Batch zero stops being theoretical on July 11. That is the day ERCOT’s rule for connecting large new customers takes effect. The new policy replaces a process that involved studying each giant load independently, then ordering restudies when new giant loads joined the queue, leaving projects stuck in a serial loop. Two prior episodes of this show traced how the new rule was designed. This one asks the people who connect the load what to fix before the next round.

Already projects are sitting in the interconnection queue as new regulatory deadlines loom. ERCOT figures show more than 445 gigawatts of large loads in the process, and the rule sorts them into base load, studied load, and excluded load. Developers have until July 10 and July 24 to meet certain filing deadlines, and the full batch study is targeted for early April. The policy also shifts more of the analysis from individual utilities onto ERCOT.

CenterPoint has been connecting large loads in Houston for decades. That experience drives a question the design phase mostly deferred: does a 75-megawatt cutoff for loads to participate in the program fit the manufacturing and industrial loads that move at the speed of business?

On this episode of the Energy Capital Podcast, Joshua Rhodes talks with Caitlin Smith, chair of ERCOT’s Technical Advisory Committee and senior vice president at Jupiter Power, and Jason Ryan, executive vice president of regulatory services and government affairs at CenterPoint Energy. Smith walks through how stakeholders developed the rules on a compressed timeline. Ryan presses the forward question of whether the 75-megawatt threshold and an annual batch process fit the loads Houston routinely connects.

Ryan’s concern is timing. When the batch becomes “the long pole in the tent,” he says, developers with real projects start to walk. The conversation works through:

* WL-PUN and PCLR, the withdrawal-limited private-use-network and provisional controllable-load resource programs ERCOT is repurposing to fit more load onto the current grid.

* The 75-megawatt cutoff, why Ryan questions whether mid-sized manufacturing loads belong in the batch at all, and the risk of projects sizing themselves at 74.9 to stay out.

* Non-firm service and reliability, how a load that agrees to curtail differs from the century-old obligation to serve, and what testing CenterPoint needs before it trusts the switch.

* What is permanent versus triage, which parts of batch zero survive into batch one and beyond as the Texas Legislature returns next year.

New to the batch zero mini-series? Start with Eric Goff on how batch zero took shape and Tiffany Wu on the mechanics.

How ERCOT sets the threshold and batch cadence will determine which loads get power on their own timeline and which wait for the next cycle.

Timestamps:

* 00:00 - Introductions: Caitlin Smith and Jason Ryan

* 02:43 - What Batch Zero is and why ERCOT needs it now

* 05:14 - Houston's diverse large loads, not just data centers

* 08:13 - Timeline: the July 11 effective date and key deadlines

* 10:44 - Base load, studied load, excluded load: winners and losers

* 12:55 - Inside TAC: compromises, new stakeholders, and fairness

* 16:10 - Does the queue mean a transmission build-out?

* 19:01 - The real number: CenterPoint's 40 to 50 GW prediction

* 23:18 - New constructs: WL-PUN and PCLR explained

* 28:13 - Non-firm service, reliability, and trusting curtailment

* 32:01 - Tracking success: what is permanent versus triage

* 36:07 - The 75-megawatt threshold and how often to run a batch

* 43:38 - Data centers, the final timeline, and what comes next

Resources:

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Caitlin Smith (LinkedIn)

* Jupiter Power (Website - LinkedIn)

* Jason Ryan (LinkedIn)

* CenterPoint Energy (Website - LinkedIn)

* ERCOT (Large Load Integration)

Company & Industry News

* ERCOT Again Revising Large Load Interconnection Process

Books & Articles Discussed

* Texas Senate Bill 6, 89th Legislature

* PGRR145, Batch Zero Process for Large Load Interconnections

Related Podcasts by Energy Capital

* Batch Zero, Explained with Tiffany Wu

* How Texas plans to serve ‘infinite demand’

* Open Season vs. Batch Zero with Travis Kavulla

Transcript:

Joshua Rhodes: Hey everyone, and welcome to another episode of the Energy Capital Podcast. I’m really excited today to have not one but two guests to talk about kind of what’s going on in the ERCOT Batch Zero process and kind of how that may continue to play out. So today on the podcast, we’ve got Caitlin Smith. Caitlin has a BA in econ from University of Texas and a JD Law from Penn State. She’s a policy consultant for CLEAResult for going on counsel at Jewell & Associates. She’s a vice president of AB Power Advisors and is currently the Senior Vice President for Federal and Regulatory Affairs at Jupiter Power, one of the largest pure play energy storage companies in the US. But she also is the current chair of ERCOT’s Technical Advisory Committee, the highest committee comprised of stakeholders, which makes recommendations to the ERCOT board. And that’s going to really come in handy today as we talk about one of the biggest policy shifts that’s working its way through the system. We also have Jason Ryan. Jason Ryan has his Bachelor’s of Business Administration and JD from the University of Texas. He was a Global Projects Associate at Baker Botts, managing partner at Ryan Glover LLP. And he’s also the information dominance warfare officer for the US Navy, which I kind of just want to stop and talk about that. If you can, you may not be able to talk about that. But now he’s the executive vice president of regulatory services and government affairs at CenterPoint Energy. Caitlin and Jason, welcome to the Energy Capital Podcast.

Jason Ryan: Thank you for having us.

Caitlin Smith: Thanks, Josh.

Joshua Rhodes: I’m really excited. So I’ve got two lawyers and two government affairs folks here today. So we’ll see how bad I do at managing this. Great. It’s gonna go great. But I know we’re under a bit of a time crunch, so we’ll get started because Caitlin, you’ve got a date for Elmo’s Got Moves. Is that right? Elmo’s Got The Moves. Okay.

Caitlin Smith: Almost got the moves. Almost got the moves. I’m seeing it tonight. I don’t know when this will air, but it’s in Austin Friday in San Antonio Sunday.

Joshua Rhodes: That’s some free advertisement there for almost got moves. But anyway, so we’ll go ahead and get started. And so the arc of this podcast is really I want to kind of catch up with what’s going on with the batch zero process. We’ve done two episodes, which we’ll link in the show notes, one with Eric Goff and one with Tiffany Wu, where we kind of looked at the overall kind of structure of the batch zero process and then with Tiffany got into kind of some of the details. But one of the things that it really was brought out, at least for my knowledge, during those podcasts, was We really had a framework for how things were going, but we hadn’t filled in all the details. And so I was just curious, Caitlin, if you could kind of refresh us on what batch zero is, where it stands, and why do we need it right now?

Caitlin Smith: Sure. And the impetus for me coming on, or one of them was Eric Goff said that the demand for load is infinite. I don’t believe it’s infinite. So I wanted to come on and correct. But maybe Jason thinks it’s infinite. So we could debate that. So batch zero, previously in ERCOT, there was not a uniform process for load interconnect. You know, before, I don’t know, six, seven years ago, nobody was really thinking about. Connecting these large loads when I was consulting, you know, we would have a call about a gigawatt hydrogen load or something that wanted to come online. This was starting in 2020. ERCOT hadn’t really heard about it or contemplated it at that point. So in the last five or six years, we had a major change to the system, which was ERCOT was actually seeing these applications for very large loads to connect and a lot of them What happened then was for the utilities, it was just either too much to process or they didn’t really know how to process it. Jason can correct me. And I think the other thing was there was not a uniform way amongst utilities on how to process these studies. And so they would study a load, another load would come on in their area, or maybe not even in their area. And ERCOT would say, No, we have to restudy. So people were getting caught in this infinite loop. So we are changing from that serialized process to a cluster or a batch, as we’re calling it, process where you can study a whole group of loads to make sure the system can accommodate the whole amount or the whole allocated amount of it at once and you can have a clear study. The other thing that does is really shift more responsibility to ERCOT. Before this was really each TSP. Was performing these studies and now there is a much larger ERCO component. And so batch zero is our way from transitioning from the status quo to the batch

Joshua Rhodes: process. Got it. And Jason, I guess the old process, like large loads were coming to transmission service providers like CenterPoint. Can you give us a feel for like when did the problem start to feel intractable in terms of like you going from having maybe one load at a time to dozens or hundreds of loads at a time? Can you give us a feel for when that started to come along to push this new process or to push talking about getting a new process?

Jason Ryan: Yeah, and so maybe I can answer it from a general perspective and then I can answer it from my company’s perspective. Sure. Because I think those timelines are a little bit different or the experiences are a little bit different. Between two years, you know, eighteen months, two years ago, I would say it started to become clear in many parts of ERCOT that something had to change. Okay. And yeah, we started talking about the batch process towards the end of last year and obviously the process has played out, got built this year and we now have more certainty on exactly what that looks like. And so I think the batch process has come together relatively quickly. Yeah. Once that problem was identified. I’ll speak to my company’s perspective. Yeah, in Houston we’ve been connecting large loads to the grid since before it was cool before everybody was talking about it. So we didn’t have the same challenges that you saw in other parts of the state. And in fact the current ERCOT study process for us continues to be very efficient, even through this transition into a batch way of doing things. Okay. Because like I said, we’ve had large customers on the grid down here in Houston for a long time, both transmission and distribution system, even we have large loads on our distribution system down here. The pace has obviously picked up. The size has expanded and gotten bigger. But for us, it’s business as usual at a faster pace. Okay.

Caitlin Smith: I think there’s a big some policy questions come into play for CenterPoint’s territory. I think a lot of those are things that need to be in the territory, right? Close to the shift channel or things that are kind of integral manufacturing businesses. That’s right. And so you also have these data centers or Bitcoin mines that come on maybe in other areas of the state that Some people maybe think don’t need to be there. Or maybe they can locate in a bunch of different places, right? They don’t necessarily need to be in the one spot. So I think not all of these loads have the same characterizations. And I think we tend to right now be solving for the data centers, which is something that’s new for us.

Jason Ryan: Yeah, I think that’s right. I’m glad you raised that too, Caitlin, because you we’ve got the largest petrochemical complex in the world here at Houston, the largest medical center on the planet, a significant amount of advanced manufacturing. And so it’s important that I share that view of a utility in a area that has a very diverse set of drivers of growth with large loads. We also have data centers, but I think you’re right. We shouldn’t over rotate on data centers and have unintended consequences to manufacturing jobs and energy and simply growth of populations that we have here in Houston.

Joshua Rhodes: totally. And I and I want to get to this new concept of well, a borrowed concept of the WL-PUN in terms of like getting through the batch zero process. CenterPoints obviously has connects a lot of the private use networks already. So you already have a lot of experience with that. I want to get to that in a little bit later, but first I want to like setting the timeline. So we’re recording this in kind of like late June. And at this point, the batch zero process has made it its way through TAC. It’s been approved by the ERCOT board. The Public Utility Commission accelerated its approval. Of batch zero and I think I got an email from ERCOT yesterday saying that the process is gonna start on July eleventh, if I’m correct, or something to that effect. Did I get that timerine right, Caitlin?

