the
  • 00:59:38years and inspections because of the age of
  • 00:59:41the equipment, there's possible findings,
  • 00:59:44you know, associated with the metallurgy of those systems,
  • 00:59:49chromology and things of that sort, correct? Yes, sir.
  • 00:59:53Okay. Okay. Any other questions for Rick?
  • 00:59:56Okay. Are there any known problems with those systems that you're
  • 01:00:00keeping an eye on now, like, you know, some. Some crack
  • 01:00:04pipe cracking or things like that to lead
  • 01:00:08you to believe that there could be more serious problems?
  • 01:00:11We have surveillance systems in use
  • 01:00:15that are paired with our control systems that
  • 01:00:20allow us to understand if the systems are
  • 01:00:23changing in real time. And so we'll
  • 01:00:27continue to do that until the start of this outage to identify anything
  • 01:00:32that needs to be, you know,
  • 01:00:35there needs to be a change in our inspection approach, for example.
  • 01:00:41So, Jen, assuming we don't like the outcome
  • 01:00:44of all of what we just discussed, what are some alternative next
  • 01:00:48steps, like issuing more mras?
  • 01:00:54We can definitely look at that as, you know, possibly doing
  • 01:00:58a, an additional MRA. I'm not optimistic
  • 01:01:02right now without going through a broader policy discussion
  • 01:01:06about how we would change the framework to get the
  • 01:01:09industry to respond with other alternatives. But that would definitely,
  • 01:01:13if the board openly decides not to move forward with any of these units,
  • 01:01:17then there is the risk of rotating outages
  • 01:01:20based upon exceedingly irls, and we'll
  • 01:01:24have to continue to work through that because it's a two year risk that
  • 01:01:28we're trying to manage until the South Texas projects start to
  • 01:01:31come in play. So, yes, we will continue to look at all available
  • 01:01:35options to minimize that risk or potentially
  • 01:01:39eliminate that risk. And we're continuing to think through
  • 01:01:42other options as well, even right now. But this is the one
  • 01:01:46through the protocol process that requires us to present this information to the board
  • 01:01:49for their consideration. Yeah. I think it's important
  • 01:01:53to remember, too, that even if the Burani units had
  • 01:01:57not retired, if they had continued to operate,
  • 01:02:00the risk of this is still there. The risk of this IRL overloading
  • 01:02:04is still there. So the Braunig RMR is not a complete
  • 01:02:08remedy for that overload.
  • 01:02:12It still exists. And so if you think about,
  • 01:02:16think about the number of hours, the expected unserved energy
  • 01:02:19that could occur without the Braunig units,
  • 01:02:23with the Braunig units in place, that number, that amount is
  • 01:02:28decreased quite a bit. But it still exists, and it will
  • 01:02:32exist until these new transmission projects are
  • 01:02:35put in place. And so we shouldn't think about this as
  • 01:02:39a complete fix for the IRL
  • 01:02:42overload. The IRL overload is going to be with us until the transmission
  • 01:02:45projects are completed. And you can look at your slide 14 and see those
  • 01:02:49kind of a summary of those projects that have already been
  • 01:02:53endorsed by the board and that are
  • 01:02:56in the process of being worked on now.
  • 01:03:01So what are the chances of those being accelerated?
  • 01:03:06I think there's a chance of them being accelerated, and we're
  • 01:03:10working with some of the TSPs now to look
  • 01:03:13at that. I can't give you a number,
  • 01:03:16though, but the possibility is being looked at.
  • 01:03:23Okay. Any other questions or comments on this topic?
  • 01:03:27Rick, thank you for sharing your insight
  • 01:03:31with us. We appreciate that. Thank you. Got a couple more slides.
  • 01:03:35Oh, okay. So Pennywill drive again.
  • 01:03:38The next three slides really get to the requirements and the
  • 01:03:42protocols as far as the evaluation of a
  • 01:03:45potential RMR or MRA resource.
  • 01:03:48And I think it's important for the board to kind
  • 01:03:52of see that this is all the data that we'll, all the attributes that we'll
  • 01:03:55consider as far as the data. There may be other qualitative
  • 01:03:59and quantitative analysis that we do, but at a minimum, we have to do
  • 01:04:03what's reflected here on the next three slideshow.
  • 01:04:06I think when you look at slide the first, sorry, if you
  • 01:04:10go back penning to that kind of first one, the third
  • 01:04:14bullet point, just to kind of highlight, we will come back with analysis
  • 01:04:17on unserved energy using the new value of
  • 01:04:21loss load that the commission decided for planning purposes at 35,000
  • 01:04:25megawatt hour over one in two years. That's a way
  • 01:04:29for the board to at least see what the
  • 01:04:32cost is for customer outages versus the cost
  • 01:04:36to have an RMR or MRA solution.
  • 01:04:40But that's just one piece of the data that we'll present.
  • 01:04:43There'll be lots of data attributes that we ultimately present to the board as
  • 01:04:47we start to put together the remaining pieces of our analysis. And that's reflected
  • 01:04:51on the next slide. Additional factors that we have to consider,
  • 01:04:55and then even the, the following slide
  • 01:04:59after that, getting more to the customer demand, affected number of customers
  • 01:05:03affected, all those type of attributes will
  • 01:05:08be part of this decision by the
  • 01:05:11board in December.
  • 01:05:17And then Woody's already kind of highlighted the exit strategy, as right now,
  • 01:05:21we do have an obligation, if the board enters into an RMR
  • 01:05:24or MRA agreement, to come back to the
  • 01:05:27board with an evaluation of an exit strategy. Right now,
  • 01:05:32this appears the most likely exit strategy, but there's an additional protocol
  • 01:05:36requirement to do that if the board moves forward with an RMR MRA
  • 01:05:40solution. And then the last slide is just to kind of represent the
  • 01:05:44timeline where we are today. And then
  • 01:05:47obviously, it kind of reflects the two year need here on
  • 01:05:51the potential for RMR service. Again,
  • 01:05:54our focus has been around unit three, because we think it's in the
  • 01:05:58best condition and the highest megawatt value.
  • 01:06:02But obviously, as Woody has indicated, all three units,
  • 01:06:05from a capacity standpoint, are needed to address the IRL
  • 01:06:10for the next two years. So with that, Woody and I
  • 01:06:13are happy to answer any other questions. But again,
  • 01:06:16there will be a decision point here in December when we start to present this
  • 01:06:19information to the RMM committee and the board.
  • 01:06:24It looks like the transmission solutions of the ultimate exit strategy.
  • 01:06:28As we've talked about in this part of the discussion, are there
  • 01:06:32any other, you know, the RMR has
  • 01:06:35a cost, and is there
  • 01:06:39any way to take the economics
  • 01:06:42of that and use that, incentivize the acceleration of the transmission
  • 01:06:46projects? That is something that Woody
  • 01:06:50and I have been Talking about. And when he responded to Commissioner Jackson
  • 01:06:54around working with the TSP, that's another
  • 01:06:58alternative that we're looking at as a solution.
  • 01:07:01So we'll have MorE information as we move FoRward over the next month,
  • 01:07:04six weeks, on whether that's a viable option or not.
  • 01:07:07I think when we come to the board in December, we want to be able
  • 01:07:10to check the box that we considered these other options as well,
  • 01:07:14and they're either viable or not, and explain to the board why
  • 01:07:18they're either in front of you as an option or they're not viable. So that
  • 01:07:22if they're not viable, you're ultimately back to this. Right.
  • 01:07:26Okay.
  • 01:07:30Okay. Anything else? Chad, Pablo, Woody.
  • 01:07:34Okay. Okay. Thank you for that presentation.
  • 01:07:38Looks like we've got a lot of heavy lifting to do between now and December,
  • 01:07:42and then we've got a big decision to make at that point in time.
  • 01:07:45So it's now time for agenda item seven, the summer 2024
  • 01:07:50operational review. Dan Woodfin and Keith Collins are going to
  • 01:07:54make this presentation. Dan, Keith, the floor is yours.
  • Clip 7 - Summer 2024 Operational and Market Review - Discussion - Dan Woodfin / Keith Collins
    01:08:00 So I'll start out and kind of look at things that have gone
  • 01:08:03on this summer from an operational perspective, and then I'll turn it over to Keith,
  • 01:08:06and Keith will go over kind of the market implications and
  • 01:08:09outcomes of what went on this summer.
  • 01:08:13Although if you've been outside on an
  • 01:08:16afternoon for the last several days and again this afternoon,
  • 01:08:20it doesn't feel like summer has actually ended,
  • 01:08:24although I do understand fall, like temperatures are coming maybe next week.
  • 01:08:29But this review really goes over the calendar months
  • 01:08:34of June, July and August, the traditional summer calendar.
  • 01:08:44So summer weather from June
  • 01:08:47through August was actually the 6th hottest on
  • 01:08:51record for Texas in terms of average
  • 01:08:54temperatures and the reason I'll show more
  • 01:08:57in a few minutes. But the peak temperatures didn't
  • 01:09:01seem to be as hot. But it was really the minimum temperatures
  • 01:09:04each day that increased the overall
  • 01:09:08average temperatures.
  • 01:09:11Now, it was still hot even during peak periods
  • 01:09:15in the afternoon, but the last
  • 01:09:19several years, as I mentioned yesterday, were the third hottest
  • 01:09:23on record, the second hottest on record, and this year being
  • 01:09:26the, the 6th hottest on record, wound up making it because we
  • 01:09:30have that recent experience made it seem hotter. You can
  • 01:09:33see here that across the state we had many
  • 01:09:37fewer 100 plus degree days this
  • 01:09:40year compared to last year.
