[0:00] Good morning, members of the ERCOT Board of Directors and guests. I'm Paul Foster, ERCOT Board Chair.

[0:07] Welcome to the October 17, 2023 Board of Directors meeting. I hereby call this meeting to order.

[0:16] This meeting is being webcast live to the public on ERCOT's website. Before we begin,

[0:21] I'd like to ask Interim PUC Chair Kathleen Jackson if she would like to call an open

[0:26] meeting of the Public Utility Commission of Texas to order.

[0:30] Thank you. This meeting of the Public Utility Commission of Texas will come to order to consider

[0:35] matters that have been duly posted with the Secretary of State for October 17, 2023. I'm

[0:42] Kathleen Jackson and I'm joined today by Commissioners Will McAdams and Lori Cobos.

[0:47] Commissioner Jimmy Glopfelty is joining us online.

[0:50] Thank you. Before moving on to today's business, I want to report that Novoraj Pokaral of the

[1:00] Office of Public Utility Commission is attending as alternate representative in the absence

[1:06] of Board Member Courtney Yaltman in accordance with my law section 4.3D. I would also like

[1:13] to highlight to committee members that the antitrust admonition and security map

[1:17] are included with posted meeting materials.

[1:21] The first order of business on today's agenda is Item 2.

[1:26] Notice of public comment, if any.

[1:29] Today's meeting agenda was posted publicly on October 10th

[1:32] and provided instructions for the public,

[1:34] for commenting in person.

[1:37] To date, no one has expressed interest in commenting.

[1:40] Is that still the case, Chad?

[1:42] That is correct, Chair.

[1:43] All right. Moving on to agenda item 3, the consent agenda. I'll turn it over to Chad

[1:51] to provide the budget impacts of the revision request.

[1:54] Thank you. Okay. On the consent agenda this morning, you have two items on the list.

[1:59] Neither one has an ERCOT staff impact. However, both do have a budget impact.

[2:05] So NPR 1184 is broken into two phases. The first phase is less than 10,000,

[2:10] and the second phase ranges from 100,000 to 150,000

[2:15] and will take six to nine months to implement after PEC approval.

[2:19] The SCR has a small budget impact of less than 10,000.

[2:23] We'll be happy to answer any questions.

[2:28] Okay, thank you, Chad.

[2:30] With that, does any board member wish to discuss or remove any item from the consent agenda?

[2:38] Hearing none, if there's no further discussion,

[2:40] I'll entertain a motion to approve the consent agenda as presented.

[2:43] Thank you.

[2:46] Second.

[2:47] Second.

[2:48] Okay.

[2:48] All in favor?

[2:49] Aye.

[2:50] Any opposed?

[2:52] That motion passes.

[2:55] Next is agenda item 4, August 31, 2023, general session meeting minutes.

[3:01] There's a draft in the meeting materials.

[3:04] Does anyone have any comments or wish to make a motion?

[3:07] I move to approve.

[3:08] Thank you.

[3:10] Second.

[3:11] All in favor?

[3:12] Aye.

[3:12] Any opposed? That passes. All right. Next agenda item five is the CEO update. And Pablo is

[3:25] up front.

[3:28] Good morning, everybody. Thank you very much for joining to discuss the important

[3:35] work that we are doing at ERCOT.

[3:43] All right. So my comments today on regards to the summer

[3:48] operations are going to be somewhat brief because we're going to have a detailed review

[3:52] of the detailed operational review a little bit later in the agenda today.

[3:56] So today I'm going to just cover some brief highlights from the summer, including a perspective

[4:00] on some of the higher pricing that we saw in the wholesale market this summer.

[4:04] I'm going to briefly review our progress on some of the market, key market and protocol

[4:08] focus areas that our team are working on.

[4:11] I'm going to review our current activities as we're preparing for our next winter peak

[4:14] season. And as always, I'd like to close with thank yous to our members of our team that

[4:19] have been really working and making tremendous progress on key issues.

[4:26] So the summer was really book-ended with challenges this year. The June summer board

[4:33] meeting when we met actually marked the first of 11 conservation type of calls that we

[4:38] made all summer. And it was book-ended at the end towards the last half of August

[4:43] and into September with 10 additional conservation calls.

[4:46] The peak heat that we experienced this summer during July and during August when we set

[4:52] 10 new records on the system was managed very well because we had really great strong and

[4:58] consistent performance from thermal generators, from solar resources, as well as from wind

[5:03] resources and our energy storage resources throughout those periods.

[5:07] And in fact, when we had our peak, most of our peaks, those were not days that we had

[5:12] conservation calls if we had the performance of all of those resources working well.

[5:18] This summer we experienced some meaningful change in terms of when the scarcity period

[5:23] shifted from just a year ago at the same time.

[5:27] Last year, the scarcest period of time during the summer was during the gross peak on

[5:33] the system, which is around 3 or 4 p.m. in the afternoons in the summer, when the heat

[5:38] is at its maximum and demand is at its highest. We saw a change this year where that scare

[5:43] system tightest period actually shifted to later in the day to 7 or 8 o'clock at night

[5:49] as we were going through the solar ramp. And the reason being is that because during

[5:53] the gross peak, we saw so much addition of solar resources from this year compared

[5:58] to last year that those additional solar resources were able to pick up the

[6:02] energy requirements during the peaks in the afternoon. And so we didn't have scarcity during

[6:06] those periods. But we ended up having scarcity later in the day on the hot days when the

[6:11] heat remained into the evening, and we started to lose the energy from solar resources. That

[6:16] became the new scarcity and tightest period on the ERCOT grid. And that shift occurred

[6:21] for the first time this year.

[6:27] The intense heat that persisted this year was record

[6:29] setting through many parts of Texas. Here in Austin we had 42 days where we are above 105

[6:38] degrees. That breaks a record that was set back in 2011 when it was only 26 days back then.

[6:46] In 2021 we had zero days where load on the system was over 80 gigawatts. In 2022 we had one day

[6:53] where we hit 80 gigawatts, and this summer we had 49 days that we were over 80 gigawatts.

[7:00] The system was clearly stressed and stretched, but it held.

[7:05] I want to acknowledge the emergency operations that occurred on September 6th due to a combination

[7:10] of extreme heat that day, low wind, and an unusual wind condition where the west wind

[7:17] was less intense than the wind coming up from the coastal bend area, which set up

[7:22] for a transmission constraint between the San Antonio area and the coastal bend area

[7:27] where it was trying to get the wind generation resources up to meet the high demands in the

[7:31] central and northern parts of Texas. This led to some generation needing to be curtailed

[7:36] in order to manage that transmission congestion constraint, and which also led to an accelerating

[7:42] of lowering PRC and frequency decline that the control room was able to manage very

[7:47] skillfully by entering into EEA2 operations in order to access needed load response resources

[7:54] that are in our RRS service.

[8:00] To touch briefly on the cost this summer, there's been a lot of discussion about the

[8:07] higher prices that have been observed in the market this year.

[8:11] Dan and Kenan are going to cover that a little bit in detail later in the board

[8:16] meeting as well.

[8:17] But what I wanted to do is share a couple of perspectives on those prices.

[8:21] So top left shows the growth in demand.

[8:25] I think we've covered that pretty well.

[8:26] You can see from the awkward charts, 2021, the gray 2022,

[8:30] and the purple 2023, the peak demands in each of the months

[8:34] for the last few years.

[8:35] So you can see strong demand as we've just discussed.

[8:38] What hasn't been discussed as much is the fact that we are

[8:41] also increasing the amount of ancillary services that

[8:43] we procure in order to manage the real-time operational

[8:47] risk of operating the current market.

[8:49] And as you look at the graph on the top right, you can see the increased amount that is being

[8:56] paid for ancillary services from 2021 to 2022 and 2023.

[9:04] It's been reported that before that, I want to make sure it's clear that because more

[9:12] and more energy is being served by intermittent resources, the risk of a forecast miss in

[9:17] any given hour is increasing.

[9:19] And additionally, price response of loads are growing on the grid and can move their

[9:24] demand very quickly up and down as well in response to a variety of inputs, and we don't

[9:29] necessarily control those inputs.

[9:31] We just have to be ready to manage the impact of those changes.

[9:35] So the Ansari services that we procure have very specific operational purposes, and we

[9:40] buy them in an amount in order to manage those operational risks.

[9:43] We do it to manage frequency.

[9:45] to recover voltage and frequency should a large unit or large load instantly come offline.

[9:50] And they're utilized by the control room in order to manage the operational risks on the grid

[9:54] and to anticipate future operational risks that may occur during a giving operating day.

[10:00] They are not purchased or deployed specifically to influence wholesale prices.

[10:05] They are reliability tools.

[10:07] And they are deployed when they are needed in order to mitigate reliability risks on the systems.

[10:11] systems. So it's been reported that prices had increased by $8 billion this summer and

[10:17] attributed largely to the incremental ancillary services and in particular the ECRS service

[10:22] that we deployed this summer. Wholesale prices are really a function of the quantity of

[10:28] supply that is available to serve demand and the price bid that are offered by suppliers

[10:33] and by controllable load resources. Wholesale prices are not a good proxy for the retail

[10:40] costs that customers pay for electricity. In fact, in August we could see that nearly

[10:45] 75% of all electric purchases and sales were transacted in advance in the day ahead market.

[10:52] In addition, we don't get visibility to all bilateral contracts and transactions that

[10:56] take place between suppliers and purchasers, and we generally estimate that on average

[11:01] 90 to 95% of all energy transactions are hedged or purchased in advance at a

[11:10] So to conclude that costs have increased by $8 billion and

[11:14] assumes that somebody is paying for that $8 billion and

[11:16] that is an inaccurate way or an inaccurate conclusion to draw

[11:19] from the fact that wholesale prices were higher this summer.

[11:24] The actual cost associated with the increased ancillary

[11:27] services as shown on the top right on this slide, an

[11:29] incremental cost of $567 million this summer, that's

[11:33] the actual cost that was passed on to load and paid

[11:36] for by load directly.

[11:38] The drivers of price quantities is one of those key drivers.

[11:43] Price bids is another, and the bottom left shows a new pattern of increasingly higher

[11:49] price bids by resources that are able to build in opportunity costs into their price bids.

[11:55] And you'll see in 2021, we did not have any price bids that were over the $4,900 a megawatt

[12:01] hour level.

[12:02] In 2022, we started to see some through June, July and August, and in 2023, we saw quite

[12:07] a bit more, especially as we got into August during the very high scarcity periods of

[12:12] time that led to some of the higher pricing.

[12:19] The market is responding to the operational conditions as it is designed to do.

[12:25] When there is scarcity, as we experienced this summer due to extreme weather, due

[12:28] to economic load growth, we're going to see higher prices in an energy-only

[12:32] market which is designed to incentivize the development of new resources in order to meet

[12:37] those demands.

[12:41] So I'll pause on here if there's any questions before moving on to my next segment.

[12:45] Pablo, I have a question.

[12:47] Do you have a sense of how responsive load was to higher pricing?

[12:53] And I know that's a very difficult thing to measure, but can you comment a little

[12:57] bit on what happened when you issued these requests for conservation?

[13:03] Yeah, we saw really, I think, very strong response from load during the conservation

[13:08] periods this summer. We can look at it. We can measure some of them very clearly and

[13:13] specifically. We have the ability to see some of the online energy uses of some of the

[13:18] larger industrial loads on the system, and we could see them respond when those

[13:22] conservation calls, as well as when prices would get high.

[13:26] On the consumer level, the way that we typically measure and assess the performance

[13:32] We look at the expected forecast for energy usage

[13:36] during periods of time in the afternoon in advance.

[13:39] We look at what that forecast looked like before

[13:41] the call and then we look at how that curve changes

[13:43] in real time and we can attribute a significant

[13:46] portion of that to the response.

[13:49] And that can be from a variety of reasons.

[13:50] It can be from the ERCOT response that people

[13:52] are responding to but also a lot of the retail

[13:54] electric providers and transmission distribution

[13:57] companies have load management programs or demand response programs that

[14:00] customers can avail themselves of and they leverage those throughout the

[14:04] summer during the peak periods and so we saw really strong performance and

[14:07] benefit from those and we had to use them. Can we quantify that at all? It's

[14:12] we've seen you know on average so anywhere between 500 megawatts to 1500

[14:16] megawatts is a general kind of a range that we experience when we have one

[14:21] of those conservations. A couple of percent. That's right and that's just on

[14:24] the consumer side. On the industrial load, it's a little bit stronger. We see between

[14:29] 2,000 and 3,000 megawatts sometimes on the industrial side.

[14:32] Second question, if I may. In the lower left-hand chart here, can you characterize who is bidding

[14:39] that dispatchable energy at the 4,900 and above megawatt hour level?

[14:43] Yeah. The type of resources that are able to build in an opportunity cost into their

[14:48] bidding strategy are those that have time or duration-limited elements to their energy

[14:54] supply. So energy storage, resources and batteries are able to do bidding of that nature. I believe

[14:59] pumped high.

[15:05] I think it's really beneficial for the audience. It's watching this to see the real data from

[15:14] this summer. Just to clarify and reiterate, the total cost of ancillary services this summer

[15:20] was just under $600 million. That was the incremental cost. So if you look

[15:24] at the chart, it's where about $1.2 billion total in 2023, and the increment over last

[15:31] year was $567 million.

[15:33] So that's the incremental cost this summer of ancillary services.

[15:36] That's very helpful.

[15:37] And so when you look at this, the real numbers compared to the $8 billion headline and all

[15:43] the underlying data that drove that $8 billion headline, that was inaccurate.

[15:48] Is that correct?

[15:49] Yeah.

[15:49] The $8 billion is just what the price of energy in the wholesale market was.

[15:52] because it was basically the price times the amount of energy being served, but that is

[15:56] not the cost that people were paying necessarily at those periods in time.

[16:00] And that's why the data that I shared around how much of the energy transactions are hedged

[16:05] and advanced, are done in the day ahead market, or outside of that, those are the actual

[16:09] costs that are being paid for by basically retailers who are purchasing and how suppliers

[16:16] are getting paid.

[16:17] Okay, I think that's important that the public knows that there is no $8 billion cost increment.

[16:22] So thank you.

[16:23] Yeah, thank you.

[16:25] Mr. Chairman, if that may?

[16:27] Yes.

[16:28] All right, Pablo.

[16:32] So it's important for the Commission to ask some questions, and we can either do it

[16:36] here in front of the full Commission.

[16:38] But affordability of energy is one of our primary responsibilities, next to reliability.

[16:45] And we've got to start digging into these numbers.

[16:51] But on August 25th, I was up at 11 p.m.

[16:55] And I took a screenshot of market prices at that time.

[17:01] And market prices in the day ahead averaged at $3,800 a megawatt hour.

[17:10] from 4 p.m. in the afternoon to 10 p.m. in the evening.

[17:17] And that's the day ahead.

[17:19] And so these hedges you're talking about were having to be procured

[17:23] because of the uncertainty on how the market would react

[17:27] as compared to system forecast,

[17:31] but also how ancillaries would be deployed the next day.

[17:35] And that's where we get into methodologies used by the system to both procure ancillaries

[17:42] and how they're used.

[17:45] And I think we would all recognize that the system is short of necessary capacity that

[17:52] we need to manage through a more volatile system which is more dependent on intermittent

[17:57] resources.

[17:59] But it's the uncertainty on how we're going to manage through that on a day-to-day

[18:04] basis that will drive up day ahead costs. And, again, that will not influence price

[18:13] responsive behavior to the degree that is desirable to us because we want them to respond

[18:19] in real time to real time prices so that they turn down their consumption.

[18:23] That's right.

[18:24] But if they've already locked in their energy at almost $4,000 a megawatt, then they're

[18:33] going to be as responsive to real-time prices because they've already booked that cost.

[18:38] So my question is, and we've talked about this at the Commission, it's important to

[18:45] recognize how the system is going to operate in a high-intermittent environment. And that's

[18:52] what you and your operators are dealing with on a day-to-day basis. Do we think we could

[18:57] issue some type or develop some type of guidance to the market and the system on how, given

[19:05] the penetration of renewables, you believe you will need to operate moving forward in

[19:13] proportion to that penetration with ancillaries so that those forwards can be, those forward

[19:20] prices can be managed accordingly based on that guidance.

[19:24] Is that possible?

[19:25] And I say guidance, it's a very specific word because it's not a protocol but it is

[19:32] how we believe we'll need to operate moving forward so that the operators continue to

[19:36] maintain flexibility but the market knows generally the doctrine that you're operating

[19:42] under.

[19:43] Yeah, I think I understand what you're asking and it makes a lot of sense.

[19:48] We want to try to signal to the market as clearly and as close to real time as

[19:54] possible what the expectations are in order to help them make the right decisions in terms

[19:59] of how they want to operate their assets, how they want to manage their portfolio of

[20:05] supply and demand.

[20:06] And so I think what you're asking for is very reasonable.

[20:09] And we desire to try to do that at ERCOT to try to help the market because essentially

[20:13] if we can be very clear and transparent in what those expectations are in terms

[20:17] of how many ancillary services and of what type and for what reasons and kind

[20:21] of layout, kind of a forecast of, here's what we expect to do because this is the kind

[20:25] of variability we want to manage, the size of the variability that we expect at differing

[20:29] points in time throughout the year, and then the associated products that we intend to

[20:33] purchase in order to manage that, the market can anticipate that and start to bring

[20:37] to bear the resources that are going to most efficiently deliver the services of

[20:41] those products.

[20:41] Because the products that I talked about that manage regulation versus those that

[20:45] manage the risk of a unit tripping versus those that might manage a forecast risk

[20:50] have different characteristics and different cost profiles.

