[0:01] Uh, good morning, ercot, board of directors and guests. I'm bill flores and I hereby

[0:05] reconvene and call to order the december 8th and ninth 2025 meeting of the board.

[0:10] this meeting is being webcast live to the public on kots website. I would like to

[0:14] provide puc chair thomas gleason, the opportunity to reconvene the open meeting of

[0:18] the public utility commission of texas. Thank you, mr. Chairman. This meeting, the public

[0:22] utility commission of texas will come to order to consider matters have been duly posted with the

[0:26] secretary of state for today, december 9th, 2025.

[0:31] uh, thank you chair gleason. The antitrust admonition and security map

[0:35] were included with the posted meeting materials. Uh,

[0:39] and we, uh, are now open for comments. Chad, has anyone expressed an interest in, uh,

[0:43] commenting to the board today? No one has expressed an interest chairman. Okay. Thank

[0:47] you, chad. Uh, our first agenda item is, uh, ercot,

[0:51] ceo. Pablo vegas is going to make his presentation with the ceo

[0:55] report, pablo.

[1:07] all right. Thank you, chair flores, and thank you everybody for your

[1:11] participation today and your interest in the important work that we are doing at

[1:16] ercot. In this morning's update, I'm excited to share

[1:20] erco t's new vision and mission and values.

[1:24] the, as the grid has evolved, our strategies have evolved along with it,

[1:28] and we're aligning our core vision and our mission to the needs of the market. And

[1:32] we've established a set of values that we believe reflect how our employees

[1:36] want to work and experience their careers at ercot. I'm gonna touch base on

[1:41] some of the changes in our supply mix since last winter. I have

[1:45] an update on our mobile generation solution that we've been talking about in san antonio,

[1:49] as well as the related reliability must run con, uh, contract with the bro three

[1:53] unit. I'm gonna discuss some of the progress being made on the provisions in

[1:58] senate bill six and the roadmap ahead of us as it relates to our op operations

[2:02] and markets and planning work. And then I'm gonna close, like I always do, with some thanks

[2:06] and appreciation for some of the incredible accomplishments that have been,

[2:10] uh, delivered since our last time together as a board.

[2:21] here we go. A year ago,

[2:25] we defined the concept of ercot 4.0 and

[2:29] what it represents in relation to earlier periods of ercot

[2:33] operations. And at a high level, it represents

[2:38] a transition in our market that is characterized by high and very rapid

[2:42] growth of intermittent and short supply, uh,

[2:46] short duration supply resources. It's characterized by a rapidly

[2:50] changing customer base that includes price responsive loads like crypto

[2:55] miners, rapidly growing large scale data centers, and

[2:59] continued penetration of distributed energy resources throughout the grid

[3:03] from people's homes to their businesses and locations across the distribution system.

[3:09] it's a significant shift in operational requirements, and it represents an opportunity

[3:13] to create a more resilient and cost-effective grid for the benefit of

[3:17] all texans. This shift created an opportunity to

[3:22] re-look at our vision and our mission, and to make sure it was aligned by the success opportunities

[3:26] that ercot 4.0 presents. And that success depends on keeping

[3:31] reliability as the bedrock of our organization.

[3:35] reliability in today's definition of reliability, which includes

[3:39] a society that depends fully on the availability of

[3:43] electricity for nearly every facet of modern life. And to do so, we're going

[3:47] to have to embrace innovation as one of our core success factors to keep up with

[3:51] the pace of change. Our new vision is to be the

[3:55] most reliable and innovative grid in the world,

[3:59] not just in texas, not just in the united states, but in the world.

[4:05] we are one, if not the leading grid globally when it comes to operational

[4:09] and technical complexities. And to be successful, we

[4:14] need to be a clear leader on a stage that represents the entirety of this planet,

[4:20] the impact of what texas represents to the global economy today.

[4:24] and if you look at it just on energy, we produce more than 40% of this

[4:29] country's oil. 30% of this country's natural gas

[4:33] have a total refining capability of about 30% of what the

[4:37] united states uses. That's just an impact inside of texas

[4:42] and the united states. But to be important in the future, to be successful, we're

[4:46] gonna have to be a global leader on that stage. Our mission

[4:50] is what we do every day to achieve this vision,

[4:54] we will ensure a reliable grid with competitive and cost

[4:58] effective electricity markets. That is our mission. It is the

[5:02] re again, reliability at the core of it, and we recognize the critical importance

[5:07] of a cost-effective grid when it comes to a thriving economy.

[5:16] and then our values that we developed, we did that directly with input

[5:20] from many, many ercot employees. We held focus groups and gathered surveys

[5:24] from hundreds of our employees who spoke to what it should feel like to work and

[5:28] to be a part of this organization, and what a set of core values that

[5:32] will create an environment that will foster both individual and organizational successes.

[5:37] I'm not gonna review each one of the values that are on this slide, but you can see that each

[5:41] one of them builds upon and supports each other to create an environment where we

[5:46] can achieve our vision and achieve success in our daily mission.

[5:54] so changes that we've seen in the grid since last winter, 2025

[5:58] a year, 2025, is gonna represent a year with tremendous supply growth

[6:02] on the ercot grid. We expect to see nearly 16 gigawatts

[6:06] of new supply connected onto this grid in 2025, just

[6:11] since the end of last winter. This is a chart showing from march 1st through

[6:15] november 1st. This year, we'll have connected approximately 11 gigawatts

[6:19] of new capacity. You can see the large majority of it continues to be in

[6:23] the two resource types we've been seeing over the last several years. Storage. We're

[6:28] now representing storage as with both the capacity, uh, peak

[6:32] capacity number, as well as its energy capacity, because since storage is duration

[6:36] limited, the energy measure is a more appropriate measure of its capacity.

[6:41] and while we are still seeing low numbers in our natural gas connections into the grid,

[6:46] we are seeing significant improvements in the natural gas pipeline expressing

[6:50] potential interest in connecting into the ercot grid.

[6:57] I think it's helpful to show this comparative, I've done this in the past as well as

[7:01] we get into the winter season, understanding the impact of supply additions

[7:05] in both the winter and summer peak conditions. And you can see from this

[7:10] integrated slide, there are very significant differences in the low carrying capabilities

[7:14] between these different resources at peak based on their production type.

[7:19] I share this to try to help explain some of the differences why during this past

[7:23] summer, during the peaks, we haven't really been experiencing scarcity grid conditions

[7:27] because the significant additions of solar and battery storage

[7:32] are optimally positioned to help during those summer peaks in

[7:36] the afternoons and early evenings. As the sun is transitioning out, winter

[7:40] still represents the higher risk period in the ercot market because fewer

[7:44] of these resources that are being added are available during the winter peak

[7:48] periods, which tend to be in the mornings before the sun rises, or in the

[7:53] early evenings right after it sets.

[7:59] I think it's important to highlight some of the progress that has been made on the weatherization program

[8:04] through our first four years, and this is a focus on our winter weatherization.

[8:09] since the inception of this program in in, uh, december of 2021,

[8:13] we have completed over 4,000 winterization inspections of both generation

[8:18] and transmission facilities. We inspect them for various preparation

[8:22] measures that are intended to reasonably ensure sustained operation at weather

[8:26] zone specific cold and hot conditions.

[8:30] we held a winter weatherization workshop, uh, in october on the 16th

[8:34] this year, we had over 200 people attend that workshop and

[8:38] it highlighted best practices presentations from three of our market participants from

[8:43] lcra, from cps energy and from an l

[8:47] the winter 2025 and 2026 inspection period. Started a week ago

[8:51] today on tuesday, and we plan to have a minimum

[8:55] of 450 inspections over the course of this winter.

[8:59] I included this, uh, graph on the right side, the winter cure periods

[9:04] because I think it's important that not only are we going out inspecting, but this shows

[9:08] how we have been seen progress on the performance of those inspections

[9:12] over the course of time. And so the cure period is

[9:16] a measurement that's found when we have found instances of non-compliance with the weatherization

[9:21] rule. And then the dealing with those, uh, we give them a cure period in

[9:25] order to deal with those findings of non-compliance. And you can see from beginning in the winter of

[9:29] 2022 to 2023, the instances that we had

[9:33] a total of, uh, 75, 55 of those were at, uh, transmission

[9:37] service. And, uh, 20 of those at, uh, supply resources. And those have decreased

[9:42] over time to a total of only five over the last winter. And

[9:46] we've had similar, similar benefits and performance, um, as well

[9:50] in the summer periods. Our cure periods have gone from about 15 in 2023

[9:54] down to three this past summer. So significant pro improvements

[9:58] in performance and findings of non-compliance. Over the course of

[10:02] the three years we've been run running the weatherization program the three, four years,

[10:11] I wanted to give a brief update on the lifecycle power mobile generation

[10:15] units that, uh, are, have been brought over into the san antonio area to help with

[10:20] that south texas, uh, transmission constraint as of october 22nd.

[10:24] all of those mobile generating units had had been able to initially

[10:29] synchronize with the ercot grid, and as of this week, all 15

[10:33] of them have been successfully tested and are available for dispatch under emergency

[10:37] conditions. And as a reminder, the contract for these mobile generation

[10:41] units runs through march of 2027, and we have the right

[10:46] to terminate that earlier if the reliability need no longer exists going forward.

[10:52] related to that, an update on the reliability must run agreement that we have in

[10:56] place with cps energy, uh, on the rig three unit, the outage,

[11:01] it began last march, if you recall, after the approval by the board last december

[11:05] a year ago, uh, from now and to date, the biggest and

[11:09] most significant issue in that outage period was a replacement of that number nine boiler

[11:13] super header, uh, super heater header. The work was completed

[11:18] for that replacement in october, uh, end of october this year. Testing

[11:22] completed most recently in november, we had a issue

[11:26] identified by cps that there were some impurities in the turbine bearing lubrication oil,

[11:31] and some additional work was gonna need to be done to, uh, refurbish those installed

[11:35] bearings that could cost an additional 1.8 million, potentially

[11:39] add about a 10 day delay to the schedule. So as of today,

[11:43] it's currently scheduled to return to service on december 15th. There is a little bit of

[11:47] risk to that schedule based on the refurbishment work that needs to occur.

[11:55] so shifting gears into the, um, regulatory and policy arena,

[11:59] we've talked about senate bill six and its broad impacts several times in, uh, in these

[12:03] board discussions. It's driving four significant new rulemakings. One

[12:07] is focused on the load forecast standardization for large loads,

[12:11] very significant part of the provision, which is intended to give us better clarity

[12:16] and better accuracy on the numbers that we expect in that load forecast, which as I discussed

[12:20] in my, in my last update a couple months ago, is really the foundation for all

[12:24] of the planning and all of the reliability reporting that we do. We

[12:28] have another rule making on large load, uh, interconnection standards,

[12:33] a third one on cost allocation for transmission infrastructure, and then

[12:37] a fourth on the net metering rules, which is addressed in this slide. We've established

[12:41] an interim net metering review process that aligns with what the proposed rule is

[12:45] that's gonna be going through. We already have seen two net metering arrangements

[12:50] formally submitted for our review at this time. And we're gonna need,

[12:54] our requirements are we have to go through and complete our analysis within 120

[12:58] days of noti notifying the puc that we've received all of the completed

[13:03] information for these net metering arrangements, and we're coordinating very closely with

[13:07] staff on those puc staff on those. We expect all of these

[13:11] rulemakings to under to go through the process in 2026

[13:15] with the net metering and the forecast standardization proceeding first,

[13:20] and then followed by the other two, uh, rulemakings.

[13:27] I had like to give a little bit of a look ahead as to what's still on the agenda

[13:31] and, uh, important work coming up. So from a current operations,

[13:35] I'll, I'll really highlight the noer 2 45. If you recall. This is the operating

[13:39] guide change that is related to the requirements for ride through requirements

[13:44] on inverter based resources through, we probably will be looking at

[13:48] reviewing the submissions that we've received in for extensions

[13:52] and for exemptions for, for compliance with that rule through

[13:56] the second quarter of 2026. And then the actual reliability assessments

[14:01] that we then run following, having all of that data in will

[14:05] proceed in the second half of 2026 with decisions on what can be exempted, what

[14:09] can be extended in terms of timing and compliance. For the noga 2 45 rule,

[14:14] there's quite a lot on the market design plate, the drrs,

[14:18] dispatchable reliability reserve service, we talked about the two npr r related

[14:22] to that yesterday. We've got the residential demand response program,

[14:26] uh, that we also discussed in yesterday's update. We have a new large

[14:31] load demand response program that is coming out of, uh, senate bill six. And

[14:35] so we'll be working on the development of that. And then, of course, from the prior

[14:39] legislative session affirming requirement, that is a significant

[14:43] piece of market design, uh, protocol work we're gonna be doing in 2026,

[14:47] and that needs to be completed by the end of this, uh, next year.

[14:52] and then at this time of year, from a planning perspective, we publish a lot of end of year

[14:56] reports. We publish the capacity, demand and reserve reports. That looks out five years

[15:01] gives a kind of a projection if certain amounts of resources

[15:05] are built and certain amount of load and materializes based on well-established

[15:10] criteria that we've used for many years. Then what does the reserves look like under those conditions?

[15:15] we've got the 2025 regional transmission plan that's gonna come out. This,

[15:19] uh, this month we publish a constraints and needs report. This is a

[15:23] focus on transmission constraints. We've also have the reliability

[15:27] standards analysis that's gonna be taking place in 2026. This will be the first formal

[15:32] evaluation of the new reliability standard that was established for

[15:36] ercot in 2024. We'll be doing that full scale analysis in 2026.

[15:42] all of these reports are going to indicate similar messaging, but

[15:46] in the very short term, the additions of supply have been helpful in

[15:50] improving the reliability characteristics of the grid. In the long term, there's

[15:54] increasing risk if the load materializes and infrastructure development doesn't keep

[15:58] up. The messaging and the, the, the risks that are

[16:03] identified are consistent with reports we've seen over the last year, and depending on

[16:07] the amount of load that comes and the pace at which it comes really is the key drivers

[16:11] to the degree that that risk may or may not be materialized.

[16:19] we hosted, um, a grid x event here at, um,

[16:24] uh, the, actually the met center here just a couple weeks ago.

[16:28] nerc does this every year or every other year. They do a large scale grid x exercise,

[16:32] which is intended to practice a response to both cyber and physical attacks

[16:36] on the electric grid. This year, we participated in, in three different ways.

