PJM and ERCOT navigate a capacity rollercoaster

Latitude Media, covering the new frontiers of the energy transition. I'm Shail Khan, and this is Catalyst. I think ERCOT has become a cyclical market, maybe especially for batteries. There was a big push through legislation to support new gas fire generation in ERCOT. I think if you look at forward markets, that's not supported by market pricing today. Coming up, the fate of the power markets. in the Mid-Atlantic and Texas. consequential brands in the industry, their team is ready to make an impact on day one. Get started today at antennagroup.com. What if utilities could meet surging electricity demand with energy assets already in homes and businesses? Uplight is making this possible by turning customers and their smart energy devices into predictable grid capacity through an integrated demand stack. Uplight's AI-driven platform activates smart thermostats, batteries, EVs, and customers to generate, shift, and save energy when the grid needs it most. Learn how Uplight is helping utilities unlock flexible load at scale, reduce costs, and accelerate decarbonization at Uplight.com. What if the next big source of grid reliability is already sitting in your home? Energy Hub software coordinates thermostats, EVs, batteries, and other devices, so they operate as a flexible resource when the grid needs support. These virtual power plants, or VPPs, help keep cost down, strengthen grid reliability, and support a cleaner energy system, all while reducing the need for new infrastructure. More than 160 utilities trust Energy Hub to manage over 2.5 million devices. Learn more at energyhub.com. I'm Shail Khan. I lead the early stage venture strategy at Energy Impact Partners. Welcome. Okay, so I'm admittedly breaking the fourth wall a bit here, but we did, I think, something like 48 episodes of this podcast last year, 2025. And amazingly, the single most popular episode was about the capacity crunch in PJM, the wholesale power market in the mid-Atlantic of the US. And I must say, that makes me very happy because I am and have always been a power market nerd. And man, what's going on in power markets right now is wild. So let's let that flag fly. Joining me today is Paul Siegel, who's the CEO of LS Power. Folks in the power markets know LS Power well, but LS is big and owns all sorts of generation and storage and transmission assets all over the country. And Paul's right in the middle of it. So I brought him on to talk about two markets that have been interesting lately. First, we talked about PJM, which is where the federal government has proposed an emergency auction to make data centers, quote, pay their way. And then we talked about ERCOT, where there was a recent winter storm that was forecast to possibly hit an all-time high for peak load, and then didn't. And the price spikes that we're used to seeing periodically in ERCOT also never showed. So what does that mean? So interesting. Here's Paul. Paul, welcome. Thank you. Good to be here. All right. We're going to talk PJM and we're going to talk ERCOT in that order. So let's start in the mid-Atlantic. I want to get to this DOE emergency order and the concept of data centers bringing their own generation and all that. But I want to get there after we talk about what's happening in that market at the high level. So start me off with the 30,000-foot view. What is the state of affairs in PJM? Yeah. Look, there's been a lot of change, and the change has been quite rapid. When we rewind back just a couple of years, we had capacity clears that were going off between $30 and $50 per megawatt day. And that compares to a little bit over $300 a megawatt day in the more recent clears and subject to the cap in the capacity auction mechanism. Those low clears were in many ways, I think, sending the signal that we had more than enough capacity. We had a period of time between, let's say, 2008, the great financial crisis, and really the last year or two where there was virtually no demand growth in the PJM market. And in the absence of that demand growth, the environment was really one where new assets were being added to the market to replace older assets, less efficient assets, higher fixed cost assets, along with the addition of renewable projects supported oftentimes by state-level mandates or corporate procurement. So in that environment, there wasn't a need, and there was certainly no price signal to go actively develop and build new generation outside of renewables. And that's the backdrop really kind of shifted really quickly over the last couple of years as probably a combination of factors hit the market and has driven up demand growth from that very quiet, virtually no demand growth, almost a market stasis to the real need for new generation. And that's where we sit today. Right. So that sounds like a fairly straightforward story, right? Like we just didn't have that much load growth in PJM. And so we didn't need that much new capacity. And then all of a sudden load growth showed up and kind of flooded the market and the market has struggled to keep up quickly enough anyway. And so we go from $30 per megawatt day or whatever it is to $300. dollars, we hit the cap, and now we are clearly under capacity, right? There is a capacity shortage in PJM, which is what's causing all the consternation and why the Trump administration turned its attention to it and so on. Is there, in your mind, was that a failure of market design or foresight in PJM? Or is it just like this is a natural result of the fact that people didn't predict how quickly data center demand was going to grow? I think all of the best minds who are focused on this market didn't anticipate how quickly this shift occurred. And we went from that moment of very little to no demand growth to hints of data center growth on the back of the emergence of ChatGPT. And that happened almost overnight. From a power markets perspective, it really virtually happened overnight. And our planning