[20:53] And with the right information in advance,

[20:55] or the best information in advance to try to optimize,

[20:58] we can be much more efficient in the cost of procuring those ancillary services,

[21:01] and that benefits the whole market.

[21:03] And so I agree wholeheartedly with what you're asking,

[21:06] and it is our intention to continue to improve the clarity

[21:10] around what we're going to do in our ancillary services

[21:12] to provide that clarity to the market.

[21:16] Julie?

[21:18] Yes, Julie.

[21:19] I would like to follow Will's question with something a little more specific.

[21:25] In terms of forecasting ancillary services for this summer or next summer, can you shed

[21:32] some color on the drivers?

[21:35] Like how much was the excessive heat in comparison to true increased load because of the economic

[21:42] growth in Texas, for example?

[21:44] And I may, I'll start an answer and I may ask Dan to weigh in on this as well.

[21:49] So in general what we do, we set the methodology at the start of the year looking ahead at

[21:54] the next year with an anticipation of the kind of resources that we expect to be on

[21:58] the grid throughout different parts of the season and really looking at the kind of

[22:02] expected load carrying capacities during various seasons.

[22:06] And so then we set out a method, the methodology we use says here's how much risk or forecast

[22:10] that we expect to try to manage and procure

[22:13] through ancillary services.

[22:15] And we essentially set kind of a floor on here.

[22:18] We don't expect it to be below this, but it can be higher.

[22:22] And those decisions are then made

[22:24] in more in a real-time fashion.

[22:26] And Dan, that's where you could jump in and help here,

[22:28] how we make those decisions throughout the year

[22:30] in terms of what to buy on a given day

[22:32] and what is the drivers of those decisions.

[22:35] Yes, so we basically this ancillary service methodology document that defines this minimal

[22:42] amount that we're going to buy for each hour of the year, we very rarely buy more than

[22:48] the amount that is designated in that document.

[22:52] And so each ancillary service has certain drivers because each ancillary service has

[22:57] to be provided by resources with certain characteristics.

[23:00] And so we buy a certain amount of each one based on the risks that those unique characteristics are needed to cover.

[23:09] And so, but we very rarely increase it more than those minimal amounts that are published in typically December type time frame.

[23:20] Is that a public document then or is it?

[23:23] Yes, I think so.

[23:29] Oh yeah, and it will come to the board in December for approval actually.

[23:34] Thank you. Pablo, following up on, I guess, everything that's being asked, one, first

[23:45] of all, it's great to have the IMM look at, you know, what's happened and based on that

[23:51] look at their advice and to hopefully implement what we can. ECRS is identified as an issue

[23:58] in their analysis as a distortion in terms of when the ancillary service came in and

[24:06] therefore the prices that were paid for it. That's one. Second, the analysis is really

[24:14] exposed always what happened and in the absence of a crisis then you look at pricing and affordability

[24:22] and of course that's a big issue but I think ex ante analysis is important

[24:28] because the cost of 4,900 dollars per megawatt hour is very high but the cost

[24:37] of not having power is infinite. So that has up type analysis that for

[24:43] example in my industry we do all the time is very important because the

[24:47] alternative is catastrophic.

[24:51] That's right.

[24:52] Maybe put those elements into the analysis to understand

[24:56] reliability and affordability as something that's

[25:00] actually connected.

[25:01] That's exactly right.

[25:02] They're intrinsically connected.

[25:03] And trying to assess the economics without understanding

[25:06] the underlying operational risks that are being

[25:09] managed and the decisions that are being made in real time

[25:11] to manage those risks doesn't really do justice to the

[25:15] overall picture of why the market is costing and pricing the way that it is.

[25:20] That's an excellent point, Carlos.

[25:22] We'll work to try to augment and supplement some of the analysis that comes out from an

[25:26] economic perspective to help tie that to the real-time operational risks that are being

[25:30] managed during those periods in order to help better quantify and qualify the impacts

[25:35] that the market has seen.

[25:37] And, of course, review how the, you know, ancillary services work and based on

[25:43] that try to adjust as we go.

[25:44] I mean, this is a system that has so many variables.

[25:49] It's not that there's parables and economists would look at it, right?

[25:53] It's not like steady state and things are normal.

[25:57] No, we're bursting in terms of demand, economic growth, record heat.

[26:02] I mean, just old installed capacity.

[26:07] It's just too many factors that are working in the system.

[26:11] And that's why I was saying match affordability and reliability together into the same equation.

[26:17] Absolutely.

[26:17] That's an excellent point, Carlos.

[26:19] Thank you.

[26:20] Pablo?

[26:21] Yes.

[26:22] And first you can correct me if my statement is wrong, because I'm not sure it's entirely

[26:27] right, but I view the ancillary services as kind of a backstop for underlying weakness

[26:35] in our market design, right, and which is why we're procuring more of them.

[26:38] Maybe not all ancillary services, but the fact that we're creating more and more ancillary

[26:44] services to me is indicative that the fundamental market design is not working.

[26:50] And how do we get beyond that?

[26:52] I know we talked a lot about PCM, everything seems to be kind of on hold.

[26:55] What's, first of all, do you agree with my premise?

[26:59] And then second of all, how do we fix the underlying market so we rely less on

[27:03] ancillary services?

[27:04] Yeah, I think I agree with the premise that the underlying market design hasn't recently

[27:11] been incentivizing a balanced mix of additional resources onto the grid, and that has led

[27:17] to a grid that has evolved to be more volatile and have more operational risk because the

[27:24] type of resources that are being incentivized are intermittent resources and those with

[27:29] shorter durations, and so the complexities of managing a growing demand and a very dynamic

[27:35] load environment with those types of resources becomes more and more challenging.

[27:40] So to manage that risk, we do have to increase the portfolio of ancillary services in order

[27:45] to anticipate any variation or issue that could happen across all of those factors.

[27:50] So I would agree that one leads to the conclusion that you put forth.

[27:55] I think the answer, there's a suite of solutions that are being developed today that are intended

[28:03] to start to address this. PCM is clearly one of those. PCM, as it's the performance credit

[28:08] mechanism, is a mechanism that's designed to provide a consistent revenue stream during

[28:15] the tightest periods on the grid throughout the year to generators or to load that can

[28:21] provide that at that point in time.

[28:24] And so the key behind it is that it's consistent, a consistent revenue reliability stream that

[28:30] could be planned on for many years, and it's not subject just to the volatility of an energy

[28:36] only market pricing model.

[28:37] So PCM certainly is part of that solution, and we're going to be continuing to advance

[28:41] PCM aggressively in order to try to incorporate the benefits it should bring.

[28:46] The legislature put forth legislation to incentivize dispatchable generation development,

[28:53] specifically in Senate Bill 2627.

[28:56] That is going to go before the public for a vote this November,

[29:00] because there's a portion that requires a constitutional amendment to do.

[29:05] And with support, that will incentivize through low-interest loans

[29:10] and completion bonuses the development of dispatchable generation resources,

[29:15] which are the ones that were not seen enough really come onto the grid in recent years.

[29:19] And then the changes that we're going to put forth, the operating reserve demand curve

[29:23] floor adder change, which is going to bring up the floor adders during times of scarcity,

[29:29] that's intended to also provide revenue to the types of resources that are operating

[29:33] during scarcity periods, which largely are dispatchable type resources in order

[29:38] to help give them revenue to stay operating and to stay active in the market versus

[29:43] if though they're considering potentially retiring or mothballing, the idea is provide

[29:47] the revenue to incentivize them to stay in the market.

[29:50] So we're doing a variety across the board between short-term changes in the energy only,

[29:55] the PCM, which is a longer-term reliability signal, and then hopefully with the passing

[29:59] of the

[30:04] We'll see those incentives combined to incentivize a more balanced development strategy going forward.

[30:10] And that's what we're looking forward to and what we're building towards.

[30:14] Mr. Chairman, if I may, just kind of sort of observation from Bob's statement.

[30:21] You know, I think all markets across the country are experiencing the same issues we are with respect to a higher penetration of renewable energy

[30:28] and less dispatchable generation being built.

[30:30] So whether that's an energy-only market or a capacity market, all markets are dealing

[30:34] with the same issues.

[30:35] So I'm not sure that it's a sign of one specific market structure failure, just case in point.

[30:41] Number two, I think what I've heard is the ancillary service methodology needs to

[30:47] be clearly set forth so that the LSEs and everybody can plan forward and hedge and

[30:52] to create some forward price stability.

[30:54] I think, you know, with the ancillary service methodology being approved in every year in

[31:00] December, I don't know that the market could really anticipate when and how much ECRS was

[31:07] going to be purchased, and so now going forward, you know, that procurement should become more

[31:13] stable and transparent, but we also have DRS coming up right behind that, and so understanding,

[31:19] I mean, you know, that ERCOT give the market as much advance notice as possible on how

[31:26] much DRS is going to be procured through that ancillary service methodology is really important

[31:30] because whether it's the ancillary service methodology that sets forth what and how

[31:35] much ERCOT's purchasing per year to maintain reliability or it's other costs that ERCOT

[31:44] is, you know, we're going to, you're going to talk about capacity contracts later. It's

[31:49] really important for the market to understand what these costs are going to be because

[31:53] if they can't hedge against them and plan forward, then those costs will be passed

[31:58] through to consumers. And especially with LSEs like Munis and co-ops that directly

[32:05] serve the consumers and retailers that have to bake those prices into their electricity

[32:11] So, the more in advance and transparent ERCOT can be through the ancillary service methodology

[32:17] and other market mechanisms, the better for everyone in terms of consumer cost and weighing

[32:23] in with reliability.

[32:24] Yes, I agree completely, Commissioner.

[32:26] I think that's our goal as well.

[32:28] And the DRRS service is going to be one that will be completed next December.

[32:33] So it will be largely leveraged into 2025.

[32:36] So we'll have an opportunity as we work through some of the ancillary service

[32:39] service methodology changes this year that's already started discussion at the public utility

[32:43] commission.

[32:44] That'll be part of the factoring for the incorporation of that new product as it comes online.

[32:48] Thank you.

[32:52] Thank you.

[32:52] Peggy.

[32:53] Yeah, thank you.

[32:54] Thank you, Pavel.

[32:55] So if I recall correctly, this slide says that we had the 10 peak demands in 2023.

[33:02] If I recall from the last meeting, we had 10 in 2020, summer of 2022.

[33:08] to. We have 11 new peaks last year and 10 peaks

[33:13] at this year. Yeah, which is incredible. A lot of growth.

[33:18] A lot of growth. And what are we projecting? Or do we have good numbers projected like

[33:24] the next two years out on the economic growth piece? Is it going to continue?

[33:30] So our estimates, when we disaggregated the demand growth that we saw this summer,

[33:36] we estimated approximately 60 percent of the demand growth to be coming from economic growth

[33:42] and roughly 40 percent coming from the higher extreme heat that we experienced this summer.

[33:48] And so if you look at that kind of that 60 percent of that demand growth, that's around

[33:53] 3,000 megawatts of incremental growth from last year's peak.

[33:57] And so if we see something, I mean, what we are anticipating is that the pace of growth

[34:02] growth in Texas will continue at a similar pace as it has in the last few years. There's

[34:07] really no economic signals to indicate that that's going to change meaningfully. So we're

[34:12] anticipating that that kind of growth is going to continue going forward.

[34:19] Any other

[34:19] questions?

[34:20] Just one.

[34:21] Oh, Catherine.

[34:23] One of the things that I noticed during the summer, particularly from an operational

[34:28] standpoint, is how important it was to have all the tools in the toolbox, but

[34:34] but also the flexibility from an operating standpoint to be able to utilize those ancillary

[34:41] services when they were needed. Could you just maybe comment on kind of going forward

[34:49] what your vision is for maintaining flexibility and, you know, meeting all of the challenges

[34:55] that we are trying to kind of manage through this management of change and also to address

[35:02] it from a risk standpoint?

[35:03] Yes, it's I think that's a really good way to describe it and flexibility is becoming the most one of the most important

[35:11] attributes of a reliable grid in today's construct and that's not just in Texas. It's all throughout the US and throughout the

[35:17] world because flexibility is critical to manage the different drivers of change that are going on on the grid and it's

[35:24] It's not just the intermittency of certain renewable sources.

[35:29] It's not just the dynamic nature of the types of loads and large loads that are coming onto

[35:35] the system.

[35:36] It is all of those factors combined together.

[35:40] And in addition, a growing resource and energy storage resources, which are a tremendous

[35:44] value to the grid, and that we are learning how to leverage more effectively.

[35:48] And I think of 1186, which is a good example of trying to maximize the flexibility that

[35:56] we can get from all of the resources and harvesting the energy and energy storage resources fully.

[36:02] That's something that is important as we look forward to needing more and more flexibility

[36:06] on the grid going forward.

[36:08] So that will be something that we'll try to describe as we lay out the ancillary

[36:13] services, the characteristics of flexibility that they're providing us and the kinds

[36:18] of variability that they're helping us manage through, and our intention is to continue to

[36:22] use that portfolio fully in order to be able to manage all those issues.

[36:26] And I think it's important to note that during the scarcest periods and when we get to the

[36:30] actual tightest periods on the grid, we deployed all of those resources.

[36:34] So we get to progressive points as we get to being more and more scarce as the demand

[36:39] gets closer to the supply levels, and we start to release and utilize all of those

[36:45] resources to meet the capacity needs of the moment. They're really not designed to be

[36:50] capacity reserves. They're designed to meet specific operational flexibility needs. But

[36:56] when you get to a place where it's the only energy that's available, we use it. And we

[37:00] used all of the ancillary services that were available to us on multiple occasions

[37:04] in order to maintain reliability on the grid. And so it's critical that we think

[37:09] about them through that lens of flexibility. But in the end, we will use all of them

[37:14] as needed in order to serve the energy needs of the grid.

[37:19] Pamela, just one follow-up comment from earlier.

[37:22] And Commissioner Nicobo is correct that all markets are struggling with the impact of

[37:27] intermittent and the like.

[37:28] And the fundamental problem from all RTOs and ISOs is no one has taken on the impact

[37:34] of what subsidies do to a market.

[37:37] And we try to backfill it with ancillary services rather than designing a market

[37:43] that compensates based on different characteristics, right?

[37:47] So as long as subsidies are out there and they're out there in a massive way,

[37:50] as long as we ignore that from a market design standpoint,

[37:54] this is what we're going to have year after year, more and more ancillary services.

[37:57] So until we design a market structure that rewards for characteristics,

[38:03] we're going to continue to have this problem.

[38:05] I think that's an excellent point. I think there's two factors.

[38:08] I think the subsidies distort all of the markets through the lens that you're describing.

[38:12] And in addition, there is EPA regulation that creates a lot of uncertainty.

[38:17] And that uncertainty makes it very difficult for those who are trying to plan meaningfully

[38:21] large investments in dispatchable generation that would last for 30 to 40 years.

[38:26] The economics of how those units could run under differing scenarios of EPA that we talked

[38:31] about in our August meeting I think is another factor that's also slowing down the balanced

[38:36] growth of resources on the grid in the U.S., in Texas, as well as throughout the

[38:40] for us in the country.

[38:43] Mr. Chairman, just one follow-up thought for Pablo, if I may.

[38:47] We've been wrestling with this at the Commission for some time,

[38:50] and I know it's been discussed around the boardroom.

[38:54] We're trying to make market behavior respond as expected

[39:01] in the way the ERCOT system is being managed.

[39:05] and to respond in concert with the way the ERCOT system is being managed.

[39:11] And the ERCOT system can only be managed according to what the operators are seeing in real time.

[39:17] That's right.

[39:19] And without sufficient capacity, the flexibility is lacking for the grid administrator to be confident

[39:28] that they can meet minute-by-minute needs of the system on any given day.

[39:35] And I think part of the challenge is, and I think what we're seeing in the numbers,

[39:40] and maybe the discrepancy between what the IMM publishes

[39:44] and what ERCOT seeds from their market analytics,

[39:48] is the market is having trouble anticipating

[39:51] what the grid administrator believes they're going to need on any given minute, on any

[39:57] given day. And it is important to have that transparent forecasting, but forecasts can

[40:04] be wrong, methodologies can be wrong. And it's, we're uncharted waters because we

[40:12] are constrained by laws, substantive rules of the commission, and ERCOT protocols

[40:19] which have force, in terms of allowing the administrator the flexibility to adjust in real time

[40:27] and then giving guidance to the market so that they can anticipate how the control room will react.

[40:34] And I think that's what we're struggling with at each one of these meetings.

[40:38] And so all I can say is, Pablo, do you believe in the near term?

[40:44] And all this is based around market forces.

[40:47] And that's what all of the markets, PJM, ISO, SPP, even though those are filled with vertically

[40:55] integrated utilities, those are still predicated on market forces, not controlled by the regulators

[41:02] of those individual states.

[41:04] The market dictates how they respond.

[41:07] Do you believe that we can start publishing some type of guidance outside of our protocols

[41:15] to give the market a little bit more signals from what because ERCOT is

[41:21] farther ahead of every other system in the country and frankly every other

[41:25] system on the planet in terms of dealing with a high intermittent resource mix.

[41:31] Do you think we can start publishing that type of guidance in the next year

[41:36] to give a little bit more insight in how you believe you'll need to

[41:41] managed through the system, as these pressures only increase. And the reason I keep stressing

[41:47] that is because we're the test case for the country. I mean, FERC is looking to us, DOE

[41:53] is looking to us, everybody's looking to Texas to sort of manage through this. And everything

[41:59] you print is going to be important. And I know that's a lot to lay on you, and that's

[42:03] a lot to lay on your control room, but do you think we can start publishing that

[42:07] so that it helps smooth out the effects, like I described on that August 25th day,

[42:12] where we want price responsive behavior in real time.