Caitlin Smith: Yes, that’s correct. I believe the rule becomes effective the eleventh, but there’s a lot of deadlines between the eleventh and the twenty fourth. Or the tenth and the twenty fourth.

Joshua Rhodes: Okay. Got it. All right. So whenever the rule becomes effective, well now that the batch zero is approved, what’s no longer theoretical here? Like what’s the process going to start to look like on July eleventh or maybe the twelfth the next day?

Caitlin Smith: That may be a better question for Jason. You know, I think a really different thing about this as opposed to some of the other policies stakeholders pass is you’re kind of immediately left with winners, kind of winners and losers. Or maybe not losers, but maybe you have to wait a little while. And so we have people who will be firm load in batch zero, right? They’re getting their studies are valid. They don’t need to be redone. They’re getting The allocation of everything they wanted, things that need to be studied in batch zero. So they’re good to go into batch zero. And then they will find out what their allocation is. And then we have people who are out of the batch who will have to wait till batch one. And so we know the criteria for that. I think by August, we will know who’s in those. The requirements are due. I think it’s mostly. The loads have to get it to the TSP by the tenth and then the TSP has to kind of affirm that to ERCOT by the twenty fourth. So we’ll know who those people are or I don’t know if that will be disclosed, but we’ll know the amount and they’ll know who they are in August.

Joshua Rhodes: So is the process, Jason, is it like are the large loads still gonna come to you first? Are they still gonna come to the TSPs first and then there’ll be a handoff to ERCOT or something like that for the big study? Yeah.

Caitlin Smith: Yeah.

Jason Ryan: That’s right. So, you know, what we’ve got now is we’ve got certainty over timeline and we’ve got certainty over requirements. In a couple of weeks you’ll know which loads are fall into what bucket. You’re either base load or your studied load, or you’re not either one. Then from there it’s the new part is ERCOT spap study, which we the utility would have provided the studies to ERCOT. ERCOT will continue to ask questions back and forth, right? We’ll provide answers, they’ll ask questions. That’s very typical even today. So the different thing is the batch study that Caitlin has laid out for us and you know, that is likely to take the balance of the year into next year. Early April is the target for the batch to be complete. And so there’s a lot of certainty now that we’ve got these rules in place, as opposed to January, February, March of this year when it was we were making the airplane as we were flying it. So a lot of uncertainty. You now have that certainty.

Caitlin Smith: Agree with that. We didn’t really start using the word batch, as Jason said, until the end of last year. And even though we did this on, I would say it was a very aggressive and kind of phenomenal timeline, it caused a lot of confusion, right? If you’re sitting there in January and you have some load projects and you just heard this word batch two months ago, but you’ve had loads in process for a couple of years. That really freaks you out, right? Even from January to today is sort of a long time to wait and have that certainty.

Joshua Rhodes: When we talked to Pablo Vegas on the podcast, I you know, he mentioned that this process was ongoing and we probably weren’t gonna get it exactly right, but it was gonna be basically building the plane kind of as we were going. I guess like the first step of that process, Caitlin, I guess went through TAC, right? Went through the technical advisory committee that you’re chairing, or at least that was kind of the process before it got handed off to the ERCOT board. And you had to take a pretty big contentious, you know, large load problem with a bunch of different stakeholders with a bunch of different wants and needs. And turn it into like a streamlined or a process. In that process, what do you felt like was the biggest compromise like y’all had to make or that everyone had to make?

Caitlin Smith: Yeah, I’ve been thinking about this because I think I may have used the word contentious or contested before. I don’t know that I would characterize this as extremely contentious, but I would characterize it as extremely important. Yeah. There was a lot of money on the line and extremely large, right? We’re sort of changing the entire system of load integration onto the grid. And we had a lot of new players. So as you said at the beginning, I chair what’s called the technical advisory committee. I can’t speak on behalf of a group here, but I have a lot of experience chairing that committee. And that committee is comprised of stakeholders, you know, from every segment, generators and Jason segment and municipals and everything. So I sit on the Committee for Jupiter Power. I happen to chair it. So I facilitate the meetings. These low developers have not been part of the process to date. So there was a lot of learning for them, right? They’re not even really voting members yet. And so they were sort of coming in from the outside to a process like this. So there’s a lot of learning. As I said, this was a little bit unusual and they’re kind of immediate commercial winners and losers. And so that gets contentious, but I don’t know necessarily that the policy things we discussed were contentious, but it was hard to differentiate sort of a policy cut versus what is a fairness issue. Is it appropriate to pick a winner and a loser? Because I think there were some issues that came up that were sort of fairness issues that people were very sympathetic to. You know, we talked a little bit with Jason already about the differences between the loads that an IOU might have, right? They might have a lot of data centers in their territory or they might have a lot of critical industry and manufacturing in their territory. And so I think there are a lot of specific to them things that load developers brought to the table. And it was sort of hard to kind of pick what needs to be in batch zero, what’s fair or not, that kind of thing.

Joshua Rhodes: Yeah, I think another word that maybe got overused a bit was when we were talking about the large load queue, we I started talking about it like there was a process. Like, you know, there was no real queue. It’s kind of more like a list, the thing, you know, and with the individual TSPs where things would kind of work their way through. That makes sense. I mean, it’s like if you’re staring down kind of the barrel of like, I think the latest number is like four hundred and forty-five gigawatts of large loads in the process and like ninety percent of that being data centers, it’s like it’s either create a process or just get paralyzed by the fact that you know, you can’t move forward. So it’s like, yeah, hats off to y’all for coming up with something so quick. That was pretty impressive. And I think the rest of the country is watching, particularly other other grids like maybe PJM and stuff. So Jason, in this process, ERCOT’s gonna allocate transmission capacity. It’s like, so we’re gonna go through this process, projects are gonna get either their full allocation or they’re gonna get like a staggered allocation. But that means that utilities actually have to build the stuff and connect. Given how much is going through the queue, is that gonna mean a like a substantial acceleration of transmission expansion in the next five or six years?

Jason Ryan: Well, not to connect to these batch zero loads, most likely. Okay. But you then have to replenish the capacity on the grid. Right. And so if you assume that we will continue to do batches, you know, if we run out of capacity on the current grid in batch zero or batch one, then obviously you have to build more capacity, which gets to maybe Eric’s point of the infinite growth. Whether it’s infinite or not, it certainly is relentless right now. And you see it’s a fair amount of transmission projects being constructed today with early twenty thirties in service dates. Yeah. I think you will continue to need that infrastructure for the future batches. But if you’re in batch zero and you want energy in twenty eight, twenty nine, you’re gonna have the existing grid that you’re counting on. There obviously will be some upgrades that are needed, but you’re not talking the hundreds of miles of transmission line. That’s gonna serve growth end of this decade, early next decade. You know, it is interesting. I think I mentioned this to you, that things will slow down for us so that it’s an unintended consequence of the batch process is that we won’t be able to move as quickly as we otherwise would. I think that will work itself out of the batch process over time, I suspect.

Joshua Rhodes: But the new classification framework, it creates base load, study load, and excluded load. Do we know how much is going to s at least start out in each one of these buckets? And do we have a feel for like what might make it out the other end of the batch zero process?

Caitlin Smith: I don’t have one I’m willing to commit to. I think we’ve heard various numbers from ERPA along the way, but sort of big ranges. And I think a big part of this process is for baseload and for studied load, there are requirements, eligibility requirements. So I think we know based on by all accounts ERCOD and the TSPs have been doing a really good job on their end of what studies are done to say who’s firm load, who studied load. But there are these criteria now for the loads to meet, right? Certain development criteria, a significant financial security posting. So I think we don’t know how many of those loads are going to meet those criteria or choose to meet those criteria. And if they get allocated less than what their project is, do they then drop out? I think what’s been hard about load and the data center load in particular is just the lack of historical context. So certainly for batch zero, we don’t have any historical precedent to say, well, about 80% of the loads, you know, end up hosting their financial security. And with the load forecast, we don’t have kind of historical data to say, well, this is a huge number, but about 60% of these aren’t real or 30% are real. We just don’t have that yet.

Joshua Rhodes: Yeah, I guess we had that for the generator interconnection queue. I remember doing a kind of a study, kind of a longitudinal, we could figure out what percentage would make it between to each stage and f at the other end. But yeah, like I said, I don’t think we even really had a queue. We called it a queue, but we didn’t really have one for large loads. Jason, are you able to offer up any numbers for CenterPoint? Like what numbers are y’all looking at when it comes to kind of what’s trying to get in bash zero at these tranches?

Jason Ryan: Yeah, so I you know, the number if you unpack what ERCOT released earlier this year informs my view of what the ultimate number will be. Okay. So of the more than four hundred gigawatt number, we were a little more than four gigawatts of that. And we have since then had additional load that I believe is real come into the batch process. So, you know, that is not Currently my number that I’m predicting. Okay. But yeah, if you want my entire queue, I can see how you can get to hundreds of gigawatts. But yeah, we meet literally every day to go through our list of potential customers. Yeah. And have only submitted the projects that we believe are real. It’s one of the reasons why our review with ERCOT continues to be relatively straightforward and on historic timelines, and we’re not getting bogged down with a lot of unreal projects. As an aside, I do think that to some extent this is a creature of the utilities making. I’m not being critical of the utilities in saying that because we didn’t have any tools to help figure out who’s real or not beyond just our judgment. Yeah. But we do have to exercise our judgment in terms of what we bring forward. And so that’s why you’re not seeing eye popping numbers out of the Houston area because we’re not turning in, you know, our entire queue. That said, I think that we’re about twenty five percent of ERCOT’s load down in Houston today. Yeah. If you assume that I’m growing at roughly the same pace as the rest of the state and that I have about the same amount of available capacity on the system today as other parts of the state, maybe I have a little bit more. I think that drives me to I think realistic number coming out of that zero base load is forty, fifty, something like that. Again, it depends on what the timeline for those projects are. If those projects are needing power in the twenty thirties, then sure, perhaps that’s not an issue. But that’s my prediction. By the time this airs, I’ll probably be proven super wrong. Because we’ll know. But you may be right. But that’s my prediction just based on what we think is real among the customers that we interact with. You know, the utilities are the closest to these customers. Right. We have to do our job. Of vetting these before we just throw them into the machine of ERCOT. And so I do think that I’m not critical of how we got to the batch process. I think it’s needed across the state, but I think when you throw around numbers that are hundreds of gigawatts, we know that that’s not going to happen in this decade, right? But like I said, the utilities were kind of without a process to make the decision on well, who does get to go forward and who doesn’t. So that’s why I think batch is good. But we also have to be more realistic on the numbers that we put out there.

Joshua Rhodes: Well Kaylin, hopefully that helps tack there to figure out kinda maybe what’s going on.

Caitlin Smith: to the number. I’m not figuring out the numbers.