horizons when it comes to large-scale gas fire generation aren't measured in months. Today, I would say they're really measured over the course of four to five years between the realization that there's a need and all of the activities that are required to go from realization of the need to fulfilling the need and delivering a power plant. Okay, so the signal is clearly there now, right? We've now had two years in a row, right, of auctions that hit the cap. So recognizing it takes time to get new capacity online, you know, we've clearly flipped and it's obvious to everyone that there needs to be more capacity. Does that mean that there's just going to be a little bit of a time lag, and then we're going to have a flood of new capacity coming online in PJM. And actually, in the arc of history, we're going to look back at this period and say, well, it was tight for a couple of years, but ultimately the market did what the market was supposed to do, and we ended up where we needed to be? Or is there some risk? Because I guess from the outside, it seems like there is concern that despite the market signal now being there, we may still not get enough capacity, certainly suit enough. So is your view that like, let it play out and it's going to be fine? Or should we be ringing the alarm bells? These markets are pretty complicated. And there are a variety of different resources that we can look to to fulfill the needs of the market on different timelines. One of the things that we watch as a resource that can respond the absolute fastest is demand response. I think that's a good place to start. So if you look at demand response and what's happened to demand response over the last several auctions, we haven't had much more demand response participation in spite of the fact that the price signal has gone from virtually no payment for capacity to a very meaningful incentive through the capacity payment to bring capacity to the market. And again, I think we need to recognize that there's a rotation inherent that's happening now where demand response for so many years was a resource that was almost never utilized. So we had demand response. We had these companies that were promising to respond. They were taking a payment as consideration for their capability to turn their utilization down. they were almost never asked to actually turn their utilization down because, again, the market was not tight. There were sufficient resources. There weren't many events where they were being called upon to perform. And now, over the last couple of years, we've shifted into an environment where the market is becoming tight and they being asked to perform with greater and greater frequency So I anticipate that in that part of the market the demand response piece there going to be customer churn Some customers that said, we thought we were getting a payment, but you were never going to need us are going to say, we don't really want to participate in this market anymore, even if you pay us more. And other participants are going to come in and say, there's a very meaningful payment here. We weren't really aware of it. We are now. we see the opportunity and we'll put the processes in place to ensure that we can deliver if called upon in exchange for this payment. So demand response is something that can be turned around as a capacity resource on a very short timeline. Yeah, I mean, I guess you just described it, but it's still notable, right? Everybody was, or I was surprised to see the demand response didn't grow between the previous auction and this most recent one, because as you said, like the price, if you have 10x the value, plus or minus, yeah, there should be some customer churn. People were not expecting to be called upon as often. But you'd think on balance, on net, you would still get a fair amount. And it's the fastest, as you said, like you don't need a five-year planning horizon to get new demand response capacity online. So it's the one that you would have expected could turn up quickest and that with the appropriate price signal, it should have, but it didn't, at least not yet. Is that just sort of, it takes time to build the momentum and now you have to reorient with these customers to tell them that they're going to get actually called upon more? Or is there a bigger problem either with the market structure or with demand response? I think it is a lot of that, that the awareness of the opportunity needs to be socialized among a broader set of potential customers. I think part of it may well have to do with the price level. The ELCC adjustment to the PJM capacity price for demand response capacity is meaningful, so they don't really see a $300-plus per megawatt day price. In other words, the value ascribed to demand response also went down over that period. Correct. The value delivered to the ultimate customer went down from what we notionally see as the gross capacity price. And we can look at these last two extreme events, both in PJM and in ERCOT, and see that there's actually a whole lot of incremental demand response that's ready and willing to perform if they have two things. One is sufficient notice, and the other is price levels that aren't really reflected through the capacity auction. Right. We're going to come back to demand response and sort of flexibility in response to price, I think, when we talk about ERCOT, because you have some interesting insights on what happened in the recent storm there. Maybe before we do, though, staying on PJM and moving on from demand response to new generation. So there's now two years of this price cap. Price signal is high. Presumably, there's a lot of new generation capacity in planning and interconnection and development, etc. And then in comes DOE with this emergency order on top of that, kind of a separate, It seems separate and apart from the existing PJM capacity mechanism. Can you, I guess, first just describe what that DOE order is meant to do or what the thinking is behind it? And