  • 01:09:45The line charts on the top here, purple is this
  • 01:09:49year, black, I guess it was last year. And you can see
  • 01:09:52that on most of the, for most of the summer, the peak temperatures on
  • 01:09:56each day were generally lower than what we saw last year by
  • 01:10:00a little bit. But the bar chart shows the comparison of the
  • 01:10:04peak demand each day from last year compared
  • 01:10:08to this year, with turquoise being this year
  • 01:10:11and gray being last year. And you can see that in
  • 01:10:15general now there's weather patterns and weekends in
  • 01:10:19there that may make a little difference. But in general, the load was
  • 01:10:22peak demands each day were about the same as what they were last year
  • 01:10:26with an obvious this year being lower
  • 01:10:31due to tropical storm barrel and then the
  • 01:10:36rainy period that occurred during July.
  • 01:10:43In terms of demand on the system, we had many in
  • 01:10:47the little box at the top here you see that we had many fewer 80,000
  • 01:10:51megawatt load days this year compared to last year.
  • 01:10:58The line charts show the maximum
  • 01:11:03demand each day and the minimum demand. One interesting thing
  • 01:11:07to note, there is that the minimum demands that we've seen this
  • 01:11:11year and last year were very similar.
  • 01:11:15And if you look back, some of the minimum
  • 01:11:18demands we've been seeing the last couple of years were as high as the peak
  • 01:11:22demands were just five years ago. And so
  • 01:11:26that shows the significant load growth that has gone
  • 01:11:30on.
  • 01:11:34The other thing, and we highlighted this last year, but I wanted to emphasize it
  • 01:11:38again this year, is that peak demand is not
  • 01:11:41the critical time in terms of how tight the system is
  • 01:11:47anymore. That happens later in the day when the
  • 01:11:50solar generation goes away. And so this
  • 01:11:54shows the net load. So that's demand on the system
  • 01:11:58minus wind generation, minus solar generation. So it's
  • 01:12:02really, that's the amount of load
  • 01:12:05that dispatchable generation in batteries has to serve.
  • 01:12:09And you can see that going for both
  • 01:12:12in June, July and August, the hours of
  • 01:12:16the day for 2024,
  • 01:12:182022 and 2020.
  • 01:12:22You can see that in 2023, you can see through that time period,
  • 01:12:26that green bar has continued to grow. And that's
  • 01:12:30the hour ending 21 each day. So that's after the sun's
  • 01:12:34gone down. The demand on the system is still
  • 01:12:38high. And so we see that that's really the time that
  • 01:12:41that dispatchable capacity and plus the batteries are
  • 01:12:45the tightest. And you can see that bar continues to be
  • 01:12:48much higher than your traditional peak demand hour, which is
  • 01:12:52our ending 17.
  • 01:13:00This is, I think, kind of the most telling chart
  • 01:13:05of the set. If you look at this,
  • 01:13:08is the capacity from offline
  • 01:13:12resources. And so when this
  • 01:13:15graph bumps against the zero line, that means all the
  • 01:13:19generation from resources were online.
  • 01:13:24And you can see in the gray that there were quite a few
  • 01:13:28times last year, quite a few days in which all generation
  • 01:13:33was online was being used to serve load and needed
  • 01:13:36to serve load. Whereas this year, you really only
  • 01:13:39see the August 20
  • 01:13:43was really the only day in which all the generation was
  • 01:13:47online. And so that's kind of the most
  • 01:13:51telling story of how much tighter this year wasn't
  • 01:13:55compared to last year. We had many days in which it was tight.
  • 01:14:00I'll also, because it'll be relevant here in a minute, if you look at the
  • 01:14:03825 as a particular day last year,
  • 01:14:06all the generation was on that day. And so on the next slide, I'm going
  • 01:14:10to compare 820 this year to 825 last year,
  • 01:14:13basically saying all the generation was online both those days. So let's
  • 01:14:17look at what happened on those days. Days.
  • 01:14:22And so 825 is like the second
  • 01:14:26from the left row of from last year is
  • 01:14:29the second row of bars there.
  • 01:14:32The 820 from this year is the last
  • 01:14:36set on this slide. And you
  • 01:14:40can see that solar was not completely down
  • 01:14:44at this tightest time, but it was fairly low.
  • 01:14:48We actually had a little more wind generation this year
  • 01:14:52as compared to that same hour, that same point in time last year.
  • 01:14:56But kind of the couple of interesting things I wanted to point out is our
  • 01:14:59physical responsive capability. The numbers at the top in
  • 01:15:03the little boxes, that's our kind of our frequency
  • 01:15:07responsive reserves that were online. That's the number that we use
  • 01:15:11to decide when we need to declare an EEA.
  • 01:15:17The numbers this year are significantly higher
  • 01:15:20than what they were on those tightest days last year. And you can see
  • 01:15:24that those PRC numbers are significantly higher.
  • 01:15:28We never dropped anywhere in the range of 3000 mw
  • 01:15:31this year as compared to last year. The other thing I wanted to point
  • 01:15:35out is that on those two days,
  • 01:15:38if you sum up the purple bars, the dispatchable
  • 01:15:42capacity and the gray bars which are the non IRR
  • 01:15:47outages. So basically it's the dispatchable capacity plus the batteries.
  • 01:15:51You see that we had about 3000 more megawatts of
  • 01:15:55that dispatchable capacity plus batteries this year once all
  • 01:15:58the generation was online, compared to that same time
  • 01:16:02when everything was online last year. So that's kind of
  • 01:16:06an indication of why
  • 01:16:10we were. One of the reasons at least that we were tighter, because wind
  • 01:16:14and solar is only part of the explanation there.
  • 01:16:20Speaking of batteries, energy storage resources,
  • 01:16:23ESRs, you can see that
  • 01:16:26on several. We looked at across the course
  • 01:16:30of a day, on several days this
  • 01:16:34past summer, those tighter days. And you can see that
  • 01:16:38where the gray line goes very high, that's when
  • 01:16:42they were discharging. And you can see that on that day,
  • 01:16:45August 20, there was almost 4000 mw
  • 01:16:48discharging during the timeframe when the sun went
  • 01:16:52down in the evening. Another interesting
  • 01:16:56thing on this chart is you see that they were charging overnight
  • 01:17:00when there was wind. It dropped down in the morning
  • 01:17:03when the sun starts to come up and there's that ramping period.
  • 01:17:07And then you see they start to charge again in the morning because the load's
  • 01:17:10still low. And now you've got solar generation
  • 01:17:14keeping prices low. Then in the afternoon over peak there
  • 01:17:17was some discharge and there's also some charging.
  • 01:17:20So there was actually charging going on over the peak as we
  • 01:17:24talked about yesterday. But then the big discharge is when the sun goes
  • 01:17:27down in the evening as the batteries are effectively extending
  • 01:17:32the solar window until the load comes down.
  • 01:17:39The other thing we wanted to highlight was the large flexible loads.
  • 01:17:42And so this is a day last year compared to a day this
  • 01:17:45year. And you can see that the gold here is our,
  • 01:17:49the system lambda. That's effectively the market clearing
  • 01:17:53price across the system a couple of days when
  • 01:17:57prices got high. One of those is August 20
  • 01:18:00of this year and then comparison last year.
  • 01:18:03And then the blue line is the output of all the large flexible loads
  • 01:18:08that we've identified that are categorized as
  • 01:18:11such. And so you can see there's a little more of them this year than
  • 01:18:15there were last year. And you can also see that they generally responded
  • 01:18:20down to, you know, some few hundred megawatts,
  • 01:18:24but reduced significantly during those high priced windows
  • 01:18:28in the evening.
  • 01:18:32And so I'm going to turn it over to Keith.
  • 01:18:35There are some, also some great other insights,
  • 01:18:39maybe in the appendix part of this, but in the interest of time, we're not
  • 01:18:42covering those, but happy to answer questions about
  • 01:18:45those when the time comes or hope you
  • 01:18:49look through them.
  • 01:18:52Peggy, you got a question? Yeah. So on this
  • 01:18:55slide, can you help me understand a little more what's going on
  • 01:19:00with the large flexible loads? It looks like they're not coming offline.
  • 01:19:04All of it's not coming offline when
  • 01:19:08the prices are high. Yeah, I think
  • 01:19:12in general, the processing part of that load
  • 01:19:15and maybe some other things are coming offline. They probably
  • 01:19:19still have some auxiliary type load that is
  • 01:19:22staying online, maybe air conditioning and those kind
  • 01:19:25of things. And so that's really the part that,
  • 01:19:30and you can also see that that actually has come down more
  • 01:19:34this year. Then, even though there's been more megawatts added, it came
  • 01:19:37down a little further, so they found ways to decrease that.
  • 01:19:41Okay, thank you.
  • 01:19:45If you could sum up the performance of the thermal fleet
  • 01:19:48this summer, how would you, how would
  • 01:19:52you describe that in less than 30 seconds?
  • 01:19:56I think we had a few more outages going on this not planned outages,
  • 01:20:00but forest outages were higher, generally across the afternoon
  • 01:20:05hours this summer compared to last summer,
  • 01:20:08but not significantly. So. Thank you.
  • 01:20:12Dan, I've got a question about during that critical
  • 01:20:17sunset hour where the batteries are discharging most
  • 01:20:21of their energy, that they're going to contribute to the grid because
  • 01:20:26there's not a lot of dispatchable mix at that particular timeframe.
  • 01:20:30Are we seeing any frequency or voltage instability
  • 01:20:35because of the high contribution from batteries?