[42:16] But the uncertainty is driving everybody just to secure themselves on price well in advance.

[42:22] I will certainly commit to following up on that question, Commissioner.

[42:26] I'd love to talk with the team and the control room and to get a sense for what we could put forward

[42:31] that would be helpful and continue to try to communicate openly

[42:34] what our intentions, our actions, our forecast, and what our plans are in order to help the

[42:40] market be better responsive and to be better able to understand what to expect.

[42:44] So I think it's an excellent question.

[42:46] I don't want to go too deep right here without having an opportunity to really work with

[42:50] the operations team.

[42:51] But I'd love to explore that question further.

[42:54] So thank you.

[42:56] Thank you, Pablo.

[42:57] I just have one quick question in that or really comment.

[43:01] And that is where the 8 million was erroneously reported.

[43:08] Not only did Kimba did that deliberately,

[43:11] that somehow they misinterpreted information that they got from ERCOT.

[43:17] Is there something that we can do to better communicate that data,

[43:24] that information, so that it gets reported correctly in the future?

[43:28] Yeah, I think there is an opportunity. When we start to look at the operational data and

[43:34] the economic data that gets published, I think there is a good opportunity to try to add

[43:39] to it an explanation of what it means beyond just what the numbers are. Because the pricing

[43:46] data is the pricing data. The $8 billion existed in the market. But the interpretation

[43:52] of that, what it means was misinterpreted and published in many headlines to say cost

[43:57] went up in the Texas market by $8 billion.

[44:00] And what that then draws people to conclude is that consumers and businesses paid $8 billion

[44:07] more this summer.

[44:08] And that was an incorrect conclusion to draw from that data.

[44:11] So I think there's definitely an opportunity as we publish this information to really add

[44:16] to the analysis what is the interpretation, what are the conclusions that we as ERCOT

[44:21] and as a commission draw from this information and be helpful to the audience, to the

[44:26] to the general public who really wants to understand what's happening on the electric

[44:30] grid and what's happening in the ERCOT market. I think that's an excellent point, Paul.

[44:36] Pablo, I'd like to, but I know you've got more for your report, but I'd like to try

[44:40] to put a bow on this part of the discussion. The big problem here, I mean, as Commissioner

[44:46] McAdams said, ERCOT is trying to manage through massive uncertainty, and that's

[44:52] reason it has all these products that have a cost is trying to make sure that we don't

[44:58] experience.

[45:00] The cost of a lack of reliability. So we're paying for reliability in addition to energy.

[45:05] And the reason we're having to do that is we have gale force winds coming from the federal government primarily that have heavy subsidies for intermittent power, which is hard to dispatch.

[45:16] And it's irregular in terms of its performance. The second thing is we've got the EPA with four new rules out that impede the development, the continued operation of legacy dispatchable assets

[45:28] assets, and also impede the construction of new dispatchable assets, which would solve

[45:33] a lot of this problem.

[45:34] You've got an EPA rule that increases demand on the grid, or that could increase demand

[45:39] on the grid.

[45:40] At the same time, the other four rules are destroying the supply of power available

[45:45] on the grid.

[45:46] And then you've got a market construct here in Texas that really doesn't quite

[45:50] get us to the point where we can incentivize the construction of new dispatchable generation

[45:56] to offset all those Gale Force wins.

[45:59] Is that a fair way to characterize where we are now?

[46:02] You've got all these factors that hurt the ability

[46:05] to have more dispatchable power,

[46:07] so that we don't have to worry about this uncertainty

[46:10] and would have good reliability at an affordable cost.

[46:14] Bill, I think that characterizes

[46:15] the supply side of the story very well.

[46:18] I think that describes the Gale Force wins

[46:20] that we're trying to work our way through

[46:21] and that investors and operators

[46:23] are trying to manage their way through

[46:25] in terms of what's possible given all of those conditions.

[46:28] I think when we talk about the long-term future for ERCOT, we have to talk about the supply

[46:33] as we are in this conversation, but then we also have to look at the role that transmission

[46:38] is going to play to help to potentially alleviate some of the pressures and the needs in

[46:43] the system and then also look at the demand side and see what we can do in terms of

[46:47] a more robust and holistic demand side capability that includes engaging consumers

[46:53] more in demand response programs, leveraging the potential of large

[46:58] industrials that have a tremendous opportunity to really manage their

[47:01] electric usage closely with ERCOT and then also of course, you know, low

[47:07] hanging fruit around energy efficiency and you know, smart investments on that

[47:10] front. I think we really need to look at the portfolio over the next few

[47:13] years in order to try to manage this because as you know, to build a

[47:17] power plant, you start the concept today and in, you know, two to four

[47:22] to five years, depending on the type of power plant, you'll have something come online.

[47:26] And so we really need to be thinking about what's the holistic set of solutions that

[47:30] we have available to us to manage this growing risk profile.

[47:33] Those are great points.

[47:34] Thank you.

[47:37] Okay.

[47:38] Thank you for the robust discussion and the questions.

[47:41] And obviously, this is very important to us.

[47:43] The economics of the ERCOT market are critical.

[47:46] They're reflected in our strategic priorities, and it's something that we want to make

[47:49] sure we're always as clear and as transparent as we can be as to what's happening

[47:53] and why the pricing is what it is fundamentally.

[47:58] I have just a couple more slides.

[48:00] I wanted to just touch briefly,

[48:02] really a reminder of kind of the key development

[48:04] and focus areas that we are working on.

[48:06] We went through many of these in detail

[48:09] in the August meeting,

[48:10] so I just want to refresh folks that the ORDC curve,

[48:13] which I talked about,

[48:14] that's actually going to be coming online here in November.

[48:17] And so that will be a new added revenue stream

[48:21] to try to incentivize and support reliability in the energy-only market.

[48:26] The DRRS, the new ancillary service is working through the TAC design process right now.

[48:32] We've had workshops on that.

[48:34] We intend to be communicating with PUCT staff and commissioners the intended design and

[48:39] construct for that, bring it back to the board in December on here's the approach

[48:43] we're going to take, and then we'll start working fervently on the actual development

[48:47] and coding of this to have it ready to go next December.

[48:50] PCM, as I talked about, is going through a scoping process right now.

[48:54] We plan to review that with the PUCT in November and then have a straw man design approach to

[48:59] bring back to the PUCT and we're working with market participants in January and February

[49:04] to really earnestly start the design work of PCM.

[49:08] Our goal is to have that design completed in 2024.

[49:12] And then the real-time co-optimization initiative, it should be the RTC plus

[49:17] be because we're incorporating the management of batteries in the state of charge inside

[49:22] of the real-time co-optimization engine. That is progressing forward as well. We've recently

[49:28] been focused on the interim state of charge issue in NPR 1186, and assuming if that gets

[49:34] approved by the board, or I think that was just approved this morning, that will

[49:37] now go forward and be developed. And then the reliability standard work is progressing

[49:43] very well. We've brought two different iterations of reliability standards to the Commission

[49:48] for Discussion. We filed and ran 48 different scenarios. We have a few additional proposed

[49:54] scenarios that we're going to be running through that add more inverter-based resources

[49:58] into some of the assumptions to see how the system would perform in that regard.

[50:02] There was an ERCOT and PUC staff workshop this past Friday to review that current analysis.

[50:08] And future work related to this is going to be incorporating the value of lost load,

[50:13] as well as developing a new cost of new entry study so that the costing side of this overall

[50:19] reliability standard process is as accurate and current as it needs to be.

[50:25] And then with regard to some of the kind of operating initiatives,

[50:29] you've been working on nodal operating guide revision request 245.

[50:33] This is a revision request that's focused on operating requirements for inverter-based resources,

[50:39] which are wind, solar, and battery resources.

[50:42] The IEEE organization, the National Engineering Standards Organization,

[50:47] has developed a standard called IEEE 2800,

[50:50] which sets essentially a uniform set of technical minimum requirements for the interconnection,

[50:55] the capability, and the performance of inverter-based resources

[50:57] that are connected to transmission and sub-transmission systems.

[51:00] And this is a recommended standard that they have

[51:04] produced.

[51:04] It is not required in any regulation or policy in

[51:08] Texas or outside of Texas at this point.

[51:10] So we are working through how to take elements of those

[51:13] standards and bring those into the operating guide

[51:16] requirements in Texas in order to help manage the

[51:19] stability and the increasing risks of stability

[51:22] that happen as more and more inverter based

[51:24] resources are running on the grid.

[51:26] We're working with the operators of those

[51:27] resources as well as with the OEMs that

[51:30] actually manufacture the underlying assets.

[51:33] And then large flexible loads, as I've talked about, this is a growing demand area on our

[51:40] system.

[51:40] It's something that we have to pay very close attention to.

[51:43] We're trying to also come up with requirements that ensure that large and flexible loads

[51:48] can ride through stability events on the grid because the loss of a large load is

[51:54] very similar to the loss of a generation supply.

[51:56] It electrically is the same.

[51:57] And so we really want to make sure that as we have more and more inverter-based resources

[52:01] and more and more large, flexible loads, the standards and the expectations around how

[52:06] to operate on the ERCOT grid are clear.

[52:09] And so that's something that we're working very closely with the developers of those

[52:16] assets and with the owners of those businesses.

[52:20] So let me move ahead into our winter preparedness activities.

[52:24] We'll pause if there's any questions on our current, and there's much more that's

[52:27] going on beyond these.

[52:28] These are the kind of the top market focused initiatives that we're going to keep in front

[52:33] of the board on a regular basis as well as a few of the protocol driven, more protocol

[52:37] and operating guide important issues that we're focused on.

[52:41] Mr. Chairman, Pablo, this is a really good look forward list.

[52:46] Could you just quickly tell us which of those might be implemented in 2024 and which

[52:51] ones are longer term or intermediate term?

[52:53] Yes.

[52:54] As the ORDC will be implemented this year, the DRRS will be implemented at the end of

[52:59] next year.

[53:00] Performance credit mechanism is tracking towards a 2026 completion date.

[53:05] Real-time co-optimization is tracking towards 2026 completion.

[53:09] The reliability standard should be completed in 2024, sometime in mid-2024.

[53:15] The Nogar 245, we're hoping to set standards related to that near the end of this year

[53:21] to the beginning of next year.

[53:23] and then the compliance dates go out into the future.

[53:27] And so we'll come back with more data

[53:28] on exactly how that is laying out,

[53:30] but that has further out compliance requirements

[53:33] because of the nature of potential changes

[53:36] that would be needed to existing assets

[53:38] to meet the requirements,

[53:40] as well as considerations for new assets

[53:42] that are connecting and the requirements for those.

[53:45] So that has longer term compliance dates.

[53:47] The reason I'm asking is,

[53:48] And as of this meeting, we have another board committee, technology and security.

[53:55] That's right.

[53:56] And I was wondering which of these might, you know, offline we could discuss which of

[54:00] these topics might better fit under technology and security.

[54:04] That's an excellent point.

[54:05] Excellent point.

[54:06] And then ideally we'd come to some agreement on the large flexible loads on what those

[54:10] kind of standards would be sometime in 2024 as well.

[54:14] I did want to mention that one of the things that ARCOT did was put together

[54:19] on those top five, the big five, I guess you call it, a workflow diagram as well as you

[54:24] came to the Commission and gave summaries on each of those initiatives. And so it's something

[54:29] that you have already kind of put in place, if you will, milestones, and you are tracking.

[54:36] And that is, of course, something that was filed with the Commission and continues to

[54:40] be updated by ERCOT so very much. You know, I think a good work effort in order

[54:46] to keep the commission informed as well as the public informed in terms of the progress

[54:52] that we're making and the milestones that we're meeting on those very important five

[54:56] top objectives.

[54:57] Thank you, Chair.

[54:59] That Chair Jackson, that's exactly right.

[55:01] So we're wanting to try to keep everybody informed as we progress and it also maintains

[55:05] the history of kind of the genesis for many of these projects as well as the milestones

[55:09] as they are achieved through that kind of tracking process and workflow document.

[55:13] So that is available and we'll keep that current.

[55:19] So as we look ahead to the winter, as we said before the summer even ends, we do begin preparing

[55:24] for the next peak season, which is going to be the winter season.

[55:29] One of the things that was remarkable in this preparation year is that we, as we

[55:36] looked at some of the analysis that came through the new monthly operational assessment

[55:42] of resource adequacy, which used to be done seasonally was the CERA report where we would

[55:48] look ahead at the subsequent season and we would put together and do modeling to assess

[55:53] different types of weather and resource availability scenarios in order to determine what kind of

[55:59] risks the system would be managing through under differing scenarios.

[56:04] It wasn't a forecast of expected outcomes, but it was really more modeling what our

[56:09] potential outcomes that could occur.

[56:10] We have moved that now to a monthly process, which allows us to be more granular and closer

[56:16] to the period in which the operating conditions will be occurring.

[56:20] And we're also focusing on being more granular when it comes to the risk assessments on an

[56:25] hourly basis.

[56:26] So now we look at a month, and we look at each of the operating hours in that month,

[56:32] and we run probabilistic models to assess what are the risks at each of the hours

[56:37] in those months under thousands of different weather scenarios and load and supply scenarios.

[56:43] And so that first Moira report was published for December in October.

[56:49] And so that report highlighted that the increased demand that we have seen on the grid since

[56:56] last year created higher probabilities of risk during certain hours in the winter,

[57:01] higher probabilities of emergency operations during peak hours.

[57:05] And those peak hours in the winter are very different than the peak hours in the summer.

[57:10] In the summer, the peaks are during the afternoon at the peak heat.

[57:13] And as I noted, the additional resources that have come onto the grid are very well-suited to help manage those peaks,

[57:19] the additional solar resources.

[57:21] Additionally, the energy storage resources are very helpful in managing the solar ramp.

[57:27] And so the more energy storage resources that come onto the Eurekaught grid,

[57:30] the more risk mitigation we'll see during those ramp periods of the peak heats in the summer to the evenings.

[57:36] The winter is very different. The peaks in the winter tend to occur early in the morning

[57:40] as everybody is getting up for the day and starting to use energy,

[57:44] but it's still very cold from an overnight cold winter.

[57:47] So there isn't solar energy available to meet those peaks during the winter.

[57:51] And then sometimes we'll have peaks in the evenings as everybody comes home

[57:55] and energy consumption goes back up again and the sun has set

[57:59] and it starts to get cold in the evening

[58:01] that we can see secondary peaks again

[58:03] in that period of time.

[58:04] So we don't get the benefit of what has been

[58:06] one of the fastest growing resources on the Eirikot grid

[58:09] which is solar energy resources during the winter peaks.

[58:13] And that's why the profile looks a little different

[58:15] in the winter than it does in the summer.

[58:17] And so as we did this analysis and saw

[58:19] during those early morning hours

[58:20] and in the evening hours, that higher elevated risk,

[58:25] we wanted to do everything we could

[58:26] in our portfolio of tools to try to manage and mitigate the potential risks of being an

[58:31] emergency operation. And so we have a protocol that allows us to look ahead at the next season.

[58:36] And if we think there could be a risk of elevated emergency operations, then we can

[58:42] issue an RFP to procure capacity, both supply capacity and or demand response capacity.

[58:49] And so it's open to both. And on the supply side, it really is focused on capacity

[58:54] that has either recently retired or recently mothballed

[58:58] that could potentially come back.

[59:00] And then on the energy, on the demand response side,

[59:03] it's really open to any net new demand response

[59:06] that could be made available during that season.

[59:08] That could be at the consumer level,

[59:10] all the way up through the industrial level.

[59:12] But it has to be net new,

[59:14] something that hasn't been part

[59:15] of our existing demand response programs,

[59:17] or part of existing retail electric provider

[59:20] or TDU demand response programs.

[59:23] because in that case, it wouldn't be net new and we would be basically procuring the same

[59:26] thing twice. So it wouldn't incrementally help the system, or not procuring it twice,

[59:32] but it wouldn't be an incremental help to the system. So that is the nature of why we

[59:38] did this RP for capacity. The 3,000 megawatt number came out of an analysis that said what

[59:44] would it take in terms of having that additional capacity during all of the different model

[59:49] runs that we ran. And in order to bring the risk of EEA operations, emergency operations

[59:54] down to below 10 percent. We use 10 percent as a threshold. It's the marker that

[1:00:00] So we use when we communicate with NERC, when we do our winter readiness assessment with NERC,

[1:00:04] if we are above a 10% risk profile, it comes out as a elevated risk, if we are below, it

[1:00:10] is considered a low risk. And so we wanted to try to drive that risk profile down to sub-ten

[1:00:15] to be low. And we used winter conditions that reflected similar conditions to last year's

[1:00:21] winter storm, Elliott, as an extreme condition to be able to manage through. And we used

[1:00:26] Elliott because Elliott was the type of storm. If you look back over time, there's been around

[1:00:30] four or so storms in the last 14 years or so that have been either similar or worse than

[1:00:35] a winter storm, Elliott. So it's not something that's highly improbable to occur. And so

[1:00:40] we thought it reasonable to try to make sure that the risk profile of the system

[1:00:44] was low during an event like that. And so those were the combination of factors

[1:00:49] as we did the analysis that led us to come to the conclusion that if we could get

[1:00:53] around 3,000 additional megawatts. It would help bring that risk profile down to two below

[1:00:57] 10. In addition, and I'll open up for questions here. I'll just run through a couple things

[1:01:02] here because not too much is net new. In addition, we've got the weatherization, the new weatherization

[1:01:09] standards are going to go into effect this winter. Those standards apply to geographic

[1:01:13] parts of Texas to specific geographies and have actual temperature resiliency requirements

[1:01:21] for transmission and generation operators in each of those regions.