then we could talk about, is it a good idea and does it fit with the existing paradigm? Yeah, we'll wait to see how it's implemented. And there will be a process at PJM. There will be a variety of parties that will provide their input. So I think we know conceptually what the governors and the White House have proposed here. And in short, I think the concept is that large data center loads that are driving a lot of the reset in these markets, they're creating the demand growth, they're creating the need for new supply, should be responsible for paying for that new supply and the cost of getting it integrated into the grid. And I think that there is some good rationale there. And why is it different than past practice? One, these loads are extraordinarily large. Two, we've gone through this, again, very short period where prices for building a new large generation resource went from, let's say, for a combined cycle. 10 years ago, we could build a new combined cycle for a little bit over $1,000 per KW. And today, the cost for building that same combined cycle has doubled to tripled. And it's happened again in a very short planning horizon. So bringing that incremental capacity on, integrating it into the grid will have a very real impact on costs. And so if there were a way, And I think that this is the drive behind the executive order. If there were a way to allocate that specifically to the customer that's creating that dynamic, that would save the rest of the consumers from being impacted by that step-up in cost. Okay, so conceptually, it's in some ways not dissimilar to what you see in other places where vertically integrated utilities are signing up tariffs with individual large load customers, data centers usually, and saying it's a bring your own generation concept, right? You pay to get generation, or in this case, capacity that is going to be sufficient to meet the needs of your load. So that's kind of the idea of the emergency order. I guess I don't really understand how it interacts with the broader PJM capacity market, though. Will a project be a part of both? Or is it like Meta or Google or whoever will, through this emergency auction, sign up a gigawatt, there will be a gigawatt of new capacity, and that's not going to be considered in the broader PJM capacity market? I think all of those things are yet to be determined and yet to be worked out, probably through a stakeholder process at PJM. But I think that the concept is that if this growth is to continue, I think that there is a real argument that for the ongoing social license for these large loads to come into a market, that they will need to be responsible for their price impacts. One capacity auction, and we can talk about all of the complexity that comes into, to your point, procuring this into a market. But I think one of the drives here may well end up being a more robust bilateral market where hyperscalers proactively, instead of being forced into an auction, but proactively go out there and procure resources that are well positioned to supply them with what they need and have the lowest impact on the rest of the grid and system so that they can be brought in at the lowest cost and brought in with the lowest risk around the market. executing all of the grid upgrades that are required to integrate them. So this emergency procurement, which prior to PJM's most recent load update would have been for six gigawatts. I think one of the questions is post-load update, is it now three gigawatts? Are we procuring capacity? For a 2027-2028 shortage, the only viable form of capacity may well be demand response. It may be some batteries. It may be integration of batteries behind existing interconnects. Which of those things can qualify? One of the things that you can do is drive up the effective load carrying capacity, the ELCC, for existing resources. So you might be able to add, again, in relatively short order, a backup fuel that takes a poor-performing gas generator from an ELCC perspective to a high-performing gas generator from an ELCC perspective, where you don't need to invest meaningful time and money in grid upgrades. It seems like a lot of the focus, both from a policy perspective and also a market perspective, is on let's build as much new gas generation as quickly as we can to meet the capacity need in BJM. And it sounds like you're saying, to some extent, yes, but that actually isn't necessarily the savior, especially in the near term. Is that right? Yeah, when I look at the resources that we have available, large-scale gas is a 2030-plus new resource. In the interim, there are other things that we can do. We can add demand response, we can add batteries, we can upgrade existing facilities. We're working on the conversion of some of our combustion turbines to combine cycle power plants that can be done more quickly than building something that's completely de novo. We have a project where we can swap out combustion turbine blades and get dramatically more capacity. So there are different things that we can do as a bridge to large scale, completely de novo, new generation. But if that's what we're hanging our hat on, we need to anticipate that that's an end of the decade plus deliverable at large scale resource. As an independent power producer, or I guess for that matter, a demand response company, whatever, as somebody who's selling capacity one way or another, are these like boom times? On the outside, you'd assume so, right? This is where you want to be. You want to be on the selling side in an undersupplied market. Is it as simple as that, or is it more complicated? I think it is more complicated, in part because the mechanisms are not yet clear. I think we had a market mechanism have a market mechanism that is still reasonably clear You know that you can clear in the capacity auction You know that there a deep market there That market clears well over 100 megawatts of load and supply with a stable set of rules. You can look back at history, you