[16:41] one, we had our it and our cyber teams compete in a hands-on technical

[16:45] exercise to identify and stop cyber attacks. Specifically. That was done

[16:49] a little bit earlier this year. The overall ercot leadership team,

[16:53] in addition to participation with the public utility commission, the texas department of emergency

[16:58] management, the fbi and other state agencies

[17:02] all gathered together, and we did a tabletop exercise that was focused on

[17:06] decision making, coordination and communication during a very complex

[17:11] cyber physical attack scenario. That was a couple weeks ago. And

[17:15] then our ercot operations team used their training simulator to emulate

[17:19] and respond to grid x attacks according to their regular training cycles.

[17:24] so, very active engagement in business continuity and disaster recovery

[17:28] preparations. These tabletops are extremely helpful in aligning roles

[17:32] and accountabilities during a crisis event, and making sure that our communication capabilities

[17:37] are both agile and ready for the challenges of the moment.

[17:44] I'd like to remind everybody coming into the winter season through of the various communication channels that

[17:48] are available at ercot to get information. Our website, you can

[17:52] see that on the top right of this slide, we have about a dozen different dashboards that help to inform

[17:56] what's happening on the grid in real time. We also have our texas

[18:00] advanced notification system. Texans, you can sign up to get email updates if there

[18:04] are changes to grid conditions that require any kind of awareness or response

[18:08] by the general public. And we also are on social media. You can follow us

[18:12] on linkedin, on x, on facebook, and on instagram.

[18:16] so lots of different channels and avenues to get real time updates, as well as to get

[18:21] informational and educational updates on what it is that our is focused on, on the priorities

[18:25] of the organization.

[18:30] and then I'd like to finish with, uh, some employee recognitions. So

[18:34] we've had three things that I wanna recognize. The first, and we talked about this yesterday, and I think matt

[18:38] marinas did a fantastic job of acknowledging the breadth, the complexity

[18:43] of this implementation and go live. And I wanna, again, reiterate now

[18:47] on behalf of everybody within our organization, our thanks to the

[18:51] broad market, to the public utility commission, to the agencies that

[18:56] we work with, and a deep thanks to all of the employees inside of our organization

[19:00] for the work that went into the realtime ization plus battery implementation.

[19:05] this is the most significant change to our real-time market

[19:09] since we converted from a zonal market to a nodal market back in 2010.

[19:14] very significant complex change, intense coordination required across

[19:19] the entire market participant list, and it went extremely

[19:23] well. So a huge thanks to everybody involved in that.

[19:30] I also want to call out those that helped to lead the core values work

[19:34] at ercot. It took weeks and weeks of work to do the surveys

[19:39] and to host the listening sessions and to gather the input and to synthesize

[19:43] and to adjust it and continue to iterate on it to get to those final values

[19:47] that we developed. And so a big thanks to the team that led that. And then similarly,

[19:52] we had an internal team that really helped to lead a successful employee summit for ercot.

[19:56] we do a once a year all employees gathering. We did it on october 14th this

[20:00] year. We had over 600 ercot employees participate, where we got together

[20:04] to talk about our core strategies, talk about why our vision and

[20:08] our mission and our values needed to change, and the opportunities and the

[20:13] challenges that laid ahead of us. So an excellent production and very well done and think

[20:17] a very high value use of time. So with that, I'll pause

[20:21] chair flores, if there's any questions from, uh, the board or from anyone else, I welcome

[20:26] the feedback or questions public. Can we ask those, uh, ercot team members to stand

[20:30] up that you just recognized the, for all three of these,

[20:34] uh, categories, correct? Yeah, if, uh, any of you are named on

[20:38] any of these three categories, if you're in the room, please, please stand up. I already, I know there's

[20:42] many of you in here, so please stand. There'll be some somewhere for record. Don't

[20:46] be shy. I was gonna give them applause, but there's nobody to applause. Well,

[20:50] , I think we've got some

[20:55] high people. Great work. Any questions for pablo?

[20:59] well, great report and, uh, keep up the great work. We look forward to, uh, the excitement

[21:04] that we have in 2026. Thank you. With that, we're

[21:08] gonna move into committee reports and we'll start with peggy higg, who serve as the chair

[21:12] of the human resources and governance committee. Uh, she will present agenda

[21:16] item 12.1, which is, uh, the committee's report. It has two associated

[21:21] voting items. Peggy, thank

[21:25] you, chair forez. The human resources and governance committee had a robust

[21:29] agenda yesterday with, uh, ms. Billman to two voting items coming outta general

[21:34] session and two voting items in executive session. The first

[21:38] item, which is voting item, was, uh, a, a discussion with pablo

[21:42] about the, uh, recommendation regarding the ercot vision, mission,

[21:46] and core values that he just referenced. And there's a, there's a, a memo

[21:51] in the, uh, materials, uh, for the board. This is

[21:55] the second time that the human resources and governance committee heard from pablo on this. And

[22:00] I think we were all very impressed with the process and the thoughtfulness

[22:04] that went into the creation of the new vision and mission

[22:08] core values. Uh, second, we reviewed

[22:13] the ercot government documents, and there are, were no suggested

[22:17] changes at this time. Third, we, uh, reviewed

[22:21] the periodicity of the, uh, ercot board meetings with

[22:25] the comparison to other isos. There'll be no changes proposed

[22:29] to the ercot periodicity at this time. And this review will be filed

[22:33] with the commission as required by the regulations.

[22:38] uh, the fourth item, which is a voting item, is that the committee voted

[22:43] to, uh, recommended that the board approve the 2027 board

[22:47] meeting schedule and annual meeting of the members. Uh,

[22:52] the, uh, proposed meeting dates are february 8th and ninth, april 12th,

[22:57] 13th, june 21 in 22, september, 2020,

[23:02] 2021, december 6th and seventh with the annual meeting,

[23:06] uh, on december 6th, 2027.

[23:11] fifth, we looked at the, uh, annual review of the board committee

[23:16] membership. We had just, uh, gotten our new compliment

[23:20] of board members, which we're very excited about, and we had reviewed that

[23:24] at the last board meeting. So no changes are recommended at this time,

[23:28] but the committee will continue to review a committee membership as needed.

[23:33] we also looked at the, uh, annual committee

[23:37] self-evaluation surveys, results of the human resources

[23:42] and governance committee, the technology security committee,

[23:46] and the finance and audit committee. And, uh, some materials were

[23:50] filed in, in the board book, but the committees are all

[23:54] functioning well. We also heard from gilbert hughes

[23:58] and mark minor presented their annual communications overview.

[24:05] and we heard from morris back on the, uh, human resources

[24:09] report for 2025, as well as initiatives in 2026.

[24:15] with that, we've got two voting items coming out of the general session, and,

[24:19] uh, if, if it's okay with you chair, I'll

[24:23] go ahead and make those motions. I move that the board accept the

[24:28] ercot vision, mission, and core values is recommended by the human resources

[24:32] and governance committee. Is there a second? Okay, chris, thank you.

[24:36] all in favor? Aye. Aye. Any opposed? Any abstentions?

[24:40] okay. The new mission, vision, and core values are approved.

[24:45] the second motion is I move that the board accept the 2027 ercot board

[24:49] meeting schedules in 2027, annual meeting of the members as

[24:54] recommended by the human resources and governance committee. Is there a second?

[24:58] okay, kathleen, thank you. All in favor? Aye. Aye. Any

[25:02] opposed? Any abstentions? Okay. The meetings are set for next year or for 2027.

[25:08] uh, next. Thank you. Thank you. Any more to your report? No, that concludes it. Okay. Thank you.

[25:13] uh, now we're gonna transition to the finance and audit committee report where I temporarily

[25:17] served as chair. Uh, we have one associated voting item.

[25:21] uh, let me walk through the report first, then we'll have the voting item.

[25:26] uh, the committee went through its normal reports, uh, debt compliance

[25:30] investments, and went through the, uh, projected outlook for the

[25:34] full year 2025 financial performance of the organization.

[25:38] all the performances were nominal and as were expected. Uh,

[25:43] now in terms of, uh, we also, the committee also reviewed the, uh, soc

[25:47] audit report. And it had a standard, uh, this is

[25:51] a standard annual requirement. Uh, the, uh, organization

[25:55] received an unmodified or clean opinion. The independent auditor also

[26:00] provided information about the enhancement to the control environment as the, uh,

[26:04] treasury management system has continued to be automated over the last couple of years.

[26:09] and so, on behalf of the finance and audit committee, I move that the board accept the 2025

[26:13] organization system, organization and control audit report is presented yesterday

[26:17] by weaver. Do I have a second? Second. Thank you, chris. All in favor?

[26:22] a aye. Any opposed? That motion is carried.

[26:26] uh, there is no other, uh, reporting. Uh, that concludes by

[26:30] report for the finance and audit committee. We'll now transition to john

[26:34] swenson, who will present a agenda. Item 12.3, the technology and security committee

[26:38] report. John? Thank you mr. Chair. Um, technology and

[26:43] security committee met yesterday morning in both regular and executive

[26:47] session. In regular session, we had a guest speaker,

[26:51] dr. Lee shay, who's a harvard professor and member of the board of

[26:55] pjm, who presented a roadmap for integrating a agentic

[26:59] ai into power systems. A very interesting discussion and continues,

[27:03] uh, with our ongoing ai theme. Um, agen ai enables

[27:08] large language models to interact with real world workflows, offering human

[27:12] ai collaboration rather than replacement. It can streamline things like

[27:17] interconnect studies, optimizing dispatch enhancing reliability through tools

[27:21] like reinforcement learning and probabilistic scenario planning. Um,

[27:26] ercot is well positioned to lead in the space and use this technology

[27:31] with opportunities to reduce engineering overhead and accelerate the grid transformation,

[27:35] uh, with an emphasis on secure ethical human in the loop ai

[27:39] uh, development. Following his presentation,

[27:44] uh, we went into our annual committee self valuation.

[27:48] and as you've heard there, that was all fine. We had a good discussion. Uh, would mention

[27:52] that ai is something that we are explicitly incorporating into

[27:56] our charter so that we will pay more attention to that in the future.

[28:00] and we'll be working with jp and his team on prioritizing

[28:05] some of the ai investments for the company. Um,

[28:09] we had a brief technical overview of rtc uh, plus

[28:14] b mainly because we, we heard from matt and others in the full board.

[28:18] um, and we talked about some of the lessons learned and, and some of

[28:22] the problems that we discovered along the way, which as, as, uh,

[28:26] jp has told us we're, we're gonna be in another six months of sort of bedding

[28:31] down that technology and getting it stabilized. So we'll be, uh, we'll

[28:35] be continuing to follow that up. Um, but, uh, it, it has obviously

[28:39] gone extremely well. Um, we had our usual overview

[28:43] of the 18 grid transformation initiatives, uh, was a request from the

[28:47] board that, uh, there'll be a little more prioritization on the things that

[28:52] are really, really important and more imminent versus the things that are still

[28:56] in the planning stages. Um, and then we, as we

[29:00] always do, we talked about future agenda items and you know, what

[29:04] topics that we wanted to bring back in front of the, the committee, including things

[29:08] perhaps related to battery and also nuclear. Um,

[29:13] and uh, as I mentioned, we wanted to make sure we prioritize the,

[29:17] uh, initiatives of the technology team. That concludes my report. Okay.

[29:21] thank you john. And, uh, you made a comment about the committee's self valuation. So I need to amend

[29:25] the f and a committee report that the f and a committee did, uh, review

[29:30] the committee's self-evaluations and found that the committee was operating effectively

[29:34] and appropriate with this charter. Uh, with that we'll move to agenda item

[29:38] 13.1. Well, let me, before I go anywhere, were there any questions from board members on

[29:42] any of the committee reports? Okay, thank you.

[29:47] uh, we'll move to agenda item 13.1, which is an adjunct membership approval of

[29:51] agen infrastructure llc membership for membership

[29:55] year 2026. Samuel branton with infrastructure

[30:00] llc is with us via webex. If the board has any questions for agtech,

[30:04] uh, chad sealey will present this item. Chad. Alright, thank you chairman.

[30:09] up on the screen as a short decision template that explains the

[30:13] background and rationale for agtech infrastructure.

[30:17] being an adjunct member for 2026, uh, consistent

[30:21] with the bylaws, adjunct membership requires board approval. Adjunct

[30:25] membership does not have any other voting rights except for

[30:29] participating at the protocol revision subcommittee in which they can vote. Uh, gentech

[30:34] infrastructure is going to align itself with the independent generator segment

[30:38] for 2026. And so we need board approval to approve their application.

[30:44] does anyone wish to make a motion in this regard? So moved. Thank you bill.

[30:48] second. So from chris, thank you. All in favor? Aye.

[30:53] aye. Any opposed? Any abstentions? Okay. Gentech membership is

[30:57] approved for 2026. Next is agenda item 13.2,

[31:02] which is a non opt-in entity load. Jo load zone change.

[31:06] uh, this is a request of lamar electric cooperative, uh, brian story,

[31:11] the ceo with lamar electric co cooperative along with ramsey crisp

[31:15] of se energy, which is part of snyder engineering. Are with us

[31:19] in person today. If the board has any questions for lamar electric cooperative, kim

[31:23] rainwater present this item. Kim?

[31:29] nope. Okay. Good morning. Uh, kim rainwater

[31:33] for ercot legal. Uh, we have a request from lamar electric

[31:37] co-op, as you can see, to move about 60 megawatts of peak

[31:41] load from the rayburn electric co-op load zone

[31:46] to the competitive north load zone. Uh, lamar is present,

[31:50] uh, with schneider engineering for any questions about the reason for

[31:54] the change, but, uh, the protocols do require board approval.

[31:59] so for our part, ercot does recommend approval,

[32:03] um, mainly for three reasons. You can see there on the

[32:07] cover slide that the lead time is 48 months. So

[32:11] these changes wouldn't go into effect until january 1st, 2030,

[32:15] which built into the process is sufficient time to

[32:19] make ready the market, um, including regarding congestion,

[32:24] revenue rights, auctions. And, um, we did

[32:28] a little bit of research. Uh, we've, we've identified two prior

[32:32] occasions at least when the board approved similar requests. Um,

[32:36] one from guadalupe valley electric cooperative cooperative move from

[32:41] lcra to a competitive load zone in 2014.

[32:45] and then we had one more recently in 2023 when, um,

[32:49] the hamilton load moved from competitive to lcra and that was

[32:53] after the brazos uh, bankruptcy. So,

[32:58] um, for, uh, from our review, ercot smes

[33:02] have reviewed and identified no reason not to approve

[33:06] lamar's request. Um, with that we would request the

[33:10] board's approval. If you have any questions for

[33:15] brian or, uh, ramsey,

[33:19] are there any questions for brian or ramsey the principals

[33:23] or for kim who's presenting this?

[33:28] I don't hear any, no comments. So for that, I'll entertain a motion to

[33:32] approve this change. I'll moved. Okay. Thank you. Julie, do I have a second?

[33:37] second. Uh, kathleen. Peggy? Uh, all in favor?