[1:01:25] And so as we do inspections, the requirements against what we're going to be inspecting

[1:01:29] will be looking at those specific requirements for the geography.

[1:01:32] So if a unit, if a power plant is up in the northern part of Texas,

[1:01:36] it'll have to be able to withstand colder temperatures because of that geography

[1:01:39] than a power plant would down in the Corpus Christi area of Texas.

[1:01:43] And so the weatherization standard is now tuned more finely to the weather risks in those regions.

[1:01:48] And so then the weatherization program will be assessing the weatherization itself against

[1:01:53] those new standards.

[1:01:55] And then one last thing I wanted to point out is that in NPRR 1176, this is actually

[1:02:00] changing the levels at which different emergency level operations are going to be established.

[1:02:06] And the reason we look at this, we have to run studies on the overall stability of

[1:02:11] the grid.

[1:02:12] And when you get down to very low levels of physical reserve capacity to be able

[1:02:17] to meet demand to PRC levels down in the 1,000 and 2,000 range where you're very, very

[1:02:22] close in a very scarce period, you have to run studies to make sure that the grid could

[1:02:27] withstand the loss of a large unit at that time and not trigger under frequency load

[1:02:33] shed if that situation were to occur.

[1:02:36] And so you look at the various stability characteristics of the grid during those

[1:02:40] low reserve periods of time and then run models to make sure that the grid

[1:02:45] could withstand that type of a change.

[1:02:48] And what we found, the last time we ran this model, I believe it was in 2014, that set the

[1:02:52] current EEA levels for the IRICOT grid.

[1:02:55] We have rerun those models with the current grid that we have in place today, which has

[1:02:59] significantly more inverter-based resources on the grid, which have different characteristics

[1:03:04] in how they support inertia.

[1:03:06] And when we ran some of those models, we realized we needed to be able to have

[1:03:12] that EEA-1 level at 1,500 megawatts in order to maintain stability at that level.

[1:03:18] And so if the grid had to ever get into a controlled load shed, we'd have to restore

[1:03:23] to 1,500 megawatts through load shed in order to be able to maintain stability on DERICOT

[1:03:28] grid.

[1:03:29] And then we spaced out the subsequent EEA levels above that at 500 megawatt increments.

[1:03:34] So at 2,000 would be an EEA level 2, and at 2,500 would be an EEA level 3.

[1:03:40] I'm sorry, I have the backwards.

[1:03:41] 3 is at 1,500, 2 is at 2,001, would be at 2,500.

[1:03:47] So that change is going to be going into effect in November for the IRICOT grid, and that's

[1:03:51] based on recent studies to ensure we can operate reliably under very tight capacity conditions.

[1:03:59] I'll pause there.

[1:04:00] I think we've talked about many of these other factors, and I know there's some

[1:04:03] questions on this.

[1:04:05] Yes, so, Pablo, I know we're going to spend some time exploring further the RFP for

[1:04:10] capacity at our winter preparedness workshop on Friday, so I don't want to delve too deep.

[1:04:14] But I think one question out there that I've heard is how does the reliability standard

[1:04:20] that we're currently working on right now, ERCOT to run 48 scenarios on and we're trying

[1:04:26] to establish, marry up with the Mora that is now a monthly report, how are those

[1:04:33] two reports or the standard going to sync up with the Mora because is ERCOT to identify

[1:04:38] by 10% as a threshold to take action,

[1:04:42] how is this all going to sync up together?

[1:04:44] And we can further talk about it some more,

[1:04:47] but I'm just wondering,

[1:04:48] because there's a lot of confusion out there

[1:04:49] as to how everything aligns together.

[1:04:53] So thank you for bringing up the workshop.

[1:04:55] That's one of the things I did want to bring up.

[1:04:57] So this Friday there will be a workshop

[1:04:59] at the Public Utility Commission,

[1:05:00] an all day workshop where we'll be delving

[1:05:02] into the winter preparedness across the industry.

[1:05:05] And so we'll have participants

[1:05:06] investments from across the sector, including ERCOT, talking about the various activities

[1:05:11] that are taking place in order to make sure we're doing everything to manage the reliability

[1:05:14] of the grid this winter. In addition, we'll go deep into Q&A and questions around the

[1:05:18] R&P for capacity, which is relatively new. So when you think about the reliability standard,

[1:05:25] what it's going to do is it's going to create essentially a target. And it's going

[1:05:30] to have value through a couple of different time periods. You'll be able to assess

[1:05:34] based on the current resource mix that exists today

[1:05:37] and the assumptions of weather conditions

[1:05:40] and performance of those assets today.

[1:05:43] So you'll be able to have a current state view,

[1:05:44] are we today operating in a way

[1:05:46] that should meet this reliability standard when it's set?

[1:05:49] And then it'll have value in a future period

[1:05:51] because that's really the, I think, the most important value

[1:05:55] because you need to look ahead to see how the grid needs

[1:05:57] to either change or stay the same

[1:05:59] in order to be able to deliver

[1:06:01] that reliability standard in the future

[1:06:03] and it needs to help support the market signals that are going to be necessary to meet that

[1:06:08] reliability standard in the future.

[1:06:10] And so we will use that standard when it's completed to run models that assume what the

[1:06:16] resource mix will look like in three years and then determine whether it will be able

[1:06:21] to meet that reliability standard to help the market design parameters be established

[1:06:26] in such a way that helps us get to that in the future.

[1:06:29] The Mora is a little bit different in that the Mora is looking at two months ahead and

[1:06:35] it's really a scenario modeling exercise.

[1:06:37] And so what it's going to do is it's going to take the best information we have right

[1:06:42] now with the current resource mix and it's going to run the probabilities of entering

[1:06:47] different levels of scarcity as a grid.

[1:06:50] And you can look at that independently from the reliability standard because it will

[1:06:55] use similar modeling, the reliability standard will take the same set of resources, run it

[1:07:00] through a lot of scenarios and find how many outliers there are to the reliability standard

[1:07:05] that's established.

[1:07:06] So we could leverage and use parameters in the reliability standard as part of the

[1:07:11] Mora to describe the outcomes of various scenarios, and that's something we haven't

[1:07:15] talked about yet, how we would potentially integrate those two components.

[1:07:19] But they could be integrated because they'll be using very similar modeling tools, and

[1:07:23] And the objective is to define what are the characteristics of the grid under many different

[1:07:31] scenarios.

[1:07:32] Yeah.

[1:07:33] And one interesting point, because I've been thinking about this myself, is right now arguably

[1:07:37] you could say we are meeting the reliability standard, the one in 10, right, currently

[1:07:41] right now in our market.

[1:07:43] However, now we have a more report that say we have a higher than 10 percent chance

[1:07:47] if we experience weather like winter storm Elliott with our load growth being higher,

[1:07:52] that we could end up in emergency conditions

[1:07:55] and ERCOT has taken actions.

[1:07:56] So there could be a disconnect.

[1:07:59] And it's got to be integrated because in one hand,

[1:08:02] if you're meeting your liability standard that we've set,

[1:08:05] but you're more as showing that we're hitting that 10%

[1:08:09] and it's triggering ERCOT action,

[1:08:11] then there's got to be some kind of integration

[1:08:14] because there could be a potential disconnect

[1:08:17] and really trying to meet their overall reliability standards

[1:08:21] it's going to require regulatory certainty and an established reliability standard.

[1:08:26] But if we have a sort of a discrete report that's being issued out on a monthly basis

[1:08:29] that's triggering actions, we just got to be cognizant of how they marry up together.

[1:08:34] It's an observation.

[1:08:35] Yeah.

[1:08:35] And I think the key thing that we'll need to work on to be very clear on is being

[1:08:39] able to describe the temporal nature of each of these different reports that we have.

[1:08:44] And so what is the time value of the Moira report?

[1:08:47] It's giving us a perspective two months down the road.

[1:08:49] The reliability standard is really looking at points in time, like a spot point in time

[1:08:54] and a future point in time.

[1:08:56] So the time periods are really relevant to this in order to help understand what the data

[1:08:59] is communicating.

[1:09:01] And so we need to be very clear as we publish these reports.

[1:09:03] This is the time.

[1:09:04] This is what we should conclude from it or draw from it.

[1:09:07] And it's reasonable to conclude that, yes, you could have a system that has at over

[1:09:11] a 10-year period a certain characteristic, but in a future month at an extreme weather

[1:09:15] scenario could have operational challenges.

[1:09:17] And those are the discrepancies we need to be able to describe.

[1:09:23] Mr. Chairman, Pablo, if I may, just a question on weatherization.

[1:09:28] Weatherization was one of, I believe, one of the most successful policy collaborations

[1:09:33] that ERCOT has had with PUC for quite some time in terms of developing a standard

[1:09:39] that would be adhered to by our generation facilities and wires companies as well as inspected to.

[1:09:46] In your mind, for the purposes of this upcoming winter, do you have a benchmark of what you

[1:09:53] consider would be a successful outcome?

[1:09:55] Because again, the point of weatherization standards is to drive beneficial behavior

[1:10:00] on the system, reduce overall weatherization related outages for the season.

[1:10:08] What in your view is a good benchmark that the board and the commission can look at

[1:10:13] for this upcoming winter?

[1:10:14] Yeah, that's a great question.

[1:10:16] So there's, I think, a couple of things that we'll want to talk about as we go through

[1:10:19] the winter and then in a post analysis.

[1:10:21] We'll want to take a look at what was the average kind of uptime or forced outage

[1:10:27] rate for particular units and how has that changed over time.

[1:10:30] So we can look at the performance of those units in prior winters and we can look at

[1:10:33] the performance of those units this winter.

[1:10:35] And we can see if there were extreme weather periods, how did it perform during those

[1:10:39] weather periods?

[1:10:40] and so actual outcomes in terms of uptime and forced outages I think is a great metric

[1:10:45] for us to do in an ex post manner.

[1:10:48] The other thing I think the real value in this is the learning and the collaboration

[1:10:51] that happens.

[1:10:52] So as we do the weatherization, actually the kind of what we find and then the changes

[1:10:58] and the cures that are done as a result of finding components or things that are

[1:11:02] not done.

[1:11:04] So that learning and sharing that learning across the communities, whether it's on

[1:11:06] the generation or the wire side, I think is a real value here.

[1:11:09] So I think I'd like to do a recap afterwards.

[1:11:11] When we complete the inspection period,

[1:11:13] what did we find during the inspections?

[1:11:15] How was that shared across the industry?

[1:11:17] And does that continue to elevate the quality

[1:11:19] of the weatherization program going forward?

[1:11:21] Because I agree 100% with you.

[1:11:23] I think it was a very well done collaboration.

[1:11:25] And I think it's probably one of the most effective changes

[1:11:27] we've done to ensure reliability

[1:11:29] during the winter periods.

[1:11:33] Navaraj, you had a?

[1:11:34] Pablo,

[1:11:37] I would like to ask you

[1:11:38] about the 10% thing you mentioned earlier.

[1:11:42] Is that a knock already defined, that 10% rule, or is that something ACOT protocol defined

[1:11:51] that 10%?

[1:11:53] I might need to phone a friend on that one.

[1:11:55] I don't know if Dan or Woody, if either of you know whether that threshold is something

[1:12:01] that has just been historically how we've communicated risk through the NERC reports

[1:12:06] or if that's something that's defined by NERC.

[1:12:10] I don't know for sure.

[1:12:12] We can follow up on that for you, Naraj.

[1:12:14] Thank you.

[1:12:14] One more question.

[1:12:15] I think Pablo was looking at a one in ten year event was the threshold that we were using.

[1:12:20] Excuse me?

[1:12:21] A one in ten year event.

[1:12:22] That was the ten percent.

[1:12:25] That was the basis for the ten percent?

[1:12:27] My question is, is it an org defined rule or is the ACOT protocol defines that rule?

[1:12:37] We'll follow up on that question.

[1:12:38] Thank you.

[1:12:39] Second question is,

[1:12:43] what is the expected budget

[1:12:44] to implement this?

[1:12:47] If you have-

[1:12:48] The expected budget?

[1:12:48] Yes.

[1:12:49] To implement which?

[1:12:51] This 3000 megawatt of reserve.

[1:12:54] We have not set a budget for this.

[1:12:57] What we have done is issued an RFP

[1:12:58] in order to understand what kind of resources

[1:13:01] might be able to perform on a short notice like this.

[1:13:05] And then we're going to take all of those bids

[1:13:08] and we'll review what we with openly so that everybody can see these are the kinds of bids

[1:13:13] that came in.

[1:13:14] And then we'll have to make a judgment call on what is a reasonable cost to pay for incremental

[1:13:19] reliability or incremental capacity that comes in.

[1:13:22] So there's not a set budget for this process we haven't established minimums or caps at

[1:13:27] this point in time.

[1:13:28] And we're really, this is one of the first times we've done this and I think 2011

[1:13:32] is the last time that IRCOT did an RFP for capacity like this and so we don't have

[1:13:38] have a good history of understanding what kind of different bids will be seen through

[1:13:41] this.

[1:13:42] Yeah.

[1:13:43] Because the reason why I ask is the reliability is something we are really concerned at the

[1:13:51] meantime the cost for consumer that matters.

[1:13:55] It does.

[1:13:56] It absolutely does.

[1:13:56] We agree.

[1:13:57] That's right.

[1:13:58] We didn't predispose it because we really were unsure what kind of bidding offers

[1:14:01] we were going to see.

[1:14:02] And so we wanted to understand that first and then try to make the best decision

[1:14:06] with the information once we had it.

[1:14:11] Any other questions?

[1:14:14] Thank you.

[1:14:14] Great question.

[1:14:17] All right.

[1:14:18] Well, then I'll just close like I'd like to in each of my reports

[1:14:22] with a thank you.

[1:14:23] I'd like to thank two groups in particular.

[1:14:25] First, the ERCOT control room.

[1:14:27] This summer was a stressful time.

[1:14:30] They operated calmly and professionally

[1:14:33] throughout some of the most difficult periods.

[1:14:36] I think the ERCOT control room

[1:14:38] has experienced during a summer period.

[1:14:39] And so I want to thank Jimmy and Daryl and Brian, they're the leadership of that group

[1:14:43] and there's over 50 operators that are in there 24 hours a day, seven days a year, every

[1:14:48] holiday, every evening, making sure that grid reliability is delivered to Texas.

[1:14:53] And then I want to thank those that led the development of the Moora Report.

[1:14:56] support. It was a pretty significant change to shift over from our.

[1:15:00] Report to the more report, and this team here really led that development, and so a big

[1:15:04] thanks to that, because I think it's going to help with more transparent and more actionable

[1:15:07] and more helpful information as to the risk profile of the grid on a going forward basis.

[1:15:13] So thank you all for your questions. Thanks for the discussion today. And with that,

[1:15:17] I'll conclude my report unless there's any final comments or questions.

[1:15:21] Thank you, Pablo. Great report.

[1:15:27] That was a great 15-minute report, by the way.

[1:15:33] Next is Agenda Item 6, Summer 2023 Operational and Market Review.

[1:15:39] Dan Woodfin and Kenan Ogerman are here to present this item.

[1:15:48] Good morning.

[1:15:52] I've got two pages of key takeaways from this presentation,

[1:15:56] so I urge you to go look at those after the fact,

[1:15:58] but we'll try to go through the actual meat of the presentation.

[1:16:02] If you look at the line graphs on this first slide,

[1:16:06] You'll see that back in 2022 there was a significant amount of heat in the middle of July.

[1:16:14] And so when you compare this year to last year, temperatures were fairly, during that

[1:16:18] two-week period, were fairly similar.

[1:16:21] But then if you look across the remainder of the year, this year's temperatures were

[1:16:27] significantly higher and stayed higher for pretty much the whole month of August and

[1:16:32] through September.

[1:16:32] And in fact, I heard yesterday that Chris had looked at the average temperatures for

[1:16:38] the period from June to September, and 2023 was only a tenth of a degree cooler than 2011,

[1:16:46] which is kind of the benchmark for hot summers that we hope we never experience again.

[1:16:51] But this summer, on average, was almost as hot.

[1:16:55] And that, of course, drove.

[1:16:56] Then if you look at the bar charts, you see that kind of the darker bars are what

[1:17:02] the peak demands were on each day last year and the lighter blue or what it was this year

[1:17:07] and you can see that we had significantly higher peak demands through August and September

[1:17:12] as compared to last year.

[1:17:15] And so we expected to have higher demands this year.

[1:17:20] Our forecasts were higher because of the increased economic growth in Texas, but we actually

[1:17:25] saw it not only higher but sustained, you know, on day after day of those kind of high demands.

[1:17:34] We've all, we've kind of seen this impressive graph of 11 new demands, new peak demands

[1:17:41] that ratcheted up last year, 10 more this year.

[1:17:45] What's really impressive to me is that we hit 49 times, we hit a demand for an hour

[1:17:52] that was higher than our peak demand just last year.

[1:17:56] And that kind of gives you an idea of just how sustained the heat was.

[1:18:04] As Pablo mentioned earlier, we've looked in this kind of breaking out the growth between last year and this year

[1:18:11] by different kinds of consumers.

[1:18:14] And then because of the profiling process that we do as part of settlements,

[1:18:19] we can break those out into residential, commercial, and then industrials, and the industrial class

[1:18:27] has both the non-optin energies, entities, so folks like the Austin Energy and CPS San Antonio

[1:18:34] and those kind is in this industrial class, but we've broken them out separate.

[1:18:41] And so you can see in the upper left that the residential number of meters from residential

[1:18:47] grew 2.6 percent. So that's a lot of that economic growth that we were talking about.