can look back at where you last cleared, and you can make a good approximation of where you will clear and carry that forward into the future. Any one year has an enormous amount of volatility over it, but if you have a clear set of rules that you believe to be durable, you can invest on the back of that. I think it's a robust time for all sorts of ideas on what kind of options might solve these problems. And as we discussed, they really range the gamut from demand response to batteries, to up rates at existing facilities, to new fuel storage at existing facilities, to completely new large-scale generation resources. Catalyst is brought to you by Antenna Group, the OGs of PR and marketing for climate tech. Is your brand a leader or challenger? Are you looking to win the hearts and minds of customers, partners, or investors? Are you ramping up your new biz pipeline? Are you looking to influence policy conversations? Antenna works with leading brands across the energy, climate, and infrastructure space to do all of this and more. If you're a startup, investor, enterprise, or innovation ecosystem that's helping drive climate's age of adoption, Antenna Group is ready to power your impact. Visit antennagroup.com to learn more. The grid is changing fast. Data centers, electrification, and extreme weather are driving a surge in energy demand. Utilities can meet the moment with existing resources by activating energy customers and their distributed energy resources to create predictable and flexible capacity with Uplight's integrated demand stack. Uplight coordinates energy efficiency, rates, demand response, and virtual power plant programs into one cohesive strategy to strengthen grid resilience, improve energy affordability, and make progress toward clean energy goals. Learn how Uplight is helping leading utilities harness over 8 gigawatts of flexible load at Uplight.com. What if everyday devices had the potential to strengthen the grid when it's needed most? Energy Hub helps utilities turn that potential into dependable capacity by coordinating thermostats, EVs, batteries, and other devices into virtual power plants that respond to grid needs in near real time. Energy Hub's latest white paper lays out a maturity model for VPPs that can be planned and dispatched with the same confidence as conventional plants, while being 40-60% less expensive to build. That's why more than 160 utilities across North America partner with Energy Hub to manage over 2.5 million devices that provide 3.4 gigawatts of flexible capacity. Read the white paper and discover what VPPs can do for your grid at energyhub.com. Let's move on to Texas, where there's an interesting, I don't know, sort of a different dynamic at play. I don't think that the view in Texas is that there's this, like, massive capacity shortage, though there is an enormous amount of load growth in Texas. And so, and the interesting thing in ERCOT is, you know, the market, the way the market is designed there, being an energy-only market, more or less, you know, we get these, like, very dramatic events in a literal sense and then also in the market sense, where you have generally some kind of weather event, as we had recently with this big winter storm that hit a big chunk of the country. And everybody amps up for what's going to happen in those events. And then sometimes they turn out to be kind of a dud and sometimes they turn out to be a huge deal with lots of outages and wholesale prices that are in the $5,000 a megawatt hour range for days on end. And it makes a ton of money for some folks and loses a ton of money for other folks. And so those events are always really interesting because it gives you a sense of what's going on in Texas and also in a bunch of other places in the country. So let's talk about what actually happened in this recent storm because it is interesting and it was not – I don't think anybody predicted exactly what was going to play out there this time. So walk me through the kind of play-by-play of what was expected as we were headed into the winter storm a couple weeks ago, and then we can talk about what actually happened. Yeah, I think when we see these winter storms coming, the market looks to prior examples of extreme conditions. And the most acute of those that we've seen in the United States over the last five years was URI, where we had a broad-based extended period of cold. We had precipitation. We had ice and freezing rain. And we had frequency deviations that really cascaded and triggered a lot of generation to be tripped off the system. So we had this extended period of blackouts. We had this extended period of extremely high prices at their peak. So the market looks for analogous situations. And looking at what was coming here, it looked like it was going to be pretty extreme, record-setting cold, record-setting demand. The market was anticipating those extreme conditions to last for an extended period of time. And that's what people were preparing for. And that's what the market was signaling in part through forward pricing, which escalated for the week days. At the end of the week preceding the winter storm, power prices for the subsequent week went well over $1,000 per megawatt hour for the subsequent week. So price signal came through. Right. And I think you have made the point that that seems to have done the trick because we did end up having, I mean, the weather event itself maybe wasn't exactly everything that was advertised, but we did have quite cold conditions over an extended period of time. So it's not that the weather event exactly disappointed. But we never saw the price spikes and the extended price spike that you saw in Yuri and that I think a lot of merchant generators and batteries probably were hoping for, to be honest. And you made the point that maybe it's because the market performed well at sending a price signal ahead of time, right? Yeah, I think the price signal ahead of time tells a generation owner or a retail