  • 01:20:40No. I mean, we're generally planning the system such that those
  • 01:20:44are not, you know, we're not going to have any kind of voltage
  • 01:20:48instability type issue or
  • 01:20:51any other kinds of, from a frequency perspective, as long
  • 01:20:55as we've got enough generation to serve the load, we shouldn't
  • 01:20:58have a frequency problem and
  • 01:21:02generally they're helping with that. The concern
  • 01:21:06would be is if the load continues to grow and we don't add
  • 01:21:10more generation, dispatchable generation capacity that can be there
  • 01:21:13during those periods, and we start depending on the batteries for a
  • 01:21:17longer time frame such that they start running out of charge,
  • 01:21:21then that's kind of the concern to roll up.
  • 01:21:25Is there a way you can show us the actual versus,
  • 01:21:28like, theoretical what we need going forward as the load grows
  • 01:21:33so we can see that?
  • 01:21:36Yeah, let's think about how to do that. Hey, Dan, talk about the
  • 01:21:41starting state of charge and the ending state of charge as you
  • 01:21:45go through one of those really tight evenings.
  • 01:21:50Yeah. So what we
  • 01:21:53were. I don't know. I don't know that I had this in my
  • 01:21:57head from this year, but I know last year there were some days where
  • 01:22:01we start out with, you know, pretty close, pretty high
  • 01:22:04state of charge. They may have discharged some, and that's
  • 01:22:07why we see this charging over the peak.
  • 01:22:10And then sometimes between the peak and when the net load peak
  • 01:22:14is, there's charging going on. If they.
  • 01:22:18And so they're pretty well charged going into the solar ramp every day.
  • 01:22:21But last year, I know there were several days where we started seeing
  • 01:22:25batteries that had discharged pretty much completely and so they
  • 01:22:29started to fall off. Not in the aggregate. I think we got.
  • 01:22:33You may have that since you asked the question, you may have the number in
  • 01:22:35your head. I think we saw it get down in the 20% state
  • 01:22:39of charge, starting off as high as 80 and
  • 01:22:43getting down as low as 20 something by the end of the solar. Yeah.
  • 01:22:47Right. And another question is,
  • 01:22:51with respect to the batteries and the charging at peak or near
  • 01:22:55peak, are you seeing congestion issues? In other words,
  • 01:22:58California, for example, is looking at siding
  • 01:23:01requirements for being on the right side of charge so you don't generate
  • 01:23:05a congestion while charging at, you know, near peak.
  • 01:23:09Is that a consideration here?
  • 01:23:13I don't think it's been enough of an issue that we've looked at
  • 01:23:16it. So that probably tells you it's not.
  • 01:23:21Okay, Keith. Thanks, Dan. Or Dan, do you have anything else?
  • 01:23:25Yeah. Okay, Woody,
  • 01:23:28I think it's important for people when they look at their PRC number on the
  • 01:23:32website. You know,
  • 01:23:35seven, eight years ago, if you looked at PRC number and you saw three or
  • 01:23:384000 mw, that was three or 4000
  • 01:23:44generation, that could last for as long as you needed it.
  • 01:23:47Today, when you see three or 4000 generation
  • 01:23:51or five or 6000 generation,
  • 01:23:54there a good portion of that is limited duration.
  • 01:23:58So as soon as you start tapping into it, it disappears because it's
  • 01:24:02going to state of charge is going to go. So maybe as much as three
  • 01:24:06or 4000 PRC may
  • 01:24:10actually be limited duration batteries. And so the
  • 01:24:13PRC number is not the same number as what we were looking at five or
  • 01:24:17six years ago. And we're going to make some changes to the website to
  • 01:24:21show that. But for someone who has watched the,
  • 01:24:25has been watching a PRC number for a number of years, they're not looking
  • 01:24:29at the same number now as they used to. The changing generation mix
  • 01:24:32has really changed the nature of what that PRC number is.
  • 01:24:38I can remember several years ago if we had 6000
  • 01:24:42PRC, that was like a lot. We were in
  • 01:24:45really good shape. It doesn't have the same security now as it did.
  • 01:24:49I'm glad you brought that up. I think it's important that we note that
  • 01:24:54for people who are using the website or the mobile app to see
  • 01:24:57with the PRC number, because I think it is.
  • 01:25:01That metric has been misused in some newsletters
  • 01:25:05to say that we have adequate resource capability.
  • 01:25:09Keith, floor is yours. All right, thank you. Dan did a good
  • 01:25:13job setting me up for this presentation here, and I
  • 01:25:17think I'll just start with the punchline as prices were down 82%
  • 01:25:21year over year, and the reasons
  • 01:25:24may not be that obvious. And so hopefully the presentation today will
  • 01:25:29help sort of flesh out what that is and help us
  • 01:25:33think about what might be coming in the coming years as well. I'll just sort
  • 01:25:37of note as well, the nice thing about the top chart is we start
  • 01:25:40at the beginning of the year comparing, comparing prices.
  • 01:25:44So our average prices, January, February, all the way through
  • 01:25:48August. And what's interesting to note, particularly for the January through
  • 01:25:51May period, is that they were fairly similar overall.
  • 01:25:55Not identical, but close.
  • 01:25:58But then once we get to June, July and August,
  • 01:26:02there's a rather large change between what we were
  • 01:26:05seeing in those months. And so really
  • 01:26:10the question is why? But I'll sort of also note
  • 01:26:14in the bottom chart, the PGRR net margin,
  • 01:26:18which we track, is substantially
  • 01:26:22different compared to this year and last year.
  • 01:26:25Now granted, as Dan noted, last year was
  • 01:26:29really an extreme year in
  • 01:26:32terms of what we were seeing in sort of weather, and this year was
  • 01:26:36different. And loads are part of this,
  • 01:26:40but they're not the only thing. In fact, when you look at loads
  • 01:26:43in June, loads in June were higher this
  • 01:26:47summer compared to last summer. But you'll see in the chart, in the top
  • 01:26:51bar chart is that June prices were substantially lower.
  • 01:26:56Gas prices were down a little bit, let's say a little over 20%.
  • 01:27:01Around 20% lower. But again, the prices in June were
  • 01:27:04lower. So if loads were higher, gas prices may be a little lower.
  • 01:27:08Well, what's driving this, and ultimately,
  • 01:27:11one of the things that we didn't talk about as much is changes to
  • 01:27:14the non thermal fleet. And so we had
  • 01:27:18increases in solar and storage. So solar was
  • 01:27:22up about eight gigawatts summer to summer,
  • 01:27:26and storage resources about doubled.
  • 01:27:29So up about nine gigawatts in total. So grew
  • 01:27:33about four and a half to five gigawatts summer over summer. So that
  • 01:27:38increase in the generation mix had a pretty substantial
  • 01:27:42effect on what we're seeing. Obviously, solar resources,
  • 01:27:46the pricing on solar is different than the thermal fleet.
  • 01:27:50And in particular with the storage, we saw a lot of
  • 01:27:54substitution on the Ansla services side. So in
  • 01:27:58terms of ancillary services,
  • 01:28:02storage is a major contributor to the total
  • 01:28:06share of resources there. And we've got a slide that'll highlight that as well.
  • 01:28:11Okay, so what are some of the other things that are going
  • 01:28:15on as a result of this change, change that I just described?
  • 01:28:18And what we're seeing here is the ORDC,
  • 01:28:21the operating reserve demand curve. And what was that contribution
  • 01:28:25to the pricing? And what we saw here is, not unexpectedly,
  • 01:28:30it was less than what we saw over the last couple years, fewer instances
  • 01:28:34of the operating reserve demand curve being
  • 01:28:38applied. And part of that had to do with the resource availability
  • 01:28:42that we were seeing in the system that Dan was talking about just
  • 01:28:46a minute ago, overall, relative to the demand that we
  • 01:28:49saw in the system. So the ORGC played,
  • 01:28:53played, played, played a smaller role in terms of the impact of price and the
  • 01:28:56frequency as well,
  • 01:29:00in terms of energy storage capacity offered into the real time market.
  • 01:29:04We saw a large shift this summer compared
  • 01:29:07to last couple of years. The bar, the height of the bar is
  • 01:29:11how much that was being offered into the market in these months.
  • 01:29:15We've also broken out in terms of the price level. We generally
  • 01:29:18see storage resources at or near the cap
  • 01:29:22of $5,000. But that's represented in
  • 01:29:26the blue bar. But what we
  • 01:29:30also saw was a growth in the amount of esrs that
  • 01:29:33were under, under that level. And that's in the sort of the grayish color that
  • 01:29:37you see there. And that substantially grew as well. So the total volume
  • 01:29:41of esrs in the market in the real time market
  • 01:29:45was significantly higher than in previous years.
  • 01:29:51Okay. And what this chart will show us is comparing
  • 01:29:55August 23 to August 24. And what
  • 01:29:59we're looking at is essentially the capacity of
  • 01:30:03solar in the orange color and
  • 01:30:07storage resources in the red color. And ultimately,
  • 01:30:10it's a significant shift up in both.
  • 01:30:14And one of the things that sort of the prices did sort of mask.
  • 01:30:18But it's important to note is that in that the
  • 01:30:21solar resources that have a profile and there's a significant ramp
  • 01:30:25down period of after the peak,
  • 01:30:28which occurs around 17, but the net peak shifting out to
  • 01:30:32our 1819.
  • 01:30:36And what we saw in the pricing, and we still see that today,
  • 01:30:39over the last few days, we continue to see that solar ramp down period
  • 01:30:43being the period of where the system is tightest.