[1:18:52] Of course, commercial and industrial consumers use more energy, but there's not as many

[1:18:57] additional meters for the amount of growth that they have. But then, if you look down

[1:19:02] in the bottom right, you see daily energy growth. You can see that actually that a lot

[1:19:10] of that growth was in the industrial class. And not as much, especially, and I guess

[1:19:17] There's a blue bar and a gray bar.

[1:19:20] The gray bar is the weather adjusted.

[1:19:22] So it's taking out the effects of growth due to weather being hotter this year

[1:19:29] and just focusing in on how much load growth there was.

[1:19:32] And you see that for residential, there actually wasn't much growth.

[1:19:35] And the explanation of that is we've got a lot more rooftop solar,

[1:19:39] which would reduce the energy consumption on those houses that have it.

[1:19:43] But we've had improved energy efficiency of appliances and lighting and those kind of

[1:19:52] things.

[1:19:53] I mean at my house I had to put in a new air conditioner this year and it's a lot more

[1:19:57] efficient than the air conditioner I had.

[1:19:59] So I contributed to this.

[1:20:02] And then you, so you see those kind of things and then from a peak perspective if you look

[1:20:07] at the upper right there you can see kind of the growth in the peaks by class.

[1:20:11] The peak also, there were a lot, I think there's been an increase in load management type programs

[1:20:17] where people can, where your retailer may control your thermostat and cause you to use less on peak.

[1:20:24] And so you see that kind of the impact of that is especially in the residential,

[1:20:29] from a weather-adjusted perspective, we didn't see as much growth

[1:20:32] as what you'd think we would for the number of meters.

[1:20:34] And that's just because there's more efficiency being there.

[1:20:38] industrial obviously was the biggest increase.

[1:20:46] So Pablo mentioned this earlier, but this is a good graph to show.

[1:20:50] So the top green line there is our peak demand across a typical afternoon

[1:20:55] from one o'clock in the afternoon out to 2100.

[1:21:03] And so you can see that, and then it also has the wind in the blue area there

[1:21:10] and the gray is the solar. And so he mentioned that you see that shift in when the net load

[1:21:18] peak on the system is from being kind of at five o'clock in the afternoon, it's shifted

[1:21:23] out to being more of the seven o'clock hour. And why that's important, that when that net

[1:21:27] load peak is, is that's kind of the time of maximum need for non-renewable generation.

[1:21:34] So all this dispatchable generation that we talked about earlier, that's kind of the peak for how much is needed to be produced by those generators.

[1:21:45] And so you can see that that has shifted out in time.

[1:21:49] And in fact, if you look at the next slide, across, if we look on average for every day of the month over the last three years,

[1:22:00] you can see that the 1,700-hour, especially in the early years,

[1:22:07] were much higher.

[1:22:09] But if you look at the green bar, that's the 2,100-hour,

[1:22:13] and you can see each month of this year,

[1:22:16] on average across all the days,

[1:22:18] our peak actually was happening on our ending 2,100.

[1:22:23] You can see this is not a one-day type thing.

[1:22:27] It actually is occurring on average every day.

[1:22:33] We issued several conservation calls this summer.

[1:22:38] The blue bars here are the peak demands on each day, and the ones that are colored in

[1:22:46] red are the ones on which we called for conservation.

[1:22:51] You can see that those are not always the highest demand day, but they are typically

[1:22:57] the highest net load days, which is the gray line graph that goes across.

[1:23:03] Now, there are a couple that aren't because we were expecting worse conditions that actually happened.

[1:23:11] So we're having to call these conservation appeals earlier in the day.

[1:23:15] Sometimes the wind blows a little more or the load's a little less than what we expected.

[1:23:19] But generally, they tend to line up very well for what the reason we're having to do them

[1:23:25] is because of that highest net loads, which is kind of what you'd expect. We've got a

[1:23:32] fixed amount of dispatchable generation, and when we're kind of needing the most of that,

[1:23:40] that's when we're going to be the tightest.

[1:23:45] One of the other things we noticed is, so

[1:23:49] the blue bars on here are the average of all the days that we didn't ask for conservation.

[1:23:54] This is the average amount of wind for each of those hours.

[1:23:58] And the black bars are the average wind for that hour across those days that we had to ask for conservation.

[1:24:08] And you can see a clear pattern that a lot of the reason we were having to ask for conservation on those days

[1:24:14] is because those days we had less wind across those afternoon and early evening hours.

[1:24:21] And that's kind of a key takeaway.

[1:24:24] We've been noting this for several years that the difference between a tight day and a not-tight day tends to be how much the wind is blowing.

[1:24:31] But this year it was very clear.

[1:24:37] Force outages.

[1:24:38] This has been a question I think we were asked last year during this presentation.

[1:24:44] So we've put this in here that really it stayed pretty consistent between four and eight gigawatts over the course of kind of the tightest days of the summer.

[1:24:54] It was a little higher earlier in the summer as some of the maintenance outages that were

[1:24:59] done in the spring extended into the June timeframe and early July, but then once we

[1:25:05] got into kind of the heat of summer, it stayed within the 48 gigawatt range.

[1:25:09] There are a few days when it's higher and we put the net load on there in the green

[1:25:15] graph because it makes it fairly clear why they were able to take more outages

[1:25:21] on those days because there was more wind, it was a slightly lower load,

[1:25:30] we didn't need

[1:25:30] as much dispatchable generation on those days and so they were able to take more outages

[1:25:36] to fix things that they might have operated through if it was a very tight day.

[1:25:46] And so if you look at the amount of generation that we have available, so installed capacity

[1:25:54] minus the outages that are going on.

[1:25:57] This shows kind of whether the units were online or not.

[1:26:02] And if you see, the gray bar was 2022, the blue line is this year.

[1:26:09] And you can see there were a few days in the mid-July timeframe that I said that we

[1:26:15] had fairly high temperatures in which all generation was online.

[1:26:19] So if you look at where it's touching kind of the zero line there, those times that it's touching zero line,

[1:26:25] that means that every generator, every dispatchable generator was online on those days.

[1:26:32] And you see there was a few days in July last year in the middle of July that that was true.

[1:26:37] You can see this summer there were a lot of days in which every generator we had that was available,

[1:26:43] that was not on an outage was online and needed to be online to serve the demand.

[1:26:55] One of the questions we had gotten was how much or what are batteries doing?

[1:27:00] How much of ancillary services are being provided by batteries?

[1:27:03] And so this graph shows that especially for regulations up service, regulation down service,

[1:27:10] that the batteries are providing that, a lot of that in the purple bars.

[1:27:14] the responsive reserve ancillary service.

[1:27:18] So this is what we procure to protect against if a unit trips

[1:27:22] and protect the frequency.

[1:27:24] They're providing a good portion, 68%, 70% of that,

[1:27:29] providing a little bit less at this point of ECRS

[1:27:32] and not much non-spin.

[1:27:34] But you can see that they really contributed significantly

[1:27:37] to serving our ancillary service requirements this summer.

[1:27:40] And this is kind of a busy graph, but I recognize this,

[1:27:47] but it's really interesting to see on some of those tight days

[1:27:51] what happened to the state of charge,

[1:27:55] especially when we got into tight conditions,

[1:27:57] and so it focused you in specifically on 9-6, so the EEA day.

[1:28:02] You can see that the green dotted line shows that the state of charge

[1:28:08] is going down a lot during that tightest time frame when prices went high in the evening.

[1:28:14] And that's because that's exactly what you'd expect to happen. Those batteries were discharging

[1:28:19] and serving energy on the system during that time frame.

[1:28:26] So several days from a transmission perspective, we really didn't have a lot of issues at

[1:28:32] all serving demand from overloading transmission lines or anything like that, except for the

[1:28:38] one event that we talked about with the R&M committee yesterday, where there were several

[1:28:44] days that that constraint was actually binding before the day that we had the EA event.

[1:28:53] And really what was going on is you had very high demand in relative to the amount of

[1:28:59] generation that was available in North, Central, and West Texas.

[1:29:03] So basically all the generation was on in those areas and there was still a little bit of generation available in the south.

[1:29:13] So trying to use all the generation, we try to transfer power into the north from those units in the south.

[1:29:19] But there's a transmission constraint that's pretty significant that we would have to curtail generation in the south area there.

[1:29:27] And so you'd see somewhat higher prices in the north and especially during that time frame.

[1:29:34] And it really wasn't a problem when the sun was out.

[1:29:37] So there's lots of generation in West Texas that's helping to serve that load.

[1:29:41] But you'd get into the conditions I just described when the sun goes down.

[1:29:46] And now the amount of generation you've got to serve the load

[1:29:49] in that area is pretty well matched.

[1:29:52] And you need a little more.

[1:29:54] And so the other thing that happened in Kanan and Pablo Kanan

[1:30:01] There were some hours in which it was strictly speaking that we were just out of capacity in

[1:30:07] that north area, and that was what was causing the percentage strain to buy. There were other

[1:30:12] hours where we were almost out and so to keep from overloading the constraint, we were having

[1:30:21] used some of the very high offer price resources in the north, and so that actually set higher

[1:30:28] prices over a larger number of hours than what we were actually in scarcity in the north

[1:30:34] because we were having to select those higher offered prices to help not overload the constraint.

[1:30:45] And then we did have one day that Pablo mentioned that we got into, that we did have to enter

[1:30:51] into our emergency operations. In this day we had the situation that I just described

[1:30:56] where, as the sun was going down, we basically ran out of capacity to serve the demand in

[1:31:02] the north, central, and west areas.

[1:31:06] That resulted in an overload of this critical transmission constraint, and the operators

[1:31:14] had to balance between the risk of overloading that constraint and there being problems

[1:31:20] there and not having enough capacity to serve the load and having to go into the A.

[1:31:24] and they appropriately balanced those two, they declared an EEA, they started to curtail,

[1:31:31] first they started to curtail generation in the, that south Texas to get the line overloaded

[1:31:37] from being overloaded. Then they, that caused us to be short of capacity, frequency started

[1:31:44] to drop and they appropriately declared an EEA too in order to take advantage of

[1:31:49] load resources. We also did some switching actions to try to unload that transmission

[1:31:55] constraint, and that helped us to bring back some of the generation that we'd had to curtail.

[1:32:01] And so overall, we managed through this and got back out of EEA by 8.37 p.m.

[1:32:09] We're,

[1:32:10] as I mentioned yesterday with R&M, we're working on some mitigation plans for that

[1:32:17] solution for that transmission constraint. And we're also, the frequency going down that

[1:32:25] happened was actually, although we still seem to have some reserves on the system that should

[1:32:31] have kept frequency high, we're having to, we're going to be sending some RFIs out

[1:32:36] to the entities that showed they had headroom, but they can't have had headroom or the

[1:32:42] frequency wouldn't have dropped. And so we're going to be doing some RFIs and

[1:32:45] and potentially having to do a protocol revision

[1:32:49] to tighten up the rules around reporting on that.

[1:32:53] Dan, before you leave this page,

[1:32:55] there's a person that has a paid subscription services

[1:32:59] headline, I guess, to gain more paid subscriptions today.

[1:33:04] As Erkaut Simmer review is misleading and incomplete.

[1:33:08] And in here, on this particular subject,

[1:33:10] he's got a paragraph that says,

[1:33:11] the agency admitted that transmission constraints

[1:33:15] were a major problem. South Texas winds were particularly strong that day, but ERCOT manually

[1:33:20] and probably unnecessarily curtailed generation to avoid potentially overloading a transmission

[1:33:26] line that could have delivered electricity to people who need it. This guy is not a physics

[1:33:31] major, but tell us what would have happened had you not taken those actions so that the

[1:33:38] people that are hearing this conversation will know what the truth is, because, I mean,

[1:33:42] You've laid out the truth, but what would the alternative have been had had we not taken those actions?

[1:33:48] I think that there is a

[1:33:50] there's risk on both sides of that and

[1:33:53] According to the North American electric reliability

[1:33:57] Corporation rules we have to properly balance those risks

[1:34:01] So there's risk of potentially low shed on one side and there's risk of potentially low shed on the other side

[1:34:07] And so we have to balance those two things

[1:34:10] I can't talk about some of the physics of it because it will quickly get into critical

[1:34:16] energy infrastructure information.

[1:34:20] But absolutely we've looked at this.

[1:34:22] I think NERC and some of the regulators will agree that we did all the right things there

[1:34:29] and really needed to do what we did.

[1:34:32] Okay.

[1:34:33] So there's nothing unfactual about the report that you got.

[1:34:36] Absolutely.

[1:34:36] I mean, the lack of factual data is in this newsletter.

[1:34:39] or it sounds like.

[1:34:40] I think there's a lot of misunderstanding about what exactly the requirements are.

[1:34:48] But I can assure you we did the right things.

[1:34:51] Yeah.

[1:34:51] Thank you.

[1:34:55] And I will turn it over to Kanan, but I will still be here if you have more questions

[1:34:59] after his part.

[1:35:06] Good morning.

[1:35:07] So Dan, I think, has laid out very effectively how tight throughout the summer conditions

[1:35:15] were.

[1:35:15] We had extremely high load and we came very close to the edge in terms of managing the

[1:35:26] system very frequently.

[1:35:29] The corresponding pricing or market story aligns with that.

[1:35:35] So when you look at the average hub prices or the average price for the ERCOT system,

[1:35:45] You see that we were higher than what we experienced in 2022 in August and in June, but July, it

[1:35:56] was slightly lower, I think, and that's because of that first half of the year, that half

[1:36:03] of the month, I should say, that Dan described.

[1:36:06] As a consequence of these high prices, we have seen Peekernet margin move up dramatically.

[1:36:14] It's the highest it's been since the year in which we had winter storm URI.

[1:36:20] So we are at, as of September 15th, we were at $239,000 for Peekernet margin.

[1:36:29] I always want to make sure I share an announcement that at $315,000 of Pekernet margin by rule

[1:36:43] we will go to a lower system-wide offer cap.

[1:36:47] So that's the trigger of or circuit breaker to trigger a move from the $5,000 offer

[1:36:57] offer cap that we see to a $2,000 offer cap.

[1:37:01] So we are relatively close.

[1:37:05] A winter event with high prices could tip us over and trigger the low cap.

[1:37:14] So I think that's important, but from a revenue standpoint, generators made significant

[1:37:21] revenue this summer if they were able to run.

[1:37:31] One interesting thing here is that the reserves that we had on the system as a general trend

[1:37:40] this summer versus 2022, the reserves were higher.

[1:37:47] And we've been kind of walking through this story multiple times.

[1:37:51] But when you put in a ECRS program that allows the operators to dispatch reserves when needed,

[1:38:04] that's one contributing factor.

[1:38:07] There could be other contributing factors in terms of reserves or congestion that could

[1:38:16] also contribute here. But thematically, and I think this has been in the press, we had

[1:38:24] more reserves yet higher prices. And that dichotomy has been discussed quite frequently.

[1:38:33] And I have spoke about this yesterday, and I'd like to speak about that some more today

[1:38:40] in terms of what's driving that.

[1:38:45] So again this is another way of saying our

[1:38:50] administrative pricing mechanisms did not trigger so much of the higher prices

[1:38:57] this year as offers did. So when we had higher reserves but higher offers as

[1:39:07] as well. And that was a contributing factor. Operating Reserve Demand Curve, the real-time

[1:39:17] rerun in case ERCOT took action, that didn't contribute nearly as much as offers did in

[1:39:28] 2023. And the way you see that is the single line over the bar line, that is the percent

[1:39:40] of the adders as a total. And you can see in 2022 that percent was much higher than in

[1:39:48] any of the months in 2023.

[1:39:50] 3.

[1:39:58] Dan mentioned congestion being a significant factor. Congestion, certainly in August, was

[1:40:09] extremely high, especially in the south, that area that he highlighted in his presentation.

[1:40:17] But also it's important to note that it's more difficult for our security constrained

[1:40:23] economic dispatch engine to manage congestion when offers are high.

[1:40:29] We have essentially circuit breakers on when security constrained economic

[1:40:35] dispatch stops trying to solve congestion, and it is driven by the

[1:40:42] offer price and the shift factor, or the impact individual units offer,

[1:40:49] offer, or I should not say it's offer, an individual unit's ability to contribute to

[1:40:54] relieving that congestion. If it has a high offer and a lowish shift factor impact on

[1:41:03] the constraint, it will trigger what we call the shadow price caps that say, Sked, okay,

[1:41:13] you've worked hard enough on trying to solve this through pricing and we're going to stop

[1:41:19] because the pricing can spin out of control and there's a desire to have a cost cap to

[1:41:27] consumers and that's where these shadow price caps come from. So those combinations really

[1:41:36] impacted the pricing that you see. And we also had significant congestion that we saw in

[1:41:46] all areas. But as you can see with the kind of very bright green, that south area congestion

[1:41:53] was the most significant for this summer.

[1:42:02] So when energy prices are high, their corresponding

[1:42:07] Funding substitute service, which is ancillary services, tend to price at a high level also.

[1:42:18] And again, we saw in 2023 very high prices for ancillary services.

[1:42:26] This is, you know, as a generator or a provider of ancillary services, I have to weigh the

[1:42:32] opportunity cost of providing energy versus ancillary services, and that is the primary

[1:42:40] driver for the high ancillary service costs that we see.

[1:42:49] One other thing that we wanted to look at is how well did the day ahead do at predicting

[1:42:58] what was happening in real time?

[1:43:00] So what you have is the real-time price overlaid with the day-ahead price.

[1:43:09] And the day-ahead is never going to get everything exactly right.

[1:43:14] It's a assumed system topology versus a real system topology.