supplier to get out there and hustle and figure it out ahead of time. That means turning plants on ahead of time. That means making sure that you have fuel oil and that if you need to change and run your plan on fuel oil, that you do that ahead of time to avoid potential gas flow interruptions. It means if you're a retail provider picking up the phone and calling big customers and saying, hey, there's a big event coming. There might be ways for us to provide you with an economic incentive to conserve during that period of time. And so I think all of these things help gear the market up. And I think this may have well been a test case where the market said forward pricing is going to be very high. And what we saw is a lot of demand response in effect emerge that wasn't getting paid a capacity payment, some of which might have been, But we saw similar dynamics in PJM as we did in ERCOT, where demand response was not called in PJM. ERCOT doesn't really have a demand response mechanism. But in both markets, we saw over 10 gigawatts of demand that should have shown up based on the weather conditions and based on normalizing those weather conditions to what actually occurred that didn't show up. It's not that the weather came in and it was a dud. The weather was real, but the load didn't show up. And I think the only reasonable explanation is that the load didn't show up because we saw it coming ahead of time. People prepared. There was a price signal. And we found a whole lot of additional demand response that might not have been able to respond with a day notice. And it probably certainly wouldn't have responded with an hour notice. but it was there with enough price and with enough visibility. So this is super notable, right? Like 10 gigawatts of load that was expected to show up, didn't show up. There is no formal demand response program, but it's a price signal. And so this is like maybe the most stark example that I've seen of load responding to price at that kind of scale. What do we know about what kind of load it was? Like who were these 10 gigawatts? So I don't know that we know definitively. I think we have to make assumptions about where are the large loads. I think you think about demand response, and generally you're looking for businesses where somebody is responsible for energy costs, where somebody has their sole job is to figure out how they can minimize the amount of money that a company pays for procuring energy. And in some cases, it may be an even more significant business decision where there's an opportunity cost associated with foregoing that production. So I think we certainly know that even at much lower prices and with a much shorter notice that there are Bitcoin miners who can turn around and curtail their production. I would imagine that there are data centers now positioned to provide demand response into the market. I know that there's a lot of other industrial and petrochemical load in Texas, for example, that well positioned to respond to high prices Some of the LNG loads who also had very high price signals to not export gas may also have had and received price signals not to consume electricity off the grid So there's a range of potential sources. And again, the question is, do we have the notice for that information to percolate and for those users to respond? I'll tell you one thing that's been interesting about it, as I've thought about it, for me. So I've long asked the question, this is an aside, but it'll relate. I've long asked the question, like, what's it going to take for large industrial loads to go off-grid? Like, what are the series of conditions that would have to be true? And particularly, I'm interested in the question of, like, if you don't need four nines of reliability. So if you can go off-grid with just solar, solar plus storage, or solar plus storage and a little bit of backup or something like that. And so what is the type of load for which that makes sense? And my thought has always been, it's got to be a load where the OPEX to CAPEX ratio is high. Like a lot of your costs are born in your energy cost. Your OPEX is mostly energy, let's say. So energy costs matter a lot to you is the other way to put that. And second, this is the one where I think the evidence from Texas recently maybe counters this. I would assume you need to be in kind of a low margin business. Because if you're in a low margin business and your energy costs are high, then yeah, if you are trying to continue production during a three-day spike of $5,000 or $2,000 per megawatt hour prices, maybe that's gross margin negative production for you and it's not worth it to do it. Whereas if you're in a high margin business, yeah, your margin will be lower for those few days, but it's probably still worth it to you to continue producing. But for example, Bitcoin miners, right, they're pretty high margin, I think, generally. Maybe that's not always true, but they do seem to respond to these price signals. And you do see it in Texas in particular, where there's a lot of Bitcoin mining. So maybe I should reorient my prior and actually, like, more large lows are flexible, according to price signals, than I would have anticipated. it. And I guess the question to you is, should we be planning around price signal-based flexibility as a significant contributor to alleviating these capacity crunches in whatever market? I recognize ERCOT is uniquely structured to deliver it, but just abstracting away from the market context, do you view that as a real sustainable thing? Look, I would certainly hope so. I think that when we look at the grid that we have, we utilize it on the order of a 50% capacity factor. So we can squeeze so much more out of the investments that we've already made on the grid. And oftentimes when we talk about the price increases and the investment that's needed, it's really to drive a solution for that marginal need. If we can avoid that marginal need through, again, a combination of price signal and