Jason Ryan: Yep. Forty or fifty gigawatts of baseload growth is mind boggling. But I think the grid could actually digest that in a relatively modest period of time. Then we should talk at some point about potential unintended consequences of the batch process because I think there are some that are worth talking about, especially down in Houston where all of our growth is not data center growth.

Caitlin Smith: Is a lot. Yeah.

Joshua Rhodes: totally. Yeah, and we’ll get to that here in a little bit. I did want to so you’ve talked thrown around a few numbers. I mean I think all of them are kind of wags at this point. Yeah, maybe but okay, between zero and in less than infinity, which mathematically is still inf whatever you

Caitlin Smith: They’re not infinity. Should do Twitter game like Russell Gold used to do. You should have people

Joshua Rhodes: we have to bet the price of oil. Yeah, next year. Okay.

Caitlin Smith: Yep, you should have people bet the gigawatts and batch zero.

Joshua Rhodes: Okay, I didn’t do it for batch zero, but I think I did this years ago. But when the numbers were like 100 gigawatts, not 400 gigawatts. And so it’s I’ll be honest. The last study I was hoping for 500, just you know, why not? Okay, but there’s a couple different to get a lot of these large loads in there, ERCOT has come up with a couple new constructs. Well, not new. They’re borrowing existing constructs to kind of help some of these. There’s the PCLR, the provisional controllable load resource, which, you know, essentially will have some firm service, but if the grid can support it, might be able to go above that during certain times, but they may be curtailed down to their firm. And then kind of this WL-PUN, which is a withdrawal limited kind of borrowing from the private use network that we kind of already have in a lot of like the high industrial loads in the CenterPoint region in the Gulf Coast region. So Jason, starting with WL-PUN, can you kind of explain just how a private use network works, like how it interacts with ERCOT and kind of how y’all see that when you’re doing your planning?

Jason Ryan: Sure. So, you know, as you mentioned, it’s not maybe the acronym is new. The concept isn’t super new of having generation sided with load, either literally right next to it or in close proximity to it. And you know, you look at a lot of our historic large load customers, many of them have their own generation. And sometimes they are using that generation for their processes and sometimes they’re selling that back onto the group. So we’re super familiar down here with how that works and how that’s engineered and those customers are super familiar with the economics of it as well. And you know, as it relates to you know, the move to more of that, it doesn’t cause us great concern because of that historic precedent. And as you talk about the controllable load resource, it’s again not super different. Then what we already see, again, the acronyms may be different and maybe everybody doesn’t have the same kind of experience that we have with these large loads that, you know, for various reasons might have to change what they’re doing, change their use of the grid in the moment, or even put extra power back on the grid for a moment. We understand how to build the infrastructure for that and how to take that into account when we’re interconnecting on

Joshua Rhodes: And Caitlin, I is my understanding that some of the acronyms are kind of new, but we’re borrowing from existing constructs that exist. Is my understanding, and please correct me if I’m wrong, that a lot of these new larger loads were actually wanting a new construct, like a point of interconnection netting, like with generation kind of behind the meter. If I got that right or it got it partially right, can you explain like what they were asking for and kind of maybe why we didn’t want to tackle it here with the batch zero process?

Caitlin Smith: I think that’s right. I think these are old concepts. You know, certainly the private use network. CLR, same thing as what I was talking about in the beginning with these loads, us not having seen this really until six years ago. I think the concept of CLR existed, but it wasn’t really being used until these data centers, maybe, I don’t know, four or five years ago. It’s basically a software solution to be able to respond to the grid as fast as a or faster than a generator would be, right? You’re a SCADA-dispatchable load. So it’s still a new concept. And I’ll want Jason to weigh in. I think what we’re talking about maybe since SB6 is more a concept of non firm service. And so these loads say, well actually I don’t need firm service all the time because I’m a CLR. Or because I’m a generator and I’d actually prefer not to have firm service if it increases my speed to market. And I think that that is a new thing, right?

Jason Ryan: Yeah, certainly newer in the electric space. We’ve been doing that forever on the gas utility side of our business though, right? That is how large users of natural gas get connected to a system that has limited capacity only in certain times. Right? So think about in the wintertime when all of us at home are turning the heater on using natural gas, we’re using more capacity. Especially here in Texas, that’s a limited period of time. Right? There are a couple of days in the year. Where we’re consuming a lot of natural gas, that capacity is there. And on a normal day, you know, the other three hundred and sixty days of the year, that gas is available to large users, but they know that they’re curtailable in the tails of the probability curve and they curtail their usage of the system. So it’s perhaps being applied in a different way, but the concept has been around to consume energy for a hundred years, right?

Caitlin Smith: Yeah.

Joshua Rhodes: Yeah, no, totally. I guess like but I guess maybe for like the electricity sector, it is like a bit of a different, you’ve always kind of had the obligation to serve, like four or five nines, you know, reliability. Whether it’s like a PCLR or just a different reliability class of something, I know that’s something I didn’t wasn’t fully aware of that we were having that particular conversation outside of the PCLR construct here in ERCOT. I know they’re doing that in PJM. They’re talking about different levels of reliability. For different customer classes. But like, I guess, Jason, say you got a project going through the batch zero process, they’re signing up as a PCLR, a provisional controllable load resource. Do you trust them enough? I guess right now? Do we have the solutions in place? Like Caitlin said, CLRs have only been around for a little while, and I think mostly have been used by Bitcoin mines, if I’m correct. But what do you need to see to be able to trust that, okay, you need to go down to your hundred megawatt firm limit? I mean, what do you need to see to make sure that your system stays stable?

Jason Ryan: Yeah, so I think it’s fair to say that we’ll have to do a fair amount of testing to make sure that we understand how this works, what impact it may have on our system when we need it to work. Yeah. And to ensure that we engineer a solution that works in all kinds of scenarios, not knowing exactly what the scenario is that would require them to trigger that feature of their site. And so I have no doubt that we will be able to work through that. There are things to work through though, right? We don’t have all the answers as we’re sitting here today. Right. I trust that we will be able to figure out together with those customers. And I suspect the answer is gonna be that you test various scenarios along the way. Not super different, more complicated, but not super different than what we do today with our load management customers. We test it periodically to ensure that they’re able to drop their load on the timeframe that they need to. This is a bigger scale. But it’s not super different than what we do already with some of our other programs. Okay.

Joshua Rhodes: Are you also concerned about one of the things when we saw this happen in PJM a little while ago? So we had a large data center, like a gigawatt worth of like data center load, like trip offline. And that created a lot of like local instabilities in the system. And when I teach electricity markets, I generally used to brush past the frequency going too high because we have like too much generation and not enough demand. And like it’s easy to turn things off. Like this is no big deal. But apparently, maybe is a big deal. And so like as you’re seeing more of these. Larger loads, what are you thinking about in terms of making sure that, you know, that side of a trip is covered? Caitlin Smith (00:30:51) I think batteries can help with that, Josh. Just I love the plug there. That works great. It’s a softball right for you.

Jason Ryan: In addition to batteries, I think again, we’ve had to consider this for a long time down here in Houston. Now again, the so take a large L and G terminal tripping off or, you know, any other kind of re large refinery type load or even some of the large manufacturers that have a significant amount of load, especially if you’re talking on the distribution system, we will need to work through that as the size of these facilities start to become multiple gigawatts, not just a gigawatt. Yeah. And so it is a consideration that we’re working closely with our engineering teams and our customers to ensure that we think through all of those scenarios and think through how we need to design a system to withstand that. By the way, it’s not super different in concept to designing a system to take that into account in terms of loss of large generation. Right? Yeah. All of these large contingencies that happen, you have to plan for and design the system to withstand them.

Joshua Rhodes: Got it. So Caitlin, TAC has handed off like the batch zero process. It’s been again been voted. ERCOT board, public utility commission, it’s getting started. What are y’all looking to track between now and I guess kind of the fall of twenty twenty seven is when this process is like supposed to end up with a plan for the regional planning group to say, Okay, here go build this stuff. What are you tracking between now and then to know whether or not the batch zero process is working? What’s success or what’s an issue?

Caitlin Smith: That’s a good question. I haven’t really thought about what kind of reporting we’ll want. I’ll defer to the other members of TAC. I should have said at the beginning, this really started with ERCOT staff and with commission staff. We did our part as stakeholders. We did, I think, more than our partners as much as we could. This was a highly collaborative process, which is an achievement on a short timeline. But the commission staff and ERCOT staff to their credit has been very hands-on and involved. I don’t think that there’s a world in which we say this is a failure, right? It’s what we’re doing. We’re moving to a new process. I think it was necessary. We’ve harped on a couple of the Things that were maybe problems before. Maybe studies were working in some areas, but there’s sort of a lack of transparency, right? Because there was no process. There wasn’t a standard interconnection agreement for load. So you couldn’t go online and see what other people were doing. Okay. You couldn’t go to a dashboard anywhere and see what your status was or if ERCOT was gonna need a restudy because some other load came online. There’s just a lack of transparency that I think needed to be. Remedied. So I think we have a lot more transparency and certainty. I think there are things that we will need to change, but there are probably things we’ll continue to want to change. You know, after batch one and batch two, we sort of always keep working on our rules for the market and for interconnection.

Joshua Rhodes: Yeah, that was gonna be my next question. Is you know, batch zero has often been characterized as kind of a triage of this big large load list or queue or whatever you wanna call it, you know, trying to inject some discipline into this process and like get things moving and get a process. But like as batch zero is kind of a triage process, presumably as we’ve mentioned, there’ll be a batch one, a batch two, a batch three, a batch in, who knows how many of these batches we’ll need. Do you have a feel for like what parts of batch zero should be treated as permanent versus what part of it is just the triage right now, kind of the emergency scaffolding here?

Caitlin Smith: You know, I think it’s a really good framework. I think people are going to have more asks, right? You brought up two of the big ones, the WL Han and the PCLR. Yeah. I think people are going to have more asks on those things. I think more people will start to weigh in, right? The legislature’s back in town next year. I think we’ll hear more voices, as I mentioned before. One of the challenges, but it was Don’t get me wrong, it was very good they were participating, but these load of developers were new to the ERCOT process. Yeah. They’re not new anymore, right? So we’ll continue to hear from them, which I think is good. But with more time, we also know more. I think they’ll just be continue to be more and more asks as we do batch one, batch two, batch three.

Joshua Rhodes: Got it. So kind of similar question to you, Jason. Kind of like we’ve got batch zeros, we’re gonna build the plane as we’re going, but you know, before we get to batch one, like is there anything in particular that’s CenterPoint?

Caitlin Smith: We built the plane. It’s great.

Joshua Rhodes: Well maybe we’re putting seats in the plane. We have engines, maybe. We’re taking off. We haven’t painted it yet, maybe? Something like that.

Caitlin Smith: I think putting seats on it is right.

Jason Ryan: We’re about to have passengers, right? So yeah.