[1:43:23] There can be differences in wind output between what is expected in the day ahead and what

[1:43:32] materializes in real time.

[1:43:35] And similarly, the same thing can happen with load.

[1:43:38] The key thing is that these things generally move in the same direction.

[1:43:43] So the item that you would be kind of most concerned about is that this area between 622 and 629

[1:43:56] where the gray line really spiked up and the teal line did not.

[1:44:02] That means there was a mismatch between expectations from the market and what really happened.

[1:44:09] Now this is going to happen from time to time just because of the various factors, the uncertainty

[1:44:16] around intermittence, uncertainty around load, and uncertainty around the system topology.

[1:44:24] But you don't want that happening consistently day after day after day.

[1:44:29] And we don't see that.

[1:44:31] But that was another item that we always like to look at for the summer.

[1:44:36] So the convergence is what we would describe as within expectations or normal.

[1:44:48] So, you know, the use by ERCOT of reliability unit commitment to commit resources has been a talking

[1:44:59] Thank you.

[1:45:00] The meeting point pretty much for all of 2023 and was a major talking point in 2022. What I

[1:45:08] can say is with the very high prices that we saw, ERCOT was not in need of committing resources

[1:45:15] through reliability unit commitment instruction. So the one, one of the positive stories from

[1:45:22] the summer is that the amount of reliability unit commitment that we saw had dropped dramatically

[1:45:30] relative to 2022. Now, that doesn't mean that we've solved the problem or anything like that,

[1:45:36] but the high system prices led to people wanting to self-commit and their vision of what the

[1:45:46] risk was aligned with ERCOT's vision.

[1:45:49] Sometimes that is mismatched, and that's where we have to

[1:45:53] step in and commit units through this reliability unit

[1:45:58] commitment process.

[1:46:06] And then the one other thing I wanted to share with you as

[1:46:10] part of this is our collateral requirements went up

[1:46:16] through the summer, primarily driven again by high

[1:46:20] prices so I mean my short story would be our process worked as it should as prices

[1:46:28] went up and risk went up to the market of a default we collected more collateral

[1:46:34] of all forms in this the other I think item worth highlighting is you know we

[1:46:42] do still break down unsecured credit here that will be going away or began

[1:46:49] going away October 1st. So in the future, you're not likely to see the unsecured collateral

[1:46:57] item.

[1:46:59] And with that, that concludes my part. I'm happy to answer any questions, and I know

[1:47:07] Dan is happy to answer any questions you may have.

[1:47:13] Canon, one question. Do you believe our minimum ORDC signals to help negate the need for

[1:47:22] Ruck will be moving forward. That happens this next month. Do you still believe, given

[1:47:28] what you observed, and it may be too early, and if it's too early, you can say it's too

[1:47:32] early, to say that it's still needed, given what we experienced after the launch of ECRS?

[1:47:38] But what are your after-summer takeaways from that?

[1:47:42] I mean, I would say for the summer, we didn't need it looking back. But, again, as prices

[1:47:49] is moderate yet ERCOT, the operator sees shortages. I think there is a possibility that RUK reliability

[1:48:02] unit commitment becomes a tool that we use more frequently, especially in the shoulder

[1:48:08] months where we can move between high and low temperatures, high intermittent output

[1:48:16] and low intermittent output. So I would say it's a little too early and we

[1:48:23] should definitely follow up with you and report on that. Those floors do not go

[1:48:29] into effect until November 1 so that they are not operating currently.

[1:48:33] And a follow-up on Commissioner McAdams observation question. The

[1:48:39] Commission also asked for subsequent reporting on the ORDC adders after they are implemented

[1:48:47] to ensure that they're actually needed. So, you know, that's going to be a monitoring

[1:48:53] mechanism that we continue to focus on to see if they're actually needed.

[1:48:57] In observation, maybe a question. So in the past, ERCOT and could prospectively still

[1:49:04] continue to do it, would Ruck units to meet a conservative operations threshold, 6,500.

[1:49:13] And as you go forward, like this summer, the higher pricing was incenting self-commitment,

[1:49:19] but you were also carrying more ancillaries.

[1:49:22] So going forward, like in the fall, if you're continuing to carry a lot of ancillaries

[1:49:27] and you're having that threshold that you want to lean on for conservative operations

[1:49:33] I mean, will Rucky even still be needed because, you know, even though prices will moderate,

[1:49:40] you're still carrying more and the whole goal of Rucky, I think, started with trying to

[1:49:45] meet the conservative operations threshold.

[1:49:48] So I'm going to make – do you want me to take shot at it and then you clean up for

[1:49:54] me afterwards?

[1:49:54] Okay.

[1:49:55] So I think it's really important – and Dan raised this issue yesterday, but the

[1:50:01] purpose for buying the ancillary services is to protect the system from

[1:50:06] certain shocks, unexpected events, and things like that. So the way I like to

[1:50:14] talk about it is we were rucking to protect the ancillary services so

[1:50:21] they were still there if the event that we bought the ancillary services

[1:50:27] So, from my perspective, if there's not enough resources committed in the day, we would still

[1:50:35] be looking to use reliability unit commitment. Now, we would prefer resources self-commit

[1:50:43] and we want to create the incentives for them to self-commit. But we wouldn't want

[1:50:50] to automatically dip into ancillary services if we saw insufficient generation committed

[1:50:58] because we are eroding our ancillary services and the event that they're there for hasn't

[1:51:04] happened yet.

[1:51:05] Dan, let me make sure I didn't miss anything.

[1:51:09] No, I mean, I think that's right, the 6500 with more ancillary services, if everybody

[1:51:16] is still committing the same amount that the market participants are still committing the

[1:51:21] same amount to serve the load that they have been committing, and then if we buy more ancillary

[1:51:28] services, then that amount ought to be enough to – the load plus 6500 isn't going to

[1:51:34] be a binding constraint anymore. We won't have to do anything extra. If people start

[1:51:39] committing less to serve the load, and then we're still getting enough to serve

[1:51:46] of the ancillary services, you may have to rock.

[1:51:49] I mean, that's basically what went on in 2021

[1:51:51] when we bought more ancillary services

[1:51:53] is people started to commit less.

[1:51:55] With the ORDC change, that may and sent them

[1:51:58] to continue to self-commit enough to serve the load.

[1:52:04] I'm just wondering how the factors all interplay

[1:52:06] with each other now going forward

[1:52:08] as you're now carrying more ancillaries

[1:52:10] because of ECRS and the addition.

[1:52:13] And then you'll ultimately add DRS,

[1:52:15] which arguably could be some of the same resources just recategorized into a different ancillary

[1:52:21] service bucket, but you're carrying more ancillaries, that's, you know, a reservation of power that

[1:52:29] has an impact on the real-time market that could have an impact on whether or not you're

[1:52:34] actually capturing the higher energy price or the ORDC adder, which you've noted,

[1:52:39] I think, in your presentation has been lower because of that effect.

[1:52:42] So it's important just to kind of understand the factors.

[1:52:44] that's what I was trying to peel back and as we go forward monitoring the actual success

[1:52:48] of that adder and whether or not it needs to stay in there because if the moving pieces

[1:52:54] stay the same, right, meaning the same sort of larger procurement of ancillaries to deal

[1:53:01] with the volatility in the market from renewables, and those impacts, that impact on the real

[1:53:07] time market and pricing, then we need to be mindful of how those, all those, and

[1:53:12] And then ORDC, because ORDC is a different variable, right?

[1:53:15] ORDC is driven by reserve levels on the system, and if we're carrying more reserves on the

[1:53:20] system, then you're not going to really get those adders.

[1:53:23] And so how does it all interplay?

[1:53:24] And I think that's going to be really important to monitor going forward is, you know, carry

[1:53:30] more ancillaries and the effects on the real-time market.

[1:53:33] And I think we'll do that through our monitoring that we've asked for on the ORDC price

[1:53:38] adders.

[1:53:39] but I guess what I'm getting at is we had lower ruck this summer because of those variables

[1:53:46] you described, but is that going to be the case going forward? You know, just understanding

[1:53:51] is, you know, I think different, it almost seems like different factors are driving

[1:53:56] higher ruck use that are now maybe not going to be as present because of the actions

[1:54:05] being taken going forward.

[1:54:08] Yeah, I mean, I would again emphasize the high energy prices

[1:54:13] driving self-commitment and there was no necessity for ERCOT to ruck.

[1:54:21] There also was nothing really left to ruck in many...

[1:54:25] But what was driving those high energy prices?

[1:54:27] So the higher prices were driven by the high load

[1:54:33] and high offers. But I need to emphasize, like if those, in many instances, if the offers

[1:54:40] had been lower, then ORDC would have kicked in and set a price. It's just that the circumstances

[1:54:51] were such that the offers were above what the ORDC would have set the price at. So

[1:54:58] So then it's just an offer that is the driver.

[1:55:03] In shoulder months, you're less likely to see those shortage conditions and more likely

[1:55:11] to see resources having a more difficult time deciding if they should self-commit for a

[1:55:19] day or not self-commit.

[1:55:21] So, I would not want to say what we saw this summer or I would want to avoid leading you

[1:55:29] down a path thinking that what we saw this summer means no rucks for the fall and winter.

[1:55:35] It would depend on the circumstances.

[1:55:38] Then the last thing I think is important to add is I do think, I agree with you that

[1:55:42] that we will try and tease out all of these factors as we talk about how ORDC is working.

[1:55:52] I think you'll want to consider the ancillary service methodology and what ultimately comes

[1:55:57] out from that.

[1:55:58] So all of these things will dovetail together and absolutely need a review and explanation

[1:56:05] and possibly shifts in where we go from a policy standpoint.

[1:56:10] point.

[1:56:11] So this gets to what we actually need, and this is going to come up during the reliability

[1:56:18] standard evaluation that Woody and Team are working on.

[1:56:22] But Dan, am I understanding you correctly from an operator's point of view to manage

[1:56:27] through this high-volatile variable environment?

[1:56:32] You believe your operators are looking for a conservative posture of PRC plus the ancillary

[1:56:40] service suite in order to account for variability on the system.

[1:56:44] And the reason I ask is because that helps inform the commission's decision on a target reliability

[1:56:50] standard and then thus the reserves that this system needs to incent to come into the

[1:56:57] system to meet day-to-day reliability.

[1:56:59] I

[1:57:02] mean, I think if the market mechanisms and the market incentives are driving the aggregate

[1:57:10] generation to commit to serve load plus the ancillary service quantities that we're asking

[1:57:16] for, then we'll never have to ruck specifically to get up to the 6,500, because we'll already

[1:57:22] be there.

[1:57:23] So you'll never have to ruck for capacity.

[1:57:25] You'll ruck for to manage the services.

[1:57:27] capacity but it would be just to get enough to survey us, we wouldn't have to

[1:57:32] rub extra like we have been. Got it occasionally. Thank you.

[1:57:38] I have a related but different question related to the high prices as the grid

[1:57:43] gets more and more dependent on wind and solar which is harder to forecast

[1:57:47] because we know weather is so hard to forecast. It's adding additional risk

[1:57:51] into the market. Are the higher, what have you looked at what fraction of the

[1:57:57] higher prices are basically offsetting that additional risk of the unknown wind and solar

[1:58:02] that we experience each day.

[1:58:06] You know what I'm saying?

[1:58:07] It's not a predictable machine.

[1:58:08] I understand the question.

[1:58:09] He can turn on and off.

[1:58:10] So again, the mechanisms are in place, but always need to be reviewed, about achieving

[1:58:20] the prices that we want when reserves drop or are at certain levels.

[1:58:27] And that is this operating reserve demand curve.

[1:58:30] The other adjustment that we make is if we take out of market action, we pull that out

[1:58:36] and try and make sure the market prices out as if we did not do that.

[1:58:41] So those two things are there in terms of pricing.

[1:58:46] But what we saw this summer is offer-based clearing prices and a much higher frequency,

[1:59:00] I guess, is the right way to say it.

[1:59:02] And I would say that the uncertainty is managed and priced in as we lose or gain

[1:59:15] intermittent, or low does something that's unpredictable.

[1:59:22] So I think that's there.

[1:59:24] What is missing is a steady forward revenue stream, or understanding of a revenue stream

[1:59:36] going forward that makes investors comfortable about putting down the capital and understanding

[1:59:48] the risk to build what we need going forward. To me, that's the big piece that's missing

[1:59:55] right now, as far as the real time or near real time.

[2:00:00] Pretty well. I'm not saying that there aren't adjustments that need to be made. The missing

[2:00:07] piece is how do you get that kind of comfort level with investing in the ERCOT footprint

[2:00:15] over the long term so that we can meet load growth and get the characteristics that we're

[2:00:22] looking for.

[2:00:29] Thank you, Kenon. We're going to try to get back on track a little bit in terms of

[2:00:36] time.

[2:00:38] Next is agenda item 7, notice of additional capacity requests for winter 2023-24, load

[2:00:46] season. Chad and Woody are here to present this item.

[2:00:51] Yeah, Woody Richardson, I'll start this off. It's a discussion about the capacity for contract.

[2:00:58] So there are really three takeaways here. We're looking to procure up to 3,000 megawatts

[2:01:06] of additional generation and or demand response for this winter.

[2:01:10] The RFP was driven by peak load growth since last winter, the proposed retirement system,

[2:01:17] dispatchable units, and the low probability but high impact risk of an extreme winter

[2:01:22] event.

[2:01:24] And finally, we're not projecting emergency conditions this winter, however, we did see

[2:01:31] in our analysis, that if we were to have an elite type storm again, there was a 20% chance

[2:01:38] of entering into an EEA. It's an elevated chance. And, Mr. Precaro, your question earlier

[2:01:45] about the 10%, that has been a traditional number that we have used when we were reporting

[2:01:53] assessments to NERC. It's not an official threshold, but it's been a number that

[2:02:00] But if your risk was above 10%, it was considered elevated.

[2:02:05] And that goes into their winter assessment that they use for all regions, not just ERCOT.

[2:02:11] So just a follow-up on that.

[2:02:17] So the summary of ERCOT's analysis, we use the probabilistic reserve risk model.

[2:02:23] That's the same model we use for Mora, not the greatest acronym.

[2:02:27] But it performs a Monte Carlo simulation, shows probabilities for how much capacity you have

[2:02:34] for different seasonal peak load days.

[2:02:39] The simulations accounted for the demand growth experience in 2023, and then we forced in

[2:02:45] the winter storm Elliott weather for this analysis.

[2:02:49] So this analysis includes a storm like we had last year of that severity, the winter

[2:02:56] storm, Elliott Storm. So what we found was that the highest risk hour for this hour was

[2:03:01] 8 a.m., which is traditionally in the winter, you see load peak early in the morning and

[2:03:09] then there will be another peak late in the evening. Both of those peaks are outside the

[2:03:13] solar output. So that's our highest risk hour is 8 a.m. The probability without having

[2:03:21] with just the, with no additional capacity, the probability was right at 20% that if we

[2:03:28] had a winter storm, Elliot type weather, there's a 20% chance we'd go into some kind of EA.

[2:03:35] By adding 3,000 megawatts of additional capacity, that could be demand or generation that would

[2:03:42] take it down to below that elevated level, 9.4%. So that was the basis, that was

[2:03:49] the summary of the analysis. That's why we put the RFP out.

[2:03:56] So some of the details, seeking

[2:04:00] capacity from generation resources or demand response, the list of eligible generation

[2:04:06] resources, demand response. The main thing I'd say about the demand response is we need

[2:04:12] things that we wouldn't get otherwise. So we're not looking to pay for something

[2:04:15] that would show up due to prices already. So this would be new sources. That's the important

[2:04:22] part there. The procurement would be for a period from December 1st through January.

[2:04:30] The

[2:04:31] inservice date would be December 1st to January 9th, and it would go through the end of February.

[2:04:38] Those are some of the details of the RFP. Are there any questions about those?

[2:04:43] What do you mean I'll just highlight that again on the in-service dates?

[2:04:46] Really we're trying to provide as much flexibility for resources to come into the program between

[2:04:55] December 1st and January 9th.

[2:04:57] The full obligation period if you enter December 1st is December 1st through the end of February.

[2:05:02] But if a resource offers in and can't be there until January 1st and the cost is

[2:05:09] reasonable as we go through the procurement decision, then we'll sign up that resource

[2:05:12] on January 1st and have them available from January 1st through the end of February.

[2:05:18] So again, I think the idea with the RFP was to provide as much flexibility as possible

[2:05:23] to address the risks that we were seeing on the system.

[2:05:28] So any other questions about the details here?

[2:05:34] What weatherization are you assuming for the generation resources?

[2:05:37] I mean, would these units be weatherized that have been mothballed and taken

[2:05:41] out of the market to the phase two requirements that we have in place?

[2:05:46] So you're talking about if we accepted an RFP from a generator, what's the weatherization

[2:05:51] assumption for that?

[2:05:52] Yes.

[2:05:53] We assume 100% that it would be there.

[2:05:56] Okay.

[2:05:58] Thank you.

[2:06:01] So what do you mean by on the next slide?

[2:06:04] The next slide lays out the procurement timeline, which is aggressive to get us to December

[2:06:10] first. Where we are right now is that we've received over 130 questions from stakeholders

[2:06:17] interested in the RFP requirements, seeking additional clarity. So we're in the process

[2:06:23] of developing those responses. Tomorrow, we will release our responses to those questions.

[2:06:30] And then the commission has, as Pablo already alluded to, an all-day workshop on Friday

[2:06:36] of the 20th, and as you'll see here on the procurement timeline, the workshop on the RFP

[2:06:43] and the governing document has been added to the commission's overall workshop.

