title: The Secret Rules Behind ERCOT Prices with Andrew Reimers
author: Energy Capital Podcast
contenttype: podcast
publication: Energy Capital Podcast
published: 2026-02-18T11:02:00+00:00
sourceurl: https://api.substack.com/feed/podcast/188294689/164031cf3289f3ddc0a57a4e7f0d6c36.mp3
word_count: 9088
Right now, Texas is planning for rapid load growth while still catching up on transmission and interconnection constraints. The challenge is not whether demand is coming, but how fast the system can realistically respond. Welcome to the Energy Capital Podcast, where we cover the decisions, data, and debates shaping Texas grid and the energy future. I'm your host, Joshua Rhodes. Today's guest is Andrew Riemers. He's Deputy Director of Arcada Potomac Economics, the independent market monitor. Andrew is an expert on grid planning, load growth, and how infrastructure decisions actually get made in Texas. In this episode, we walk through what planners know, what they are assuming, and where uncertainty is doing real work in the system. We discuss load forecasts, transmission bottlenecks, and the trade-offs between moving quickly and maintaining reliability. You'll walk away with the decision-useful lens for understanding how Texas is navigating growth right now, and where the biggest pressure points are likely to emerge next. Let's get into it. Andrew Riemers, welcome to the Energy Capital Podcast. Happy to be here. Thanks for the introduction. Yeah. You know, I have, I think, known each other for like 13 years now. Yeah, I know it has been a while. I was wondering at a high level, if you could just describe what Potomac Economics does relative to Irkott. Yeah. So, you know, you have Irkott, who is the independent system operator. So they are sort of a quasi-government institution. They're really a non-profit institution with a charter through the state of Texas to manage the flow of electricity on the transmission network, and then also run various wholesale electricity markets. And you know, there are several different flavors of that. The most important one for the conversation we're going to have today is the real-time market. So that's really where the physical scheduling of generation happens, and everything ultimately is transacted according to the prices that come out of the real-time market. That's Irkott, where Potomac Economics comes in. This whole concept of an independent market monitor. If you kind of take it back historically, all of these power grids and deregulated electricity markets used to be vertically integrated utility markets, where you'd have retail customers that were in a monopoly all the way up to the farms that own the generation and stuff. And that model still exists in certain parts of America. Like the Southeast. Yeah, the Southeast, parts of the Midwest are still kind of like this. The Rockies are like this, although that's kind of an evolving situation. Most of the rest of the U.S. is what we call deregulated. That means that you have divested the transmission system from the generation system, and there is no longer necessarily as strict of a monopoly on the retail side. And be that as it may, you still had a lot of legacy firms that had a lot of concentration in the market. So like in Texas, the big firms might be yet luminant slash Vistra that historically could be traced back to Dallas power and light, and maybe of NRG, reliant, who can be traced back to Houston power and light. These two firms, even though they're now in a deregulated market, are still very big players. And so there's a concern about the ability of these players to exercise market power, and whether or not the market is sufficiently competitive to kind of incentivize those players to bid competitively. That's really where the role of an independent market monitor comes in. We kind of have two different fundamental roles, the first of which is to monitor the market for uncompetitive behavior. We have various screens and things going on that are meant to catch peculiarly looking behavior, maybe on economic offer behavior, on economic outage behavior, and then related to that to identify problematic market design situations, maybe make recommendations for improving market design to kind of improve the competitiveness of the market. My firm in particular is called Potomac Economics, and so we have a contract with the state of Texas to serve as the independent market monitor for ERCOT. We also are the independent market monitor for several other of the big deregulated systems in America. So MISO, which is kind of the big Midwestern ISO, ISO New England, New York ISO, and then we also are the market monitor for Reggie, RGGI, which is the Regional Greenhouse Gas Initiative in the Northeast. So those are all different aspects of what our firm does, and my team in particular focuses on ERCOT. And my role within that team, I kind of manage the personnel. And then I'm particularly oriented around the market design aspect of the job. So most of my work kind of individually has been more on market design stuff than necessarily the market monitoring stuff. And in particular, what I'm hoping we can talk a lot about today, I've worked a lot on operating reserve policy. And so that is a big part of market design where things are changing very quickly. And it's very important that we kind of get the details right. Yeah, no, I know that that's a really big aspect of what's going on in Texas and ERCOT. I do want to get there. But before we get there, I kind of wanted to ask like, so in that role, you know, there's the market monitoring and then there's the market design, you know, what do you see in that role that other folks in ERCOT don't see? Well, the biggest thing if you're taking what we see versus everyone who isn't ERCOT, the biggest difference would just be we have direct access to all of ERCOT's data. And so, you know, that is a major distinction between what say market participants would be able to see versus what we can see. As far as what we're doing and why it's distinct from what ERCOT does, several of the ISOs have an internal market monitor. So KISO and SPF, for example, have their own internal market monitoring division. Some of the ISOs, to my understanding, have both internal and external market monitors. I know it's the case with New England and it might be the case with NISO as well. The reason to have an independent market monitor is really that there are going