  • 01:30:47And the prices reflect that as well. We saw prices on August 20,
  • 01:30:52$5,000 and the date that Dan showed earlier. And the discharge,
  • 01:30:57the prices during that period were also up and around
  • 01:31:00the cap on that day. And so the
  • 01:31:05storage that is available is able to fill in that gap of
  • 01:31:09the solar ramp periods. But I will note that the expectation of
  • 01:31:13what we see coming forward in the next year or two is
  • 01:31:17that we expect that storage could double
  • 01:31:20in the next year and that solar could double
  • 01:31:24in the next two to three years. So if you've got a doubling
  • 01:31:27of solar, that ramping, that ramp down period is also likely to double
  • 01:31:32as well. So the storage we
  • 01:31:35saw this year, as Dan showed, was able to fill that gap
  • 01:31:39during that period. But we would expect going forward that as
  • 01:31:43that solar resource continues to grow, that those needs on the system
  • 01:31:47will also grow and the pricing will reflect that as well.
  • 01:31:52Switching gears a little bit, talking about congestion on
  • 01:31:55the system, compared to the last couple of years, congestion was not a,
  • 01:32:01it was relatively milder compared to last year. And,
  • 01:32:06you know, not that different from a
  • 01:32:10little lower, but not overall that different from previous
  • 01:32:13years. And so overall congestion, not as
  • 01:32:16a major driver in the summer months, and again, not to be as
  • 01:32:21you've got more transmission available, more resources available.
  • 01:32:24Congestion during the peak periods is generally not a major driving
  • 01:32:28factor. But as we enter shoulder periods
  • 01:32:31and resources take outages, we expect congestion to increase ancillary
  • 01:32:38services. And I think this is a major point,
  • 01:32:41is that ancillary service costs were, for the
  • 01:32:45summer months, totaled 36 million.
  • 01:32:48And we compare that to August of last year, which totaled over 800
  • 01:32:52million. So this is a dramatic shift in the total cost of
  • 01:32:56ancillary services. And one
  • 01:33:01of the key factors is the, the resources that are making up
  • 01:33:05those ancillary services are increasingly,
  • 01:33:10those resources are increasingly made up of energy storage resources.
  • 01:33:14And that's what we'll show here on the final chart that I have is
  • 01:33:18this bar chart shows us the last few summers.
  • 01:33:22Each bar height is up to 100% is the share of
  • 01:33:25those ancillary services that are covered by energy storage resources.
  • 01:33:30And what we see is that for regulation, up in
  • 01:33:34the blue represented about 75%,
  • 01:33:37and that was similar to last year, but there were changes
  • 01:33:41in terms of regulation. Down. Also around
  • 01:33:4675 80% was energy storage resources.
  • 01:33:49The RRS was around a little under 50%.
  • 01:33:54And then ECR, the ECRS product in particular,
  • 01:33:58had an increased share of ESR
  • 01:34:02resources, providing ECRS up
  • 01:34:06in the 40% to 45% depending
  • 01:34:09on the month. And then finally Non-Spin.
  • 01:34:13While the percentage increase was different as the share increase, it's only about 5%
  • 01:34:18of Non-Spin. But overall, it's important to know that
  • 01:34:21this, this is a pretty dramatic shift over the last few years in terms of
  • 01:34:25resources. Providing ancillary services has shifted primarily
  • 01:34:29towards ESR resources and storage resources.
  • 01:34:33And again, what that can do is you're substituting storage
  • 01:34:37resources. Resources that may have been dispatchable thermal resources are
  • 01:34:41now available to participate in the energy market,
  • 01:34:44whereas before they were participating in the ancillary service market. And so that further
  • 01:34:48has an effect of dampening prices as well. So I
  • 01:34:52will pause there and see what kind of questions you may have for me.
  • 01:34:59So Keith, is there a way to summarize
  • 01:35:03the pricing structure for this past summer
  • 01:35:08in terms of what that means for someone that's considering making an
  • 01:35:12investment and a thermal dispatchable resource?
  • 01:35:16So I think what's interesting
  • 01:35:19from that perspective is we know that there is a,
  • 01:35:24or expect to be more load in the future.
  • 01:35:28We have our study in 2030 that says 150
  • 01:35:33gigawatts, which is very different from where we are now. I think what we're
  • 01:35:36seeing in this year and the next
  • 01:35:40couple years potentially, is that there will be generation
  • 01:35:45increasing and in this case generally the
  • 01:35:50non thermal resources. However, there is
  • 01:35:54this expectation that there's likely to be significant load
  • 01:35:57growth potentially in 27, 28, 29.
  • 01:36:00And so when you're thinking about pricing and investing in
  • 01:36:04thermal generation, you really have to weigh
  • 01:36:09the generation increases. We're seeing now, this summer,
  • 01:36:13potentially again next summer. And that has a potential impact
  • 01:36:17on the price for sure, but also expectations of load growth
  • 01:36:21that's likely to occur potentially in 28, 29 and
  • 01:36:2430. So in terms of investment decisions,
  • 01:36:28you have to sort of weigh the generation, makes the generation that's coming on
  • 01:36:32now also with the load side that's expected coming in the future.
  • 01:36:36Keith, could you add, could you add to that answer a little bit about a
  • 01:36:39perspective on price curves and how we've seen how price curves in
  • 01:36:43the two three year window are shaping up in our kind of what signal that,
  • 01:36:47you know, what that represents to that question. Yes. So we
  • 01:36:51do have a look into the forward prices that are trading on exchanges,
  • 01:36:57and what we're seeing there, that there has actually been a reduction in those forward
  • 01:37:00price curves over the last few months
  • 01:37:04relative to what they were earlier in the year. So earlier in the year,
  • 01:37:07the prices were a little higher, going out to 2030,
  • 01:37:11and we've seen those prices come down over the
  • 01:37:14last few months as they project out further in the future.
  • 01:37:18It's really hard to say specifically what's driving that,
  • 01:37:21but what we do know is that we're
  • 01:37:26seeing the increase in generation and we know we'll
  • 01:37:29be implementing the RTC program, which will be very efficient,
  • 01:37:33but that can have an impact on prices as well.
  • 01:37:37Keith, going back to what you responded to,
  • 01:37:40Bill, the way I think about the ERCOT market, and feel free to correct me
  • 01:37:43if it's not the right view, but ERCOT used to be kind of a baseload
  • 01:37:48market. It shifted to a load following type
  • 01:37:51of generation market. But now we're seem to be moving towards
  • 01:37:55a combination of the boat of both, because some of these large loads expected
  • 01:37:59to come in are 24/7 loads that are going to need
  • 01:38:03more traditional base load type generation. At the same
  • 01:38:07time, we have a lot of load following assets. So it just
  • 01:38:10seems like it used to be this, now it's this, now it's going to
  • 01:38:13a combination of both as we look towards the future. And I'm not
  • 01:38:17sure the price signals are going to be there until they're
  • 01:38:21there. Yeah. I think under the construct we
  • 01:38:26live under in the ERCOT market, the real
  • 01:38:30time is where we see the price movements. And I think your point
  • 01:38:33is, it's hard to anticipate what that may look like until it happens.
  • 01:38:38And I think your point on the different profile of the
  • 01:38:42gentle, which can be variable, and even on
  • 01:38:46the load, where we can see some load responsiveness. Right. So it
  • 01:38:49depends on the load. There are some loads that are more base, as you
  • 01:38:53suggested, and there's other loads that can be very flexible, so that that
  • 01:38:56paradigm is shifting, for sure.
  • 01:39:00Okay, Keith, I think you've got a ruck slide.
  • 01:39:03Did you want to go through that? Oh, yeah, yeah. That was my final.
  • 01:39:06Sorry, that was my final slide. Here is the ruck. And I know
  • 01:39:11for me, being sort of new to the ERCOT market, one of the things I
  • 01:39:14heard was, yeah, ruck. Oh, wow. It's such a big issue and it's
  • 01:39:19almost felt like this weight of crushing. And then I looked at the
  • 01:39:22data and said, wow, there doesn't seem to be that much ruck going on in
  • 01:39:25the summer. So I take this as a very positive
  • 01:39:29occurrence that the instances of ruck are greatly
  • 01:39:33diminished over where they were a couple years ago and less than were last
  • 01:39:36year. So I see this as a positive thing, that the reliance on RUC
  • 01:39:40as a tool, particularly in the summer months, is a positive thing.
  • 01:39:44Although I will note that what we've been seeing a little more recently,
  • 01:39:47given that solar ramp down period, is that as ramping needs have been increasing,
  • 01:39:52you know, the ruck tool, particularly in September October timeframe,
  • 01:39:55is perhaps more, more rucks than we had seen.
  • 01:39:58And so we definitely want to think about what that means going forward
  • 01:40:01and how that impacts pricing. All right.
  • 01:40:05Okay. Thank you, Keith. Any other questions? Comments for Keith?
  • 01:40:09Okay, thank you. We'll now move to agenda item eight,
  • 01:40:13and I'd like to invite Caitlin Smith, who's the chair of TAC, the technical advisory
  • 01:40:17committee, to present this agenda item.
  • 01:40:31Sorry, Caitlin, I should have made you a better heads up this
  • 01:40:35time.
  • 01:40:45I know. I thought there was break scheduled, so I thought I was going to
  • 01:40:48get to stretch before this. All right, good morning.
  • Clip 8 - TAC Report - Discussion - TAC Chair
    01:40:52 I'm Caitlin Smith, chair of the technical advisory committee, and we
  • 01:40:56are happy to have this opportunity to present.
  • 01:40:59And I do follow Arkad on Instagram. I think I was
  • 01:41:02like the 22nd follower. So, you know,
  • 01:41:06that's a challenge, I think, because I saw they're only at 73.
  • 01:41:09So I think everybody needs to follow ERCOT on Instagram.
  • 01:41:13So, as we do at each board meeting, we'll be presenting
  • 01:41:17a summary of the TAC meetings that occurred since the last board meeting.