[33:41] aye. Aye. Any opposed? Okay, the motion is carried.

[33:46] uh, the next thank you kim. Uh, the next is, um,

[33:51] this is a mouthful. Here we've got a request from bher, power

[33:55] resources and agenda item 13.3, uh, with an application

[33:59] for permanent site specific exemption from compliance with paragraphs

[34:04] five and six, a protocol section 10.3, 0.2

[34:08] 0.3, which is generation netting for ercot poll settlement

[34:12] meters. Uh, neil connor with bher power

[34:16] resources is with us via webex. If the board had any questions for bher

[34:21] and brent del will present this item. Brent, thank you chair. You want

[34:25] us say this in a simple format? I'm brent riddell, deputy general counsel

[34:30] for ercot. Um, I'm here to discuss a-b-h-e-r

[34:34] power resources exemption request, which was previewed yesterday by tac chair kaitlyn

[34:38] smith during her report. The decision at hand

[34:42] before the board is whether to approve a permanent exemption for bher power

[34:47] resources from an ercot protocol provision. Our rule state that

[34:51] facilities must connect to the grid only through designated metering points.

[34:56] there is an exception that exists for auxiliary loads up to 500 kilowatts.

[35:01] the bher facility located in big spring has been operating for 35

[35:05] years. It exceeds that 500 kilowatt auxiliary load

[35:09] limit, um, and reconfiguration to meet the

[35:13] cap is not practical. In october,

[35:17] ercot received bhe r's exemption request. At the november tech meeting,

[35:22] encore supported the request and tac voted to approve it.

[35:26] uh, tag noted that the facilities configuration predates the current rule.

[35:31] so the recommendation before you today from our staff is that the board approve

[35:35] the permanent exemption. And as the chair mentioned, neil connor, general manager

[35:39] of bhe renewables is presumably joining us from big spring via

[35:43] webex. If you have any questions, any

[35:48] questions for brand or for the company representative, with

[35:52] that, I will entertain this motion, which would be that the board accept the

[35:56] application for permanent site specific exemption from compliance with paragraphs five

[36:00] and six of protocol section 10.33 generation

[36:05] netting for ercot poll settlement meters, which is a request from bher

[36:09] power resources. Do I have that motion? So moved. Okay,

[36:14] peggy. Thank you a second, julie. All in favor? A aye.

[36:18] any opposed? Any abstentions? Okay, that is approved. Thank

[36:22] you. Alright, the next is, uh, agenda item is

[36:26] 14. There are sub items under this one, uh,

[36:30] regional planning group projects, which includes three voting items that christie hops

[36:34] can pres present. The first one that she will present is the agenda item

[36:39] 14.1, which is 25 rpg 0 2 5

[36:43] a ep, texas cps energy, encore, and cmp texas 7 65

[36:48] kv step eastern backbone project. We know that

[36:52] two no votes and two abstentions were cast attack, but tax still has

[36:56] recommended the project for approval. Christie, please walk us through the project

[37:00] and then we'll have an opportunity for any further comments. All right. Good morning board

[37:05] members and bill, I'm glad you had to read that name of that project instead of I

[37:09] , not me. What a, a great year

[37:13] it's been to be a part of system planning and watch how we really have

[37:18] involved here in the ercot market from the landmark decisions

[37:22] that our regulators made at the puc earlier this spring,

[37:27] uh, that led forth for reliability plan into the permian

[37:31] basin and then building off of the work that we started last year.

[37:35] the board has before you quite an opportunity to

[37:40] consider a project, um, that I believe will be a big reliability benefit

[37:45] for continuing to power the state of texas

[37:49] both reliably and efficiently. So

[37:53] if you'll indulge me, we've added a few extra slides. Just knowing

[37:57] the magnitude of this project would like to give some of our newer board

[38:01] members some history on how we got here. Um, the study

[38:06] process that we went through and how we came to our decisions and

[38:10] our recommendations that we have before you today

[38:21] in 2024, as we were not only looking at the permian

[38:25] basin reliability plan and how to most efficiently

[38:29] and reliably serve the needs in the permian basin area,

[38:33] we also started to observe in our planning forecast the

[38:37] need out in the future for more transmission to reliably serve the

[38:42] growing state. And what we saw in that 2030

[38:46] forecast was a growing demand to near 150 gigawatts

[38:52] compared to the previous years when we had studied in about the 120 gigawatt

[38:56] range. So at that time we realized we could not keep planning

[39:00] the system the way we always had, meaning 3 45 voltage

[39:05] being the highest level to serve the customers.

[39:09] at that time, our team embarked

[39:14] on a process to look not only at planning the system the way we always had, but we

[39:18] also looked at using 7 65 voltage

[39:22] in fact building what I would call a super highway. You think about building the interstate system,

[39:27] connecting your generation in your large load centers. And

[39:31] we looked at how that might work with our current network.

[39:35] and we provided two plans throughout 2024 and

[39:39] filed some comparison documents of the commission that looked at the pros and cons of using

[39:43] vote. That was back in january.

[39:48] in april. As I mentioned, the commission made the decision for the permian basin

[39:53] to use the import path capability at the 7 65 level.

[39:58] this would allow ercot to start using that in our planning process. As

[40:02] we looked at the reliability needs for the rest of the state

[40:08] in the summer, we had a joint project that was submitted through our

[40:12] normal regional planning group process from encore,

[40:17] a ep center point and cps that would

[40:21] have us continue to study the eastern backbone of the 7 65

[40:26] network. So throughout the summer and this fall, ercot

[40:30] completed additional sensitivity studies, economic analysis

[40:35] as well as stability, uh, analysis in coordination

[40:39] with the stakeholders, reviewing stakeholder comment and input.

[40:43] and we delivered our final recommendation to the regional

[40:47] planning group and tac considered in november of this year.

[40:51] thus it's before you for board endorsement today.

[40:57] so again, just a little bit of the detail as we went back and looked,

[41:01] what was the best option to be able to serve the needs of the state?

[41:07] there are several reliability benefits that I wanna highlight that really

[41:11] led to our recommendation that's before you today.

[41:16] the first is if you think about these 7 65 lines, while yes,

[41:20] 7 65 is new to texas, it's not new technology, it's

[41:24] been in use since the 1960s in the us so it's tried and

[41:29] true by using this higher voltage

[41:33] greenfield new right of ways, new build

[41:37] out of the system that allows us the flexibility we need

[41:41] to continue taking maintenance outages on the current system. We have,

[41:46] as we've continued to grow, it becomes more and more difficult each day for utilities

[41:50] to be able to take the outages they need to maintain lines

[41:54] to cut in new lines for additions of generation or additions

[41:58] of loads to the system. So this gave us more flexibility from that

[42:02] perspective. You'll see in the comparison chart

[42:07] through the economic analysis, by utilizing the 7 65

[42:11] network, there are reduced congestion cost on the system.

[42:16] so yes, while that's an economic benefit, it also provides an underlying

[42:20] reliability benefit. So if you think about if you

[42:24] have a system where, uh, power can flow freely without

[42:29] congestion where it has to be rerouted, that gives us more flexibility

[42:33] not only where generation is sided, but once it's sided there, being able to get it

[42:37] to where the consumers need it. The most

[42:42] impact to customers. I know when you say 7 65,

[42:47] you think 3 45 it must be twice as big. While, while it

[42:51] can carry much more power across those lines, it takes a lot less

[42:55] right of way to move the same amount of power. A 7 65

[42:59] right of way is needed about 200 feet compared to five

[43:04] and half, 3 45 ride aways to carry the same amount of power.

[43:09] so just 1 7 65 line could be built instead of five

[43:13] and a half, 3 45 lines less impact to the

[43:17] consumers of texas as bride aways are needed to be built.

[43:23] and then last but not least as we did our research, uh, in talking with

[43:27] others systems that utilize higher voltage,

[43:31] they seem to find that they have fewer forced outage rates on those

[43:35] higher voltage lines because of the setup in their configurations.

[43:44] so jumping in, uh, to the particular project in front of you, as I studied,

[43:48] uh, the utilities brought this to us this summer. We

[43:53] utilized, uh, during our normal processes, uh, the opportunity

[43:57] to build off of the work that we had done in 2024 is

[44:01] our base case to do additional analysis and sensitivity studies.

[44:06] one of the things that we focused on, and we get a lot of questions is the concern

[44:11] this plan was developed for load increases in the state, substantial

[44:15] load increases. What if those loads don't materialize?

[44:20] so we ran sensitivity studies to take a step back and look

[44:24] what if those large loads don't materialize. So we ran the

[44:28] reliability need based off of lower levels of load

[44:33] and we still still saw the need demonstrated for this 7 65

[44:37] system.

[44:43] so over basically a two year process timeline,

[44:47] we continue to review, do additional analysis, take in stakeholder

[44:52] feedback and comments. Our project summary,

[44:56] uh, this is a list of the recommendations that would be needed for new

[45:01] additions to the system to build out that plan.

[45:06] and so I stand before you now to, uh, bring you ercot recommendation

[45:11] to move forward and request your endorsement of moving forward with

[45:15] this project as well. I'll pause there 'cause I know

[45:19] you probably have some questions. Okay, any

[45:24] questions for christie for this incredibly important project? So

[45:28] christie, what you're saying, even in our, our low load case, this is still

[45:33] required for reliability. So throughout all three scenarios, low base,

[45:37] high load, this is required for reliability and the best alternative.

[45:42] yes, I that is correct. Um, one thing that I failed to also

[45:46] point out is a part of that two year study process. Not only did we study it looking

[45:50] out to 2030 during our 2024 review cycle, but

[45:54] we've been undergoing with, you know, additional new loads

[45:58] that have come in as we're studying 2025 looking out to 2031.

[46:04] and as we've gone through this year's annual regional transmission planning process,

[46:09] we also see the need for this infrastructure to be able to reliably

[46:13] serve the future demand on the system. So

[46:18] low, medium, high as well as we've seen that now two

[46:22] years in a row in our studies that it is needed. And what's

[46:27] the approximate time to construct? So what the utilities

[46:31] have told us, and I know they're here if they want to jump in and correct, um,

[46:36] it would be in the 2030, probably 2031 timeframe.

[46:40] okay. It's all contingent upon, I know they, they've been moving

[46:44] forward, um, as they have been with the permian working,

[46:49] uh, to get the equipment they need. Um, but also, uh, what

[46:53] would be next steps if the board endorses this, then the utilities, then it moves over

[46:57] to, to the commission process or the utilities would

[47:01] do, um, customer notifications for potential right

[47:05] of way decisions. Um, and that would take, you know, probably

[47:09] most of next year to work through that process at the commission before they can actually start

[47:13] building. Okay. Thank you. Christie, when did, when did

[47:18] you sort of freeze the load analysis? Uh, did you, is it,

[47:22] is it sort of july timeframe that you were using data from

[47:26] or, or more recently than that? So this particular

[47:30] review on this case was done, um, they submitted

[47:34] it based off of the need that we saw in our 2024 analysis.

[47:39] mm-hmm . So that load was froze, um,

[47:43] in late probably april, may of

[47:47] last year. And that was that study process. Now

[47:51] fast forward we're, we're doing a similar study where we also see the need

[47:55] during 2025 and that load, uh, wasn't finalized. If you

[48:00] recall, we went through, uh, a forecast, um, discussion with the commission

[48:04] and that was locked in in june. So, so june timeframe and

[48:08] since then there's been more load added to the queue, right? That's correct.

[48:14] kristy, uh, can you comment on our confidence level around

[48:18] the cost of the project? So the costs,

[48:22] uh, that are in this were based off of estimates that

[48:27] were provi or generic type estimates that were provided based on the information

[48:31] from last year. Um, I would probably defer

[48:35] to the tsb counterparts, um, that have been doing negotiations with,

[48:40] um, vendors for securing supply chain. Um,

[48:45] one thing I would note, um, I know there was debate in the

[48:49] past, um, from some previous larger transmission projects about

[48:53] how the cost went up in time. And what we found is we implemented a new

[48:57] practice this time around. So when we estimated the mileage that would

[49:01] be needed for these, we added a 20% adder to the mileage

[49:05] because we recognize when you go in and try to cite

[49:10] where that line is actually gonna be placed, it's probably not gonna be a straight

[49:14] line from point a to point b. And so, uh, we do add increased

[49:18] mileage to account for that. Um, because every

[49:23] turn on the, on the build of the system does add, you know, additional equipment that

[49:27] needs to be accounted for. Thank you.

[49:31] okay. Benjamin, do you have a comment? Uh, just a couple of questions. Why 20% for

[49:35] the cost out from, we went back,

[49:39] um, historically when we were doing it just a straight line

[49:43] approach, what we saw on the average it was about 18% when

[49:48] they would actually then come back to the commission. And so that's why we chose 20%.

[49:52] it was based off of historical, uh, information.

[49:57] so it didn't factor anything into like the geography of the area of this going through.

[50:02] no. Uh, so this is about the same size as the permian

[50:06] basin plan, which had a monitor. Is there any consideration for having a monitor or some sort of

[50:10] cost reporting requirement for this plan? For this? So my recollection, um, how

[50:14] the permian basin monitor was established was during the commission

[50:18] deliberation process where they added that into their final

[50:23] order for the permian plan to keep, um, overview

[50:27] of schedule and cost, um, because of the importance of the timely

[50:31] build out for the consumers in the permian. And that is actually being

[50:35] run by and overseen by the commission. So I would defer

[50:40] to, to commissioners, uh, whether that's something they would want

[50:44] to entertain or a consideration of, of some version of that for

[50:48] this project. Yeah, I'm happy to weigh on, on, in on that ben.

[50:52] so I've talked to pc executive staff, um, about

[50:56] this. I think at minimum we will take the construction reports

[51:01] that will be filed by the tsps and compare those to the cost

[51:05] estimates that, um, are in this approval if it gets approved so

[51:09] that we have a benchmark that we can compare against. I'll continue to talk to

[51:13] connie and barksdale about, you know, the portal that we've set up and if we have money

[51:18] to expand the data that we put into that. Um,

[51:22] but I think at minimum we will take the construction reports and do a comparison

[51:26] and we can post that information online. 'cause I too, you know, uh, cor was

[51:30] one of the first projects I was, I was involved with when I came to the commission

[51:34] and so I'm, I'm very aware of, uh, the public's desire to know

[51:40] cost overruns if schedule slips. And so I think it's important

[51:44] given the, the magnitude of this and the cost that we are transparent about

[51:48] any cost overruns and slips in schedules. So we will, we will do everything we can at the commission

[51:53] to, uh, to make sure that that information's public so that everyone from the governor to the

[51:57] legislature to, uh, the public at large knows, knows what's going on with this

[52:01] project. I I appreciate that. Thank you

[52:13] christie. My question has to do with the, uh, execution of the project.