to be cases where you're making recommendations that go against what the ISO has proposed. And you need an independent third party to effectively make an alternative case than what the ISO has proposed for why they want to do things. You know, this sort of situation is going to vary depending on the kind of nature of the ISO. So, for example, a single state ISO has a different kind of set of political incentives than a multi-state ISO. The other thing is that Texas is unique in ERCOT being entirely isolated in Texas. So in KISO or New York ISO, even though there are single state ISOs, they're synchronized on a bigger grid. And so there still is some extent to which the politics of those states can't entirely dictate what the ISO is going to do in Texas that's a lot less the case. And you know, that has implications for the role of the IMM. Yeah, that's really interesting. We talked a little bit about pushing back against ERCOT and as the role is the independent like why it's important to be independent. I mean, Potomac has pushed back on ERCOT and gets several role-makings. You know, what usually drives those disagreements? Well, at least since I've been here, it's mainly been operating reserve policy. And so I mentioned that earlier, it might be where it's going ahead and explaining what that is. But there have been plenty of other issues in the past. And they aren't always directed at ERCOT per se. So we also have proposals against rule-makings at the legislative or PUC level. So for example, we've been critical of 4 CP a lot. We can talk about that later. I know that's topic that you're interested in. But as far as things at ERCOT, it's probably helpful to explain what an operating reserve is. Yeah, go for it. So your audience, I know, you know, I listen to this show. I suspect your audience is fairly savvy about how some of this works. It's going into the background a little bit. So the real-time market for electricity technically clears every five minutes. So every five minutes, the market is kind of producing new instructions for who's supposed to be generating how much. Importantly, one of the kind of nuances here is that this market isn't necessarily instructing resources to turn on or off. So that aspect of things, we call that commitment, is a more complicated scheduling. And ideally, the way this market functions when everything is going smoothly is generators decide for themselves when they're going to turn their resources on. Usually it takes more than an hour to turn those resources on. And so it's something they kind of have to have a view for what prices are going to be during the day. And then once they're online, the real-time market moves them up and down according to changes in supply and demand. You can think of on a summer day, the sun is coming up in the morning. We might turn down some of the thermal power plants because the solar is starting to enter the system. We might also start having higher temperatures. And so the demand for electricity overall is going up as the air conditioning load is going up. And then maybe at some point in the day, thermal power plant trips and you need to schedule some generation to fill the gap from that power plant tripping offline. So those are all examples of what the real-time market is doing to schedule generation. And before December, those reserves are being scheduled in the day ahead market. But now they're being co-optimized in the real-time market, is that right? That's right. Yep. And so what you're referring to is called real-time co-optimization, which also happens to be a former Potomac Economics recommendation for ERCOT to implement. Well, congratulations on getting it through. Indeed. Yes, we finally made it. It took almost two decades. So, but we got there. So you referred to December. So on December 5th, real-time co-optimization went live. And so far, we haven't seen any major system issues. There are some pricing outcomes that we think are problematic that we might get into later, but that's all very in the weeds. Yeah. So just to clarify the point you were saying before, until December 5th, the way the market worked is operating reserves were only procured in the day ahead market. And then that award was effectively a physical obligation to carry operating reserves in real-time. There were nuances to this. You could trade in and out of these positions. What have you? But in real-time, if you were carrying an operating reserve, then you were expected to be able to provide it, whereas the way it works now, you don't even have to sell operating reserves in the day ahead market. If you do, they are entirely just financial positions. And your awards in real-time kind of determine what you're physically obligated to do in real-time, and you're kind of just arbitraging between day ahead and real-time. So that introduces all sorts of things that we haven't really covered yet. We haven't really covered what the day ahead market is or what operating reserves even are. So maybe it's helpful to go back into that. So if the market only clears every five minutes and we're not actually scheduling who turns online, that is really where the need for operating reserves kind of comes from. So you can imagine the demand and supply of electricity are actually changing on a much faster time scale than every five minutes. So you need some capacity in the system that can respond to those short-term fluctuations. So for example, a common type of operating reserve is something called regulation or regulating reserve. If you're providing regulating reserves, you're getting signals every four seconds to adjust your output to address every time someone flips a light switch, someone turns on their dryer or something like that. There needs to be capacity in the system that can respond to those short-term fluctuations and supply and demand. But then you also have issues related to how these commitment decisions work and if there were forecast uncertainty in the day. So for example, there's really volatile weather conditions and at 12 p.m. we think demand at 4 p.m. is going to be relatively low. And then as 4 p.m. approaches, we realize demand is actually a lot higher than we thought. The clouds are clearing. It's hotter than we expected. Maybe the clouds are coming in and it's just cloudier than we expected and we don't have as much solar generation online. These dynamics can leave you where you don't have enough