  • 01:41:21Those were our August and September TAC meetings.
  • 01:41:24We have included some more information to this report starting
  • 01:41:28this month. And always happy for feedback. As we discussed
  • 01:41:32yesterday, kind of an effort to provide more information
  • 01:41:35about what's happening with the stakeholders to the board.
  • 01:41:38So we have added highlights from the groups,
  • 01:41:42not just TAC, but the groups that report directly to TAC, which are four
  • 01:41:46subcommittees, the credit finance subgroup. And then currently
  • 01:41:50we have two task forces that report directly to TAC. Those are
  • 01:41:54the RTC+B and the large flexible load task
  • 01:41:57force. At the August and September
  • 01:42:00meetings, we voted unanimously to recommend approval
  • 01:42:04of eleven revision requests. And we also endorsed
  • 01:42:09ERCOT's recommended 2025 ancillary
  • 01:42:12services methodology. So here are those
  • 01:42:15eleven unanimous revision requests,
  • 01:42:20and here is where we added the highlights from the subcommittees and
  • 01:42:24the subgroup and the task forces. I think I will just pick out a
  • 01:42:28few and not read the whole list to demonstrate the type of issues
  • 01:42:31that are happening. And then if asked or if there's feedback,
  • 01:42:34we can add more. The reliability and operations
  • 01:42:38subcommittee is really digging in on the transmission
  • 01:42:42needs and kind of the methodology and planning around that. And so
  • 01:42:46transmission planning items related to
  • 01:42:50NPRR1247, incorporation of congestion cost
  • 01:42:53savings test and economic evaluation of transmission projects,
  • 01:42:58and the PGRR 117.
  • 01:43:01And these are implementing the PUC rule changes
  • 01:43:05on the economic cost savings test that
  • 01:43:09was added to transmission following legislation.
  • 01:43:12Load forecasting related issues such as PGRR 107
  • 01:43:16related to NPRR1180, inclusion of
  • 01:43:20forecasted load and planning analysis. And that's where we are
  • 01:43:23getting these large load numbers for transmission planning.
  • 01:43:27Large load issues from the large loads that are wanting to interconnect,
  • 01:43:32including NPRR1235 for interconnection requirements
  • 01:43:35for large loads and modeling standards for loads 25 mw
  • 01:43:40or greater. And so that's what's happening at that
  • 01:43:43group. On the slide. We also have the retail market
  • 01:43:46subcommittee. They have been working very hard and for a
  • 01:43:50long time on Texas set version five
  • 01:43:54implementation. They are working still on the
  • 01:43:58lubbock power and light transition to competition, and then TDSP
  • 01:44:03updates from hurricane barrel.
  • 01:44:08I think this slide also has so
  • 01:44:12prs, they are not taking up
  • 01:44:16as many kind of separate issues, but this is where grinding out
  • 01:44:20those NPRRs happens. And so an NPRR will
  • 01:44:23always kind of start at prs and then end here for language review
  • 01:44:28and the IA, the implementation and the impact analysis,
  • 01:44:32which is sort of the implementation timeline and cost before it goes to
  • 01:44:35TAC. So in, I guess in the last
  • 01:44:39couple of months, they forwarded five NPRRs to TAC for consideration,
  • 01:44:45the wholesale market subcommittee.
  • 01:44:49And so this is where a lot of the, I think this is really
  • 01:44:53fun subcommittee, a lot of the arguing about market principles
  • 01:44:56happens here. And so the large load interconnection
  • 01:45:01report has been here for a couple months. I believe that will move to
  • 01:45:05TAC when the task force wraps up. And then
  • 01:45:09I wanted to point out that they did have the IMM
  • 01:45:12discuss the 2023 state of the market and
  • 01:45:16the recommendations that the IMM had in those,
  • 01:45:19you know, WMS has great leadership. It's Eric Blakey
  • 01:45:22and Jim Lee. And, you know, they did a good job of inviting
  • 01:45:26the IMM to present this report. I think it's something we
  • 01:45:29should consider kind of formalizing every year into the
  • 01:45:33stakeholder process. I know commission staff had a similar
  • 01:45:37memo on kind of their recommendations on the IMM recommendations
  • 01:45:41and the commissioners took it up as well. So I think formalizing
  • 01:45:45that or, you know, at least doing it kind of traditionally or
  • 01:45:50continually every year would be good in the stakeholder process.
  • 01:45:55I do want to bring your attention to a WMS conversation
  • 01:45:59from October, I think it was last week. It didn't make it into this
  • 01:46:04presentation. WMS and its working
  • 01:46:07groups, both its wholesale market working group
  • 01:46:10and support supply analysis working group, have been discussing
  • 01:46:14NPRR1235, and that is the
  • 01:46:17implementation of DRRS, a dispatchable reliability
  • 01:46:21reserve service, as a standalone product.
  • 01:46:24And there is kind of a very robust policy
  • 01:46:27discussion that has formed there. This is
  • 01:46:31based off of comments that were recently filed by luminant and
  • 01:46:35an interpretation of the statute that legislated
  • 01:46:38DRRS. And so this policy question is basically
  • 01:46:42whether that ancillary service should be designed to be a tool for
  • 01:46:45operational uncertainty or a tool for both operational
  • 01:46:49uncertainty and one used to meet the reliability standard.
  • 01:46:53So I don't necessarily expect an answer right now,
  • 01:46:56but I think as we discuss the process and things like how
  • 01:47:00and when to get policy direction,
  • 01:47:04this is a policy kind of inflection point
  • 01:47:07that I think stakeholders need some more feedback,
  • 01:47:11maybe from the commission or maybe from the board, to know
  • 01:47:15that they're headed in the right way. There's some technical details on the NPRR
  • 01:47:18they can continue to work on and implement. But I think there
  • 01:47:22is a policy inflection point. I do think
  • 01:47:26that'll be kind of a recurring discussion at R&M
  • 01:47:30yesterday, we presented the reasons on no votes to
  • 01:47:34the ancillary service methodology, and I think there were some similar
  • 01:47:38concerns from the no votes, like how does that fit
  • 01:47:41into the reliability standards? And so I think you're getting this question
  • 01:47:45of what tools at ERCOT that we're working on at
  • 01:47:48TAC and stakeholder groups need to be, how do we need to
  • 01:47:52be thinking about those to meet the reliability standard, whether it's ECRS,
  • 01:47:56DRRS, or what have you? And so that's kind of a flag there
  • 01:48:00for a policy decision that I think needs to be made for stakeholders.
  • 01:48:06I can pause there if there's questions or comments.
  • 01:48:11All right, Caitlin, I have a question. Yes. With respect
  • 01:48:15to the discussions at Ross on transmission planning,
  • 01:48:19particularly NPRR1247.
  • 01:48:22PGRR there, that's the implementation of
  • 01:48:25the economic transmission planning test, right?
  • 01:48:29Yes. And that was required by a legislative bill in 2021.
  • 01:48:32Yes. So what is the current state of this NPRR?
  • 01:48:36Because I don't know that we should enter this next session
  • 01:48:39without having to implement an economic transmission planning test.
  • 01:48:42Yes, I believe that is still at PRS.
  • 01:48:46And Ross, you know, there was some concern about that,
  • 01:48:50I think. I don't want to say a miscommunication,
  • 01:48:54but I think more clear communication would help.
  • 01:48:58I think the timeline's very tight on
  • 01:49:01that. So I believe that's at PRS. We could take that up
  • 01:49:04at TAC before the end of the year, but I
  • 01:49:08don't know if we could get it to a December board meeting. And I believe
  • 01:49:11the commission would then have to waive some notice
  • 01:49:14to get it through by the end of the year. Our understanding
  • 01:49:17was on the sort of regular timeline that the last TAC
  • 01:49:21to pass it would have been the September TAC.
  • 01:49:25It was tabled at the September PRS.
  • 01:49:30I think the concern there was the language
  • 01:49:33just wasn't accurate enough, and there was some discussion
  • 01:49:37over this being a priority that we need to get in by the end of
  • 01:49:41the year to have the commission have in place. But I
  • 01:49:44think the language wasn't where stakeholders wanted
  • 01:49:48it to be to move it forward. Well, I know that ERCOT hired
  • 01:49:53e three to help develop this test. Our staff has spent a lot of time
  • 01:49:56working on this test, that the NPRR was
  • 01:50:00not deemed urgent. I think that. Is that correct?
  • 01:50:03The vote failed? The vote failed on urgency. That's correct. Okay.
  • 01:50:06So, I mean, I would just flag that for Chairman Gleason. I mean,
  • 01:50:10this has been hanging out there since 2021. So, you know,
  • 01:50:14if anything that can be done to bring this to a
  • 01:50:17close would be important. I think as our state continues to grow,
  • 01:50:22we're going to need capacity to be moved around to serve load.
  • 01:50:26This is a different criteria than reliability, but at the same
  • 01:50:29time, it will serve to move capacity around,
  • 01:50:34you know, in more remote areas of the state. So I
  • 01:50:38would just urge the stakeholder
  • 01:50:42process to kind of get going on this and get it done.
  • 01:50:46Okay, let me get with ERCOT staff and then maybe
  • 01:50:50get back with you and see if there's a way we can pass it this
  • 01:50:53year. My understanding of the conversation, I certainly
  • 01:50:56don't think anybody disagreed with the rule or that
  • 01:51:00this is important. I think the concern was some of the
  • 01:51:03language wasn't quite there yet, kind of like in technical
  • 01:51:07terms and making sense for where we needed. But let me make sure,
  • 01:51:11I think ERCOT and stakeholders are continuing to work on that. So let me see
  • 01:51:14if we can find a path to getting that passed.