[52:17] can it be phased in and let's say

[52:22] to match load expectations because that is

[52:26] the load forecast seems to be so dynamic at this point. What, what was

[52:30] deliberated about in terms of basing

[52:34] the project? So I, I like to think about what's before you, if you

[52:38] think about it. It's, it's a loop. So there were three set points

[52:43] that were decided they're already established by the commission as a

[52:47] part of the permian basin plan and then this completed the loop.

[52:51] um, if you think about what we're recommending here, again, it's the super highway

[52:57] and what it's giving us the opportunity, the points that we chose when we were preparing

[53:02] this were strategically chosen, whether they're already large load centers

[53:07] or they're generation pockets where we see a lot of generation on the system

[53:11] today. So those are knowns and that helps us more efficiently move

[53:15] power around. But as that load materializes over time,

[53:20] we know it's important to know where they're gonna be located so that you can build transmission

[53:25] to them. I would foresee this as being your interstate

[53:29] as we, and it's needed based off our sensitivity, whether that

[53:33] large load materializes it or not. But what this provides

[53:38] you is when those new large loads or new generation comes to the system, where

[53:42] do you build the exit ramps? And we have the flexibility to be able to do that

[53:46] with a lower voltage.

[53:51] this is a little bit off of normal protocol, but given the scope

[53:55] and size of this project, if, uh, representatives from a ep encore

[53:59] or cps or uh, uh, cnp would like

[54:03] to comment, we're willing to listen.

[54:10] okay. I don't see anybody jumping up. Alright,

[54:15] carpenter. Okay. Okay. We do have a commenter. Okay.

[54:34] uh, yes, this is mark carpenter, senior vice president with encore electric delivery.

[54:40] um, the cost estimates we have in this we think are prudent costs

[54:44] given the information we have at the time, things like tariffs and

[54:48] right away costs. And some of those things are variables that, uh, uh, we've

[54:53] taken our best guess and, but we're very comfortable with the, with the

[54:57] cost estimates and I believe the other two tsps would say the same thing.

[55:04] okay. Thank you. That's helpful. Anybody else?

[55:10] christie, any closing comments? No, I, I would,

[55:14] uh, thank you for your consideration. As I said, it's been, uh,

[55:19] a very long process to get to here, um, a lot of

[55:23] review and and consultation. Um, so I'm excited to see what your

[55:27] decision is. Okay. With that, I'll entertain a motion

[55:31] to approve the 25 rpg 0 2 5

[55:36] a ep texas cps energy encore and cnp texas

[55:40] 7 65 kv step eastern backbone project. So

[55:44] moved. Okay. Thank that was bill. Yeah. Okay. Uh, second?

[55:48] yes. Second. Okay. Got two of me, linda and kathleen. All in favor?

[55:52] aye. Aye. Any opposed? Any abstentions?

[55:57] okay. That project is approved. Christie, would you proceed with

[56:01] the next agenda item? Sorry. And lemme go ahead and read it. It's agenda item 14.225

[56:07] rpg 0 2 2 encore, and a psc drill hole to sand lake

[56:12] to solstice 7 65 kv line project.

[56:17] all right, so we've, we've talked about from the 7 65 perspective,

[56:21] when we looked at the strategic transmission expansion plan to

[56:25] reliably meet the needs of consumers into the future, we had the permian

[56:30] portions, we have had the eastern portions you just considered. If you think about

[56:34] out in far west texas and the permian basin area, there

[56:38] are three import lines that were approved by the commission.

[56:42] they all end there and this project was brought forward at the same time

[56:47] based off of the, the same analysis we discussed, uh, on the other project

[56:52] to close in those three endpoints so that we would have a fully

[56:56] networked 7 65 backbone on the system. 'em,

[57:01] we went through that same review process in, in considering, um, looking

[57:05] at what we had analyzed in 2024, what we had analyzed in our

[57:09] 2025 planning process working with the regional planning group.

[57:14] and we still saw, um, the reliability need. And I think from this

[57:18] perspective, I look at it not only as reliability but resiliency.

[57:22] it'll give us more flexibility in the future as we're looking at outages

[57:26] that may need be needed for, for maintenance to be able to have that system fully

[57:31] networked. So the request before you, um,

[57:35] is to endorse the need for this project based

[57:39] on our reliability planning criteria. And

[57:43] would you replete the estimated cost again? Sure, it is,

[57:48] um, I believe it's $742 million.

[57:53] okay. This is just for line cost. Uh, the substation costs were

[57:57] already a part of the permian plan approval. Okay.

[58:01] any questions for christie on this? No

[58:06] questions, no comments. Uh, hearing none I will entertain

[58:10] a motion to, um, approve the 25

[58:15] rpg 0 2 2 encore and a psc drill hole to sand

[58:19] hole to sand lake. So to solstice, excuse me, drill hole

[58:23] to sand lake to solstice. 7 65 kv line project.

[58:27] so moved. Thank you. Chris. Do I hear a second? Second,

[58:32] peggy? All in favor? Aye. Any opposed?

[58:36] any abstentions? Okay, that project is unanimously

[58:41] approved. Bill, before we go on to the next one, I'd like to just take an opportunity to

[58:45] send a thank you to our teams that are probably watching. Um,

[58:49] they've spent a lot of time and analysis not only in the planning

[58:54] department, uh, coordination, working with dan's folks, the the markets folks

[58:58] to look at some of the economic analysis. So it was a, a large effort

[59:02] by a lot of folks at ercot to bring this forward. Um, I think woody

[59:06] likes to joke, if you were a planning engineer in another iso, you

[59:11] may get to work on one u line in your career. And, um,

[59:15] the planning engineers on our team have had quite the past two years.

[59:19] so, uh, thank you chris.

[59:24] with that, we're gonna proceed to the third voting item, which is agenda item 14.324

[59:30] rrg, r pg 0 2 0, encore connell

[59:34] 3 45 slash 1 38 kv switch and connell to

[59:38] rockham 3 45 kv double circuit line project option

[59:42] one. Christie, would you present that to us please? You bet. So this is

[59:46] $110 million, uh, project that was brought forward by

[59:51] encore. If you recall the last couple of board meetings, dan's been

[59:55] providing information in the far west texas area. We know that's an

[59:59] area that is growing. Um, while there are a lot of projects

[1:00:03] that have already been endorsed that are being built in the area, as we continue

[1:00:07] to see additional demands on the system in far west texas, you're gonna need

[1:00:11] additional infrastructure to continue supporting them. And so this project was

[1:00:15] brought forward by encore, went through our, uh, review process

[1:00:20] and we saw reliability need in that far west as additional loads

[1:00:25] would be continued to be added to, um, do

[1:00:29] upgrades, um, to the system in the region to eliminate

[1:00:33] or, um, thermal and voltage violations in that far west

[1:00:38] texas area. This project was unanimously endorsed by

[1:00:42] attack. Um, and so with that, I would

[1:00:46] request the board's endorsement of this, uh, encore

[1:00:50] project in the far west area, uh, which totaled about $110 million.

[1:00:56] any questions for christie? One question is yes

[1:01:01] for this project, christie, how, how fast can this be done and what, what

[1:01:05] will the timeline look like? Um, lemme let me take a quick look at our report

[1:01:09] here. Um, what the expected timeline? Um, I think I

[1:01:13] know one disclaimer while I'm looking up that, that timeline, um,

[1:01:17] it's, it's needed for in-service in 2026. So

[1:01:21] this is looking at a project that would be next year. There is 13 miles

[1:01:25] of right of way that are required. So they will have to go through, uh, the commission

[1:01:30] ccn process to establish that need and

[1:01:34] get approval for the siding of that new right of way. Um, and I know one disclaimer

[1:01:39] that the utilities typically put in when they give us timelines on how quickly

[1:01:43] they think they can build the project, um, is that it's

[1:01:47] dependent upon, um, outages. So when we talked about approving

[1:01:52] the 7 65 plan and how our system is utilizing

[1:01:56] its full transmission capability today, it becomes harder and harder to take those

[1:02:00] outages. So it's also dependent upon weather and being able to take those outages

[1:02:04] needed to, to upgrade the systems. Thank

[1:02:09] you. Sorry. If, if you don't mind, encore, representative

[1:02:13] kin to speak to that. Yes, liz jones on behalf of encore.

[1:02:18] um, I, I do have some updated information in response to your question.

[1:02:22] because of the delay in processing this rpg submittal

[1:02:26] and because of customer needs, encore went ahead and filed

[1:02:30] the ccn proceeding with the puc and that

[1:02:35] is nearing its end. And so there will be some time savings

[1:02:39] as we move forward to build and operate the

[1:02:44] facilities. So don't leave liz, any questions for liz while she's

[1:02:48] up there? Okay. Alright, thank you.

[1:02:52] that was helpful. Any other questions or comments?

[1:02:57] I'm not hearing any, so I'll entertain a motion to approve the two four

[1:03:01] rpg 0 2 0 encore con connell 3 45, 1 35, 1 38

[1:03:08] kv switch and connell to rock hand. 3 45 kv double

[1:03:12] circuit line project option one. Do I hear a motion?

[1:03:16] so moved. Thank you julie. I have a second. Second. Okay. Who is that? Bill.

[1:03:21] okay, thank you. All in favor? Aye. Any opposed?

[1:03:26] any abstentions? Okay. Uh, ercot board has endorsed this project

[1:03:30] for approval. Next, we'll move to agenda item 15, commercial

[1:03:35] markets. The first agenda item is 15.1

[1:03:39] market price correction, incorrect generation to be dispatched, values

[1:03:43] used in scad gordon drake is gonna present this item. Gordon.

[1:03:53] thank you chairman flores and members of the board. It's my pleasure to be here, uh,

[1:03:57] to present this potential price correction for your consideration, uh,

[1:04:01] to talk about the events that that led to the issue in our market systems

[1:04:05] and request board approval to correct prices for operating day october 14th.

[1:04:12] on october 14th, um, we had, uh, an input

[1:04:16] into our generation to be dispatched value in our market systems.

[1:04:21] that is a, a parameter in our market system that determines how much, uh, generation

[1:04:25] do we need to, uh, instruct to, to generate in order to meet the, the

[1:04:29] load. Um, and a key input into determining that generation two

[1:04:34] b dispatched value is the, the load forecast that they, that the controller

[1:04:38] is using and our market systems observe. And we had been,

[1:04:42] uh, using our external short term load forecast as an input to our market

[1:04:46] systems when we noticed an abnormal spike in the, um,

[1:04:51] in, in that load forecast. And the control room has the ability

[1:04:55] to switch to another load forecast that more accurately reflects the

[1:04:59] expected load pattern. Uh, as they were executing that switch, uh,

[1:05:03] because of the, uh, the observed spike, unfortunately, there was a,

[1:05:07] a software bug that prevented that from, uh, appropriately executing.

[1:05:11] and so that, that that price spike, so that load spike was reflected

[1:05:16] in the calculations for the, the generation to be dispatched parameters

[1:05:20] as a result that the, the generation to be dispatched parameter,

[1:05:24] um, impacted prices between, uh, eight 10 and 9:15 pm

[1:05:29] resulting in high system-wide prices, uh, in between, uh, eight 10

[1:05:33] and 8:15 pm so all the prices were impacted within that window, but

[1:05:37] we, we noticed, uh, particularly high prices in that eight 10

[1:05:41] to 8:15 pm window. We identified this as

[1:05:45] a software issue, uh, on october 23rd. Um, and

[1:05:49] as thus could not meet the, the two business day timeline in the protocols

[1:05:54] in order to correct prices before they went final. And that is why we are

[1:05:58] here today requesting your approval. The, the cause of that software

[1:06:02] bug that prevented the effective switch between the load forecast was identified and

[1:06:06] affix was deployed near the end of october. We communicated the,

[1:06:11] uh, event in our investigation to the market through two market notices, uh,

[1:06:15] the first on october 24th, uh, providing the same details that

[1:06:19] we are sharing here today. And on nover november 17th. Uh,

[1:06:23] upon concluding our analysis, uh, and informing the market of our, uh, intention to,

[1:06:28] uh, present it to the board of directors for approval at this meeting,

[1:06:33] we determined that the impact of prices met the significance criteria

[1:06:37] in our, in our, uh, nodal protocols, um, exceeding the thresholds

[1:06:42] of, uh, an impact of 2% and also greater than $20,000

[1:06:46] or 20%, and also greater than $2,000 to a single counterparty.

[1:06:51] we had 18 counterparties that met the first criterion and three counterparties

[1:06:55] that met the second criterion. And the absolute value

[1:06:59] to counterparties, uh, to a single counterparty was a maximum

[1:07:03] of $140,000. Um, which, and the maximum percentage

[1:07:08] criteria of nearly 22% and nearly 150% for

[1:07:12] the second criterion. Overall,

[1:07:17] the impact to ercot settlements was just more than $800,000,

[1:07:21] um, representing the shisha of 4% of the total market settlements for that

[1:07:25] day. Um, in summation, we had, uh,

[1:07:30] an issue in our software that led to, uh, an impact to an

[1:07:34] inappropriate impact to prices for operating day october 14th, which met

[1:07:38] the significance criteria in our protocols, and we are requesting

[1:07:42] board approval to correct the prices, uh, for the real time market for operating

[1:07:46] day october 14th. I'm happy to answer any questions. Okay, chris,

[1:07:51] uh, just to comment, uh, gordon, I would say good job on describing

[1:07:56] a tough and complex issue. Um,

[1:08:00] I, I, I appreciate it. This isn't, it's not easy to describe and explain.

[1:08:04] thank you. What has happened here, and I'm glad there's a fix.

[1:08:09] any other questions for gordon or comments? And

[1:08:14] you provided your assurance that that particular issue has been fixed, so yes,

[1:08:18] sir. Shouldn't have a repeat occurrence. Okay, thank you. I don't hear any other

[1:08:22] comments or questions, so recognizing that, uh, I'll entertain a motion

[1:08:26] to approve the price correction as presented. So moved. Okay. Thank you, chris.

[1:08:31] any second, sir? Okay, peggy, thank you. All in favor?

[1:08:36] aye. Any opposed? Any abstentions? Okay. The price

[1:08:40] correction has been approved. Next, we're gonna move to agenda item 15.2.

[1:08:45] keith collins is gonna give us a commercial up, uh, markets update.

[1:08:56] all right, good morning. This is an informational discussion

[1:09:01] and we'll cover some of the key initiatives we're working on,

[1:09:05] uh, over the last several months, but also moving forward as well.