generation online to serve load effectively. And so you procure some amount of reserves in advance to handle these kinds of forecast errors. And for some added context to that, that problem has gotten a lot more complicated with the combination of intermittent renewables, duration limited resources, i.e. batteries, and then the kind of aging of the thermal fleet. And so those are all different things that are leading to a situation where operating reserves are a much more impactful policy and where there's a lot of new thinking about how to handle them correctly. So the forecast error for the weather is more impactful on the supply side than it used to be. It always was impactful on the demand side. But now it also has big implications for how much you're generating with wind and solar. Those affecting both sides of that supply must equal demand equation. That's right. Yeah. And this is a contrast to how other regions do it, right? Like Erkott has scared, securities, constraint, economic dispatch, but PJM, I believe also in the day ahead or other regions have scud. I've heard it called stuck is what Kaiso calls it short term unit commitment. Okay. So there's a whole alphabet soup of things, but basically is like they pre commit generators in the day ahead, right? So as far as the biggest difference between Erkott and other ISOs in terms of operating reserve policy, the biggest difference is that we are in electrical islands. And so if things really hit the fan in Texas, the downsides are a lot greater. You have a lot of generation trip offline, something like that. In the big Eastern interconnect, PJM can kind of rely on the fact that they're in a big synchronized network and they don't need necessarily as much of their own operating reserves to keep things stable. The NERK kind of requirements for grid reliability and things like that are sort of the minimum requirements. And then what you see in Texas is a lot more extreme than that. And some of that is valid and some of it is questionable. The other big thing is just the percentage of generation from intermittent renewables and storage is way higher in Texas than just about anywhere. The only place that might be comparable and I think Texas is rapidly exceeding this would be maybe like California, which has a ton of solar demand isn't as high. So the percentage is, you know, maybe about the same. But like I said, California is in the Western interconnect. So they are less anxious about having to deal with all of this on their own. Yeah, they can import power, you know, random states like Iowa have a lot of their generation from renewables. Iowa is actually the second or third biggest wind generating state in America, despite only having, you know, three or four million people or something like that. And so there are exceptions. But for the most part, the island nature of the ERCOT grid and the much larger penetration of renewables make it sort of a unique situation from operating reserves. Yeah. I want to touch on some of those implications, the fifth anniversary of winter stormy area. I want to get there and chat about that, but before we kind of leave some of the disagreements and things that Potomac has had with either ERCOT or the PC or the legislature, can you point to an example of like, maybe there's a current one, but like a well intentioned change that created issues or long term risk or, you know, pricing issues like we might be seen right now. I know you've been working on some stuff like that. Yeah. So this ultimately does kind of get into the winter stormy area talk. So it all does these days, right? It all does. So that elephant in the room is still the kind of aftermath of winter stormy area. And without relitigating that whole situation, even though it really didn't have much or anything to do with operating reserves, one of the kind of political effects of it was that a decision was made that the grid would operate more conservatively. And what was meant by that is that more operating reserves would be kept online to deal with potential supply shortfalls or something like that to avoid, you know, not just to avoid outages, but even to avoid the concern about outages. So you might recall a few summers ago when it seemed like every other day we were getting a conservation warning. 2023, I believe you. This kind of stuff was seen as politically problematic, especially after how traumatizing winter stormy area was. And so a decision was made that we'd operate the system with a lot more reserves. That can have negative impacts on pricing in either direction. So it's important to kind of spell out the nuances here. You mentioned PGM and the fact that they schedule a lot of their generation the day ahead. That is really a downstream consequence of the fact that they have a capacity market. And so Erkott, famously, energy-only market, the signals for investment decisions only come through the energy and its service prices in the real-time market, we'll get more into how that actually works. And pretty much every other ISO, there is some kind of forward capacity construct, which is how you go about looking ahead to see how much demand you think you're going to have, and then acquiring capacity through an auction to cover that kind of future demand. One downstream aspect of that is if you are picked up in that capacity auction, there are certain must-offer obligations in the day ahead market in PGM. And so that day ahead scheduling, a lot of that is a function of how many of those resources participated in the capacity market. And so you have something like 95% of all of the available generation has to participate in the day ahead market. And so you come into real-time with a schedule that's already pretty close to what you're expecting in real-time. Erkott isn't like that. Instead of having this capacity construct, we have all of our kind of revenue for incentivizing new generation comes from the real-time market ultimately. And the important aspect to how those prices are formed is something called scarcity or shortage pricing. Basically, in situations where reserves get really tight, conceptually what's happening is the probability of some kind of loss of load event is getting higher. And you try to impose something called an operating reserve demand curve on top of that, which is going to produce elevated pricing to reflect the fact that the marginal value of the reserves is going up as they're