Joshua Rhodes: There are about

Caitlin Smith: But not infinite passengers, a finite amount.

Jason Ryan: That’s fair, yeah, yeah.

Joshua Rhodes: Not infinite passengers. But Jason, so like before batch one gets going, like is there anything in particular like the CenterPoint is already looking to like get or caught the change or fix or to alter?

Jason Ryan: So I think I’ll talk maybe conceptually the things that we should be asking. Yeah. I feel like we should be asking ourselves is seventy-five megawatts the right cutoff to go into a batch? And that’s gonna depend on the answer to the other kind of high level question I think we should ask ourselves. But it’s not uncommon for us to add a hundred megawatt customer down here, especially on the manufacturing side of things, and the timeline to win a project like that whether it’s a new customer or an expanding customer, is not going to line up well with the batch process as we see it today. Okay. What I mean by that is we’ve got customers that have options. They could build a manufacturing facil they could expand their Houston facility or they can expand their Mexico facility. They’ve got contracts and obligations with customers to make stuff. And they are going to make that stuff wherever they can get the power quickest. And they’re not gonna be gigawatts of manufacturing facilities, right? So that’s why I say maybe that seventy five needs to be looked at and have some kind of stratification for what is still large load, but I’m not sure it’s the large load that’s causing the need for the batch. Okay. So I think that’s a question. And then the second question is how often are you going to run a batch? Yeah. And you could design a batch process that works even for manufacturing expansion where you can move at their speed of business, but maybe not if it’s only once a year. Okay. You probably could if it was twice a year. And so as you get past batch zero and you know, one through end, yeah, can we at some point get to the point where the batch process is not the long pole in the tent. If I have available capacity today There is no batch process that’s the long pole in the tent. It’s getting the studies through ERCOT, which is relatively efficient for us down here, and then connecting to the customer at their speed. Right. When you have the batch process be the long pole in the tent, not whether I have the capacity to serve them. Mm-hmm. That’s where I think you have unintended economic development losses. In Texas, we don’t accept those outcomes. I am confident we will figure this out. But I think those are the questions that we have to ask ourselves post batch zero. What do we want this to look like forever? And I think those are the top two considerations from my symbol.

Caitlin Smith: Is there a solve for that?

Jason Ryan: I think that if you don’t want to change the seventy five megawatt threshold and if you don’t want to increase the frequency of the batches or don’t want to or can’t, then you know, perhaps there’s a separate track where there’s clearly available capacity. Yeah. So again, if I’ve got a hundred megawatt facility that they just wanna employ a couple thousand Houstonians, I’ve got the capacity, everybody agrees there’s the capacity. Yep. Why should they wait? For a batch to be run. So you could maybe create that kind of exception. I don’t like having an exception to a brand new process. Exception. That’s why I think that we have to ask ourselves, are we concerned about the hundred megawatt loads? Because if we’re not and we’re concerned about you have a super large loads, then perhaps you create some kind of different process going forward.

Caitlin Smith: That’s interesting. You know, the seventy five megawatts, I’ve been wondering about that. Like, do we see a bunch of seventy four point nine? Like you see the nine point nine generation.

Jason Ryan: Hundred percent. We are seeing it today. Yeah. In terms of the distribution interconnection requests that we’re getting. So I think you are absolutely going to see that because when the process becomes the long pole in the tent, business is gonna wanna move at their speed still. And if the only option to move at their speed is to stay below that cap, I think you’re gonna see a lot of projects that stay below that cap in order to get speed to power. That’s why I raise the question if Is that the right threshold for a longer process? And the answer could be yes, right? I just think we need to ask that.

Joshua Rhodes: Yeah, no, that’s fair. I think that’s one of the questions I was wanting to ask is like, okay, how many 74.9 megawatt data centers are you seeing? Cause I think this’ll be get more clear as kind of like the needs of AI actually play out. So 90% of these large loads are data centers. Gonna presume, given the CapEx spin, that most of this is AI at this point. And we presume we need big data centers for the training of these models to create the new near next frontier models. But for the inference, the actual my students cheating on their homework or, you know, everyone asking kind of how things go, like you don’t necessarily need gigawatt scale data centers kind of for that. And there’s a lot of people talking about we may we’ll start to see a lot more inference data centers that are smaller that are popping up. I may have misunderstood you, Jason, there bit. It sounded like you were arguing for the cap to go up. I’ve heard most people argue it to go down. Like the original was 25 megawatts or something, but it sounds like you’re arguing for the cap. To go up for the batch process. Is that what I’m hearing?

Jason Ryan: I mean that’s the question that I would like to have a debate on. And again, maybe this is the exact right number. Maybe it should go down. No. I think the unintended consequence though of a batch process that is not more frequent than once a year is not going to be consistent with non-data center large loads business plans. Yeah. Especially if they just want to expand an existing site. I think the unintended consequence is that we could lose out on those projects. That’s what I think we need to have a debate about. You know, again, it is not uncommon for us to have a 75 or 100 megawatt facility dropped into our system. We’re quite used to that. It could be unusual in other parts of the state that aren’t used to that kind of large industrial manufacturing load. And I would dare to say that I don’t think those are the ones that are causing the need for the batch. If all we had was a lot of hundred megawatt load, not that that’s small. Right. But I don’t think that we would be in the So why are we scooping them up as well? Right. And again, we may decide that we need to. And I’m always happy for that to be the answer once we have the debate. Yeah.

Caitlin Smith: You know, the lower number, I think it’s confusing, but I don’t know that it’s a real problem. I think ERCOT, FERC, and NERC all have different numbers for what is the large load. So I think that will get confusing. But what Jason raised about raising the megawatt threshold, I think maybe makes sense. The exception point is something I’ve been thinking about a lot because we can get to a n great outcome. We can pass something through TAC that everybody loves policy wise. But what if something critical to Houston’s economy wants to interconnect? You know, what if yeah the governor has a press release about a hyperscaler load? You know, what about all these things that are really critical to our economy? How are we going to accommodate those? Or how are we going to say, well, now that’s on hold for eighteen months, even though we got everybody excited about it or we need it in our city. And it’s just really hard, I think, to provide for exceptions. So maybe the idea of raising the threshold is one that could help with that.

Joshua Rhodes: Yeah, I mean, I I wonder how politically salient something just putting us a particular customer class in the batch system, like the customer class maybe that’s kind of like maybe causing the need for the batch system to come around. I mean, I know that other regions are also looking at separate, either like we were talking about earlier, a little bit reliability standards or different rate classes or different transmission cost allocation mechanisms and things like that for particularly data centers right now that are kind of driving a lot. Of this. And so maybe that’s some of the debates and things like that that we’ll be having. But Jason, I have heard that concern from like non-data center loads about, you know, being kind of caught up in this kind of whole process. But we’re going after the same thing, electricity. Right. So it’s like a tough process. I guess like one final question is we kind of touched on this a little bit, but like the timeline is is we’re going to start the rule takes effect mid July. And, you know, there’s a roughly a five step process kind of coming out the other end. Are we still expecting that we’ll be able to have transmission plan handed to RPG at the late to the end of 2027 that would allow for the output of the batch zero process to then start to take effect, which then won’t get built out for the next like five or six years, kind of depending on how it kind of lands.

Jason Ryan: You raise a good point that I also think raises the question of unintended consequences because the timeline that you just laid out is quite long. Right. And if you think about it, this process is designed in part, maybe in large part, but at least in part, to kind of weed out speculative projects. Yeah. The question you’re raising that talks about all the steps, even once you get past the July tenth and July 24th dates of this year, you’re going well into the end of next year for even more process. I think that customers that are the most real are going to have a problem with that timeline. Okay. Right? So if I am a real customer with contracts with other real customers to deliver something to them, whether I’m a data center or I’m building something, and my contract with that customer has a timeline associated with it. That the more process and longer the timeline to get power, the more you are weeding out the most real projects. And I think that’s the reason why once we get past batch zero, batch zero kind of is what it is. Yeah. But once we get past batch zero, we have to start asking some of these questions of how do I make sure that we maintain the reliability of our system and affordability. Of the rates of that system, but also move at the speed of business. And I am confident we’re going to figure that out. But I think these are the critical questions we have to start asking. Because again, if you start then saying, well, what’s the timeline for batch one? Mm-hmm. You’re talking about timeline for batch zero that goes through the remainder of next year. If I get asked by a customer, what’s the timeline for batch one, when do you think I can get power? It’s very uncertain right now. Okay. And I think the more That the utilities who are kind of on the front line with those customers every day have to shrug their shoulders and say, I don’t know. You know, the more we have the possibility of losing out on development. And that’s why I’m encouraged that ERCOT’s going to turn their attention very quickly to batch one so that we’re not in a phase of having to shrug our shoulders because we don’t know. And again, I have great confidence that we’re going to figure this out and be able to meet this moment. ERCOT, do you see? All the stakeholders have worked super hard to get to this point. I know we’re going to work super hard to understand batch one. And the more we can have certainty over that future batch and what it’s going to look like, the more we as the folks that are talking to the customers on the front line can exude that confidence that Texas is open for business. We want their business. We want the benefits to existing customers of this growth that’s going to reduce costs. Not add to them. Right. But we have to get started on batch one and I’m excited that we’re gonna start those conversations soon.

Joshua Rhodes: Well it sounds like you’ll be there to ask a lot of questions of Caitlin in the intact and as soon as we get this photo. Someone will be there. So it sounds like we need more podcasts later on about this process as Infinite Podcast. That’s exactly right. Caitlin and Jason, thank you for coming on the Energy Capital Podcast.

Caitlin Smith: Infinite podcast.

Jason Ryan: Thanks for having me.

Caitlin Smith: Thank you.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

ERCOT made a choice years ago that most of the country is now reconsidering. Texas runs an energy-only market with no capacity payments, connects generation through connect-and-manage, sorts out delivery in dispatch, and pushes interconnection risk onto developers. That design is a big part of why Texas has added generation faster than any other U.S. grid.

PJM, the operator for much of the eastern U.S., is now weighing whether to move in that direction. A white paper from the operator describes a shift from managing surplus to managing scarcity as data center demand outruns new supply. The paper lays out three pathways: long-term bilateral contracts, differential reliability standards for new loads, or an ERCOT-style tilt toward an energy and ancillary services market with a smaller role for capacity. The scale is large in both regions. ERCOT is now considering roughly 445 gigawatts of large-load interconnection requests against an 85-gigawatt system, while in PJM, one Dominion territory alone projects 70 gigawatts of new demand against a 24-gigawatt peak.

On this episode of the Energy Capital Podcast, Joshua Rhodes talks with Josephus Allmond, Virginia’s chief energy officer, about what separates the two grids and what PJM can take from the Texas model. Allmond points to ERCOT’s interconnection speed as the clearest lesson, given PJM’s projected 700 days from queue to agreement before construction even starts.