[1:09:10] and we'll cover, uh, our current credit situation in terms of,

[1:09:14] uh, the, uh, we haven't seen any significant market credit or settlements

[1:09:18] related items, and we'll cover that in a second. So, uh,

[1:09:23] starting off, we've, we've discussed a couple of these, uh, a few times, but I think it's important to

[1:09:27] highlight again that, uh, the first key initiative we're working

[1:09:31] on is dispatchable reliability reserve service. We did cover this a bit more yesterday,

[1:09:36] but just to give a few more highlights, we did have a study,

[1:09:40] uh, from a more aurora energy research that showed the,

[1:09:44] uh, the potential benefits of, of the, the various

[1:09:48] permutations of, of drrs. We'll talk about that in a few minutes.

[1:09:53] we did post the two nprs, uh, our drs an ancillary

[1:09:58] service version under 1309 and drs ancillary service

[1:10:02] plus under 1310. And we will be hosting

[1:10:06] a stakeholder workshop here, uh, a week from, uh, a

[1:10:10] week from tomorrow, uh, at the met center to with aurora

[1:10:14] to discuss the report with stakeholders. Uh, secondly,

[1:10:19] uh, our residential demand response program. We had a,

[1:10:23] uh, we had a, uh, had good discussion with stakeholders

[1:10:27] at the wms on november 5th. There was a lot of good feedback that

[1:10:31] we received at that. Uh, during that discussion. We are taking that feedback,

[1:10:36] uh, and, and the points raised during there and working on revising

[1:10:41] the proposal based on some of the key points that we, we, we

[1:10:45] learned during that discussion. We expect to have, uh, some, uh, a modified

[1:10:49] npr, uh, early next year. And then the

[1:10:53] final point is the energy attribute certificate program. This

[1:10:57] was something that we discussed in june at the june board under npr

[1:11:01] 1264. We have been making significant, uh,

[1:11:05] progress on that. Uh, I, I will note that we are have been working with stakeholders

[1:11:10] on a sort of a lightweight option that had been discussed at the board.

[1:11:15] and, uh, ultimately we have, uh, provided some updates to

[1:11:19] the prs and the wms on a request for a quote for a

[1:11:23] vendor. Uh, ultimately part of the next steps will be to select a vendor, but we have

[1:11:28] at least have, uh, uh, a draft version of, of that request.

[1:11:32] and we've made some draft comments to, uh, the stakeholders regarding

[1:11:37] 1264 to better define the processes, roles and responsibilities.

[1:11:41] and sort of the final point that I wanna make as, as part of our key takeaway, obviously, rtc,

[1:11:45] all of this has been going on while we've also simultaneously been working on rtc

[1:11:49] plus b, but I do want to sort of note that there are some stabilization efforts

[1:11:54] going on over the, over the course of the next few months. We mentioned some of those yesterday.

[1:11:59] I, uh, thankfully that it, it, it has been, uh, a relatively smooth,

[1:12:03] but, but again, there are some cleanup items that we want to just not ignore as we move forward.

[1:12:10] and then talking about market credit update, there have been no significant issues,

[1:12:15] uh, in either the settlement or credit related defaults. Uh,

[1:12:19] when we, we view our total exposure, there's generally a seasonal pattern, and we saw

[1:12:24] a summer peak, uh, 1.84 billion, and that's come down,

[1:12:28] uh, to about 1.57 in october. Just a update

[1:12:32] on npr 1277. This is something that we

[1:12:37] discussed, uh, starting at the end of last year, beginning of of this year,

[1:12:41] we did have an npr, uh, that went through the process to

[1:12:45] help improve the collateralization requirements and the impacts of high

[1:12:49] volatility that passed the commission in november.

[1:12:53] and we do anticipate implementing that in early 2026.

[1:12:58] the other item that I want to highlight is that we have been, uh, working

[1:13:02] on a credit, uh, our credit staff is working on an

[1:13:07] analysis that evaluates and measures market stress scenarios. And we do look

[1:13:11] forward to bringing that through the stakeholder process, uh, in 2026.

[1:13:18] uh, that concludes my update, and I'm happy to answer any questions that, uh,

[1:13:22] the board may have. Any questions for keith?

[1:13:27] okay. John, do you have a question? Yes. Keith, as you look out over time, um,

[1:13:32] be beyond the immediate things that you're working on, are there any

[1:13:36] things on, on your roadmap that would continue to send better price

[1:13:40] signals to the marketplace about the need for dispatchable generation?

[1:13:45] and if so, can you give us a bit of an idea of what kinds of things you're thinking about?

[1:13:50] I, I think the, the most immediate thing that we're, we're looking at is our,

[1:13:54] our dispatchable reliability reserve service. That's, that's really our focus. We think that

[1:13:58] has the ability to do precisely what you're hitting on is you,

[1:14:02] uh, incentivize dispatchable resources, uh, within

[1:14:07] the market in, in order to address the, the reliability concerns,

[1:14:11] the growing relian concerns we're seeing, is it enough

[1:14:15] by itself? Uh, what, what we see, and we'll talk about this in just a

[1:14:19] few minutes, is that, uh, the combination of, uh,

[1:14:23] what we saw in senate bill six and the drs ansley

[1:14:27] service plus version in combination should be enough

[1:14:31] to, to address the majority, if not all the issues, uh, that, that we've

[1:14:35] studied. Okay. Thank you.

[1:14:39] okay. Thank you, john.

[1:14:43] I'd like to, I mean, there's also the, uh, the reliability standard

[1:14:48] study next year. That'll be a good indicator too.

[1:14:54] okay. Any other questions for keith? Alright,

[1:14:59] keith, I think you have the next agenda item, which is, uh, 15.3

[1:15:03] dispatchable reliability reserve service, or as we call it, drrs.

[1:15:08] drs. Yes. Thank you. Thank you, mr. Chairman. Uh, I'm here to present,

[1:15:12] uh, on the study that was done by aurora. We have representatives from aurora here

[1:15:16] as well, aurora energy research in the event that there may be some questions from

[1:15:20] the board, uh, they're here with us today. Uh, I'm here to

[1:15:24] not present the full report, but to give the highlights, uh, that we, and key

[1:15:28] takeaways of, of that, of that report. Uh, this was presented

[1:15:32] to the commission a few weeks ago, and we, we plan to

[1:15:37] have, uh, some dialogue with stakeholders, as I said earlier, in a couple weeks, to, to go

[1:15:41] through the, the specifics of the report.

[1:15:45] and so, um, starting with the

[1:15:49] conclusions, and I think this was, was, was kind of key, was that

[1:15:53] there is no silver bullet, uh, market design solution, uh, either

[1:15:58] on the load side, uh, with, with potential load curtailment or,

[1:16:03] uh, on the generation side market design. However,

[1:16:07] and this gets to the question that, that, uh, I just just responded to,

[1:16:11] is that when you, when you do look at, uh, the impacts of these

[1:16:15] different, uh, tools, they do have significant effects individually

[1:16:20] on improving, uh, the resource adequacy and the potential for,

[1:16:24] for outages in the future. And in particular, the,

[1:16:28] the drs ancillary service plus case, as opposed to

[1:16:32] some other analyses we looked at. And we compared different alternative scenarios. And

[1:16:36] that included, um, the dispatchable reliability, reser

[1:16:41] reserve service that was presented in 1309. We looked at that as

[1:16:45] just an ancillary ser as a, as primarily as an ancillary service design. And

[1:16:49] we did look at the ordc, um slash adcs as they

[1:16:53] are now, uh, in, in the market. And we looked at modifications there and said, well, would those be

[1:16:57] significant enough? And what we found was that the, the drs

[1:17:01] ancillary service plus scenario adds more dispatchable

[1:17:05] capacity at lower costs and provides greater resource adequacy

[1:17:09] benefits under, uh, different load and, and extreme weather conditions.

[1:17:14] and so it, it did provide the, the most benefits at, at the

[1:17:18] lowest value, at the lowest cost. And so, uh, uh,

[1:17:22] so the study did a good job of, of evaluating that, that universe. And,

[1:17:27] and so when we look at the combination of that drs an

[1:17:31] service plus in combination with the senate bill six programs

[1:17:35] to, for large load and, and large load curtailment, you can end

[1:17:39] up in a scenario where you'll cover a range of potential outcomes that

[1:17:43] that could potentially exist.

[1:17:47] all right? And so the, the first slide here is essentially an

[1:17:52] evaluation of, of the status quo market design, uh, under,

[1:17:56] um, under, under stress conditions, either a winter storm

[1:18:00] or a summer heat wave. And the winter storm, uh, this is, is the equivalent

[1:18:04] of winter storm elliot, not necessarily winter storm yuri,

[1:18:08] winter storm. Elliot was, uh, uh, essentially a christmas

[1:18:13] time, uh, winter storm in, in 2022. The summer

[1:18:17] heat wave that we looked at was just, uh, the summer we experienced a few years ago in 2023.

[1:18:22] so these are, are, uh, relatively recent events. And

[1:18:26] if we apply the same conditions under the load conditions,

[1:18:30] uh, and by load conditions, we looked at the ercot 2025

[1:18:34] long-term load forecast and an aurora, uh, what

[1:18:38] they call the aurora central case, which is, is a more moderate demand scenario.

[1:18:43] uh, that what we find in both scenarios that we see, uh, the,

[1:18:47] the duration, uh, the magnitude, which you see here

[1:18:51] represented in the bars in terms of the outages, the duration, uh, in terms of hours,

[1:18:55] uh, you see around that, uh, 15, 11 to 15 hour range. And

[1:18:59] the total amount of, of load shed, you see are in the gray boxes under the chart

[1:19:04] of, uh, in, in, of about 60 to over a hundred gigawatt

[1:19:08] hours of, of load shed. And then the costs are represented in the

[1:19:13] bottom chart in terms of how much cost at the, at

[1:19:17] the value of lost load would we expect, uh, to

[1:19:21] occur during those events. And you'll see that being, uh, ranging for about 2 billion to,

[1:19:25] to just, just under $4 billion. So this is under the status

[1:19:30] quo in 2030 in the event that we had, uh, an event,

[1:19:34] uh, like, uh, like winter storm elliot, or like,

[1:19:39] uh, uh, a summer event like 2023. So it is, it is a reasonable

[1:19:43] to assume that those could potentially occur in the future, and this is the outcomes that we

[1:19:47] would anticipate based on their analysis.

[1:19:52] alright, so we asked, we asked the aurora staff to look

[1:19:56] at, uh, the senate bill six. Uh, we knew that that had

[1:20:00] the potential to improve the scenarios. And, and what

[1:20:04] we see is, is essentially mixed, uh, that under some scenarios it has significant

[1:20:09] benefits under other scenarios. It, it, uh, has some benefit, but, but limited

[1:20:13] effects. And, and so we'll start with the charts on the, on the left,

[1:20:17] which show under high load growth scenario, this, this being equivalent to

[1:20:21] a significant amount of large load, uh, inter interconnection

[1:20:25] by 2030. Uh, and what we see under those scenarios that, that

[1:20:29] flexibility afforded to you under those scenarios under emergency

[1:20:34] conditions. And that's, that's important that a lot of that, uh, the

[1:20:38] access to that capability occurs, uh, not necessarily under market conditions, but potentially

[1:20:42] under emergency conditions. You can, you can, uh, potentially

[1:20:46] address the, both the summer and winter events and

[1:20:50] that, that you see there by the elimination of those bars and elimination

[1:20:54] of the costs on the right hand side. If you end up with a moderate

[1:20:58] load growth scenario where you do have, uh, data centers coming, but

[1:21:03] maybe perhaps not at that, that high level that is envisioned in a long-term

[1:21:07] load forecast, then what we see is that there's a more

[1:21:11] limited effect that those large loads can have on on outcomes

[1:21:15] and that can lead to significant, still, still have significant outages

[1:21:20] remain and significant costs as well. So, uh, again,

[1:21:24] this is a scenario where the, the senate bill six large load, uh, uh,

[1:21:28] curtailments under emergencies can have positive effects. But again, it's not a

[1:21:32] silver bullet. All

[1:21:36] right? And then concentrating on the drs

[1:21:40] ancillary service plus scenario, we find that, again, it

[1:21:44] has the potential to help alleviate both under the high and the

[1:21:48] moderate load growth scenarios, but it doesn't eliminate the scenario.

[1:21:52] uh, what we do also look at is, uh, uh, the storage

[1:21:57] included and not included. And so that does add another wrinkle. The, the khaki

[1:22:01] color that you see here is has the storage excluded the yellow color, has it

[1:22:05] storage included. And what we find is that it's, it's mixed in some

[1:22:10] scenarios, the storage can help in some scenarios. The storage doesn't

[1:22:14] have the same benefits as, as excluding them. Uh,

[1:22:18] and again, I think that's primarily related to duration. When you're, when you're

[1:22:22] evaluate, we evaluated this with four hour storage and four hour storage,

[1:22:27] uh, under, under summer conditions tends to be, uh, uh, more

[1:22:31] effective under the longer winter term scenarios. It, it, it tends to be a little less effective

[1:22:36] than dispatchable thermal capability. And so really

[1:22:40] what we see is a reduction, uh, when we have ansi service, plus

[1:22:44] we see a reduction in the magnitude, the reduction in frequency, the

[1:22:48] reduction in the number of hours that we see impacted in a reduction in the costs. But again, it

[1:22:53] is not a silver bullet and, and we're cognizant of that, but it does have a significant

[1:22:57] impact on the outcomes that we see. And interestingly enough too, is that

[1:23:01] where the, under the high growth scenario, the large loads

[1:23:06] tend to to be more effective. We see under the moderate load growth scenario

[1:23:10] that the, uh, drs ansley service plus, uh, tends to be,

[1:23:14] um, a bit more effective in addressing concerns. And that, that, that shows they're a bit

[1:23:18] complimentary, if you will.

[1:23:22] okay. And then comparing the drs ansi service plus to alternatives,

[1:23:27] we looked at the cost, we looked at the amount of, uh, dispatchable

[1:23:32] generation that we see added, and that's sort of a proxy in their, in their report, they

[1:23:36] show that ultimately the, the drs ancillary service plus

[1:23:40] scenario does have a greater level of reliability benefits

[1:23:45] as compared to the others. And so, um, but, but in this chart, we're covering

[1:23:49] the costs and, and the quantities. And what we see on the far left chart

[1:23:53] is this is the all in system costs under the different scenarios,

[1:23:57] including the status quo. The chart in the middle,

[1:24:01] uh, effectively does the, the comparison for you. It's comparing each

[1:24:06] scenario, the ansi service scenario, the ansi service plus scenario,

[1:24:10] and the ordc scenarios. And it's comparing it. And, and we

[1:24:14] see in the middle chart that ultimately the cost associated with

[1:24:18] drs ans answer service, ansley service case, uh, uh,

[1:24:22] we see a net net cost of about 700 million in the

[1:24:26] drs anser service. Plus case, we see a net cost of 400 million.