[2:06:48] And that discussion will occur at around 2 p.m. on Friday afternoon, where we go through

[2:06:53] those responses and answer any other questions from the stakeholders or the commission.

[2:06:59] And then as we head into next week, we're given an opportunity to amend the RFP and the

[2:07:06] other governing documents.

[2:07:07] At that point, that is truly the final RFP that everybody is able to consider and decide

[2:07:14] whether they want to offer in a proposal on November 6.

[2:07:19] And then you see the rest of the timeline as we start to move forward.

[2:07:22] board, the award notice on Friday, November 20th, and then an execution phase that again

[2:07:28] could take us all the way up to January 9th as a target start date for any resources that

[2:07:34] are eligible.

[2:07:36] And then we'll come back in December and obviously update the board on whether we

[2:07:41] signed any contracts under this process.

[2:07:45] Woody and Chad, first of all, applaud the organization for coming up with this

[2:07:50] concept.

[2:07:50] But it does several things. One is it signals to the market and to the public that we have

[2:07:56] a potential problem this winter because the market has not provided the level of dispatchable

[2:08:03] resources that Texas needs. Secondly, it was designed in such a way to be able to stimulate

[2:08:10] the addition of additional generation and or to acquire some new demand response.

[2:08:18] So my question is, on the 130-some-odd questions that you have in, do you have a feel for how

[2:08:25] much of those – how many of those questions are related – or what percentage of those

[2:08:29] questions are related to bringing back generation versus demand response?

[2:08:35] Do you have a feel for that?

[2:08:40] The ones that I've seen, they're targeted on understanding the demand response side

[2:08:45] of it, you know, energy storage, resources of opt-in questions.

[2:08:49] We have posted all the questions on our website,

[2:08:53] and so everybody is able to go look at what those questions are

[2:08:56] as we develop those responses.

[2:08:58] You know, I think we obviously listed in the market notice

[2:09:02] when we came out on October 2nd,

[2:09:04] all the resources that are either mothballed

[2:09:08] or in some state of suspended operations,

[2:09:11] recognizing that, you know, some of those

[2:09:14] won't be able to come back, and so we recognize that.

[2:09:17] And so we really think this is a good tool to see what demand response capability is out there that we're not already receiving through other programs.

[2:09:25] We've allowed a lot of flexibility here for the demand side.

[2:09:29] And so I think this will be a good use case to see how the demand side steps up, evaluates this proposal, and sees if they want to offer it.

[2:09:37] Okay. Well, again, I applaud your disinitiative. I think it's well thought out. I think it does stimulate

[2:09:45] innovative way of looking at providing for additional resources as we go into a tight winter.

[2:09:54] Woody, have you identified the type of resource that you want? For example, ramping capability,

[2:10:01] or are you just waiting to see what comes in? Question one, question two would be,

[2:10:05] And how will you handle a non-performing resource as well?

[2:10:11] So from a ramping standpoint, we will look at anything.

[2:10:14] So we don't have a specification that says you have to be able to ramp up within a certain amount of time.

[2:10:18] We would adjust when we ask for them based on what the ramping capability is if we were to get one or two or whatever.

[2:10:25] Non-performance is, if we'd be able to handle that, they wouldn't get paid.

[2:10:30] I mean, there will be clawbacks on that if we did call them and they didn't show up.

[2:10:39] And of course, the demand response is done afterwards, that payment, so we would have

[2:10:46] settlement.

[2:10:47] Would there be penalty in addition to non-payment?

[2:10:53] I don't believe there is a penalty.

[2:10:57] Just non-payment.

[2:11:05] Okay.

[2:11:06] Other questions?

[2:11:06] Thank you Woody, Chad.

[2:11:14] Next up, be sure of, is Agenda Item 8, Independent Market Monitor

[2:11:23] Report. IMM Director Kerry Bivens is here with us to present this item. Kerry?

[2:11:48] Good morning everyone. It's Kerry Bivens with Potomac Economics. Happy to be here to give

[2:11:54] my usual report. In fact, a lot of what I was going to cover, actually Kanan covered

[2:11:59] in his summer review, so I'll skip through some of that quickly. I do want to go ahead

[2:12:05] and address. I hadn't intended to talk about our ECRS analysis because that was done in

[2:12:10] conjunction with the Ancillary Services methodology, which is not before you today.

[2:12:15] But I did just want to kind of add a couple of thoughts. One is that when that

[2:12:21] program was approved by the board and the business case for the new service had to do

[2:12:31] with efficiency, adding market efficiency, and it had nothing to do with particular,

[2:12:40] you know, ramping needs or net load or anything like that that we've been talking about.

[2:12:44] But, you know, we know that this service has not increased efficiency because of the analysis

[2:12:51] that we performed.

[2:12:52] And the purpose of that was to show order of magnitude to understand, you know, what

[2:12:59] are these costs and are they, you know, small or significant?

[2:13:04] And we intend to provide red line comments to the Ansler services methodology to tweak

[2:13:10] how the ECRS is purchased and how non-spin is purchased in order to bring that into alignment

[2:13:16] with what we think are more reasonable reliability goals.

[2:13:21] Real-time co-optimization will solve a lot of the issues that we identified, not all

[2:13:24] of them, but a number of them.

[2:13:27] And so we appreciate that IRCOT's continuing to work on that project, and that is going

[2:13:31] to make a big difference eventually.

[2:13:34] But we've got a ways to go until that comes, and so I hope that we can engage

[2:13:39] you guys in December to talk more about the ancillary services methodology.

[2:13:45] So we already talked a lot about prices. Of course, prices were very high in August.

[2:13:49] Kanan talked about peak or net margin. That's about two and a half times cost of new entry.

[2:13:54] It's a pretty substantial and remarkable result for a system that is meeting the one and

[2:13:58] exceeding the one in 10 standard.

[2:14:03] Ancillary services costs are up pretty drastically

[2:14:05] for the summer. A lot of that is driven by ECRS, but also RRS because these are co-optimized

[2:14:12] services in the day-to-day market. And when, you know, the supply of one service is restricted,

[2:14:19] it tends to raise the prices of all the services.

[2:14:24] We talked a lot about load trends, so I won't

[2:14:26] go up too much about this other than to note that there's load growth in all zones.

[2:14:32] And we also wanted to show the other side of the equation, which is also, which

[2:14:37] is addition of capacity. There have been a substantial amount of capacity that has also

[2:14:41] grown since the summer of 2021 to address some of the slow growth that we've seen.

[2:14:49] I have a question on that. Is that a net new capacity or is that gross?

[2:14:55] That's gross.

[2:15:00] So, there's been a lot of stuff fall off, too.

[2:15:02] No, I can't think of. We didn't have any retirements last year, and I think we only had one proposed

[2:15:08] retirement this year. So, since 2021, I don't think that would be a significant difference.

[2:15:19] Around low forecast error. So, with conservative operations, ARCOT is sometimes choosing the

[2:15:25] most conservative forecast, and we can see that within the low forecast error. In the

[2:15:29] afternoon and evening, especially at the peak hours, that's the blue line that's like above

[2:15:35] all the other lines there. You can see it's pretty significantly in June and July and August

[2:15:43] over forecasting by 1,600 to 3,200 megawatts of load.

[2:15:51] And also there's been a lot of discussion of the thermal generation fleet and how it

[2:15:55] performed this summer. So if we looked at last summer versus this summer to see

[2:16:00] what was the generator performance and typically we always see, we typically see good performance

[2:16:06] in summer because that is when outages, planned outages are low. It's, everybody's preparing

[2:16:13] for the summer and the shoulder seasons and they want to be highly available to capture

[2:16:17] summer pricing. We did see higher deratings and outages in June and, but pretty similar

[2:16:27] for July, August, and September.

[2:16:31] And so when you look at the monthly average,

[2:16:33] whereas there might have been some days

[2:16:35] in which we had high thermal outages,

[2:16:36] we had other days in which they were low,

[2:16:38] and if you look on an average basis,

[2:16:40] the generator performance was pretty similar to last summer,

[2:16:43] maybe with the exception of June

[2:16:45] in which we did see higher outages.

[2:16:49] That's my last slide.

[2:16:51] Any questions for me?

[2:16:52] Hey, Carrie, I've got a question.

[2:16:57] Early in the presentation, you talked about commenting on the, or making changes to the

[2:17:04] Ancillary Service methodology to get a reasonable rate of reliability, a more reasonable rate.

[2:17:11] A more, yeah, more efficient procurement to meet the reliability.

[2:17:15] Okay.

[2:17:16] I guess my question is the Ancillary Service methodology will be completed in December

[2:17:21] of this year.

[2:17:22] That's right.

[2:17:22] And the reliability standard won't be done until probably after that.

[2:17:29] That's right.

[2:17:30] So how do you marry up those two things?

[2:17:31] How do you look forward to a future reliability standard

[2:17:37] and make changes to the Ancillary Service methodology now?

[2:17:42] So, in my view, a reliability standard is more of a planning metric.

[2:17:47] And the Ancillary Services methodology is for the operating time horizon.

[2:17:51] in. And so, those are different views. I would say that what we're trying to do in

[2:17:57] our comments for the AS methodology is look at what is each service, what is it being

[2:18:02] used for, and what are our recommendations for how to make modifications to those things

[2:18:10] like, for instance, you know, I don't know if I want to get into all the details,

[2:18:15] but just tweaking some of the quantities so that the better aligns with even the stated

[2:18:24] goal of the service. For instance, ECRS is a 10-minute service, and it is used and deployed

[2:18:30] for 10-minute net load ramps. And so we believe that 10-minute net load errors are the accurate

[2:18:37] reliability metric to use for that methodology, not 30 minutes, as it currently does. That's

[2:18:42] one example. And so it's things like that that we will be proposing to change and we'll

[2:18:48] take that to WMS next month.

[2:18:51] Kerry, when you go back to the previous slide where John asked the question about the new

[2:19:00] generation that's come online, did you say that during this period, no generation would

[2:19:07] come offline?

[2:19:09] I can't remember off the top of my head. I'm trying to remember when we did our

[2:19:13] annual report I think we had like I know we have one announcement right we have

[2:19:18] Barney Davis announcement this year and it's so is that not offline yet it's not

[2:19:25] offline yet there was I think there might have been one at the end of 2021 I

[2:19:32] don't think there were in any 2022 this is 20,000 megawatts so any any

[2:19:36] Any retirements we've had have been like 400 megawatts.

[2:19:38] I was thinking it was already offline but it's just announced and we're trying to get

[2:19:45] it.

[2:19:46] We hope it will come back in through the RFP.

[2:19:54] I have a couple of things.

[2:19:56] One is I think the actual retirement since 2021 are about 1.2 gigawatts but I'll get

[2:20:00] the exact breakdown of that so that it can be baked into the next analysis.

[2:20:04] that would turn that, the dispatchable power negative in that graph or get it

[2:20:12] close to negative or zero. Going, when you look at the cost of answering services

[2:20:18] that's paid for in order to try to encourage reliability, to try to create

[2:20:27] a reliable grid.

[2:20:30] The offset to that is that there is a cost of an avoided load shed. And

[2:20:37] so what is the value of that? Basically, Ancelary Services is paying for the avoidance of load

[2:20:42] shed. How do you make those two together? I think you'd admit that reliability is important

[2:20:48] and that ought to be the goal of any grid operator.

[2:20:51] Of course, absolutely. Ancelary Services are very specific capacity products. They're

[2:20:55] not general capacity products to meet a reliability standard.

[2:20:59] They are very specific to follow the load

[2:21:02] and to ensure that the frequency is followed,

[2:21:04] or if a unit trips to be able to replace those megawatts.

[2:21:07] But you can spell out reliability.

[2:21:09] Yes, absolutely.

[2:21:10] But what I'm trying to point out

[2:21:12] is that they have very specific uses.

[2:21:17] And those specific uses can be studied and analyzed

[2:21:19] to determine how many do you need to meet them.

[2:21:22] It actually has no, the reliability standard

[2:21:25] is something that's completely different from that?

[2:21:28] The reliability standard is different,

[2:21:30] but these services are procured to ensure reliability.

[2:21:34] And if you didn't do that, or if there's

[2:21:38] criticism of the cost of it, the cost that they are offsetting

[2:21:42] is avoided load shed.

[2:21:44] And so we need to look at the value of that.

[2:21:46] Somewhere that's got to be baked in to this analysis

[2:21:49] is that those are done to avoid load shed,

[2:21:51] because load shed has a cost to consumers.

[2:21:54] the economy to people to physical health and so forth. Absolutely we should we

[2:22:00] should absolutely procure enough to have a reliable grid we should have the

[2:22:04] right services to meet the specific attributes that the grid needs but we

[2:22:09] should not buy more than that more more megawatts is just more cost more

[2:22:13] megawatts and you need to meet all of those attributes it's just additional

[2:22:17] costs it's not actually buying you any additional reliability and it's not

[2:22:21] actually in my opinion I think we would have been just as reliable this summer

[2:22:25] without these excess ECRS megawatts. But that's looking backwards that's not

[2:22:29] from the perspective of the control room operators got a deal with the

[2:22:34] uncertainties of an intermittent grid power supply as well as potential

[2:22:40] things that could go wrong. Yes I'm aware of that I just think that there

[2:22:45] is a right amount to buy and we shouldn't buy more than that.

[2:22:51] carry on the new unit capacity that is that all just nameplate like for the

[2:22:55] wind and solar is that just nameplate or is that effective capacity I believe

[2:23:01] it's cumulative summer it's summer summer capacity so it's their rated name

[2:23:06] play it's not the ELCC number it's not the ELCC it's the summer max it's so

[2:23:11] it's temperature adjusted and so 14,000 of that is wind and solar so you

[2:23:16] see maybe a third of that if you're lucky right yeah it's just temperature

[2:23:20] are adjusted nameplate for sure.

[2:23:22] And that goes back to 21.

[2:23:23] If you look at that compared to low growth from 21,

[2:23:26] if you adjusted that down, I think

[2:23:29] that would tell the story.

[2:23:41] I do think in listening to the discussion today,

[2:23:44] maybe it's for R&M or the board.

[2:23:46] But it would be helpful to understand

[2:23:48] the protocols around each of the ancillary services

[2:23:50] and kind of the rules and engagement for each of these.

[2:23:56] Yeah, we could do that.

[2:24:01] Any other questions?

[2:24:03] If

[2:24:07] not, Gary, thank you.

[2:24:08] Thank you.

[2:24:12] All right.

[2:24:14] At this time, I'd like to invite Cliff Lange, Chair of the Technical Advisory Committee,

[2:24:20] to present an Agenda Item 9 TAC report.

[2:24:24] There's one non-unanimous revision request as a voting item under the TAC report today.

[2:24:31] NPRR 1188, which the Board remanded to TAC in August.

[2:24:36] The Liability and Markets Committee discussed this NPRR yesterday, after Cliff reports on

[2:24:44] tax recommendation on NPRR 1186, RNM Committee Chair Bob Flexin will report on the RNM Committee's

[2:24:53] discussion and recommendation.

[2:24:56] At yesterday's RNM Committee meeting, Stephanie Smith from EOLENLP addressed the RNM Committee,

[2:25:02] And she is here again today if any board members or commissioners have questions for her or for her.

[2:25:10] Dan Woodfin is also here to answer any questions regarding ERCOT's recommendation.

[2:25:18] Cliff, please proceed.

[2:25:19] All right. Good morning, everyone.

[2:25:22] So a rather abbreviated tax summary for you this month.

[2:25:25] We did have three revision requests and, of course, as Chair noted, one of which was

[2:25:30] non-unanimous in that regard.

[2:25:32] The first two NPRRs, 1184 and SCR824, you'd already taken up in your consent agenda.

[2:25:39] 1186 we'll discuss in a second and we'll talk about the TAC highlights at the end

[2:25:44] of my presentation there.

[2:25:46] Regarding NPRR 1186, as was noted, this one was remanded to TAC for consideration.

[2:25:52] We had five sets of comments that we considered when we last met in September to discuss this

[2:25:59] and our other items at that meeting, and of those five comments, one of which included

[2:26:04] a set of comments filed by IRCOT that included language changes.

[2:26:09] We spent time discussing the merits of those language changes and did have some questions

[2:26:14] regarding the intent since the language did go beyond what was originally remanded

[2:26:19] to TAC to consider.

[2:26:20] We did spend a fairly significant amount of time talking about additional concepts that

[2:26:26] were contained in the preamble to the language changes, but not being considered by TAC otherwise

[2:26:32] in the context of the language changes that ERCOT submitted.

[2:26:36] Those included discussing compliance metrics that were associated, potentially associated

[2:26:41] with nonperformance.

[2:26:43] We also asked questions about additional comments ERCOT had regarding limits to ancillary

[2:26:47] service provision from energy storage resources and potential increases in the ancillary services

[2:26:54] in the event that there was a failure to maintain state of charge. Again, those items were not

[2:26:58] in the context of the revisions that you're going to be discussing today, but we're in

[2:27:03] the preamble language that was discussed and did peak interest from TAC members. We had

[2:27:08] an almost unanimous decision with one opposing vote. The reasons for those really revolved

[2:27:13] around the necessity for penalties and whether that was something we needed to proceed with,

[2:27:19] whether the NPRR was actually discriminatory towards one asset type, in this case energy

[2:27:24] storage resources, and then lastly whether this was a waste of resources on the ERCOT

[2:27:30] perspective in terms of taking away resources that would be needed for real-time co-optimization

[2:27:36] plus battery storage changes that are upcoming.

[2:27:40] Lastly, we had a couple of highlights here that I wanted to bring to your attention.

[2:27:44] We did approve our major transmission elements list that was brought to us by the Reliability

[2:27:50] Operations Subcommittee.