He also points to the state line, where borrowed fixes hit a wall. Virginia’s State Corporation Commission requires large customers to pay a generation charge for 14 years, even when a data center builds its own power. A load that sources its own generation, Allmond says, ends up “paying their own way and then turning around and paying Dominion.” The conversation works through:

* ERCOT versus PJM structure, energy-only and connect-and-manage against PJM’s capacity market and consensus-driven stakeholder process, and why one moves faster.

* PJM’s three pathways, and how the energy-market tilt is the one Allmond reads as closest to ERCOT.

* The large-load tools, controllable load resources, and behind-the-meter generation in Texas, and the Virginia charge that makes the same moves uneconomic.

* Interconnection speed, ERCOT’s developer-risk model against PJM’s roughly 700-day queue.

What PJM borrows from ERCOT, and what it refuses to give up, will shape how fast the East Coast grid can serve the load now lining up.

Timestamps

* 00:00 - Introduction and Guest Background

* 01:52 - Virginia’s Chief Energy Officer Role

* 04:15 - Data Center Alley and Virginia’s Hub Status

* 06:29 - ERCOT vs. PJM: Governance and Transmission

* 10:53 - PJM’s Shift from Surplus to Scarcity

* 19:29 - PJM’s Three Reform Paths

* 24:19 - Virginia’s Minimum Demand Charge Problem

* 29:36 - The Data Center Tax Exemption Fight

* 31:50 - Path C and the ERCOT Parallel

* 35:17 - What Has to Give: Allmond’s Closing Answer

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Micalah Spenrath (LinkedIn)

* Matt Boms (LinkedIn)

* Texas Advanced Energy Business Alliance (Website)

* Energy Capital (Website - LinkedIn - YouTube)

* Texas Energy & Power (Substack)

* Josephus Allmond (LinkedIn)

* Office of the Virginia Chief Energy Officer (Website)

* Southern Environmental Law Center (Website)

* PJM (Website)

* Monitoring Analytics — PJM Independent Market Monitor (Website)

* ERCOT (Website)

* FERC (Website)

* Dominion Energy (Website)

* Virginia State Corporation Commission (Website)

* Virginia Department of Energy (Website)

Books & Articles Discussed

* Powering Reliability Through Market Design — PJM White Paper (PDF)

* How Will Data Centers Pay for Power? — Travis Kavulla, American Affairs (Website)

Company & Industry News

* PJM floats options for capacity market overhaul (Utility Dive)

* Spanberger creates new cabinet position, appoints Allmond chief energy officer (Virginia Mercury)

Related Podcasts by Energy Capital

* How Texas Plans to Serve Infinite Demand, with Eric Goff (Texas Energy & Power)

* NRG’s Gigawatt VPP in Texas, with Travis Kavulla (Texas Energy & Power)

* Who Pays for Texas Grid Growth? — Roundtable Discussion (Texas Energy & Power)

* Who Pays for the New Grid, with Pablo Vegas (Texas Energy & Power)

Transcript

Joshua Rhodes: Hey everyone and welcome to another episode of the Energy Capital Podcast. I’m really excited to have Josephus Almonds on today to get us out of our comfort zone a little bit here in Texas and ERCOT and talk a little bit about PJM, kind of some of the things that are happening in other grids. PJM is one of the other grids that is experiencing large amounts of load growth, particularly from things like data centers. Texas is no stranger to that. And so it might be useful to figure out kind of how other regions are doing it, approaching it, and maybe we can

Cross-collaborate on some of those. So Josephus got his JD from Duke, where he did a couple of stints at BakerBots and Kirkland and Ellis. And then he was an attorney with the Southern Environmental Law Center, where I should say that we worked together on Dominion’s IRP a couple years ago, intervening in that. But recently was named CEO, should say Chief Energy Officer, although this may be one of the few podcasts where Chief Energy Officer might get you more kudos than Chief Executive Officer for sub.

But Josephus was recently named Chief Energy Officer from Governor Spanberger. Josephus Alman. Welcome to the Energy Capital Podcast.

Josephus Allmond: Yeah. Thank you so much for having me, Josh. It’s good to see you.

Joshua Rhodes: Yeah, it’s good to see you too. So first I gotta ask, how’s dad life treating ya?

Josephus Allmond: It’s great. We actually just had his first birthday party this past Saturday. So awesome. We went all out with a clues theme, had paw prints all over the house, a bunch of decorations. We had my in laws were in town from California and some of her aunts from Texas. So full house, lots of friends and family over and a blue smash cake that Josephus really loved.

Joshua Rhodes: Nice. That’s awesome. You know, Aiden’s only just about a month ahead there. I remember when I when we were working together when you were at SELC and I was like, hey, I’m not gonna be able to make this like super important meeting that I said I’d be at because it’s literally on the day of my son’s birth. I think you told me that y’all were also expecting. So that’s awesome. We’re right in there together. Neither of us are probably getting any sleep at all. So we’ll see where this goes.

Let’s start out with the job title. So Virginia now has a chief energy officer. So what was the problem that the Commonwealth was trying to solve with creating that role? And what does success look like for you there?

Josephus Allmond: Yeah. So historically we’ve got a Virginia Department of Energy, used to be known as the Department of Mines Minerals and Energy. And so they do all of the permitting for mines for oil and gas, mostly out in Southwest Virginia, and recently started to do more of the state energy office stuff as Virginia created the RPS and started its clean energy journey six years ago with the Clean Economy Act. So that’s sort of one agency within the Secretary of Commerce and Trade, but

We all know that energy sort of touches everything. And so the governor really wanted to create a more nimble cabinet level position that could work with the different secretariats on energy issues as they pop up and as they’re impacting the different secretariats. And so the Virginia Department of Energy is still under the Secretariat of Commerce and Trade and we’re working really closely together. They’re doing some modeling to inform an energy plan that we gotta put out later this year.

But I’ve really got sort of the ability to work not only with them, but with the Secretary of Labor when it comes to apprenticeship requirements or the Secretary of Education when it comes to apprenticeship programs in K twelve or energy savings performance contracting, as we’re looking at trying to get more efficient government buildings to even working with our Secretary of Public Safety and thinking about

Can we develop some distributed solar facilities at our jails and prisons and incorporate some training there? So really trying to bring energy to the forefront in sort of everything that we’re doing. And in today’s world where affordability is sort of dominating the conversation, having that position at a cabinet level, I think really just elevates the importance of it and puts more of a high profile on it, just given how much it sort of seeps into everything that we’re doing.

Joshua Rhodes: Yeah, totally. I mean, particularly on the affordability front with all the load growth and with electricity and data centers. I mean, Virginia’s no no stranger to data centers. You’re kind of the original area. Can you talk about data center alley? Where is that located and what’s the importance of that region and the energy that it consumes?

Josephus Allmond: Yeah, so we are sort of the data center capital of the world. Loudoun County is home to Data Center Alley up in Northern Virginia. And there are a number of reasons why I think that emerged as a hub. We’ve got a great fiber network already built out, the proximity to DC for the three letter agencies and their needs. And then our tax exemption is something that we’ve had on the books for a really long time and gives an exemption for

Basically all of the equipment that you purchase for your data center facility, that’s going back, you know, fifteen years at this point. And the way that that exemption has played out over time is that once a data center sort of obtains that exemption in a specific county, everything else that they do in that county is rolled up into that same memorandum of understanding. And so even if, you know, the subsequent facilities don’t hit the original investment and jobs numbers to get you that initial exemption.

you can still sort of roll new facilities into that. And so that’s why we’ve sort of seen that clustering effect in Northern Virginia, but even now in some other counties where they’ve started to develop.

Joshua Rhodes: Okay, I’d never heard that part. That makes a lot of sense. I mean, on Texas has some economic development tax codes and things like that for abatements and things. Well, we won’t get down into the weeds of those necessarily. I remember hearing something like seventy percent of the world’s energy traffic goes through Northern Virginia and data center alley. I think Texas is trying to give Virginia a run for its money when it comes to data center capital of the world. I think we’ve, you know, got hundreds of gigawatts of data centers that are trying to connect. I haven’t I haven’t believed these numbers in a long time.

Around here. I don’t know that anyone believes load forecasts right now. But I mean a lot of the focus of this podcast is really around electricity and we’re deeply steeped in ERCOT. Can you explain for an audience like what the biggest structural differences as you see in between like ERCOT and PJM are?

Josephus Allmond: Yeah. So I think the the biggest one that comes up to me is sort of the governance. And so PGA app has a stakeholder consensus process that can really slow things down. And so they’ve got to reach a certain threshold of votes to get to consensus on any given issue before that even goes to the board for consideration. And then more often than not, you also need FERC approval after that. Whereas less FERC oversight with ERCOT.

And then for transmission planning, Texas had the competitive renewable energy zones a long time ago that really laid the foundation for transmission. PJM does transmission, I say more of an incremental fashion through the RTEP process, regional transmission expansion process that sort of looks to build out infrastructure over the next several years, but not quite as comprehensive as sort of that competitive renewable energy zone process from Texas.

Joshua Rhodes: Yeah, we’ve built a lot of transmission down there. You mentioned the Kres lines. We’ve got another tranche of lines coming, the Permian Reliability Project or the STEP lines, as it were, building some really big 765 transmission lines, some really even higher even higher voltage ones. They’re working their way through the siding process right now, which, you know, is a whole another regulatory kind of firms. Whenever you’re, you know, moving that linear infrastructure. You mentioned like a pretty

detailed like consensus. I talked to a consultant named Eric Goff on a couple of podcasts ago and ERCOT used to have a stronger consensus. He said ERCOT used to have a stronger consensus mechanism and then post URI it became more of kind of an advisory body. It became less consensus or less binding. If the consensus is slowing things down, is there any look in how that might change in PJM or anything like that?

Josephus Allmond: Yeah, I think that’s one of the big issues is sort of how slow things are moving and also how fast they need to be moving going forward with the supply-demand gap that PJM is projecting, these sort of long, drawn out stakeholder processes might be good in an environment with no load growth where careful planning can sort of take its time. But when we need to be making really significant overhauls of the capacity market generally.

It’s good to see how that stakeholder process can sort of lead to that result in any amount of time that sort of solves the problem that we’re we’re needing to solve.

Joshua Rhodes: One of the biggest differences also between like ERCOD and other regions like PJM is, you know, this kind of multi-state governance situation you got going on. There’s a lot more people in the room when it comes to making decisions, a lot more people maybe represented in the room. There were some recent statements out of FERC saying that maybe BJM was a little bit ungovernable when it comes to that. Is that that’s all I’ve heard really of that? But I mean, is that making any waves around in your part of the world?