becoming more scarce. So you can imagine what that looks like, basically, the tighter the system is, the smaller the difference between the available supply and demand, you're going to clear at bigger prices. So part of the problem with conservative operations, as it's called, IE, carrying this large volume of operating reserves, one of the problems is you can suppress the prices. So now your MO is that outages are to be avoided, and the way you're avoiding it is causing prices to be suppressed, which is disincentivizing investments in new generation, which you can see coming back to bite you in the long run if you are concerned about demand increasing. So that's one aspect of it. You kind of alluded to something earlier with how the market design has changed before co-optimization. It's also possible for this kind of conservative operations posture to result in prices being higher than they should be. So what happened a few years ago, ERCOT introduced a new Anslery service called ECRS. The way this was implemented before real-time co-optimization meant all of that capacity was kept out of the energy market. And so in the summer of 2023, we now had thousands of megawatts of capacity that used to be in the energy market and was effectively removed from the energy market and kept in reserve. And now what happened a lot that year, even though we had a lot of capacity in reserve, the energy market perceived itself as being in scarcity because it couldn't access those reserves because we didn't have real-time co-optimization yet. And so rather than suppressing prices, this caused prices to blow out, and we estimated billions of dollars of excess costs caused by how this situation was managed. And so you can have price distortions in either way. And on one hand, they're reducing the incentive to build new generation, which creates kind of resource adequacy concerns. On the other hand, you're creating excess and unreasonable costs for consumers. And in either case, you're creating a lot of uncertainty and risk for anyone who's trying to figure out. How should we go about investing in this market, whether it's on the load side or the generation side? Yeah, it's been interesting, since Winter Stormyrie, we've had a bunch of discussions of, well, frankly, capacity-like products, right? Capacity is a four-letter word, interocod, but I remember there was the LSE obligation. There was the PCM, the performance credit mechanism. We're now looking at another insulation service. We mentioned the CRS, but we're talking about DRRS. You want to touch on DRRS, like what that might look like? What it actually stands for, etc. Yeah. So, DRRS stands for Dispatchable Reliability Reserve Service. And believe it or not, the origins of DRS also come from a Potomac Economics recommendation. You know, part of the story with conservative operations that I haven't really touched on is a concept called Reliability Unit Commitment. So I mentioned, in general, the market does not decide when to commit resources. So ideally, resource operators decide for themselves when they're going to turn their power plants on, based on some view of what prices are going to be that day. But in the case of forecast error or what have you, ERCOT does have the ability to force generators to turn on. And this process is called Reliability Unit Commitment or Ruck. Everybody hates Ruck. Why does everyone hate Ruck? Everyone hates Ruck because the impact it has on clearing prices and because it isn't hedgeable. And what that might mean is, if you're a load serving entity, whatever your cost exposure to Ruck is, you may have hedged your other kind of cost exposure. So regardless of what happens in real time, you have a price locked in. But if you're then on the hook to help cover the cost of committing these resources, then you weren't able to hedge that in advance. So that is one reason people hate it. Another reason is a lot of times what's getting committed are older resources. And it's just kind of a pain to start these up. And there's an implied opportunity cost of starting them up. So if you imagine like CPS and San Antonio has big issues with their emissions constraints. So since they're right near a city, there's air quality constraints they're trying to manage. If you turn on my resource in March and say it's an annual emission limit that I'm trying to stay under, now I'm running in March, I would really like to save my emissions kind of threshold for in the summer when the prices are higher, for example, or I might not want to have to keep as many staff around in March, or I might not want to have to do my maintenance during this window when the kind of maintenance market is more expensive. So you know, I know you've reported on this before the maintenance window in ERCOT keeps getting tighter and tighter because everyone wants to be available in the summer when prices are elevated that we increasingly have big winter events where people need to be around. And so in the fall and spring, everyone's competing for the same relatively, you know, small market of maintenance vendors. And so you might want to be able to kind of stagger when you're getting some of your facilities worked on. And if you keep getting instructions from ERCOT to turn on these old plants, it's hard for you to do that. So those are just some examples of why people hate rock. And DRRS in some respects was really imagined as a way to bring that process into the market in a more economical, transparent, tangible way. And we initially referred to it as an uncertainty product. So kind of like what I was talking about earlier, you look a few hours ahead and it looks like you had been under forecasting load and over forecasting renewables and you realize you have a supply shortfall on your hands and we can send out an instruction to commit a resource now or several resources because we see that there's this looming shortfall. That's the idea of the RRS originally. Now people tell me that if you went to those hearings where they were referring to DCRS where they were talking about it, it was also well understood that part of the motivation of DRRS was to to some extent incentivize new investment in dispatchable generation. It might have been part of the spirit of DRRS, but it's hard to say. There was all this other stuff in the mix. There was the PCM like you mentioned before, eventually there was the Texas Energy Funds. There are all these