  • 01:51:17But my understanding, again, was not that they disagreed
  • 01:51:21with anything you're saying or disagreed that it was important. It was sort
  • 01:51:24of the language not being there. Christy,
  • 01:51:27you're knee deep in this. Do you want to. I wanted to just clarify,
  • 01:51:31or. From my perspective, I wouldn't take the discussion that there
  • 01:51:35was inaccuracies in the language. It was that stakeholders
  • 01:51:39were looking for additional information on how we would apply the criteria,
  • 01:51:42which we're providing through a separate document, so that they have
  • 01:51:46a full understanding of how we would apply the criteria in the planning studies.
  • 01:51:50So I'm hopeful, if they have that information, they'll be able to move that
  • 01:51:53forward quickly. So, Christy, currently, right now, because the
  • 01:51:57test isn't implemented, is ERCOT reviewing transmission projects from an
  • 01:52:00economic standpoint? We are.
  • 01:52:03That's right. And that. What is the interim measure again? It's the
  • 01:52:07generation revenue reduction test. Marie,
  • 01:52:10collection. Okay. So the ERCOT transmission planning continues to
  • 01:52:14review economic projects under that interim test, but I
  • 01:52:17think it's just important to get this test done. I mean, we spent years
  • 01:52:21already trying to get this done. We spent a lot of time at the commission
  • 01:52:24trying to get the rule passed. ERCOT went through the trouble of
  • 01:52:27hiring a three and, you know, trying to come up with a good test.
  • 01:52:30Our staff, I know ERCOT team, has spent time looking at it, and so
  • 01:52:35I would just urge to kind of wrap this up.
  • 01:52:39Thank you,
  • 01:52:44Caitlin. Please continue.
  • 01:52:47We are here the credit finance subgroup.
  • 01:52:52This is a newer group. We conflated the market credit working
  • 01:52:56group and the credit working group that used to report directly to the
  • 01:52:59board. They take up kind of those separate
  • 01:53:03issues, but they also evaluate each revision
  • 01:53:06request for the credit impact. So they review those for the credit
  • 01:53:10implications and report that to TAC,
  • 01:53:13the RTC+B task force,
  • 01:53:17they're kind of powering through their current issues list,
  • 01:53:21the RTC associated revision requests.
  • 01:53:24We've all talked about the ancillary service demand curves and
  • 01:53:27kind of the policy discussions there. But really, at this group,
  • 01:53:32Matt Moranis and stakeholders do a really good job of
  • 01:53:35sort of the timeline and project managing. As was noted earlier,
  • 01:53:40we got the announcement since the last board meeting that the implementation of
  • 01:53:44RTC+B will be in December of next
  • 01:53:47year. So they are doing a good job at kind of really managing
  • 01:53:51the project and the timeline from the kind of stakeholder input perspective.
  • 01:53:55The large flexible load task force, they are talking
  • 01:53:59about maximum size of a single large load connection,
  • 01:54:03and then NPRR1238, voluntary registration
  • 01:54:07of loads with curtailable load capabilities.
  • 01:54:12Here are our August and September, but really, I think
  • 01:54:16these are only September. TAC highlights the proposed
  • 01:54:20changes to the 2025 ancillary service methodology.
  • 01:54:24We had a long discussion about this yesterday at R&M.
  • 01:54:28ERCOT also presented their recommendation. And then Pablo reviewed
  • 01:54:32that with you today. This was the first year with the required
  • 01:54:36commission approval, so the timeline was earlier.
  • 01:54:40You know, I will do my own version of Pablo's thank
  • 01:54:44yous to people, which I did yesterday. The ERCOT
  • 01:54:47staff on this did a really great job. They came to us
  • 01:54:51in June with the timeline and then kind of a
  • 01:54:54plan to socialize it with stakeholders. So that's Jeff below
  • 01:54:58and Nitika Mago and their teams. And so they
  • 01:55:02brought the timeline, as I said to us, in June. This was discussed at
  • 01:55:05several working groups in July and August,
  • 01:55:08at the wholesale market working group, performance disturbance compliance
  • 01:55:12working group and operations working group. It went to both
  • 01:55:15the wholesale market subcommittee and the Reliability operations subcommittee.
  • 01:55:20And then it was at TAC. We did choose to endorse
  • 01:55:24this methodology. There was one opposing vote from the
  • 01:55:28independent generator segment and two abstentions. One of those from
  • 01:55:32the independent generator segment and one from the
  • 01:55:36independent power marketer segment. We had a
  • 01:55:40good, not super contentious, but a good robust discussion
  • 01:55:44at TAC. We had requested the imm be there.
  • 01:55:47They were there and opined and said they did not oppose
  • 01:55:51this. And, you know, a lot of the discussion was between
  • 01:55:54ERCOT and the generator segment on
  • 01:55:57reduced volumes of services. And so the no
  • 01:56:01vote outlined two main concerns. One was reduced RRS procurement
  • 01:56:06during winter morning ramp, and that bringing more risk to the system.
  • 01:56:10The second was impacts of ECRS
  • 01:56:13and Non-Spin reductions, viewing those as occurring in
  • 01:56:17a vacuum and not considering long term impacts to resource
  • 01:56:20adequacy and reliability. Regarding the
  • 01:56:24reduction of ECRS and Non-Spin. This was about investment
  • 01:56:28signals. And as I kind of touched on already the interaction
  • 01:56:32with the newly adopted reliability standard, the two
  • 01:56:36abstentions. One was regarding reducing Non-Spin
  • 01:56:40and sort of in the alternative,
  • 01:56:43relying on RUC and so moving things from
  • 01:56:46a market based mechanism to an out of market based mechanism.
  • 01:56:50And then the second was sort of similar to the no
  • 01:56:54kind of concern with the suppression of
  • 01:56:58suppressing market signals. While you might be working on
  • 01:57:01a more holistic plan for meeting the reliability standardization,
  • 01:57:06the major transmission element list,
  • 01:57:09the September TAC, TAC voted unanimously to
  • 01:57:12approve this list as passed. And then the stakeholder
  • 01:57:16process improvements discussion. I know several
  • 01:57:20of the board members listened in and I want to thank you guys
  • 01:57:24for that. I think this is the beginning of the
  • 01:57:28conversation. The discussion was really around
  • 01:57:32getting more communication to the board and I think
  • 01:57:35to the commission. And so, again, really happy to get
  • 01:57:38feedback. I think we'd like to see more written comments when possible,
  • 01:57:43from stakeholders, and especially more written comments
  • 01:57:47after between TAC and the board. Even if you knew somebody opposed
  • 01:57:50something through the process, just what's their position now?
  • 01:57:54How strongly do they feel? What arguments do they need you
  • 01:57:57to hear? I think coordination with commission staff was
  • 01:58:01a big theme that came up, and Barksdale English
  • 01:58:05did sit with us, and I thought that was a really great first step,
  • 01:58:08and he had a lot of input. And so we'd like to try to
  • 01:58:11continue that coordination.
  • 01:58:15An area where I feel there's a little bit of pressure
  • 01:58:18is a lot of times when
  • 01:58:22things come to TAC, it is the first time
  • 01:58:26TAC, and we have to vote it out that day. I reviewed
  • 01:58:30the big stakeholder process chart yesterday, and so we get
  • 01:58:33all this information from very detailed and technical working
  • 01:58:37groups. But again, it's hearing all the arguments,
  • 01:58:41making sure we are reviewing all the data that came from those working groups
  • 01:58:44and then relaying that up to the board. And so I
  • 01:58:48think having more time would be helpful.
  • 01:58:52Another flag that came along those
  • 01:58:55lines was somebody said that the aging
  • 01:58:59revision requests makes them feel a little bit pressured to pass things
  • 01:59:03through the stakeholder process quickly. And I have gotten
  • 01:59:06a lot of concern about that, too. I think that's something for
  • 01:59:10further discussion. And what that is is we have a list of aging
  • 01:59:14revision requests which have been approved
  • 01:59:18and that stakeholders in ERCOT feel are important but
  • 01:59:21just don't have time to be implemented. So during after winter
  • 01:59:25Storm Uri, we had kind of a hold on a lot of the things
  • 01:59:29that had been in motion because of policy decisions
  • 01:59:33that would be made at the legislature. And then now we have sort
  • 01:59:36of a hold, kind of a system process hold because
  • 01:59:40of implementation of RTC. So in those different time
  • 01:59:43periods, we've gotten this backlog of revision requests
  • 01:59:47that are improvements that people feel strongly about, that have
  • 01:59:51been approved by everybody, but just don't have time to be implemented.
  • 01:59:55So that's sort of a recurring feedback I
  • 01:59:59get from stakeholders. So I think that is something that we'll want to look to
  • 02:00:03addressing as well.
  • 02:00:07That ends my presentation. And I do want to say,
  • 02:00:10Chairman Flexen, I am very sad to hear that you'll be leaving.
  • 02:00:14He's provided really great leadership for TAC.
  • 02:00:17I know, for TAC leadership and for the group. He has engaged
  • 02:00:22a lot and given us really valuable feedback. So I'm
  • 02:00:26sad to hear that you are leaving. Thank you. Caitlin,
  • 02:00:31any questions for Caitlin? Any comments?
  • 02:00:34I have just a comment. Caitlin, you went in this last slide.
  • 02:00:38You were going over the stakeholder process improvement.
  • 02:00:42And I just want to reiterate one point you made about getting
  • 02:00:46comments in writing. It's very hard for
  • 02:00:50us if we don't have a written record as to what positions
  • 02:00:54are. So I just want to encourage TAC and its
  • 02:00:57members to do so. We agree. I think
  • 02:01:01that was kind of a consensus view, was that that would be helpful.