Josephus Allmond: It’s something that I’ve heard more and more. I was at an energy conference last week and heard someone talk about maybe it makes sense to have some of the regulated states, you know, Virginia, West Virginia, North Carolina sort of form a PJM South. Not say I’m endorsing that idea, but that’s something that’s coming to the forefront as I’ve grown into this role sort of appreciating the difference between regulated and unregulated states within PJM.

and sort of the different positions they take and how that affects, you know, how they view the actions that P J M’s taking, because certain things that P J M’s thinking about has a much larger impact on a state like Pennsylvania than it does on a regulated state like Virginia.

Joshua Rhodes: Can you pull that thread a little bit? Like when you’ve got all these folks in the room, are disagreements like falling along those lines, the regulated versus the unbundled or kind of deregulated states? What’s the tension there?

Josephus Allmond: Yeah. So I’ll I’ll just give an example and we’ve actually hopped into the PGM Governors Collaborative, which is my counterparts in other PGM states that have been thinking about this problem for over a year now. And this goes back to sort of Governor Shapiro driving for the cost cap a while back and their continued engagement. But I think this comes up a lot when we’re talking about how we’re doing resource adequacy versus how we’re doing bilateral contracts to sort of hedge long term.

And especially with some recent decisions that have come out of our State Corporation Commission that make that bilateral contracting a little bit more difficult for large load customers.

Joshua Rhodes: Got it. I want to get to some of the Virginia specific pieces in a a little bit later. But one of the things, like when we were going back and forth about this, trying to get you on the podcast, is you sent me a white paper that PJM had just put out, I think just a couple days before when we were having that conversation. The white paper basically, you know, says you’re moving from managing a surplus to managing scarcity. I remember back in the early days of Energy Twitter making charts showing how big PJM’s reserve margins were compared to everybody else’s.

And being like, isn’t that silly? So for moving from, you know, managing surplus to managing scarcity, do you think the core is of the issue is that PJM’s market design is broken or is it just demand is moving too fast? What caused them to want to write this white paper?

Josephus Allmond: Yeah, I think the problem sort of inherently is that new demand is just coming faster than new capacity can beat it in PJM. And the markets were designed to reach lowest cost units in an era of declining load, and they’re now unable to incentivize sort of high capital investment that we need, the growing demand. But I want to put a caveat on that and sort of going back to something you mentioned about the Texas load, it’s like I think before we even start.

This discussion, we’ve got to get a much more informed view on the load forecast and the confidence that we have in that load forecast. The numbers coming out of, you know, just Dominions, DOM LC alone is 70 gigawatts of new capacity from large loads coming online in the next couple of decades. Our system peak right now is 24 gigawatts. And so the idea that we’re gonna triple our capacity over the next couple of decades.

The independent market monitor was on a panel at a conference I was at last week and called the numbers fantasy. And I largely agree. I mean, if we sort of rewind to Virginia back in 2018 when Mark Christie was still on the State Corporation Commission here, he basically ordered Dominion to stop using their own loop forecasts and to start using PJMs because for years and years they had consistently over forecasted demand at about a five percent annual clip.

And so now they’ve shifted to using the PJM load forecast, but the wrinkle there is that the only thing that’s driving up the PJM forecast are the sort of supplemental forecasts that they get from individual utilities that then they do not vet. So the utilities who have a history over forecasting demand have been feeding these supplemental forecasts to PJM that indicate really serious growth without sort of

Any check on the back end by PJM to see if there’s duplication across those loads. Something that I know we talked about going back to that IRP proceedings, this I idea of phantom load where you’ve got developers putting in bits in a number of jurisdictions trying to see where they can get the best deal. And if you don’t really have a process to suss that out, then you’ve got really overstated loads.

Josephus Allmond: Coming at you from a number of utility jurisdictions. And I think that’s exactly what PJM is dealing with right now. And so if you’re thinking about hitting that aggregate demand number that really has never been investigated, then I think that’s partially driving the because we’re trying to solve a problem that is really unsolvable. There’s no way we’re going to build an additional 45 gigawatt of moon generation in the DOM zone here. So

I think that’s step one is like really investigating, interrogating the forecasts and trying to figure out what’s real there.

Joshua Rhodes: Yeah, sounds like Dom’s trying to add a basically a Texas word about eighty five gigawatts, but getting kind of close there. Yeah, I mean, I think this is a conversation that’s being had across the country. And I’ve had a couple discussions with folks around, you know, ERCOT is setting up this dispatch zero process where they’re gonna try to figure out of all this load, which is like four hundred and forty-five gigawatts of like large load right now, again on an eighty-five and a half gigawatt system, they’re trying to figure out

We’re gonna try to shove all this into a study, but we’re gonna have some inclusion criteria of who makes it into the study. And you gotta get in the big study if you’re gonna get, you know, any megawatts out of the other end. It’s one thing they’re trying to figure out, okay, do you have like land controlled? Do you already order equipment? They’re trying to figure out what’s real, kind of what’s not. And Texas is working from SB6, which also forces these developers to say if they’ve got the same project in multiple different areas.

I recently talked to Travis Cavula who had a piece in American affairs where he was talking about, well, we should just like set this up to the highest bidder. It’s basically as like whoever can all the transmission folks get out there and say, Okay, we’ll build this much and then you start bidding that out to the highest bidder, and then you’d really find like you’d only get as much as you can support and then you’d find what it was worth. Is there any movement over there in terms of any of those two approaches or kind of what’s the current thinking?

Josephus Allmond: Yeah, it’s sort of the open season contract that he was discussing at.

Joshua Rhodes: Yeah. Well there’s a couple and there’s like four open season, fronting capital, transmission service agreements and then like BYOG. There’s a few things, but his main one was that open season. Yeah.

Josephus Allmond: Yeah, I’ve talked to Travis quite a bit. He was someone I reached out to first to try and get a handle on some of these PJM issues and just talk to some really smart folks. In Virginia, and I would I haven’t looked at the orders from other states that have like gone down the line of establishing large load tariffs. There’s sort of a structural problem that really is preventing these large loads from going out and doing something like that and bidding, trying to build out their own generation. Because with sort of the take of

or pay requirements that the SEC established. Basically you’ve got to pay 60% of your minimum generation for 14 years. That applies even if you go out as a large load customer and acquire your own capacity to match what you’re bringing online. And so you’ve got a situation where if data centers wanted to go out and provide for their own needs, like we’re seeing from the White House Protection Pledge or calls across the country really for data centers paying their fair share.

they would sort of be paying their own way and then turning around and paying Dominion sixty percent of that minimum generation charge over those fourteen years. And so not quite a double payment, but about a hundred and sixty percent for the energy that you would need normally.

Joshua Rhodes: Yeah. And my understanding is that like if you were doing that and like the utility went out and bought generation to cover that, or, you know, built generation to cover that. And then something happened to the data center, the risk there would be on the remaining ratepayers, right? That’s the big issue, right? Is like these data centers, they’re going out and we’re getting our own stuff, but we’re having to make this other side payment to get more capacity. But that risk is on the rate payer, not the shareholder from like the first round. Is that right?

Josephus Allmond: Yeah. So they’re really insulated from the utility is really insulated from risk there because they’ve got these sacred pay arrangements. And so that’s sort of the worst case scenario, right? Data center show up and that’s sort of put back on the rest of the rate base. The commission did do some things about allowing for sort of transfer capacity and so if that were to happen, maybe they could line up another

you know, large load customer that was in line for them to sort of assume that as opposed to it being socialized. And so I think they’ve done some things to mitigate against that. But yeah, that’s sort of the overall structure here.

Joshua Rhodes: Got it. I mean, that was definitely one of the things Travis was suggesting in that kind of open season that it would be a transferable thing. It’s like, you know, if you get it and then you decide, I don’t want to build my data center or whatever, you can sell that right, which then makes it easier to go out and get the right from the get-go and maybe even drives the cost up because there’s, you know, not as much risk of, you know, if you don’t end up getting what you want and dropping out and losing everything, which is the current way it’s happening in ERCOT, really. It’s like

You know, if you make it into the process and you make it to the third out of five step and decide to drop out, it’s kind of use it or lose it. But anyways, we’ll see kind of where we go from there. So I mentioned the PJM white paper. It kind of laid out three different pathways for PJM, you know, path A, path B, path C. Would you be able to give like a high level overview? Like these potentially could be some pretty major changes for PJM. Like what are they suggesting are some pathways forward here?

Josephus Allmond: Yeah. So path A is really looking to lean more on long term bilateral contracts to secure most of the supply and then the capacity market would sort of be a residual, not as much of an emphasis on it. Path B is what they’re calling sort of differential reliability, and so differing standards of reliability for new loads that are coming to town. Path C is what I’ve thought of as more of the ERCOT.

approach, which is moving more to an energy and ancillary services market with a a really small role for the capacity market to play in the background. So at a high level, those are sort of the three routes that they’ve laid out. They don’t really pick one that they think is the preferred way forward. It’s just sort of a menu of options.

Joshua Rhodes: Got it. Yeah. So Path A is kind of like a cum hedged model. It’s like, if I understand it, it’s like load is procuring that capacity, right? It’s not going necessarily through or as much going through like the centralized, but you’re, you know, the bilateral part there. It’s funny, is like Texas actually considered something like this post winter storm Uri. We called it the man, there were so many acronyms at that point. It was like the load side energy reliability obligation. I I think I butchered that.

I always called it LASO, even though that’s not the acronym. L S E R O or something like that. This is when we were flirting with all kinds of capacity mechanisms, we decided to go with none of Do you think path A would be a practical fix, or is it just shifting risk around from investors to consumers?

Josephus Allmond: Yeah, I think it’s more of the latter and also an issue, especially in Virginia, because of that minimum generation demand charge. And so because you’re asking sort of the loads to come edge, you’d be putting the loads in a position where they would be going out and doing this bilateral contracting, but then still have that requirement back to the utility. And so I imagine the the large loads, especially in Virginia, where a lot of them are located.

aren’t fans of sort of path A, especially with that minimum demand charge hanging over them.

Joshua Rhodes: Yeah, got it. And so path B gets kind of this like this differential path B is this differential reliability. I mean, essentially utilities that kind of had this obligation to serve at the highest levels, say three nines or five nines, you know, nine nine point nine nine nine percent reliability. Is how would path B work out in terms of like when would the reliability suffer here if it needed to be?

Josephus Allmond: Yeah. I think it would be sort of to the extent that they didn’t bring the capacity that they needed. And so they would be curtailed in those sort of peak hours where capacity wasn’t sufficient to serve them. This also I think has a problem, especially in Virginia, because, you know, if you put large loads in Virginia in that position, not many of them are gonna go out and hedge. And so they’re gonna be exposed to this sort of differential.

reliability where they would be curtailed, I would think, more than large loads elsewhere in PJM where they would be more free to contract and secure their own capacity.

Joshua Rhodes: Are you saying path B would be applied differently in different states, just based on kind of what the state level regulatory structure is like?

Josephus Allmond: Yeah. And you see sort of PJM encouraging states to get their cost allocation in order. And I think this applies more to like the deregulated states who haven’t really done this, but sort of in anticipation of this trying to figure out how they’re going to allocate those costs.