time, we can utilize what we have to a higher capacity factor, which can allow us to drive down the costs of the grid, to drive down the costs of delivered energy. So I think that this is a moment that I think identifies an opportunity where we found, I think this is in some ways a miraculous thing that can only be driven by a free market where people saw this incredible price signal and decided that it was in their interest to use less at that peak. One thing that was interesting was that a couple of days after the extreme weather in ERCOT, we did have a day where prices went to well over $500 per megawatt hour for an extended period of time. And I think that was because a lot of the system exhaled. We weren't running everything at maximum capacity. We weren't prepared for the need for every last resource to be online and ready to respond. Everyone was exhaling, buying less gas, maybe shifting off of their fuel oil, demand response that we created in that moment of price signal, and that faded away. And we saw real pricing come back into the market. I'm curious what this means for, I mean, I've heard without looking at the data, I've heard anecdotally that spreads in ERCOT have compressed for the past couple of years. And so this is, I think, particularly relevant for batteries. There's a lot of merchant storage generation in ERCOT. And the merchant storage generation is generally relying upon spreads on a diurnal basis, but equally, I think, on these types of events where they make a lot of money in a short period of time. So, what does it say about this merchant storage in Texas that we haven't seen those kinds of spreads in general, and that then when this weather event shows up, it doesn't result in these sustained really high prices? Is there a wave of merchant storage in Texas that's really hurting right now? I think the short answer is yes. I think that this last event in Texas probably, and I haven't reconciled, looked at the forward graphs, but I would expect that this was a disappointment from a power markets perspective. this forward price signal turned into a period of oversupply, turned into a period where we had very low spread clears. And so part of the flow through of the signal will be that those forward hedging opportunities are less robust. Now that we've learned that we have 10 gigawatts of incremental supply of some sort ready to respond, along with a pretty well-performing system. When we have extreme situations, it takes some of that risk of extended periods of peak pricing out of the market. And so the probability of that happening goes down in the available margin for the existing resources, batteries being one of the big new entrants into the ERCOT market, really the air gets let out of the balloon. Does that mean, I mean, these markets are all kind of cyclical. So are we now going to enter a phase of underinvestment and new capacity in ERCOT? It's a funny thing where there's these dynamics that seem to push against each other. On one hand, the existing assets in the market are not making as much money as they would have expected because the spreads aren't as big and because these events aren't showing up. On the other hand, I think the load growth in ERCOT seems to only be accelerating as far as I can tell, which you would think would push in the other direction. And so there's some dynamic here where I don't know on net whether to assume that we're going to now underinvest in new capacity and end up with ERCOT in a PJM-like situation in three or four years, or whether these things kind of balance each other out and it's going to be totally fine. I'm sure nobody knows, but do you have a view on it? I think you're completely right. I think ERCOT has become a cyclical market. It may be especially for batteries. There was a big push through legislation to support new gas fire generation in ERCOT. I think if you look at forward markets, that's not supported by market pricing today. It may be supported by bilateral contracting opportunities. But when you look purely at forward spreads, those don't look particularly robust, especially given how expensive it's become to build new gas fire generation. A couple of years ago, we transitioned Intercut from a market that relies heavily on ancillary services to support batteries, and that was very robust. We built into that. That market was overwhelmed with supply. And then when you move out of the sort of smaller ancillary service market, you need to look at the bigger market. And the bigger market is the day ahead energy arbitrage market. And at least today, probably over the course of the last year, we've had sufficient batteries to load to send a price signal that seems to be that you're not going to get a great return on investing that incremental dollar on the battery, in a battery. But that may flip again, and again, large loads who are coming into this market may not want to bear that risk. They may not want to live with that volatility that comes through the market. So that volatility itself, I think, will encourage them to look at contracting, to enter into longer-term arrangements to mitigate their risk and to support ongoing construction development of the kind of resources that we're going to need to keep this market in equilibrium. Well, Paul, this was very fun. I look forward to the next weird flare-up being in like MISO or SPP or New England ISO or CAISO or something like that. I'll have you back on. We'll end up doing a tour of all the wholesale power markets in the U.S. But in the meantime, really appreciate your time. Looking forward to it. Good to talk to you. Paul Siegel is the CEO of LS Power. This show is a production of Latitude Media. You can head over to latitudemedia.com for links to today's topics. Latitude is supported by Prelude Ventures. This episode was produced by Max Savage-Levinson. Mixing and theme song by Sean Marquand. Stephen Lacey is our executive editor. I'm Shail Khan, and this is Catalyst. What's wrong with the sun?