[1:24:31] and we see on the rdc case a cost of about 2.2 billion.

[1:24:35] and so very different cost profiles depending on which scenario

[1:24:40] you take. But, um, what we see in the final chart is

[1:24:44] how much dispatchable capacity relative to the status quo do we see,

[1:24:48] uh, under the ancillary service scenario. Uh, we see 900 megawatts of incremental,

[1:24:53] uh, capacity. Again, it's a very incremental program. Uh, it

[1:24:57] is, it is designed as a, primarily an ancillary service. And so

[1:25:01] it's, it's going to have incremental effects. Uh, whereas the ancillary

[1:25:05] service plus case, we see five gigawatts of additional dispatchable generation,

[1:25:10] and what we see is a reduction in the amount of solar, uh,

[1:25:14] and the short term and, and even some of the four hour storage. And

[1:25:18] then under the ordc, what we see is an increase of,

[1:25:22] uh, 1.7 gigawatts of dispatchable thermal capacity. But

[1:25:26] we also see solar. We also see one hour battery. We also see two hour battery,

[1:25:31] uh, storage as well, uh, in addition. So, uh, in terms

[1:25:35] of additional dispatchable thermal cap capacity, the

[1:25:39] drs ancillary service plus is, uh, we see it's the lower net costs,

[1:25:43] we see it's more dispatchable capacity. And when we translate that into reliability,

[1:25:48] it has, uh, greater reliability benefits compared to the other scenarios as well.

[1:25:54] so in terms of next steps, uh, the two nprs that we've been talking

[1:25:59] about, the 1309 has the urgent status, and the

[1:26:03] 1310 will also be brought up in the stakeholder process. It's

[1:26:07] important to note that what we're deeming the release factor, which

[1:26:11] is a part of the ancillary service plus scenario, uh, that's what creates

[1:26:15] the reli. The, the resource adequacy benefit is this release factor.

[1:26:20] ultimately, uh, that is going to be in an off position until approved

[1:26:24] by the, the commission to, to switch it into the on position.

[1:26:28] and then ultimately, the energy storage under thir, uh, npr

[1:26:32] 1310 will also be in an off position until approved to turn on

[1:26:37] by the puc. And then, and then finally, as I noted,

[1:26:41] we will be having a stakeholder discussion on december 17th. So again, a week from

[1:26:45] a week from tomorrow, we will be discussing with stakeholders all the various, uh,

[1:26:49] addressing all their various questions. And we've been receiving several of them, uh, but,

[1:26:54] but, uh, mostly pointing to pointing them to the discussion that we have, so we

[1:26:58] can all hear it, and, and I'll have, uh, uh, a common set of understanding of what the findings

[1:27:02] of the report were. So, uh, I'm happy to answer any questions. I also have, like I

[1:27:06] said, the, the representatives from aurora to answer any questions that you may have. Uh, keith,

[1:27:10] I'll start with the questions. Let's go back to, uh, slide six, if you would.

[1:27:15] yes. Looking at the right hand column. So we saw a decrease in battery

[1:27:19] and storage, right? Uh, so what we have in that, that right

[1:27:23] hand chart, what you see in that middle scenario right, is a, a decline

[1:27:28] in, and this is relative to this status quo case, correct? Right. So you're

[1:27:32] not, you're not, you're not retiring those resources, you're just adding

[1:27:36] less, you're not adding them. So the, my question is, are they not being added because

[1:27:40] of a policy consideration or an economic consideration? It is

[1:27:44] primarily because of the economics of the drrs ansi

[1:27:48] service scenario. So the as plus, as plus scenario correct, uh, creates a

[1:27:53] lower economic incentive for capital deployment for storage companies.

[1:27:57] is that correct? For the, for storage and for the, um,

[1:28:01] for the solar as well. And, and just to point out, this whole, all of the modeling

[1:28:05] on this page is done with the batteries ineligible to participate,

[1:28:10] correct? Correct. As the prior slides, that's right. We did see scenarios with eligibility

[1:28:14] inclusive and non and non-inclusive. So this one,

[1:28:18] all of these scenarios show without batteries being eligible. Correct. But that's why I was trying to dis grade

[1:28:23] is how much of it's because batteries are ineligible versus economics that were causing that

[1:28:27] capital and not be deployed. And, and, and there isn't. There

[1:28:31] is a chart where, where pablo is, is noted. We have a comparable chart that

[1:28:35] shows the battery's eligible, but those batteries eligible are the four

[1:28:39] hour batteries, right? So what we'll see there in that chart is an increase.

[1:28:44] um, so the increase in the dispatchable capacity will won't be as high. So

[1:28:48] it's five gigawatts in this, it'll be a little bit less, and then you'll have

[1:28:52] a, a value for the, um, the four hour storage, but

[1:28:56] then you'll, you'll have reductions in the short hour, the short duration

[1:29:00] storage, as well as the solar. Okay. Any other questions? There's

[1:29:05] lots to digest. Okay, chairman, thank you, mr. Chairman. Uh, keith, I

[1:29:09] think it would be probably beneficial for the board members to hear, uh,

[1:29:13] to hear you respond to a question I asked at our last open meeting. Um, you

[1:29:17] know, some of the, the critique I've heard of this has been around

[1:29:21] a lot of these charts, and a lot of the discussion sounds similar to the discussion around the pcm.

[1:29:26] so can you kind of compare and contrast this to the pcm

[1:29:30] market design that we had, uh, so many discussions about previously?

[1:29:35] absolutely. And, and if you just bear with me with a moment, I'll sort of start with

[1:29:40] an analogy and then we'll get into the specifics of how it can differ from

[1:29:44] the, the, the pcm. So I think there, what we've heard

[1:29:49] from folks is, is potentially some, um, some

[1:29:53] reactions that are, well, this looks like pcm or this is a capacity market.

[1:29:57] and, and I think part of that is that when you're seeing something that you're,

[1:30:02] that you, you've never seen before or is new to you, um, and we see this with

[1:30:06] lots of innovations and things that you're, you're gonna describe it like something, you know,

[1:30:11] and for example, if, if you're, you're going to the ocean for the

[1:30:15] first time with, with, with a child and saying that you see a,

[1:30:19] a, a big creature jump out of the water and, and the child says, hey, look at the big

[1:30:23] fish. Well, um, a whale is not a fish. Um,

[1:30:27] but you can forgive them for, for mistaking the difference between the two.

[1:30:32] and so I, I sort of look at these reactions the same way, because

[1:30:37] the, the primary difference between the drs ancillary service plus

[1:30:41] case and the pcm is, uh,

[1:30:45] we talk about, uh, our market as an energy only, but that's

[1:30:49] not entirely true because we have ansley service markets.

[1:30:54] we have a crr market, we have an ers process, so we have

[1:30:58] things that compliment the energy only market, and one of them is ansley services,

[1:31:03] which is, which is what drs, uh, is designed

[1:31:07] to be an ansley service. And so what we have done in this release

[1:31:11] factor process is to use that ancillary service mechanism

[1:31:16] and to allow it to enhance resource adequacy.

[1:31:20] and so it will be paid like an ancillary service. It'll be settled like an ancillary service.

[1:31:25] and, and so it's using that mechanism. And so we don't

[1:31:29] have a mechanism like that today. Um, and it's my understanding that no

[1:31:33] market has a mechanism quite like that. And so it is

[1:31:37] not a separate mechanism like you would see with the

[1:31:42] capacity market, like you would see with the pcm that sits outside of

[1:31:46] that existing structure. And so really, we're using

[1:31:50] ansley services to promote resource adequacy. And I think that's

[1:31:54] very different. And, and, and I think one of the things that I think of is

[1:31:58] there, there are, there are different ways you can achieve resource adequacy. Um, just

[1:32:03] like you have many creatures swimming in the sea, but not all of them are

[1:32:07] capacity markets. And not all of them are pcm in this case. It is in fact an ancillary service,

[1:32:12] um, um, to promote resource adequacy.

[1:32:16] it's kind of a fishy analogy. Uh, anyway,

[1:32:20] any other questions or comments on this particular subject? There's

[1:32:24] a lot to digest here. Thanks for this analysis. And all

[1:32:28] of us are still digesting the very thorough aurora report.

[1:32:33] um, was any analysis done looking at like a

[1:32:37] $0 price floor and $0,

[1:32:43] um, any price floor at all? No. We,

[1:32:47] we did not look at, uh, price floors as, as part of the analysis.

[1:32:52] okay. Okay. Public, did you want to, I, I was just gonna add

[1:32:56] on to chair thomas's, uh, chairman gleason's question. And

[1:33:00] I, I think I, the important question that, that I also hear

[1:33:04] often time and as we discussed this, is why does this question

[1:33:08] keep coming up? Why, why are we continuously trying to find

[1:33:13] something to address what is either a perceived

[1:33:17] or real gap in the energy market? And

[1:33:21] as you look back historically over the last 10 years, you see a

[1:33:25] trend of resource additions onto the grid that has been fairly consistent

[1:33:30] and steady defined by the market construct that we're operating today.

[1:33:35] and its primary focus on economic signals being the,

[1:33:39] um, what drives favorability and for success in the market.

[1:33:44] what's, I think not fully considered in our current market design,

[1:33:48] and, and I alluded a little this a bit to this in my comments last night at the annual meeting,

[1:33:52] is that, you know, the market design was fundamentally put in place at a

[1:33:56] time when all of the resources that were

[1:34:01] operating with that, uh, construct were fairly homogenous. They

[1:34:05] were thermal resources, long duration. There were coal, there were nuclear, they were in

[1:34:09] actual gas. And so what the market design, which was intended to

[1:34:13] drive efficiency did, is it drove, it was driving efficiency among

[1:34:17] a resource set that had the same operating and reliability characteristics

[1:34:21] or very similar ones. And it would replace less efficient thermal

[1:34:26] resources with more efficient thermal resources, with the introduction

[1:34:30] of a completely different set of resources that have

[1:34:34] different operating characteristics and different reliability characteristics like

[1:34:38] wind, solar, and short duration resources. The same market

[1:34:43] construct, which is designed to bring efficiencies only

[1:34:47] is now doing so with resources that have very different reliability

[1:34:51] characteristics. And, and that's the reason why this issue exists, is

[1:34:56] because the original intent, which was always assuming to deliver reliability,

[1:35:00] because the reliability characteristics were the same in the, in the

[1:35:04] construct and in the resources that they were going to, it was gonna be supporting. But

[1:35:08] because those characteristics have changed so meaningfully, we now have, uh, over

[1:35:12] 70 gigawatts, 70 gigawatts of renew of, of

[1:35:17] wind and solar installed on, on the ercot grid. We reach periods of

[1:35:21] time where 75% of the energy delivered in the ercot

[1:35:25] system is coming from just wind and solar. We have a completely different

[1:35:29] resource mix. And so the economic incentives have remained fundamentally

[1:35:34] the same. The operating characteristics are radically different than what

[1:35:38] they were 25 years ago. So that's the reason this

[1:35:42] question keeps coming up. We are trying to find a way to continue to sustain this market for the next 25

[1:35:46] years, and now we're facing a large high growth environment ahead of

[1:35:50] us. And so we're trying to figure out how do we keep up with that growth? How do we

[1:35:54] make sure that we can be ahead of that growth so that the bedrock

[1:35:59] of this organizational's mission, which is reliability, never falls

[1:36:03] behind the needs and the expectations of texans on a business

[1:36:07] or on a residential front. And so I think that's really the important question, is to acknowledge

[1:36:11] that we've got this issue fundamentally, and that the underlying system has

[1:36:16] changed. And so we have to find a way to continue to support those

[1:36:20] original goals of this energy only market. Those original goals were

[1:36:24] presumed reliability and improved efficiency with subsequent

[1:36:29] investment in subsequent refreshments. Those original goals are not

[1:36:33] being met in the same way today because of the very different characteristics

[1:36:37] of that resource mix on the grill resource mix on the grill on the grid.

[1:36:43] thank you. That's helpful. Any other comments or questions?

[1:36:48] okay, so I'm sorry, real quick, sorry. Um,

[1:36:53] pablo, you said one comment about building for the next 25 years. So do you think

[1:36:57] drs if used correctly, can be what is solving

[1:37:02] the problem for the next 20 to 25 years? I, I think it has the potential

[1:37:06] to, because it's, it's, it's tied directly to

[1:37:10] the, um, to the shortfall

[1:37:14] of a balanced resource mix. Looking forward using that reliability

[1:37:19] standard, the intention would be use the reliability standard analysis to

[1:37:23] identify if in the future we're gonna lack the appropriate mix to meet reliability,

[1:37:28] and then find the most cost effective way to get there, to get the, that

[1:37:32] answer. And so if it's constantly providing real

[1:37:36] time in injects into the market, looking ahead at a need to

[1:37:40] anticipate the needs of the market a few years down the road, which that reliability standard

[1:37:44] analysis will do, I think it has the potential to keep up with what is needed.

[1:37:49] and this is based on, you know, a set of assumptions. It's looking at 2030, it's looking at the assumptions

[1:37:53] we've put forth, which was the high load case, the assumptions that aurora put forth, which were the

[1:37:57] moderate load case. And it says, okay, based on those assumptions, here's the numbers.

[1:38:01] but as that changes, which changes every week, it'll be able to adapt

[1:38:06] to those needs by constantly having that view of looking forward and trying to

[1:38:10] fill in that gap. So I do think it has the potential to be a sustainable part

[1:38:14] of that solution set. And, and frankly, I think it's a, it's a relatively low

[1:38:18] risk way to put something into the toolbox that as

[1:38:22] the commission and the stakeholders in the market look at that growth being

[1:38:26] realized, we start to see is the economic growth actually materializing to

[1:38:31] the degree and to the speed that, uh, that we anticipated? May we

[1:38:35] now have a tool that we can, you know, put in place and, and see how that works.

[1:38:40] okay. Any other questions? So keith, update us on one

[1:38:45] last issue. So this is under consideration now, and what, what are the next steps? When

[1:38:49] does the board see this again? So, so, um,

[1:38:53] with regards to the drs ancillary service scenario

[1:38:58] that you'll see in june. Okay, my understanding and discussions

[1:39:03] with, with, uh, ta leadership is they're, they will

[1:39:07] bring both, but if they can't do both at the same time,

[1:39:11] 1310 will go slower. 1309 would go faster. Okay. As we discussed

[1:39:16] yesterday. As discussed yesterday. Okay. I just wanted the board to recognize

[1:39:20] this is coming back. Any other questions, comments?

[1:39:24] uh, do we need aurora to comment or we good at this stage?