Joshua Rhodes: There’s a couple ERCOP parallels in here. One of the things we’re doing in the batch zero process is like we’re potentially only giving large loads like a set amount of offtake. Like say a large load wants to be 300 megawatts, and we say, well, we’ll only give you a hundred megawatts. But if you sign up to be this controllable load resource, it’s a PCLR, during times when the grid’s got capacity, we’ll let you go above that. But like if we ever need to, we might shut you back down to that one hundred.

Or there’s a second pathway, which is kind of a BYOG like pathway where it’s like you can only withdraw or inject a certain amount, like say a hundred megawatts. But if you have a three hundred megawatt data center, then you can bring your own two hundred megawatts of generation and that’s going to be fully kind of behind the system. So I mean, I guess it kind of depends on where you define like that level of reliability. I guess in Texas we’re trying to define it at that point of interconnection where we’re saying we’ll only give you this, but you can do

what you want with your own generation. Is there discussions around that? Like how is behind the meter gener is there behind the meter generation allowed and kind of how is that working out for large loads in the region?

Josephus Allmond: Yeah. So I think it depends on which state you’re in. And so behind the meter gen is allowed. And I think Dominions had sort of a self generation tariff on the books for thirty, forty years that some old manufacturers have used to do their own coal or gas on site. So it is an option at just again, frustrated by that minimum demand charge because even with that on site generation.

Powering your own needs, you’re still on the hook to Dominion, basically for 60% of that generation cost. So at least in Virginia, a lot of these PJM proposals sort of run into roadblocks that weren’t designed as such by our state corporation commission, but just as the way they’re functioning, I don’t think is going to allow large loads in Virginia to participate in these PJM options in the way that they’re envisioning them, which which seems to be more

Tailored towards the deregulated states.

Joshua Rhodes: Okay. So that sounds like a policy issue. I mean o obviously the policy issue. Electricity’s physically the the physics are the same everywhere. Is that something that has any room to wiggle or would that be a pretty tough mountain to climb?

Josephus Allmond: You know, so the SCC established that in their most recent order in the rate case. I don’t think they’re gonna sort of be upsetting that decision. And so there is always the option to affect change through legislation, which would also be difficult just politically speaking, because utilities also have lobbyists at the General Assembly and also trying to protect their interests. And so they see that minimum demand charge as something that protects

the rest of their customers in the event that data centers don’t show up. And so I think there’s some room, but also some discussion I think needed to be had about, okay, if we are going to allow large loads to go and shop, what’s the standard that we’re subjecting them to in the event that they have to come back to the utility? Cause I think that’s a concern that has merit from the utilities. They don’t want to end up in a situation where half of the data center load in their territory goes and

you know, shops and then a big chunk of that all of a sudden decides that they want to come back to utility service, that puts the utility in a tough spot where they’ve got to come up with a bunch of generation or capacity, very short amount of time. We just shortened the notice return window. It used to be five years that you had to give the utility heads up that you were coming back from being a shopper. Now it’s just 18 months. And so

What happens if that large load decides to shop and then wants to come back? Are they sort of subjected to some sort of curtailable schedule like PJM’s considering here? I think that’s something fair to think about. But I think there’s gotta be some trade offs if we’re thinking about sort of unraveling that minimum demand charge, making it easier for large loads to shop. How are we protecting customers in the event that a lot of them come back to the system after a excursion in retail shopping?

Joshua Rhodes: Got it. And if you don’t want to opine on other states in the general vicinity, I think West Virginia is setting up something or like some micro gridding. It’s funny to call them micro grid. These things are massive hundreds of megawatts. But setting aside these kind of special tariffs and things like that for some of these large loads, I think to make it easier is just right across the border. Is that do you think that might pull some data centers over that away or some large loads, I should say?

Josephus Allmond: They’re certainly trying their hardest to pull data centers over there. Yeah, I think there’s a lot of reasons why Virginia has become the pub that it is. And so a lot of that’s the fiber that’s been built out. I question whether West Virginia has some of that infrastructure ready to serve these data centers in a sort of to the extent that they need it, right? That’s something a concern that I hear when we’re, you know, looking to diversify geographically where these data centers are located, even within Virginia.

Once you get out to sort of the southwest corner of the state, your broadband is more sparse, there’s less fiber, even though there’s excess capacity in the APCO system down there, those other factors sort of lead data centers to deciding, maybe this isn’t the right place for me.

Joshua Rhodes: Yeah, totally. I mean, I I think one of the biggest aha moments or whatever I had recently was looking at okay, where is fiber located? And everyone said, Okay, well fiber’s located along we built the fiber optic network in the nineteen seventies around kind of where we had existing rights of ways. And that was where the interstate highways were, which was determined from where we’d be originally built the railroads. You gotta go like, so why are there so many data centers, you know, in Northern Virginia or in Texas, it’s in Dallas.

There’s this huge convergence of all of these much older rights of ways that we had the ability to build this infrastructure and so we did. Which really fascinating. We touched a little bit on like, okay, some policy change, things like that. I mean, I guess you don’t have to opine on this one if you don’t want to either, but I mean, it seems like data centers don’t have that many political friends right now or don’t have that much popular support, I should say. Like there’s a lot of groundswell like kind of opposition. So

As I was asking that question, I’m like, Maybe no one wants to even try to spend any political capital there right now. We’re starting to see that in Texas, but I’m sure that’s happening around the rest of the country too.

Josephus Allmond: Yeah, it’s sort of central to the budget fight that we’ve got here in Virginia. Typically the General Assembly sends the governor a budget and that’s finalized by the end of the General Assembly session. We’re still waiting to get a budget deal done in part because of a difference on what to do about the data center tax exemption. And so Democrats in the Senate here have proposed just eliminating it entirely. I think that comes out to about one point six billion dollars, just eliminating that.

exemption entirely. The governor is not there. And so it’s not just a tax exemption that these data centers have. It’s a tax exemption and then a subsequent memorandum of understanding that they’ve entered into with the state of the Commonwealth of Virginia. And so there’s two sort of categories of this. The sort of lower investment in jobs level gets you an exemption out to twenty thirty five. And then there’s a much higher investment threshold this year.

If you’re bringing $70 billion of investment to Virginia and a higher jobs threshold, you get the exemption out to twenty fifty. To date, Amazon is the only one that has entered into an MOU pursuant to that higher investment threshold, but that was really recently. And so the Commonwealth entered into a contract with Amazon to get them to expend that capital here in Virginia. The governor is really worried about the signal that sends to business if the Commonwealth just decides

one legislative session that we’re going to get rid of tax exemptions that have been long fought and negotiated for. And so as opposed to that sort of more rash approach of just ripping the rug out from under the data center industry, we sort of see an opportunity here to really affect some change in the way that data centers are operating by potentially attaching some conditions to that tax exemption and saying that

Hey, on energy, on water, on backup generators. You’ve got to do some things differently to be able to be in a position to keep that exemption. So that’s actually a big wedge issue that’s sort of holding up the budget here in Virginia. And I’m hoping we can get to a good place with colleagues in the Senate and the House of Delegates here.

Joshua Rhodes: That makes sense. Quickly get to pass C, so there’s a third option or a third pathway in this white paper. It shifts more revenue recovery into energy and ancillary services, but I think it it still kind of keeps the capacity market kind of in there. Is that PJM inching towards like an ERCOP structure or would it be a fundamentally different kind of hybrid model there?

Josephus Allmond: I think it’s a little bit of both. So it’s kind of getting trying to get more like ERCOT is, but keeping a capacity market in a way that ERCOT, as you mentioned earlier, has sort of explicitly decided against. So maybe that’s just a little bit of the organizational inertia and wanting to cling to the capacity market. But, you know, I think energy is already sort of the largest component of the wholesale cost of electricity here. And so moving to this energy only framework probably provides greater

benefit to intermittent resources and limited duration resources, which wouldn’t be bad from our perspective. Getting more solar and storage online. That was a big focus of the governors in the most recent legislative session is really expanding the amount of storage that our law calls for. And so now Dominion is tasked with getting 16 gigawatts of short duration storage over the next 20 years, four gigawatts of long duration storage. And so I think these

more of an energy only approach actually benefits those resources in a way that the current system just doesn’t.

Joshua Rhodes: Yeah, I mean one of the things that like absent the capacity market, if you’re not necessarily chasing a capacity payment or have to show deliverability during time, you can get closer to the thing we do in Texas called connect and manage, where we’re like, we’ll connect a lot of generation and we’ll just like manage it through the dispatch. Generation is mostly a competitive, you know, aspect in ERCOT. And so that shifts that risk to the developer, but it’s one of the things that has allowed us to move much quicker. And so as we’re having these conversations around flexibility, ERCOT has some

institutional inertia on that. Like we’ve got some institutional inertia on be like, okay, we’ll flex you because we’ll have to. And we’re trying to figure out if we can do that with load. I do see that as one of the issues in terms of if you’ve got that capacity kind of payment or that capacity market issue that makes it quite a bit harder. I don’t know, it’s always been weird to me like how you can give like solar in the region like a six percent effective load carrying capacity, but then require full deliverability in the studies. To me that makes no sense. Like that’s something that could be easily done.

very quickly because they don’t even care about capacity, not getting paid for capacity. Am I getting that wrong?

Josephus Allmond: No, I mean like at six percent ELCC, I don’t know, put the question to developers. Like, do you want full deliverability at the six percent capacity value? Are you willing to take the risk of being curtailed at certain times? PJM has this energy resource interconnection service option that they say is sort of similar to connect and manage, but I think when you dig into it, they’re still treating that E risk more akin to how you

traditionally study generators. And so there’s a lot more contingencies in place. And it ends up being almost as much of a headache as sort of going through the full study process. And so streamlining that process and really simplifying it to something that resembles ERCOT’s process more closely, I think would really allow the developers to make that choice. Because right now they look at the E-Ris option in PJM and they say, that’s almost as much work as doing the full study.

Why don’t I just do the full study and I’ll get the six percent, right?

Joshua Rhodes: Yeah, no, totally. I know we’ve talked about that before in different roles. So kinda last question. So if Virginia wants affordable power, data center growth, reliability, clean energy at the same time, like is there anything here that’s gotta give, like speed of load connection, who pays for transmission, tolerance for curtailment, or you know, the old assumption that every customer gets the same, you know, reliability product? Is anything gonna have to give to move quickly as you said, like the Commonwealth needs to move?

Josephus Allmond: Yeah, I think the thing to me that could make the biggest dent is really simplifying that ERIS process and making it something more akin to what you see in ERCOT. Because even with the sort of updates to the interconnection process, PGM’s still projecting almost seven hundred days from getting in line to getting your interconnection agreement. You’ve got another several years for construction after that. And so if we’re really trying to solve this near term

capacity shortfall, we should be trying to get as many resources online as quickly as we can. And so borrowing some of the things that have led to record deployments in Texas, I think is a really smart idea. And so, you know, maybe that involves looking at past C and looking at that option more seriously going forward. But that to me sticks out as one of the sort of biggest things that we could do to really get at this problem in a concrete way.