  • 02:01:05I think we needed to make some clarifications.
  • 02:01:09You know, we do collect kind of written by email reasons for
  • 02:01:12opposing and abstention votes that I present to you. But I think it's
  • 02:01:16important if somebody feels strongly about something about
  • 02:01:20the TAC decision that they have a kind of new set of comments
  • 02:01:23that you can read or take a that because a lot of these NPRRs have
  • 02:01:27a record that's a year and a half long. And so I
  • 02:01:31think getting the up to date information and writing is helpful,
  • 02:01:33too. Anything else for Caitlin?
  • 02:01:37Caitlin, I want to thank you for the detailed report and thank you for leading
  • 02:01:41the TAC effort for the stakeholder improvement process.
  • 02:01:44Appreciate the PUC dedicating resources to the
  • 02:01:48TAC meetings. And as I told you the other day, I'll be that I'm going
  • 02:01:51to try to be more engaged at the TAC process. I'll be
  • 02:01:54at the meeting on November 20. Thanks for the detailed
  • 02:01:58report and thanks for providing extra insight into the
  • 02:02:02key issues that you're working on as you move forward
  • 02:02:06with that. The schedule or the agenda
  • 02:02:10calls for a break right now. We can do that or
  • 02:02:13we can power on through.
  • Clip 11.1 - Break
    02:02:16Okay. Okay. I heard an emphatic let's take a break.
  • 02:02:20So we will adjourn.
  • 02:02:25We will suspend the meeting for a five minutes,
  • 02:02:28and we need to let Chairman Glason do his thing
  • 02:02:32for the PUC. This meeting of the Public Utility Commission of Texas
  • 02:02:35will stand in recess. We will be back.
  • 02:02:39We'll have a hard start at 12:10.
  • Clip 9.3.1 - Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements - Vote - Chair
    02:06:30 Service requirements as recommended by ERCOT staff, the R&M
  • 02:06:34committee and as endorsed by TAC to be effective January 1,
  • 02:06:382025. Thank you for the motion, Bob.
  • 02:06:41Any. Who's a second? Okay,
  • 02:06:45Peggy, thank you. All in favor?
  • 02:06:48Aye. Any opposed? Any abstentions? Okay,
  • Clip 9.3.2 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs - Vote - Chair
    02:06:51that is approved. So next, the R&M committee considered NPRR1190,
  • 02:06:56as you recall from the board's August meeting there, and six opposing
  • 02:06:59votes TAC by consumers on NPRR1190.
  • 02:07:03And the board tabled the revision request to consider the quantitative data
  • 02:07:07in ERCOT comments since the August board meetings, ERCOT staff
  • 02:07:11filed additional comments on September 19,
  • 02:07:142024, which the R&M committee considered yesterday,
  • 02:07:17along with comments submitted by joint consumers on
  • 02:07:20October 2, 2024. Yesterday, the R&M
  • 02:07:24committee heard in person comments from the commission staff,
  • 02:07:27ERCOT staff and the corporate member from
  • 02:07:31Lyondell Chemical for different reasons. Both commission staff and
  • 02:07:35Lyondell Chemical indicated the current version of NPRR1190
  • 02:07:39is too broad and recommended the board remand NPRR1190
  • 02:07:42to TAC. NPRR1190 does not have urgent status
  • 02:07:46and ERCOT staff has commented the policy issues don't impact
  • 02:07:50reliability as such. The R&M committee yesterday recommended the board
  • 02:07:54remand NPRR1190 to TAC.
  • 02:07:57I move the board remand NPRR1190 to TAC as recommended
  • 02:08:01by the R&M committee. Motion to remand NPRR1190
  • 02:08:06back to TAC. Is there a second?
  • 02:08:082nd John seconded. All in favor?
  • 02:08:12Aye. Aye. Any opposed? Any abstentions?
  • 02:08:15NPRR1190 is back to TAC.
  • Clip 9.3.3 - Reliability and Markets R&M Committee Report - Discussion - R&M Chair
    02:08:20 The R&M committee yesterday also recommended the board approve price
  • 02:08:23corrections for two sets of events that met the protocols
  • 02:08:27criteria for correction. The first price correction was
  • 02:08:30also discussed during the technology committee meeting yesterday
  • 02:08:35and the price correction would essentially result in returning
  • 02:08:38money to generators who paid too much. I moved the board
  • 02:08:41as recommended by ERCOT staff and the R&M committee to one determine
  • 02:08:45that real time locational marginal prices, real time settlement
  • 02:08:48point prices, real time price for energy metered resources and
  • 02:08:52real time price for energy metered for settlement only generation
  • 02:08:56for operating day August 20, 2024 were
  • 02:09:00affected by the incorrect recall of VCR's and two
  • 02:09:04direct ERCOT staff to implement the appropriate price corrections.
  • 02:09:07Pursuant to Protocol section 6.3,
  • 02:09:12we have a motion for price corrections for operating day
  • 02:09:15August 20 20th, 2024. Is there a second?
  • 02:09:19Okay, thank you. Second all in favor? Aye. Aye.
  • 02:09:23Any opposed? Any abstentions? The price corrections
  • Clip 9.3.4 - Real-Time Market Price Corrections – Incorrect Resource Data Impacting the Real-Time Market - Vote - Chair
    02:09:27motion is approved. So ERCOT staff also has a corrective action
  • 02:09:31plan for the Price correction and Board agenda item 8.2.
  • 02:09:34I move the board as recommended by ERCOT staff, staff and the R&M committee to
  • 02:09:38one determine that real time locational marginal prices,
  • 02:09:41real time settlement point prices, real time price for
  • 02:09:45energy meter resources and real time price for
  • 02:09:49energy meter for settlement only generators for
  • 02:09:53operating days August 9 and 10th, 2024 were
  • 02:09:56affected by incorrect resource data and two, direct ERCOT staff to
  • 02:10:00implement the appropriate price corrections. Pursuant to protocol
  • 02:10:04section 6.3. We have a motion
  • 02:10:07for operating days price corrections for August 9 and
  • 02:10:1010th. Do we have a second?
  • 02:10:142nd okay Julie, thank you.
  • 02:10:16All in favor? Aye. Any opposed? Any abstentions?
  • 02:10:21Okay, for the record, all of the R&M committee motions
  • 02:10:25were unanimously approved and finally,
  • 02:10:28chair ancillary service demand curves were discussed by staff and
  • 02:10:32the independent market monitor. During the standing update on real
  • 02:10:36time co optimization plus batteries, ERCOT staff
  • 02:10:39reported they drafted and posted an ancillary service demand curve's
  • 02:10:43white paper TAC. And the IMM discussed their work to develop
  • 02:10:46ancillary services demand curves that would not delay implementation
  • 02:10:50of RTC. And with that, that concludes my report. Thank you,
  • 02:10:54Bob. We appreciate your report. Unfortunately, it's going to be your last one,
  • 02:10:58but we appreciate your service. Thank you. Next,
  • 02:11:01John Swainson will present agenda item 9.4, the technology and
  • 02:11:05security committee report. John, please proceed with your update.
  • Clip 9.4 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs - Vote - Chair
    02:11:09Thank you, Mister chairman. The committee met yesterday.
  • 02:11:13In general session, there were no voting items other than meeting
  • 02:11:16minutes. We had a presentation on emerging
  • 02:11:20technologies from Doctor Jim Fulham of the Northwest National Lab on
  • 02:11:24phasor measurement units, or pmus.
  • 02:11:27Pmus are used to sort of measure voltage
  • 02:11:30and phase shift in a grid.
  • 02:11:33We've been using them here in ERCOT for over a
  • 02:11:37decade, and they're capable of sending real time streaming information on
  • 02:11:41oscillations in, you know, 30 or 60
  • 02:11:44times a second. So, very fine grained data.
  • 02:11:48This gives ERCOT control room operators greater situational awareness to
  • 02:11:52react to grid instability, and can aid in identifying specific equipment
  • 02:11:56that's causing a problem. Fred Wang followed up with
  • 02:12:00a discussion of our current use of implementation of pmus and ways that
  • 02:12:04we can continue to grow and leverage the usage,
  • 02:12:07which, I would add, is becoming increasingly important, given the heterogeneous
  • 02:12:12nature of the generation in our grid.
  • 02:12:16One issue that's delaying implementation by some transmission operators
  • 02:12:21has been cost, which is borne by the operator
  • 02:12:25ratepayers and must be justified. At present,
  • 02:12:29the transmission of data from pmus to ERCOT is voluntary,
  • 02:12:33and many transmission operators do, in fact, give us access
  • 02:12:37to their data, but not all. And so we're discussing ways to
  • 02:12:40incentivize broader development or broader deployment,
  • 02:12:44whether voluntarily or through a planning guide. Change staff
  • 02:12:49also presented a number of committee briefs,
  • 02:12:52including our normal update on projects.
  • 02:12:55There are 60 odd projects currently under development,
  • 02:12:58and I would say they are all running with the normal
  • 02:13:02ups and downs, but generally on schedule. We did,
  • 02:13:06as we usually do, a deeper dive on real time co optimization.
  • 02:13:10And as you've heard already, we've now set dates for implementation
  • 02:13:14of that. And we got into a little bit of detail on what are the
  • 02:13:17necessary preconditions to ensure that the implementation happens
  • 02:13:21as scheduled for December 5, 2025.
  • 02:13:25And then our last topic in the general session was future agenda items.
  • 02:13:29And we're looking at having a presentation on the
  • 02:13:33development of small modular nuclear reactors in Texas,
  • 02:13:37and there's interest in doing that.
  • 02:13:40So we're going to see if we can schedule that for the December meeting.