different things in the mix that are trying to incentivize new thermal generation. That Texas Energy Insurance product, remember that tin gigalot thing too? Yep. So the PCM didn't really get off the ground. There were various proposals to try to design something that would satisfy the legislative population. TEF seems to be having a hard time maintaining interest and the original series of proposals for it has went down to a relatively small stack and it's unclear how much of that's actually going to get built. Now we're left with the RRS and Berkoth feels like they have to at least try to inject a kind of resource adequacy objective into the DRS product. One of our big fights with our cut right now is to push back against this concept and insist that the DRS be developed as strictly an operating reserve product because there's some kind of fundamental flaws with the resource adequacy concept they've come up with. I'm happy to get into all that. This is something we've been talking a lot about lately. Yeah. If you could, part of what Potomac does is comments and dockets and other types of things like that. Can you talk a little bit about those disagreements there that y'all have had in the public sphere? Yeah. They've had various workshops on DRS. I've been it all or most of them. They have two distinct rule makings out. These are called NPRRs. What does that stand for again? Notal Protocol Revision Request. Anytime there are changes to the RKOT market, they are usually instantiated through this NPRR process. The two NPRRs related to DRS currently are 1309, which defines DRS as an operating reserve product in 1310, which incorporates the kind of resource adequacy components for DRS. We are mostly okay with 1309. Think it might be two in the weeds to explain where we have issues with that, but sure, 75% onboard with it qualified support for it. In 1010, we recommend that it be dismissed with prejudice, so we have severe issues with 1310. So what are we talking about? RKOT is talking about implementing an hourly capacity product, which they want to refer to as an answer service. You can imagine that every hour you are procuring a certain amount of capacity, the idea of this capacity product is simply to inject revenue into the market to support resource adequacy. Fundamentally, the problem with this concept is you can't effectively set procurement targets today to satisfy demand in the future. So we are procuring this capacity in the day ahead in real-time markets according to a demand curve, and that's supposed to produce enough revenue that we are going to get the investment that we need to have the capacity built for the future. So that's kind of the fundamental issue here. Yeah. Any more thoughts you've got on that that would be great. I mean, you also brought up a good point about it's trying to plan today for what the future looks like, and that's also somewhere where I wanted to go, because I mean, you know, the future of five years from now, at least from all the charts and all the reports and like, you know, everything in terms of demand growth, look way different than they did five years ago, right? Sure. And so what's different there? And if you want to tie in like what your feelings are on this product relative to where demand looks like it's going, that'd be great to know. Yeah. So we covered the kind of demand forecast perspective in our last edition of the state of the market report. So I don't know if I mentioned that at the top. So one of the main deliverables that my office produces is something called the state of the market report, right? Every IMM produces these for whichever ISOs they monitor, and it's a series of metrics and trends and things like that that have been observed in the market over the last several years. And then usually there are deep dives into a handful of contemporary issues where we've either identified something strange or problematic or we are using it as a case study to propose some kind of recommendation. Okay. It's a very useful report. I've used every single one of them, I think, for the past decade or so from some level happy to hear it. The 2024 edition of the report features a kind of long deep dive into the whole demand forecast situation. And these numbers are really crazy to put it simply. Like as far as the actual... I think that's the scientific term. Yes. As far as the actual forecasts on demand, our position on that has been that the analysis that's been done to produce those forecasts probably is over forecasting how much load we're going to have. If I can get into specifics, there's this officer letter load business, which is effectively transmission utilities, get a request to interconnect something and the developer of that project, signs something saying that they intend to develop this project that gets sent to ERCOT. Now this is in ERCOT's demand forecast. And part of that was driven by like a bill in 2023, like HP 5066, right? It's not just ERCOT. It's the legislature saying that I'll consider this, right? Well, a lot of the problem that we are seeing for better or worse is the way that legislation actually manifests itself on the ground. And you know, I've seen at first hand, I totally sympathize with how difficult it is to satisfy the language of a lot of this legislation, because once you actually start trying to implement these things, it's hard to do it in a way that is going to satisfy the statutory language while also being sound market design and everything. I remember like post-Uri, it seemed like the legislation was getting more and more specific, whereas before it was the legislature sets like general goals, the public utility commission puts them into like policies and then ERCOT creates metrics or protocols, right? Well, it actually designs the, you know, technical things that are needed to satisfy the PUC rulemaking or what have you. And that is conceptually how I think it's supposed to work. And the more detailed the legislation is, the harder it is to actually implement it properly or in a way that isn't going to have other negative consequences. And so I'm not an expert on how you would necessarily go about doing this if you were trying to do it effectively. It's a perfectly reasonable idea that future demand growth should be factored into whether it's, I mean, a big part of it would be transmission upgrades, for example. And maybe if you want to factor into your shortage pricing