[2:27:52] That seeds are what we call a height list or a high impact transmission element list.

[2:27:58] And we also kicked off our process of doing our annual TAC and TAC subcommittee procedural

[2:28:03] review.

[2:28:04] We did have our subcommittees do their self-assessment.

[2:28:07] We did have a meeting on October 13 to discuss those results, an informal meeting at that.

[2:28:12] And we will discuss our findings at our upcoming meeting next week, and we will bring those

[2:28:17] to RNM in December.

[2:28:19] And that is it for our TAC report.

[2:28:21] Any questions?

[2:28:28] I guess not.

[2:28:29] Thank you, Cliff.

[2:28:30] Thanks very much.

[2:28:31] You're quite welcome.

[2:28:36] Okay.

[2:28:36] I think we're looking for Bob to provide an update from the RNM on 1186.

[2:28:41] Yes, so we did reconsider the NPR or 1186 following our prior meeting where the Board

[2:28:48] had remanded to TAC of the deployment as you discussed during the August 30th R&M Committee

[2:28:55] meeting and the August 31st Board meeting. So in addition to TAC reporting, we also

[2:29:01] had ERCOT staff report and also Stephanie Smith present it again on behalf of Eolean.

[2:29:07] So the commissioners, the committee members, IRCOT staff, and Stephanie Smith, we discussed

[2:29:12] the changes that were proposed to NPRR 1186 following the remand attack that allowed

[2:29:18] for resource flexibility and bidding for the Ancillary Service Award, the impacts

[2:29:26] of the resources charging during emergency conditions, and non-distinction regarding

[2:29:31] resource state of charge between scarcity intervals and non-scarcity intervals.

[2:29:35] and the potential impacts that NPRR 1186 could have on investment and development of longer

[2:29:42] duration batteries and qualifying scheduling entities and the management of reserves.

[2:29:48] So we had a robust discussion with all those parties and all those different considerations.

[2:29:53] I'll do a full report out later, but the R&M Committee did approve it unanimously.

[2:30:00] And I feel that all parties had ample time to express their thoughts and considerations.

[2:30:07] And the approval came with an attachment that ERCOT to look at potential penalty and mitigation

[2:30:16] structures through another NPRR for nonperformance. So we have approved it down at the RNM level.

[2:30:24] And again, if anybody from either ERCOT or Stephanie from EOLI will like to comment, please do so.

[2:30:30] But we really did air it all out yesterday and reached the final conclusion.

[2:30:39] Okay, so we have a recommendation from RNM to the Board to approve 1186.

[2:30:46] Does anybody have any?

[2:30:47] So let me just clarify.

[2:30:49] I think Bob, your recommendation is to approve 1186 as recommended by TAAC.

[2:30:53] And then there were these two other items that were discussed at R&M about the board designating

[2:30:59] one or more priority NPRs to deal with the compliance and the financial penalties piece,

[2:31:04] correct?

[2:31:05] Yes, correct.

[2:31:06] Okay.

[2:31:11] So I would entertain a motion to approve.

[2:31:15] So moved.

[2:31:16] So moved.

[2:31:16] Second.

[2:31:17] Okay.

[2:31:18] Motion to second.

[2:31:19] All in favor?

[2:31:20] Aye.

[2:31:21] Any opposed?

[2:31:23] Thank you.

[2:31:24] I know that was a lot of hard work and effort from everyone involved, but confident we ended

[2:31:31] up in the right place.

[2:31:32] We came up with a better product.

[2:31:43] Next is agenda item 10, load zone changes, request of lower Colorado River Authority,

[2:31:50] and Chad will present this.

[2:31:53] Yep.

[2:31:53] I'm going to just do it from here so Penny, if you'll drive, try to catch us up.

[2:31:58] So doing this on behalf of LCRA, this is a board voting item.

[2:32:02] You have a decision template in your public materials.

[2:32:05] This is really related to the BRASIS bankruptcy matter where BRASIS had to relinquish all the

[2:32:12] load under its mark participant registrations.

[2:32:16] And so LCRA has contracted with this one co-op member that was in BRASIS's area.

[2:32:23] And LCRA now wants to align that load with its designated load zone.

[2:32:28] There is a specific process in the protocols that authorizes the board to add, delete,

[2:32:35] or change load zones, and that's what this request is.

[2:32:39] There are competitive and no-e load zones across the system.

[2:32:42] LCA has its own no-e load zone.

[2:32:45] If the board moves forward to vote on this today, it will be effective 48 months following

[2:32:50] this approval, and that's because we have a congestion revenue write auction that

[2:32:55] That goes out three years and so gives certainty to those entities participating in the CRR

[2:33:00] auctions on where that load is going to be in the model in future years.

[2:33:04] So that's why it takes 48 months for it to become effective.

[2:33:07] On slide three here you see just kind of a visual representation of the Hamilton load

[2:33:14] in the upper right quadrant in blue and of course 48 months later it would turn

[2:33:20] to yellow, which is represented here on the scale, is LCA's load zone, if the board approves

[2:33:26] us.

[2:33:30] And there is a representative from LCA here if the board members have any specific

[2:33:34] questions to LCA on this load zone change.

[2:33:40] Happy to answer any questions.

[2:33:45] Do you want a motion? Yes. I'll move it.

[2:33:49] Second. All right. We have a motion to second.

[2:33:52] All in favor? Aye.

[2:33:54] Any opposed? All right. It passes. Thank you.

[2:34:02] Next, we have the committee reports.

[2:34:06] First bill will present agenda item 11, finance and audit committee report.

[2:34:12] Thank you, Mr. Chairman.

[2:34:14] Finance and audit committee discussed several items yesterday.

[2:34:19] First of all, let me state that there are no voting items that will be presented to

[2:34:23] the board today.

[2:34:25] The first thing we did was to review, was to talk about the fact that we will

[2:34:29] have self-evaluation of the committee members that will be done sometime during our December

[2:34:35] meeting. Secondly, we reviewed the most recent financial performance of the organization

[2:34:42] as well as comparisons to the expected financial performance at the time the budget was considered

[2:34:50] back in June. And I'll come back to that in just a minute. Lastly, or excuse me,

[2:34:55] Additionally, we reviewed the status of our current investments and they'll comply with

[2:35:00] our investment policy.

[2:35:02] We also looked at our debt governance performance and have determined that we are in full compliance

[2:35:07] with all debt governance.

[2:35:09] Now, moving back to the financial performance of the organization, compared to what we expected

[2:35:15] when we looked at the budget in June of this year, the organization has had positive

[2:35:22] to financial performance that I think needs to be considered by the PUC when it looks

[2:35:27] at the system administration fee for future years.

[2:35:32] In particular, our interest income is about $27 million higher or expected to be $27 million

[2:35:38] higher than what it was when the initial forecast were put together in June.

[2:35:45] Our system admin fee revenues are higher by about $6 million because of additional

[2:35:50] low during the summer months, as we've talked about several times during this meeting so far.

[2:35:55] Expenses are $4 million favorable to a variety of factors, including lower

[2:35:59] than budgeted insurance premiums. So the net net is we've got about $36 million more and resources

[2:36:06] available to us at the beginning of 2025 than we expected to have when the budget was put

[2:36:13] And so, if you were to prepare the budget today and present that to the PUC, you could

[2:36:22] possibly come up with a system admin fee somewhere less than the 71 cents that we originally

[2:36:29] proposed when this board approved the budget back in June.

[2:36:33] So based on that, I've asked the, on behalf of the Finance and Audit Committee, I've

[2:36:38] that ERCOT staff submit a revised rate calculation to the commission that includes the updated

[2:36:45] 2023 forecast during yesterday's FNA meeting as we anticipate that the commission is going

[2:36:51] to address ERCOT's 2024-2025 budget request at its November 2nd open meeting.

[2:36:58] I think that, you know, those additional resources should be made available to reduce

[2:37:04] the impact of the cost of the system admin fee on the consumers of the state.

[2:37:10] And that's my report.

[2:37:12] All

[2:37:15] right.

[2:37:16] Any comments or questions?

[2:37:18] So I just want to, based upon Chair Flores's F&A direction, we will add some additional

[2:37:28] materials into the docket in which the commission is going to consider our fee proposal and

[2:37:34] budget proposal before the November 2nd opening.

[2:37:43] Thank you.

[2:37:44] We appreciate that.

[2:37:45] And the diligence going back and kind of looking at taking a second look, and that obviously

[2:37:50] came out of the scrutiny that ERCOT did, looking at, you know, what we had that was

[2:37:55] available when we actually put the budget together, ERCOT did, and then what's available

[2:37:59] now and then taking that action.

[2:38:01] So we very much appreciate that.

[2:38:06] Next, Peggy Hig will present Agenda Item 12, which is the HRNG Committee report.

[2:38:13] Peggy?

[2:38:14] Yeah.

[2:38:15] Thank you, Chairman.

[2:38:16] This will be short.

[2:38:17] We had no voting items in the Human Resources and Governance Committee meeting.

[2:38:22] And the only item we discussed in the general session was the self-evaluation similar to

[2:38:30] what Bill mentioned for FNA.

[2:38:32] So that will be going out to committee members.

[2:38:35] members, and we welcome input from many board members, and we will discuss that in the December

[2:38:41] Human Resources and Governance Committee.

[2:38:45] Thank you.

[2:38:46] Okay.

[2:38:47] Comments?

[2:38:47] Questions?

[2:38:49] Thank you.

[2:38:50] Next, Bob will present Agenda Item 13, R&M Committee Report, which has one associated voting

[2:38:57] item.

[2:38:58] The item recording voting deals with the R&M Committee Charter.

[2:39:01] The committee charter was revised to reflect the adjustment for formation of the technology

[2:39:07] and security committee and also some additional revision requests recommended by TAG for board

[2:39:16] approval.

[2:39:17] So we made note of that maybe further updates in the language in the future as well as

[2:39:22] revisions to the board policies and procedures of protocol section 21.

[2:39:26] so recommending to the board to accept the adjustment to the RNM committee

[2:39:31] charter all right motion by Bob I'll move it second by Julie all in favor any

[2:39:40] opposed thank you that passes and next we also went through some additional

[2:39:47] discussions on standing committee items weatherization updates system

[2:39:52] planning and weatherization update. We reviewed the interconnection queue, the impact of regulatory

[2:39:58] certainty on speculative generation, and the number of generation applications that have

[2:40:03] commissioned into service and how they've been decreasing over time. We went through

[2:40:09] the monthly resource adequacy report and use of the dispatchable generation energy storage

[2:40:15] resources and capacity contracts.

[2:40:20] We analyzed the probability of outages due to storm

[2:40:24] and the weatherization assumptions for each of the scenarios,

[2:40:28] and the mix of staff and contracted labor to perform the actual inspections of weatherizations.

[2:40:34] The system's operations update in response to the latest solar eclipse,

[2:40:41] we took a look at the generation down ramp of five megawatts

[2:40:44] rather than a potential 12 megawatts in the plans to use the lessons learned

[2:40:48] for the upcoming full solar eclipse in April of 2024.

[2:40:56] We also took a look at the peak or net margin which we discussed here at the Board meeting

[2:41:00] as well, and we also discussed the impact of energy storage resource capacity offers

[2:41:07] as a factor in some of the high prices that ERCOT saw during the summer.

[2:41:15] And then we took a look at a few high-profile projects.

[2:41:19] We did an update on the reliability standard study where ERCOT filed simulation results

[2:41:24] with the PUC for 48 scenarios and proposed additional scenario simulations.

[2:41:31] We talked about real-time co-optimization update, projects are in flight with initial plans

[2:41:36] to deliver in 2026, and our COD staff highlighted the need for stakeholder feedback, especially

[2:41:41] regarding the incorporation of demand curves, and we had an update on the ADER pilot project

[2:41:49] status and the staff report increased volumes of the ADRs in the program and have accepted

[2:41:56] aggregation forms from 9 ADRs comprising ERCOT-wide energy at 8.3 megawatts and ERCOT-wide non-spin

[2:42:03] of 2.7 megawatts. And that's the items for the report.

[2:42:10] Okay. Thank you. Questions or comments?

[2:42:15] Thank you, Bob. Next, we have John Swenson.

[2:42:20] will present Agenda Item 14, the Technology and Security Committee Report. John?

[2:42:27] Thank you, Mr. Chairman. We have one voting item, and that is the recommendation of the

[2:42:32] Board to designate Committee Secretary, notably to designate Chad or his designee as Committee

[2:42:39] Secretary. Am I going to have a motion? That does not require a Board vote, so let's

[2:42:45] I'm sorry.

[2:42:46] Any action?

[2:42:47] Okay.

[2:42:47] My understanding.

[2:42:49] We had quite a, this was our first meeting, as you might imagine, and being a committee

[2:42:55] comprised of four engineers, there was a lot of discussion about structure and scope

[2:43:00] and process, and we did not conclude on a scope document yet, although there's been

[2:43:08] a lot of good work done by the staff.

[2:43:10] we will bring that forward to the next board meeting as part of our charter.

[2:43:18] But suffice to say that the committee views that its scope is quite broad.

[2:43:25] It's not the Information Technology and Security Commission.

[2:43:28] It's the Technology and Security Committee.

[2:43:31] And as such, we want to make sure that we are looking at it fairly holistically,

[2:43:36] but not overlapping with things which rightly fall into the domain of RNM.

[2:43:41] So we've got a little bit of work to figure out what fits where,

[2:43:46] but we are looking forward to taking on, you know,

[2:43:50] some future technology discussions and trying to understand how those would impact the grid going forward.

[2:43:55] We also have some standing briefs that previously came to the board or came to RNM.

[2:44:02] One to do with the technology OKRs which Giant reviewed with us

[2:44:07] and I'm pleased to say are all in the green.

[2:44:10] There are four of those.

[2:44:12] There are 61 technology projects in total.

[2:44:14] The four of them are at the OKR level.

[2:44:17] Not all 61 are green, but the four that are at the OKR level are green.

[2:44:24] We had an update on information technology from JP who's our management sponsor.

[2:44:32] and and then we had an update on security from Betty and and we'll go into a

[2:44:37] little bit more of that in in the executive session and that concludes my

[2:44:41] report

[2:44:44] okay comments or questions thank you next agenda item 15 annual membership

[2:44:55] meeting announcement the 53rd annual meeting

[2:45:00] December 11th, one week before the meeting.

[2:45:03] ERCOT will send meeting notices to those who are members as of November 17th.

[2:45:08] The date of record has set forth in the ERCOT bylaws.

[2:45:12] And Chad will provide additional details. Okay, so you have a short presentation

[2:45:17] here and the public materials that gives you the location

[2:45:21] at Austin Marriott downtown. If you remember before COVID,

[2:45:25] We used to have kind of a lunch annual meeting.

[2:45:29] This time we're going to convert it to a late afternoon annual meeting from 4.30 to 7.

[2:45:36] With a little bit of just a gathering at 4.30 to 5.30 before we actually kick off the meeting.

[2:45:44] So we think it will be a great opportunity for the corporate members and invited guest speakers

[2:45:48] and commissioners to all be there and talk about the end of the year activities

[2:45:53] activities and looking to the future. Obviously, this is required of the Texas Business Organization

[2:45:58] Code and our ERCOT bylaws to have an annual meeting every year and it coincides with the

[2:46:03] board cycle. So we're checking the box of all those corporate governance regulations.

[2:46:08] On the next slide, you just see a sample agenda. Again, starting at 4.30, just kind

[2:46:14] of a registration reception and then kicking it off at 5.30 with Pablo and Paul kind

[2:46:19] hosting this, along with a couple of guest speakers that we're out trying to get commitments

[2:46:24] from. And I think this year we've started talking to TAC leadership, and I know they'll talk

[2:46:29] about this at TAC next week, is trying to get the corporate members to get up and say

[2:46:34] a couple words at the annual meeting as well. This is really all about the corporate

[2:46:39] members and engagement with everyone. So I know my team has talked to TAC leadership

[2:46:44] about having two corporate members get up and do some introduction speaking and engagement

[2:46:50] with the rest of the members as well. I think they'll talk about that next week at TAC.

[2:46:54] And so you see a little bit of here of what a sample agenda would look like.

[2:46:59] And then the last slide is just obviously where this hotel is located is downtown.

[2:47:03] We'll obviously have a lot more details as we get closer to mapping everything out

[2:47:07] and give notice to the corporate members in November.

[2:47:15] Okay, thank you.

[2:47:18] The last item before we move into executive session is agenda item 16, other business.

[2:47:24] Would any board member like to raise any other business?

[2:47:29] Mr. Chairman, I do have one comment.

[2:47:32] Back during the IMM report, I talked about retirements that we were aware of,

[2:47:39] and I used an estimate of 1.2 gigawatts, the actual number of retirements,

[2:47:43] or the amount, the quantity of retirement since September of 2021 is 1.259 gigawatts.

[2:47:49] So that chart was either had a mistake or was not really candid in terms of that the net net

[2:47:59] additions of dispatchable power. Thank you. That's what I thought. Those are all thermal too,

[2:48:05] I believe. Well, all coal plants, yeah. Mostly coal and some gas.

[2:48:12] Okay. Thank you, Bill.

[2:48:14] All right. At this time, the board will adjourn general session and convene an executive session.

[2:48:21] No voting items are anticipated during the executive session.

[2:48:24] So general session will not reconvene after the conclusion of the executive session.

[2:48:30] General session is now adjourned and the webcast will be concluded.

[2:48:35] We'll take a five-minute break before convening an executive session.

[2:48:38] Thank you for your attention, Chair Jackson.

Oct 17, 2023 Board of Directors Meeting - ERCOT - Electric Reliability Council of Texas

Agenda

Transcript