[1:39:29] okay. Looks like we're good. Thank you, keith. Thank you. Uh, the next is agenda item

[1:39:34] 16, system planning operations. There are two sub items. The first

[1:39:38] is agenda item 16.1, system operations and winter

[1:39:42] weather update presented by dan woodfin. Dan,

[1:39:48] good morning. Got, uh, three items I wanna talk to you about this morning. Uh, the first

[1:39:52] is kind of a preview of, um, winter, maybe

[1:40:06] not moving. Okay.

[1:40:11] okay. Um, so, um, our meteorologists are expecting

[1:40:15] a cooler winter over average

[1:40:20] across the entire winter this year than what we've seen say the last four

[1:40:24] years, but that still would be above average

[1:40:29] temperatures over the course of that winter. We've just seen such hot winters,

[1:40:33] uh, the last, uh, four years that we could still be

[1:40:37] cooler than those. And on average, high, hotter and all. They're

[1:40:42] also expecting that we'd see, uh, from a precipitation perspective,

[1:40:46] that we'd see drier than normal conditions over the course of the winter.

[1:40:51] now, as, as we talk about every year, even in an above average

[1:40:55] temperature, uh, period over the course of the whole winter, that

[1:40:59] doesn't mean that we will not see significant coal spell during

[1:41:03] or one or more significant coal spells during that winter.

[1:41:08] and I think there, there may be more potential than that this year, since we've

[1:41:12] already started to see some disruption of the polar

[1:41:16] region. Uh, and it's caused really the northeast quadrant

[1:41:20] of the us to see pretty cold weather already this, uh, so there's

[1:41:24] always the potential for that. And that means we've, uh, collectively as an industry need

[1:41:29] to be prepared for it. And, um, pablo talked

[1:41:33] about this morning, some of the, the preparation work that we're, we're doing, uh,

[1:41:37] through our weatherization program.

[1:41:41] the next thing I wanted to talk about was we, we've talked about the last several meetings that

[1:41:45] we're doing various studies related to ride through characteristics

[1:41:51] of these new large electronic loads. And jeff talked about

[1:41:55] yesterday that we're proposing, and the board has now made that a

[1:41:59] priority revision, uh, to put in place, uh,

[1:42:03] ride through standards for on a going forward

[1:42:07] basis for these large electronic loads. But these studies

[1:42:12] are really studying what's, what's already on the ground or what's already been approved to energize.

[1:42:17] and so before we got too far into those studies, we wanted to give the opportunity

[1:42:21] for the large electronic loads to provide updated

[1:42:25] information so that we're not as having to assume kind of the most

[1:42:30] conservative ride through characteristics, but if they have the

[1:42:34] capability to do better than that, they can. They, we issued an rfi

[1:42:38] that would allow them to provide better information to us. And

[1:42:42] of course we had to ask for that through the tsps 'cause we don't have a

[1:42:46] direct relationship with these large electronic loads. And we also put out a market notice.

[1:42:51] and when we got back, uh, we got responses from nine of 24

[1:42:56] rfis that we sent out. Um, only two of them showed that

[1:43:00] they had better than the kind of the, what we call the iic

[1:43:05] curve, the, um, um, that, that, that

[1:43:09] kind of more, um, conservative, uh, assumption that we've been making

[1:43:13] in these studies. So the studies going forward that we'll be bringing at forward to the stakeholder

[1:43:17] groups, and probably here as well over the next couple of months

[1:43:21] will be, um, uh, including the id curve for all, but those

[1:43:26] that that show, um, that provided responses

[1:43:30] that they can do better than that. Um, now there

[1:43:34] is an ongoing opportunity for those guys to, uh, provide

[1:43:39] better data, update their models, go through that process.

[1:43:43] so there's, there's still that opening, uh, as, as we, uh, work

[1:43:47] forward. So it, it highlights the need that,

[1:43:52] that we may need a more direct relationship somehow

[1:43:56] with these, uh, the large loads so that we can communicate with

[1:44:00] them more directly and request information and then get information back from

[1:44:04] them, is what we've, we've kind of the point of that.

[1:44:10] and then finally, uh, we do a, a black start training every year. And of course,

[1:44:14] we don't want to ever have a system black start type

[1:44:18] event, but that doesn't mean we shouldn't plan for it. And so we have a plan in

[1:44:22] place for restarting the grid if that were to ever happen. And, uh,

[1:44:26] not only do we have a plan, but we train on it every year. This year we,

[1:44:30] we did that through a six week cycle. So there's a different group of people

[1:44:34] that go through the training on our simulator, including people

[1:44:39] from ercot, my staff and ercot operations, but also people

[1:44:43] from qsc and people from that own generation or that operate

[1:44:47] generation and also transmission owners. And we go through a simulation

[1:44:51] to say, what if it, what if we had to restart the grid? How would that work? And

[1:44:55] so we had a really successful one this year, uh, but about 750

[1:45:00] market participants that were involved in that. And I just wanted to highlight that because

[1:45:04] it's not something you hear about every day, but it's, it's really a important

[1:45:08] function, um, and involves a lot of people, obviously.

[1:45:13] and that's it. I'm happy to answer any questions. So

[1:45:18] is it appropriate, appropriate to, uh,

[1:45:22] ask what the, uh, longest and shortest black

[1:45:27] start scenarios look like? It's, uh, we

[1:45:31] don't want to do it. And in fact, because it would take longer than anybody would be

[1:45:35] comfortable with. Okay. And, you know, in fact, one of the things people always ask, well,

[1:45:39] what could get us into that kind of situation? And I ha

[1:45:43] always answer that, well, if we figure out something that might

[1:45:47] get us in that situation, you'll see an nprr or some rule change

[1:45:52] or some operating procedure change that will eliminate that risk

[1:45:56] as quickly as possible. Yes, sir. That's, that's the appropriate response. Okay. Good.

[1:46:00] any questions? Okay, jury, I

[1:46:05] have a generic question. Um, now that we've implemented

[1:46:09] rtc plus b, congratulations in our decks are the

[1:46:13] typical operating metrics, are you projecting any

[1:46:18] moderate changes in what the trend lines we're seeing as a result of rt c? I think that's

[1:46:22] something we've been looking at very closely the last several days.

[1:46:26] um, we've actually, I sent a note this morning, what about this?

[1:46:30] and so we're, we're definitely looking at this. I think we, when we have more of a trend line

[1:46:35] than having three points on it, we'll, we can come back and, and make kind

[1:46:39] of more of a here's the, what we've seen both between me and keith, I think.

[1:46:44] okay. Anything else for dan? Dan, do you have anything else? Okay,

[1:46:49] peggy? Yeah. Hey, dan, I remember you presented to us after

[1:46:53] the event over in europe mm-hmm . About, uh, looking at

[1:46:57] lessons learned from that and ways to improve to get back

[1:47:02] online quickly if we have an event. Are you guys still evaluating that?

[1:47:06] and, uh, um, can you provide us an update?

[1:47:10] um, we, we've done some things. One of the things that we're looking

[1:47:14] at is, uh, the potential for, um, um,

[1:47:20] temporary ac ties that we could use to, to make the island kind of the restoration

[1:47:24] happen faster. I think that was one of the lessons learned that that could happen.

[1:47:29] um, the, they were able to get that grid back. Blake started very quickly,

[1:47:34] amazingly fast, in fact, uh, because of that, I actually hosted a group from

[1:47:38] portugal recently, and, uh, that was one of the things that we talked about with

[1:47:42] them. And so I think we're, we're looking at that. We've got a couple of different

[1:47:47] kind of low level initiatives going on to look at that. Uh,

[1:47:51] but that's, that's our intent to still learn from that. We don't have anything

[1:47:55] ready to bring for you yet.

[1:48:00] okay. Dan, I think that's it for you. I'm gonna say anybody else raise their hands.

[1:48:04] so we're gonna pr uh, move to agenda item 16.2, system

[1:48:09] planning and weatherization update. And, uh, christie's gonna be back at the podium for

[1:48:13] this presentation.

[1:48:17] all right, so we talked about the infrastructure needs from a transmission perspective.

[1:48:22] and so I think as you look at some of the updates that we're seeing on the system, both

[1:48:26] from the large load and the generation kind of completes that

[1:48:30] picture. So I wanna share where we're at on those stats as well as work

[1:48:34] that we're doing and the resource adequacy, the weatherization. Um,

[1:48:38] and then finally some updates on where we are on reviewing

[1:48:42] the information received from stakeholders from ger 2 45,

[1:48:50] large load interconnection request. Um, a lot of press

[1:48:54] being given to how this queue has, and

[1:48:58] I should say queue because there is not a queue of a first in, first

[1:49:02] out, but how this group of large load request has really

[1:49:06] grown over time. As you can see on this slide, we

[1:49:10] are tracking over 226 gigawatts of large load

[1:49:14] requests as of november 18th. But

[1:49:19] to show you how quickly things are changing, I asked the team on friday,

[1:49:23] so what have we seen in the, in the next several days

[1:49:28] as of this past friday, that number is now up to 233 gigawatts.

[1:49:33] so we continue week after week to see more interest in

[1:49:37] connecting to the ercot grid. Over 75 or

[1:49:42] 70% of those requests are data center request

[1:49:46] across the system. And recognizing,

[1:49:51] um, you know, we, we hear the developers loud and clear

[1:49:55] the need for certainty, and we agree there's need for certainty, and we also

[1:49:59] recognize there's need for improvements to the process. If you look at what's

[1:50:04] happened just since the beginning of this year, so when we met

[1:50:08] last year at this time, we were tracking about 83,000

[1:50:12] megawatts worth of requests over the course of 2025.

[1:50:17] that's grown. Now, as I just stated, we're up to 233

[1:50:22] gigawatts. That's almost a 300% increase

[1:50:26] in the amount of megawatts that are wanting to connect to the ercot system.

[1:50:33] we have outgrown the process that was established for reviewing these large

[1:50:37] loads. It was originally set up for,

[1:50:41] we were thinking about 40 to 50 loads back in the

[1:50:45] 2022 timeframe. And as you can see now,

[1:50:50] we're tracking, just this year we received 225

[1:50:54] new requests. So this,

[1:50:58] the amount of loads in how we study them, we can no longer be looking

[1:51:02] at them individually because we have to look at their impact to each other as well.

[1:51:07] um, again, on this one, these stats were pulled on november 18th,

[1:51:12] as of last friday, we had had an additional five new requests come in in that short

[1:51:16] period of time over the thanksgiving holiday and last week.

[1:51:23] I guess one thing I would note, um, when you look at the request on

[1:51:27] the large load slide and the amount of megawatts, you know, over 200 gigawatts

[1:51:31] of request, we recognize the importance of working with

[1:51:35] the commission to implement the sb six

[1:51:40] statutes that were put forward to be able to get better information about

[1:51:44] the certainty of which of those loads move forwards. Just like the large

[1:51:48] generation interconnection queue that we'll see in a couple slides,

[1:51:52] we don't expect that all of those will materialized. So again, it's very important to

[1:51:56] get those low forecasting and standardization rules in

[1:52:01] place so that we have better information as we're studying and making recommendations

[1:52:05] on how to move forward.

[1:52:11] here's the slide that I was looking for, 2000 generation requests,

[1:52:16] and this was as of october. And again, those things are changing as well. I had the

[1:52:20] team take a look at what we had as the end of november, and we've

[1:52:24] actually gotten additional, uh, megawatts in from those requests as

[1:52:28] well. Tracking over 432 gigawatts. That's now up to 435.

[1:52:34] but what I would say is the most notable, you know, we've seen the trend

[1:52:39] month after month that the majority well over, almost 80%

[1:52:44] is coming from solar and battery energy storage request. We

[1:52:48] are still, we're starting to see an uptick in the natural gas, uh,

[1:52:52] request as well. When we were here in december of last year,

[1:52:56] we were tracking 26 gigawatts of gas as of november 30th,

[1:53:01] that number is now up to almost 53 gigawatts.

[1:53:09] always like to keep you updated on how the texas energy fund projects are

[1:53:13] moving through the process of those seven gigawatts or 18

[1:53:17] projects that are moving forward. We actually had our first project

[1:53:21] pen peaking, um, receive its part one approval to energize. So

[1:53:25] it's actually connected to the system going through testing and enabled

[1:53:29] to, um, to produce energy.

[1:53:36] just another snapshot of looking at how the generation is materialized

[1:53:40] in 20 24, 25 in 2025. Across

[1:53:44] those years, we saw about 23 gigawatts of generation resources synchronized

[1:53:48] to the grid. Um, but you can tell the majority of those are coming from

[1:53:53] these blue lines, battery energy storage or the green lines, which

[1:53:57] are solar. As we look ahead, those resources

[1:54:01] that have already gone through our qualification process and are planning to energize,

[1:54:06] uh, q1 of next year, we're looking at almost another 10 gigawatts coming

[1:54:10] to the system. Again, those are mainly comprised of solar

[1:54:15] and battery energy storage.

[1:54:19] from a transmission planning perspective, um, the team has been really

[1:54:24] busy. So not only looking at ways that we can improve the planning

[1:54:28] processes, looking at, um, the potential, uh, implementation

[1:54:32] of 7 65, but just the sheer volume of projects. In

[1:54:36] fact, in 2025 alone, um, we've more than doubled the amount of

[1:54:40] projects that the team has reviewed and brought forward to you. Um,

[1:54:45] this year we got in study or have already brought forward

[1:54:49] 48 various projects last year. That number was 22.

[1:54:55] I think that trend will continue, uh, as we start to look at receiving

[1:54:59] projects from the utilities to implement both our 2024

[1:55:03] rtp and 2025 rtp roadmaps

[1:55:09] from a resource adequacy reporting perspective. Um, the graphic in the middle just

[1:55:13] gives you a quick snapshot of our monthly outlook on resource adequacy

[1:55:18] at the time we put these slides together. Both december and januarys were available

[1:55:23] this past friday. We also published the february more and we see

[1:55:27] a consistent trend, um, this year compared to last year,

[1:55:32] lower chances of going into emergency operations or

[1:55:36] even load shed given our probabilistic analysis.

[1:55:40] and the main reasons for that is, you know, you think back to the previous slides, the amount

[1:55:44] of generation that has been added to the system since then, um, is

[1:55:48] playing a key factor. One other note,

[1:55:52] uh, wanted to or two other notes from the resource adequacy reporting perspective,

[1:55:57] each may in december, we come out with our capacity, demand and reserve

[1:56:01] report. This is really, um, a log of all of the

[1:56:05] generation that has met certain requirements for coming onto the system into

[1:56:10] the future years, as well as our forecasted demand that we

[1:56:14] received from input from the utilities. And that release is planned

[1:56:18] for the third week of december. Per protocol requirements

[1:56:22] did wanna highlight, we will be pushing out a market notice to make all participants

[1:56:26] aware, but one thing we're doing differently this year is we're actually going

[1:56:30] to have a draft version of the capacity, demand and reserve report

[1:56:34] available to the supply analysis working group page.