mechanism in a market like ERCOT, having some future view on both supply and demand, because I keep mentioning how forecast error factors into the operating reserve situation. If you're imagining the rate at which we've built more solar, then you might want to formulate your shortage pricing over the next year, based on the fact that you're expecting even more solar in the system. The magnitude of your forecast error is going to grow a certain amount, and you want to account for that in the way your shortage pricing works. And so it's a reasonable enough thing that you'd want to factor these forecasted changes into market design, transmission planning, things like that. When we looked into it as far as last year, the forecasted low growth didn't seem to be very reasonable to us, based on what we were able to get our hands on. And so if you're going to use that kind of forecasted load to justify some kind of market design change, that's going to be a problem. But the real problem with the DRS thing isn't so much that they're trying to incorporate future demand growth into some kind of resource adequacy product. Because they want to clear that product in real time, based on real time operating conditions, to produce the revenue to satisfy capacity needs in the future. And that's really where the disconnect comes from. It's a completely different thing if you're talking about we have scarcity pricing in the market today. You're getting paid based on the value you're providing the system today. But that elevated pricing is also telling investors, okay, there's room in the market for more capacity. If we're producing high prices like this today, then that means that already based on the current kind of supply and demand dynamics in the system, we can expect prices to stay high until more generation gets built. And so in that sense, producing prices today based on real time operating conditions is an effective incentive to build more capacity for the future. Putting in a capacity product where you're trying to produce revenue, even if the supply and demand conditions today are not stressed. And the whole objective is to hope that that's going to be like some efficient allocation of capital to invest in the future. The signals just don't work very well that way. Okay. So we've talked about pricing, we've talked about products, we've talked about summer demand and all this kind of thing and we talked about 2023. One of the things that I have seen the past couple summers though, is prices seem to be a bit divorced from peak demand, right? I mean, the past couple summers, 2024 and 2025 didn't hit the peaks that 2023 did. But I mean, I think one of the big drivers there was like a lot more solar, right? For sure. Even when the systems delivering the maximum amount of electricity to end users like prices have been low, and the spicy part of the grid has been pushed to like, you know, the net peak demand, the seven to nine PM, like, how are y'all thinking about that in terms of price signals and things like that? It seems like that price window is getting a bit narrower. And I, where there have been any conservation alerts in the past couple of years. Right. Right. So you're definitely correct that the massive increase in solar has kind of disconnected the correlation between prices and demand. So you still have some elevated pricing like in the evening when the sun is going down. Yeah. Batteries are quickly kind of cannibalizing all of that. They're really effective at managing that situation because usually it's pretty predictable. Like every night the sun goes down and you need batteries to fill the gap of tens of gigawatts of solar coming offline. And we have something like 15 gigawatts of batteries in the network now. And so they're pretty effective at doing that. Even though their duration constrained, usually they can generate power for one or two hours at full output. And so that's more than enough usually to handle this kind of situation. But like I've been saying all along, it's not as simple as just what's the peak demand or even the peak net demand. It's really the forecast error. So something that happens not infrequently is, you know, wind is a lot trickier to forecast than solar. So, you know, the sun comes up, the sun goes down, you know, shocking regularity, shocking regularity. Clouds do complicate solar and the magnitude of the forecast error is still, you know, something that has to be designed around. But the general shape of the generation profile is pretty consistent. Wind is more mercurial and just a quick aside on a Andrew Rhymer's take that is not a Potomac economics take. I think wind is a trickier resource to design your system around for all those reasons. I mean, it generates a lot, which means it kind of cannibalizes the market for other resources. So maybe a lot of thermal resources that used to stay on overnight now turn off overnight because the wind is blowing a lot and they're not going to make any money because prices are depressed. And then you can't necessarily count on the wind to be there when you really need it. An example of that is say the solar down ramp happens almost every day of the way that happens is the sun is going down and then the wind kind of picks up as it cools off and gets darker. Well, say that wind picking up is just delayed by 30 minutes to an hour. Now you have a reliability situation on your hands where you're probably going to see elevated pricing and depending on how big that delay is and the magnitude of that delay, are you concerned that you're going to use your storage resources effectively to manage it. This is all kind of a long way of getting to my point. We think the way to kind of manage that situation is something called a multi-interval real-time market. So they already have these, Kaiso has this, you really need something like this if you're going to strategically and economically schedule batteries. So batteries, the important thing to think of is opportunity cost. By discharge the battery now, I can't necessarily discharge it in the future and I might really prefer to have it in the future, it might even make more money in the future. And so if you can run a real-time market that looks ahead over the next hour or two hours and sees that you want to reserve some of that battery capacity because demand is going up and because the wind forecast has changed or something like that, that's really how