  • 02:13:43That's my report. Thank you. Okay. Thank you, John. Any questions for John
  • 02:13:47on this report? Okay, the next item is Gen item ten,
  • 02:13:50the annual membership meeting announcement. I believe. Chad,
  • 02:13:54you're presenting this?
  • Clip 10 - Annual Membership Meeting Announcement - Discussion - Chair / Chad V. Seely
    02:13:57Yes. All right. It's getting to be that time of the year
  • 02:14:01as we head toward December that we'll have our annual
  • 02:14:05membership meeting. And consistent with last year,
  • 02:14:08we're going to do it at the downtown Marriott.
  • 02:14:12We got a lot of feedback. Last year seemed to be a good space
  • 02:14:16for everyone to have the annual meeting. We'll incorporate
  • 02:14:20some of the feedback we received from the board into the corporate members into
  • 02:14:24the agenda. But we're expecting obviously to have
  • 02:14:28engagement opportunities for the members and the board and ERCOT staff and invited
  • 02:14:32guests before we kick off the meeting. This is
  • 02:14:35obviously a requirement on the next slide. We're required to do this on
  • 02:14:39the Texas business organization code and the ERCOT bylaws require an annual
  • 02:14:43meeting. So we must hold an annual meeting. And coinciding
  • 02:14:46with our board cycle. So it'll be on Monday, December, December 2.
  • 02:14:50On the next slide, you'll just see kind of a draft agenda.
  • 02:14:54Again. We're going to open up the doors early for kind of
  • 02:14:58pre meeting social engagement and then we'll get
  • 02:15:01started with our annual meeting agenda. For this year for corporate members,
  • 02:15:05we have Colin Martin, who is senior director of transmission
  • 02:15:09grid operations at Oncor, who's also the TAC vice chair.
  • 02:15:13That'll be the corporate member doing speaking engagement. And then
  • 02:15:16we'll have two guests speakers that we're finalizing as well. And then we'll obviously
  • 02:15:20get through our membership meeting requirements.
  • 02:15:23And then there'll be an opportunity for post meeting social reception as well.
  • 02:15:27So as we move forward on the last slide,
  • 02:15:31corporate members will receive an invitation on November
  • 02:15:3511. And right now we're going allow the opportunity for
  • 02:15:39an invited guest. Depending on kind of what
  • 02:15:43the capacity looks like, we may be able to extend that additionally beyond just
  • 02:15:47one invited guest, but we'll manage that as we start to see acceptance
  • 02:15:51invitations coming in after November 11. So look forward to
  • 02:15:55that in December. Thank you, Chad. Any questions
  • 02:15:58about the annual member meeting? Okay, let's move to
  • 02:16:01agenda item eleven. This is the last time before
  • Clip 11 - Other Business - Discussion - Chair
    02:16:05we move into executive session. Is there any other business that any
  • 02:16:08other board member wishes to raise?
  • 02:16:11Okay, I don't hear any at this time. The board is going to
  • 02:16:15adjourn general session and we will reconvene in executive
  • 02:16:18session. There are two voting items that we anticipate
  • 02:16:22that will come out of executive session. So the general session will reconvene at
  • 02:16:25the conclusion of the executive session. Chair Gleason,
  • 02:16:29this meeting of the Public Utility Commission of Texas will stand in
  • 02:16:32recess. The general session is now recessed, and I. Webcast will be
  • 02:16:36concluded.
  • 02:16:56Carlos, she's still on.
  • 02:16:59Don't leave. Carlos. Yes. Yes, I'm here. Okay, we got
  • 02:17:02two things to vote on, and then we'll leave you to
  • 02:17:05recuperate. Okay, thanks.
  • 02:17:24Good afternoon. This is Bill Flores ERCOT
  • 02:17:27board chair of. The general session of. This meeting is now reconvened. We have
  • 02:17:31two voting items from executive session. I'll have an announcement at
  • Clip 12 - Vote on Matters from Executive Session - Vote - Chair
    02:17:34the end of those votes. First, I'll entertain a motion to approve the contract matter
  • 02:17:39discussed during executive session under agenda item es
  • 02:17:42two, 1.1. So moved. Okay, thank you,
  • 02:17:45Bob. 2nd. 2nd from Peggy. All in
  • 02:17:49favor? Aye. Any opposed?
  • 02:17:52Any abstentions? Okay, that motion is approved.
  • 02:17:56Second, I'll entertain a motion to approve the contract matter discussed
  • 02:17:59during executive session under item es two,
  • 02:18:021.2. Submit. Thank you, Peggy.
  • 02:18:06Second. And a second for Bob. Thank you. All in
  • 02:18:09favor? Aye. Any opposed? Any abstentions?
  • 02:18:13Okay, that agenda item is approved. And then
  • 02:18:17lastly, but not least, I am pleased to announce that Julie England
  • 02:18:21will be our new R&M chair. Move forward.
  • 02:18:24Congrats, Julie. We look forward to your leadership on that committee.
  • Clip 13 - AdjouR&Ment - Chair
    02:18:28And with that, this meeting is now adjourned.
  • 02:18:52It.
0 October 10, 2024 Board General Session Agenda
Oct 02, 2024 - pdf - 132.7 KB
2 Notice of Public Comment, if Any
Oct 02, 2024 - pdf - 99.5 KB
3.1 Unopposed Revision Requests Recommended by TAC for Approvals
Oct 02, 2024 - zip - 2.1 MB
4 August 20, 2024 Board General Session Meeting Minutes
Oct 02, 2024 - pdf - 218.5 KB
5 CEO Update REVISED
Oct 07, 2024 - pdf - 976.5 KB
5 CEO Update
Oct 02, 2024 - pdf - 386.7 KB
6 Update on CPS Energy Reliability Must-Run (RMR) and Must-Run Alternative (MRA) Process
Oct 07, 2024 - pdf - 925.8 KB
7 Summer 2024 Operational and Market Review
Oct 02, 2024 - pdf - 2.4 MB
8 TAC Report
Oct 02, 2024 - pdf - 150.6 KB
9.2.1 Ratification of Officer
Oct 02, 2024 - pdf - 149.5 KB
9.2.2 Appointment of Non-Independent Manager and Officer of Texas Electric Market Stabilization Funding M LLC (TEMSFM)
Oct 02, 2024 - pdf - 159.8 KB
9.2.3 Appointment of Non-Independent Manager and Officer of Texas Electric Market Stabilization Funding N LLC (TEMSFN)
Oct 02, 2024 - pdf - 159.1 KB
9.3.1 Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements
Oct 02, 2024 - pdf - 613.8 KB
9.3.2 NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs
Oct 02, 2024 - zip - 516.2 KB
9.3.3 Real-Time Market Price Correction – Incorrect Recall of ERCOT Contingency Reserve Service
Oct 02, 2024 - pdf - 139 KB
9.3.3 Real-Time Market Price Correction – Incorrect Recall of ERCOT Contingency Reserve Service - Attachments
Oct 02, 2024 - zip - 133.4 KB
9.3.4 Real-Time Market Price Correction – Incorrect Resource Data Impacting the Real-Time Market
Oct 02, 2024 - pdf - 166.6 KB
9.3.4 Real-Time Market Price Correction – Incorrect Resource Data Impacting the Real-Time Market - Attachments
Oct 02, 2024 - zip - 3.4 MB
10 Annual Membership Meeting Announcement
Oct 02, 2024 - pdf - 373.8 KB
1 - Call General Session to Order - Chair
Starts at 00:01:41
2 - Notice of Public Comment, if Any - Discussion - Chair
Starts at 00:05:11
3 - Consent Agenda - Vote - Chair
Starts at 00:05:49
3.1 - Unopposed Revision Requests Recommended by TAC for Approval - Vote
Starts at 00:05:56
3.1.7 - NPRR1244, Related to NOGRR263, Clarification of Controllable Load Resource Primary Frequency Response Responsibilities - Vote
Starts at 00:06:03
3.1.1 - NPRR1188, Implement Nodal Dispatch and Energy Settlement for Controllable Load Resources - Vote
Starts at 00:06:12
4 - NPRR1188, August 20, 2024 General Session Meeting Minutes Vote - Chair
Starts at 00:07:10
5 - CEO Update - Discussion - Pablo Vegas
Starts at 00:07:49
6 - Update on CPS Energy Reliability Must-Run RMR and Must-Run Alternative MRA Process - Discussion - Pablo Vegas / Woody Rickerson / Chad V. Seely
Starts at 00:34:46
7 - Summer 2024 Operational and Market Review - Discussion - Dan Woodfin / Keith Collins
Starts at 01:08:00
8 - TAC Report - Discussion - TAC Chair
Starts at 01:40:52
11.1 - Break
Starts at 02:02:16
9.3.1 - Recommendation regarding 2025 ERCOT Methodologies for Determining Minimum Ancillary Service Requirements - Vote - Chair
Starts at 02:06:30
9.3.2 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs - Vote - Chair
Starts at 02:06:51
9.3.3 - Reliability and Markets R&M Committee Report - Discussion - R&M Chair
Starts at 02:08:20
9.3.4 - Real-Time Market Price Corrections – Incorrect Resource Data Impacting the Real-Time Market - Vote - Chair
Starts at 02:09:27
9.4 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs - Vote - Chair
Starts at 02:11:09
10 - Annual Membership Meeting Announcement - Discussion - Chair / Chad V. Seely
Starts at 02:13:57
11 - Other Business - Discussion - Chair
Starts at 02:16:05
12 - Vote on Matters from Executive Session - Vote - Chair
Starts at 02:17:34
13 - AdjouR&Ment - Chair
Starts at 02:18:28

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