[1:56:39] so it, it will be available to anyone, um, that would like to review it as

[1:56:43] a draft form. Um, as we found, um, getting input from the stakeholders

[1:56:47] throughout the process has been beneficial and making sure that final report

[1:56:51] that we put out, um, is meeting, um,

[1:56:56] our requirements. We will have our protocol required

[1:57:00] requirements, and then we've also added in some additional scenarios that look

[1:57:04] at the impacts of our assumptions

[1:57:09] based off of the senate bill six large load curtailment and the

[1:57:13] texas energy fund assumptions. So for example, generation

[1:57:17] that is in the texas energy fund hadn't met the protocol requirement for

[1:57:21] being included in our ledger of generation that's available. Those are some

[1:57:25] scenarios that we'll look at as a part of that report just to give people different perspectives,

[1:57:30] um, on different scenarios that could play out. Pablo

[1:57:34] also mentioned the reliability standard analysis. So we've

[1:57:38] been working with commission staff, uh, as well as our

[1:57:43] staff to prepare for next year's work that will be undertaken

[1:57:47] as the first reliability standard assessment for puc rules.

[1:57:52] uh, earlier this month, uh, we filed in in coordination

[1:57:56] with the, from input from the tsps, um, information

[1:58:01] as to the magnitude. So if you think about the reliability

[1:58:05] standard has three legs, it's frequency, magnitude, and duration.

[1:58:10] and the reason for the magnitude piece is we recognize

[1:58:15] from lessons learned from winter storm uri, the utilities can only safely

[1:58:19] rotate through a set amount of megawatts on their system

[1:58:24] until they get to a point where they can no longer rotate through customers. So

[1:58:28] we take input from the tsps on their capabilities, compile that

[1:58:32] information, and we've provided that to the commission, which will be one of the

[1:58:36] inputs going into next year's reliability assessment.

[1:58:41] we're also working on what our assumptions will be for our model

[1:58:45] that we'll run next year for the assessment. We'll be filing those with the

[1:58:49] commission in mid-january. It will open up an opportunity for stakeholder

[1:58:53] comment on the assumptions that will go in, and then

[1:58:57] based off of commission decision, that'll be finalized. And

[1:59:01] then we'll run throughout the summer, be running our model analysis and we'll keep you updated

[1:59:06] on that as we move through next year.

[1:59:10] weatherization perspective, you know, this group was

[1:59:14] established in 2021

[1:59:19] we have going into, um, this winter season.

[1:59:23] and you can see the trend is we've been doing more and more resources

[1:59:28] and more transmission facilities over time. That's

[1:59:32] as we've added additional staff, but more importantly because there are

[1:59:36] more resources and more transmission elements on the system. So in advance

[1:59:41] of winter to help, uh, work with stakeholders, we really tried to make this,

[1:59:45] uh, a collaborative program where we

[1:59:49] are providing input, sharing best practices. So we've had workshops with,

[1:59:54] uh, the utilities, with the resources. Um, we've held additional,

[1:59:58] um, sessions for those new resources coming to the system to help

[2:00:02] them prepare their documentation and answer their

[2:00:07] questions about the, the rule and preparations. We started our weatherization

[2:00:11] and inspections last week, um, and we've completed

[2:00:16] 13 transmission and 21 resource inspections. Uh, we've

[2:00:20] got a target of doing at least 430, uh, throughout the

[2:00:24] winter season. And we really use a risk-based approach on how we choose

[2:00:29] which, uh, resources and utility, uh, equipment that we go

[2:00:33] in and research. So for example, um, from a resource perspective,

[2:00:37] we're looking, there's a rule requirement that we must see 'em at least once every three years.

[2:00:42] so have we seen them yet in that three year period? Have we seen them in a weather,

[2:00:46] um, season? Have they had previous issues and

[2:00:50] we need to go back to make sure they have corrected, um, and cured those, those

[2:00:54] problems. And then most importantly, newly commissioned resources,

[2:00:59] making sure they understand the rules and are prepared

[2:01:04] in the off seasons. Um, one thing I did want to highlight, one of the things that the weatherization

[2:01:08] inspection team does, because they are um, across the state,

[2:01:13] is we are able to utilize them to go out and inspect the,

[2:01:17] the facilities, um, that have been awarded the firm fuel supply service

[2:01:21] to make sure, um, they are prepared as well for going into the, the

[2:01:25] winter season in case that service has to be called upon

[2:01:32] noer 2 45. Um, so this is based on inverter

[2:01:36] based resources and requirements that they meet, uh, voltage ride

[2:01:40] through requirements. We continue going through the

[2:01:45] analysis of the information that we received from the resources

[2:01:49] back in september. We are looking at

[2:01:54] their three categories of request. They can request

[2:01:58] an extension so they believe they can meet the requirements,

[2:02:03] but they need additional time maybe to work and make changes in the field.

[2:02:07] there are entities that are requesting an exemption. They do not feel that they

[2:02:12] can meet those and um, there's no changes. Maybe they're an

[2:02:16] older type turbine, for example, and they can't make changes to their configurations

[2:02:20] to be able to meet the ride through requirements. And then we have some

[2:02:24] entities that have requested both because they're still maybe working with their vendors

[2:02:29] and they don't know whether they can make it. They think maybe they can,

[2:02:33] but then they might not be able to. So they've requested both to be on the safe side.

[2:02:38] we're right now prioritizing our review of the extension request.

[2:02:43] um, and updated stat, this says 130, but

[2:02:47] out of as of um, earlier, uh,

[2:02:51] this or late last week as of friday, we'd sent out

[2:02:55] 141 notices of missing information to resources.

[2:03:00] so looking at those extension requests, we found that additional information

[2:03:04] is needed or wasn't provided correctly

[2:03:11] from an exemptions perspective. Um, a key part

[2:03:15] of that is providing models to show

[2:03:19] what their, their capabilities are so that we can review that.

[2:03:23] um, there are 72 resources that were seeking an exemption that

[2:03:28] still have not provided their models, which were to have already

[2:03:32] been provided to us. So we continue to try to obtain those

[2:03:36] from the resource entities to be able to run the reliability

[2:03:41] assessment next year. It's important that we have good dynamic

[2:03:45] model information, so when we run

[2:03:49] to see whether or not we can grant an exemption, we need to know

[2:03:54] what's currently on the system and how it's gonna interact and whether

[2:03:58] we can take, um, except it's a minimal level of risk

[2:04:02] for that particular entity that's asking for an exemption.

[2:04:07] as of the time of pulling these slides, we had over 400 resources that

[2:04:11] still had not provided their updated models to their capabilities.

[2:04:16] and so this, once we receive those models, we have to go through a model quality

[2:04:21] test. It requires, you know, additional review by ercot.

[2:04:25] so it's very important that we get that information from the

[2:04:29] resources to be able to then do the reliability

[2:04:34] assessment next year. So, christie,

[2:04:38] what's their obligation to provide it? I mean, is that a mandatory obligation or

[2:04:42] voluntary obligation? It's a mandatory, um, obligation

[2:04:47] via the nodal operating guide rules that were passed and approved by the

[2:04:51] puc and what are the consequences that they don't by

[2:04:55] a certain date. So if they don't, this would be something then we could turn

[2:04:59] over to, um, our erm that would review

[2:05:03] for, you know, non-compliance with the protocols and guides

[2:05:07] and then turn that over to the commission for enforcement. That's a substantial

[2:05:11] portion that you're still waiting for. Yes.

[2:05:16] I just wanna follow up. Did you wanna say something? Go ahead. Okay. I just wanted

[2:05:20] to follow up on that line of questioning. Christie. I know we've made a little bit

[2:05:24] of progress in this area, but it is quite frustrating,

[2:05:29] a lack of responsiveness, especially given how long it took us

[2:05:33] to get this passed in the first place. And, uh,

[2:05:39] when you come back and report on this the next time,

[2:05:43] if we're not not making significant progress, I think we need to have a more

[2:05:47] fulsome discussion about what our options are. And maybe the commission needs

[2:05:51] to be thinking about that too, because it's a serious issue.

[2:05:55] thank you. Well, can I add onto that, uh, what's

[2:06:00] tax's role once they pass something to help encourage

[2:06:04] compliance to a new role? Should we ask tax to also

[2:06:09] address this matter?

[2:06:14] I mean, tech leadership is listening. They can, um, I, I don't

[2:06:18] think there's a lot of value on what tech can do. You're talking about individual companies now that have

[2:06:22] a compliance obligation on the roles and that we've interacted with for quite

[2:06:27] some time. So I think we have the ball as we're

[2:06:31] managing to understand where we're going with the reliability assessments.

[2:06:35] as christie indicated, there are mechanisms to move this over to the

[2:06:39] enforcement side. And so we're kind of balancing out all that as we look at a tremendous

[2:06:44] amount of data that still has quality issues associated it with

[2:06:48] it, and a lack of models that have come in. So

[2:06:52] we will continue to manage it with, as pablo has indicated, and christie's indicated at

[2:06:56] some point, we will move forward and do the reliability assessments based upon the information we have.

[2:07:00] and those outcomes will, will, we'll move forward with either granting

[2:07:05] or not a, granting the exemptions or the extensions.

[2:07:09] and, and then from there, it it is a compliance regulatory process that

[2:07:13] falls within the commission to ultimately handle at the end of the day. And

[2:07:18] I think what might be needed, chad, at some point, is a plain english

[2:07:23] language communication to all the affected parties,

[2:07:27] reminding them of their obligations and the consequences of not fulfilling

[2:07:31] them. Those communications have happened

[2:07:36] in plain english or in lawyers speak.

[2:07:40] plain english. Okay. Not, not misunderstood.

[2:07:44] yeah. Things that engineers can understand. This is what happens if

[2:07:49] you don't do it. Uh, to go back to julie's, uh,

[2:07:53] comment, I don't know that we wanna put tac in an enforcement position. That's not really their role.

[2:07:57] well, and I think they'd be uncomfortable with that. Let me, let me give a little background. This

[2:08:01] is a member organization, uh, wasn't asking so much

[2:08:06] tax enforcement so much as what are they seeing

[2:08:10] causing resistance and delays in the membership that agreed to do this?

[2:08:15] yeah. Feedback. Yeah, I think would always welcome their feedback. Chair

[2:08:19] gleason. Yeah. Mr. Chairman, since um, compliance and enforcement got brought up,

[2:08:23] maybe I'd ask our deputy executive director barksdale english to speak to

[2:08:28] staff's role in enforcing, uh, these provisions. Thanks,

[2:08:32] chairman. Um, so as chad mentioned, the, um, the

[2:08:37] erm process, uh, is, is gonna be ercot

[2:08:41] staff's primary way for referring any outstanding

[2:08:45] issues to the commission to seek enforcement over. Um, my staff

[2:08:49] works very closely with the, the reliability monitor here. And,

[2:08:54] um, we are constantly juggling the myriad issues that,

[2:08:58] um, that face the stakeholders here and trying to prioritize

[2:09:02] which, um, which efforts need to be, um, escalated

[2:09:07] and move forward more quickly. Um, this is certainly a, an

[2:09:11] important one. Um, and we also wanna recognize that

[2:09:15] the exemption process that christie was talking about is, is novel,

[2:09:19] uh, for this market. And so I think, uh, in my opinion, ercot

[2:09:23] staff is doing a good job of trying to provide a little bit of grace to allow the member companies to

[2:09:28] figure out how to get through that process. Um, but

[2:09:32] I would agree with the members', uh, concerns here that at a

[2:09:36] certain point we need to, you know, call time and, and start moving forward

[2:09:40] with something more serious and in an enforcement investigation. Uh, and

[2:09:44] just so the members are aware, uh, failure to comply with ercot

[2:09:49] protocols, uh, could result in a daily fine of up to $25,000

[2:09:53] per violation or potentially being kicked off

[2:09:58] the, the grid. That could be a resulting action as well, sir?

[2:10:02] yes. Okay. Uh, so those 416

[2:10:07] noncompliant members need to get their information in 130 that have missing

[2:10:11] information, need to get that in. So for those that are listing in kristy, keep going.

[2:10:17] that completes my update. Any questions? Okay. Any questions?

[2:10:22] all right, very good. Uh, if there are no other

[2:10:26] questions for christie, uh, we'll move to agenda item 17,

[2:10:30] other business. Is there any other business that any other board member would like to raise?

[2:10:36] hearing none, the board will recess and convene an executive session. Follow the

[2:10:40] executive session. We anticipate several voting items, so general session

[2:10:44] will reconvene at the conclusion of the executive session. The general session

[2:10:48] of ercot board of directors meeting is now recessed and the webcast will be suspended.

[2:10:52] chair gleason. Thank you. Thank you mr. Chairman. This meeting,

[2:10:56] the public utility commission of texas will stand in recess.

[2:11:03] okay. Good afternoon. I'm bill flores ercot, board chair. I hereby reconvene this meeting

[2:11:08] of ercot board of directors. I've confirmed that a quorum is present in person.

[2:11:12] this meeting is being webcast live to the public on our cop's website.

[2:11:16] uh, we have three voting items, uh, carried over from

[2:11:20] executive session, uh, for, uh, this is agenda item

[2:11:25] 18. Uh, first I'm gonna entertain a motion for board approval of the two

[2:11:29] personnel matters discussed during executive session. Under agenda items

[2:11:34] es 2.4 and two point.

[2:11:41] so moved. Uh, thank you, peggy. Is there a second? Second.

[2:11:45] okay. Second for chris. Thank you. All in favor a. Aye.

[2:11:49] any opposed? Any abstentions? The personnel matters are approved

[2:11:53] as, uh, as presented. Next, I'll entertain

[2:11:57] a motion for board approval of the contract matter discussed during executive session under

[2:12:02] agenda item es 2.7 0.1.

[2:12:07] john, thank you. Second, julie. All in favor? Aye. Aye.

[2:12:11] aye. Any opposed? Any abstentions? The contract matter has been

[2:12:15] approved. And then lastly, I'll entertain, I'll make the motion,

[2:12:19] uh, to approve the selection of weaver and tidball lp as a 2026

[2:12:23] independent system and organization control auditor

[2:12:28] for the soc audit for 2025. 2026.

[2:12:32] second. Thank you, peggy. All in favor?

[2:12:36] aye. Any opposed? Any abstentions that has been approved? Thank you.

[2:12:40] the meeting of the ercot board of directors is now adjourned and the webcast will be concluded.

Dec 09, 2025 Board of Directors Meeting - ERCOT - Electric Reliability Council of Texas

Agenda

Transcript