you would go about doing that rather than what we see ARCA doing, which is trying to account for more and more forecast error in their operating reserve policy. Is this kind of the pushback that you've been having on the post real-time co-optimization in terms of like the battery duration requirements? It 100% is. So for example, non-spitting reserve. Non-spitting reserve is, you know, until taking the R.S. out of the question or whatever, the slowest, lowest grade quality of reserves that ARCA has in the system really meant for over an hour or so dealing with forecast error. ARCA has committed to maintaining a four-hour duration requirement for non-spitting, meaning whatever volume of non-spin they want to procure is related to the forecast error over four hours. You know, where does that four-hour number come from? A lot of it comes from looking at the existing genmix where we seem to be rucking these four and six-hour start-time units a lot. It is based on concerns over duration constraints or duration limited resources rather. Our position on that has basically been, say you have an issue that manifests itself over an hour and you're worried about the duration that the batteries have. If this is a real, you know, scarcity situation, you're going to expect elevated prices. And as that hour goes along, that's plenty of time for, we usually have a gigawatt or more of quick start gas turbines that can turn on in an hour. And so the idea would be the batteries have more than enough juice to handle things for an hour. And then by the end of that hour, you've sent the signal to this gas generation to commit. And so the idea that you need all of that baked into your operating reserve policy as opposed to letting real-time market prices incentivize more generations to come online, that has been sort of a big part of our complaint here. Another aspect of this complaint, and this is a little more technical, but let's see if I can explain it. By imposing a four-hour duration requirement on batteries to provide an onspin, you're actually incentivizing them to sell energy rather than to carry operating reserves. So I always use the example of as a 100 megawatt, 100 megawatt hour battery. So I can only output a full power for one hour. I can either sell 100 megawatts of energy or I can sell 25 megawatts of nonspin. And so unless the price of nonspin is four times higher than the price of energy, I would just rather sell energy and say all the other operating reserves are fully subscribed. So I'm just making a trade-off between nonspin and energy. So now I'm going to sell energy and I'm going to run out of state of charge and then say the problem persists. I mean, if I had just been selling reserves instead of selling energy, I'd have more gas in the tank to be around for this problem. You can see how this is the kind of thing that a multi-interval market could potentially help mitigate. Is that something that's only making recommendations on and push for? Yeah, yeah. It's been a recommendation of ours for a while. It's something that would take forever to actually make its way through the ARCOT stakeholder process. It's not a trivial thing at all. Yeah. Who would be foreign? Who would be against that? Would there be camps on that one? I'm sure there would be. But I would need to think more about it because a lot of entities, even if you can imagine them benefiting from the situation, they might have their business model oriented around the status quo. You could imagine if you're a thermal resource where I'm like a 30-minute turbine or something like that. Having the ability to be economically committed by the system could be beneficial to me. It could reduce risk that I'm going to commit and prices aren't going to be sufficient to cover my costs, for example. I think it could also be beneficial to batteries, but you create all this uplift problem as well, which is if I am looking ahead and see a need for generation in the future, but then it turns out I had the forecast wrong, and I saved you now. I didn't discharge you now, and I discharged you 30 minutes from now, and you lost money because I didn't discharge you when prices were actually high. That creates kind of an opportunity cost problem that you have to figure out how to deal it. It introduces new complexities. It's really an effective kind of reliability scheduling tool more than anything else. Okay. Just a couple more questions. What's one thing you wish policymakers better understood about the electricity system in Texas? Yeah, so here's the story I have been spinning recently. Let's follow the logic of conservative operations a little bit, and let's take it for granted and try to fix it instead of arguing against it. So say you want to operate the grid more conservatively because you have a very low tolerance for outages. Well, one thing you're saying is you have a very high value of loss load. We haven't really gotten into a value of loss load. It's a very controversial topic. I actually have a paper here from our friend, Will Gorman at Lawrence Berkeley, also a Weber group student, also former Weber group, the quest to quantify the value of loss load. So it is as academic as it gets, but conceptually it relates to how you formulate shortage pricing. So if you're worried about some probability of low shed, you have to also put a price on how costly low shed is before you can really do anything about scarcity pricing. So we need to adjust this shortage pricing to reflect the fact that we have a very high value of loss load. So now we're going to take all those demand curves I was talking about earlier, and we're going to calibrate them to the fact that we have a low tolerance for outages. So far so good, that's at least a consistent way to go about doing things, but now what are you going to do? You're going to tend to raise the price of electricity. You've effectively bumped up the floor on the clearing price for electricity. Maybe that's okay. Maybe people are really would prefer to pay more for electricity if it meant that they were really buying themselves security against outages. Like you pay for firm gas versus like market gas or something like that? Perhaps. It's not entirely unlike thinking about insurance or something like that. Yeah. Okay. I would pause it that as an aid of Texan, the whole kind of reason that this sun bleached hellscape has become a massive economy and a very dynamic place is really because it's been a good place for doing business. It's been cost effective, the energy markets and things like that, whatever their flaws have been have been efficient and relatively lower cost than a lot of the competition. I mean, if you compare Texas and California, there's a big difference in the access to and cost of energy. And so I would just suggest that if you follow the logic where to get the reliability that conservative operations supposedly is trying to get you. The only way to do it is ultimately to pay more for electricity and then you're left with a real conversation about how much more are we willing to pay for this level of reliability and is this kind of a reasonable in goal? Hmm. Sure. I'll make a plug for my part of Texas East Texas, which is less sun bleached. Lots of pine trees. Really tall pine trees. Yeah. I guess my last question is, Andrew, is there anything I didn't ask you that you wish I had? Okay. So something that you didn't ask me about that is another topic that, you know, relates to this whole issue is the concept of out of market actions. And so basically, there are all these different programs that get glued into the electricity market design kind of landscape. And you're familiar. I'm sure with a lot of these, we have emergency reserve service. We have firm fuel supply service and there's a proposal for an out of market residential demand response service, something I want to highlight for listeners of this podcast who are interested in these topics is that all of these programs are ways of kind of injecting revenue into the energy market that is not directly coming out of the clearing prices themselves. And what they actually do is they incentivize behaviors that tend to suppress the energy price. For example, if you're paying through some sort of backdoor mechanism to turn down residential load, for example, that's going to have an impact on the clearing price for electricity. And so what we're trying to get at here, and this is kind of a big push from my offices, all of these programs ultimately are pulling revenue out of what is set by the energy price and sort of inefficiently allocating it through all of these other programs. We'd really recommend really nailing down the shortage pricing mechanism as the primary way that investment signals are made in our cot is kind of the overriding mission of this office, presently. So to keep it pure, what you're saying? Keep it pure. I mean, you know, we don't want to be overly ideological about it. It's just that there are counteracting forces here if you go the other direction. So you might think you're improving the situation by implementing some of these programs, but it's hard to actually say how any of that's going to net out. And what we're confident of is that it's going to have an impact on efficient price formation. And if you believe that the wholesale market is a really efficient way of allocating, you know, scheduling who's going to run and forming a price, then you would be apprehensive to do anything that's going to interfere with that. So would that look like all of these programs figuring out how to actively bid into the market? Yeah. Sure. So a good kind of juxtaposition here. The Aitor program we've generally been pretty favorable for. So, you know, the guys from base may have been on the podcast already. I'm not sure they're basically like a residential battery developer. They have a pretty interesting business model where they're now a pretty big player in our Cots Aitor program, where that is one way of kind of getting retail customers exposed to wholesale prices. That's a much more efficient solution than this ResDR program that our Cots has proposed. In ADR stands for Advanced Distributed Energy Resources. I think it's aggregated distributed energy resources. Yeah. Because they basically for each kind of load zone, you aggregate all of the customers who are participating in that program and now they're treated as one resource in kind of the ERCOT market model for loads on. So if you're in that program and you're actively participating in ERCOT's market dispatch through SCED, I mean, that's kind of like you're participating in the energy side of the market, right? Versus like some of the other things you're saying, if they're more capacity type products because we don't have a capacity market, like they're being shoehorned in there, is that the fair summary? Well, so for example, ERCOT recently presented that a huge percentage of the emergency reserve service market has been taken over by crypto operators. I'm not here to throw crypto operators under the bus. I used to work for one. Fair enough. But part of the whole point of the way those, the economics of that kind of business is, it's very price responsive. And so when wholesale prices are higher, they have a strong incentive to reduce their load. Right. And so they're already going to be responsive to price conditions on the grid that are supposed to be reflective of the reliability situation on the grid. And now you're just funneling all of this extra money to them for something they were going to do anyway. And so that would be another example where, you know, rate payer money is being distributed really inefficiently. You're not really getting anything extra for what you're buying in that case. Yeah. Okay. That sounds like something that the market monitor would want to be on top of. Yeah. This is definitely something we're kind of working on our response to now that we've seen this report from ERCOT at a recent market meeting presentation. With that, Andrew Emerson, thanks for being on the Energy Capital Podcast. Thanks a lot, Josh. It was fun. Thanks for listening to the Energy Capital Podcast. Today's conversation helped you make better sense of how the energy system actually works. Share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy Empower at texasenergympower.com. That's where you'll find every episode, every article, and our latest updates. We're also on LinkedIn, X, and YouTube, where we share clips, insights, and ongoing commentary on energy policy, markets, and the grid. Before we go, a quick note. The views expressed on this podcast are my own and do not represent the official positions of the University of Texas, Ideas Miss, Austin Energy, or Columbia University. A big thanks to Nate P.D. our producer. I'm Josh for a Rhodes. Thanks for listening, and we'll see you next time.