Joshua Rhodes: Yeah, absolutely. I mean, we’re not perfect and you know, we’re not doing it perfect, but we’re down here trying to figure it out. So like ask us anything, we’ll we’ll try to help out as as as much as we can. Josephus Salman, thanks for coming on the Energy Capital Podcast.

Josephus Allmond: Yeah. Thanks so much for having me, Josh. Good to see you. Absolutely.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy Empower.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, Idea Smith, Austin Energy, or Columbia University. A big thanks to Nate PV, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

Texas spent five years rebuilding its electrical grid based on the lessons of Winter Storm Uri. Now regulators face a harder question: who pays for the surge of large new customers trying to connect?

The projections for electricity demand run far above what will actually get built, and hyperscalers want to power their data centers within 18 months, a pace much faster than the three-to-five years large industrial loads once took. ERCOT has run out of spare capacity, and the cost of building more lands squarely on residential and small-business customers if the projected load never arrives. The state’s answer is to make new load prove its intention and viability to build and pay for the grid it requires.

On this episode of the Energy Capital Podcast, Matt Boms talks with Thomas Gleeson, chairman of the Public Utility Commission of Texas, the regulator who must write the rules to make that principle work. Gleeson’s North Star is SB6, the 2025 law that rewrote how large loads connect. He explains the trade-offs behind the decisions commissioners are weighing, from financial gates that screen speculative projects to a December deadline to overhaul who pays for transmission.

Gleeson returns over and over again to the demand side, arguing that “the megawatt we don’t use is just as important as the megawatt that we generate.” The conversation works through:

* Batch zero, ERCOT’s first round of committing firm capacity and the financial security and fee requirements, recently set at $50,000 per megawatt and meant to screen out projects that are purely speculative.

* 4CP to 12CP, the proposed overhaul of transmission cost allocation, with a minimum demand charge so that large customers cannot zero-out their shares by curtailing at a few predicted peaks.

* The reliability standard, a new three-part measure of how often, how long, and how large an outage Texas will tolerate.

* Demand-side resources, the aggregated distributed energy resource pilot, virtual power plants and a $1.8 billion backup-power program funded through the Texas Energy Fund.

How Gleeson and the commission write these rules will set how much cost current ratepayers must shoulder and which projects ever get built.

Timestamps

* 00:00 - Introduction and Chairman Gleeson’s PUC background

* 00:48 - A new chapter for the Texas grid: from Uri reform to implementation

* 04:19 - The core problem: interconnection capacity and speculative vs. real load

* 08:28 - SB6 and ERCOT’s Batch Zero process

* 15:10 - Large-load ride-through and performance standards

* 19:18 - The reliability standard and load modeling assumptions

* 23:39 - The ADER pilot: lessons and whether to scale it

* 25:01 - Virtual power plants and the NRG proof of concept

* 27:29 - Standardizing DER interconnection across the state

* 29:20 - The backup power package: resilience for critical facilities

* 32:33 - From 4CP to 12CP: reallocating transmission costs

* 39:30 - Closing: taking a breath, and what the era will be remembered for

Resources

People & Organizations

* Matt Boms (LinkedIn)

* Texas Advanced Energy Business Alliance (Website - LinkedIn)

* Thomas Gleeson (PUCT Biography)

* Public Utility Commission of Texas (Website)

* Other Orgs

* ERCOT (Website)

* ADER Pilot Project (Overview)

* Batch Study Process for Large Loads (Overview)

* Texas Energy Fund (PUCT Program Page)

Company & Industry News

* Texas PUC Approves TEF Backup Power Program (RTO Insider)

* ERCOT’s Batch Zero Proposal and What It Means for Large-Load Projects in Texas (Seyfarth)

* ERCOT’s Proposed Batch Zero Process: What Developers Need to Know (Foley & Lardner)

Related Podcasts by Energy Capital

* How Texas Decides Which Data Centers Connect (Tiffany Wu) (Listen)

* How Will Data Centers Pay for Power? (Travis Kavulla) (Listen)

Related Posts by Texas Energy & Power

* How Texas Decides Which Data Centers Connect (Read)

* Price the Grid or Keep Rationing (Read)

Transcript

Matt Boms: Today, we’re very pleased to welcome back Chairman Thomas Gleeson of the Public Utility Commission of Texas. Chairman Gleeson was appointed to the commission and named Chairman by Governor Abbott in January 2024, but his service to the state of Texas goes back much further than that. Over more than 15 years at the PUC, he has served in a number of important leadership roles, including Executive Director, Chief Operating Officer, Director of Finance Administration, and Fiscal Project Manager. That gives him an unusually deep understanding of the agency, the Texas electric market, and the work required to turn major policy decisions into real world implementation. Chairman Gleeson, thank you for your years of service to Texas and welcome back to the Energy Capital Podcast.

Chairman Gleeson: Absolutely. Thank you for that introduction. Looking forward to the discussion.

Matt Boms: Awesome. Well, thank you for your time. We know that you’re really busy. This interview happens in the middle of a million conversations that are happening right now around energy in Texas. We’re gonna try to hit on as many as we can. And you know, just to kind of set this up, Texas is growing fast. The commission is trying to separate real projects from speculative ones, protect existing customers, use flexibility and customer side resources more efficiently. And build a grid that can support economic development without sacrificing reliability or affordability. So I want to start with, you know, since you last came on the podcast and Doug had you on, it feels like the Texas grid conversation has shifted a little bit from post-Uri reforms and market design and broad policy ideas into a very serious implementation phase. So, from your perspective, do you see this as a new chapter for the Texas grid?

Chairman Gleeson: Yeah, I absolutely do. I think you’re right. I think the reforms coming out of Winter Storm Uri, for the most part, have all been implemented. And I think the legislature, the governor, citizens are all happy with the reforms that we’ve put in place. You know, the grid has been tested a few times since Winter Storm Uri and has performed really well. So I think, yeah, the conversation has definitely now shifted to large loads, data centers, hyperscalers, how we’re going to incorporate those reliably and safely onto the grid. And then really, who’s going to pay for it? And I think as we move forward from today onward, who’s gonna pay for all of this is gonna take f you know, primary focus for everybody.

Matt Boms: Yeah, absolutely. And I think Texas has always been a growth state if we look back to our our history. But does this load growth moment feel different to you?

Chairman Gleeson: It feels a lot different. And the main reason for that is the speed at which it’s changing. You know, historically when large loads have come onto the system, it’s taken three, four, five years for those facilities to need their power. When you’re talking about hyperscalers, these companies want power sometimes within eighteen months to be fully operational. So the speed at which we’re being asked to make decisions that impact the economy is going quicker and having a much, you know, more difficult effect on us coming up with the right decisions in a short amount of time.

Matt Boms: And, you know, given all those decisions that need to be made and looking down, you know, over the next few years, what are two or three things that you think Texas absolutely has to get right here moving forward?

Chairman Gleeson: Yeah. So the first part again is who’s going to pay for this? We want economic development in Texas. You know, as the governor says, Texas is open for business, but we want to make sure that residential rate payers and small businesses are not bearing the brunt of all the costs that are going to come along with hyperscalers moving to the state. So I think figuring out how to effectively and efficiently allocate costs to those that are actually putting those costs on the system is going to be the number one thing that we do. Number two, and this will always be an issue coming out of Winter Storm Uri, I think, for for the rest of time for Texas and the ERCOT market. How do we ensure that we’re getting the right resource mix on the grid for generation resources? You know, we continue to see a proliferation of batteries and renewables on the grid, particularly solar. And that’s great for the state. You know, those resources keep prices down. When it comes to batteries and solar, you know, they help us a lot in the winter during our two peaks and the summer during our afternoon peak. But I think there’s a growing concern that we need more what we would consider baseload twenty four by seven generation, mostly thinking about gas generation. And so continuing to have discussions about how we incent that type of generation to come onto the grid, I think will continue to be really important for the state.

Matt Boms: Absolutely. And for listeners who are not living inside of ERCOT stakeholder meetings, that we certainly have listeners that do live inside of those meetings, but plenty of listeners that are new to the energy space. What is the actual problem that Texas is trying to solve here with large loads and data centers? Just for a beginner who is, you know, hearing this for the first time.

Chairman Gleeson: Yeah. So historically the grid has always had a lot of excess capacity. So the transmission system has capacity. A new customer can come and interconnect and not have a problem getting the service that they need. But because of the size of these facilities and the speed at which they are looking to interconnect into the grid, we’ve run out of existing capacity on the system. And so what was happening over the last say six to eight months was large loads were looking to interconnect and not being able to, because as soon as they would have a study validating. Their ability to interconnect, another load would come in behind them at relatively the same point on the grid, thereby invalidating their approval. And so that has been the problem we’ve been trying to solve for, like I said, the last eight or so months, how we can ensure that once these companies have an interconnection agreement that they are ready to move forward, they know that capacity will be there to serve them so that they can make proper business decisions.

Matt Boms: Yeah, if that’s the death spiral of the different pieces moving around, it’s just hard from the grid operator’s perspective, right? It’s how do you plan for a grid where with all those moving pieces?

Chairman Gleeson: Yeah, it’s and how you ensure that all of these loads can be interconnected reliably. Cause I think that is always going to be the key from ERCOT’s point of view is we want the economic development here, but we have to ensure it is paramount that reliability is the focus. And so it’s making sure we can interconnect all of these loads and loads in a reliable fashion. Yep.

Matt Boms: Yeah, for sure. And on reliability, I think Texas has earned a lot of credit across the country for how far we’ve come since Winter Storm Uri. And that’s that’s another podcast. And I encourage folks to check out the previous podcast that you’ve done with us because there’s a lot of good conversation there. But so for considering the load growth that’s coming, how should Texans think about the difference between projected load growth and load that’s actually ready to interconnect?

Chairman Gleeson: Yeah, so the projections are extremely high. And what we know is all of that load will not actually come here. A lot of it is speculative. But what we’re trying to endeavor to do right now is figure out what of that load is actually real. And that’s important for two main reasons that touch on the first two points I made. One, knowing what load is real ensures that we build a system, a transmission grid that meets those needs without overbuilding. You don’t want to overbuild the system to its needs. And because the main reason you don’t want to overbuild is those costs have to be borne by someone. If those loads, those large loads, don’t actually show up, most likely those costs will be borne by residential and small commercial businesses. That’s not an outcome that we want. Secondly, if the load is real, you will see an increase in what we would call wholesale electric prices, the forward markets for those prices. That should provide the incentive for new gas generation and other sources of generation to locate within ERCOT. So as we are approaching the need for more baseload generation, hopefully those future signals will allow those companies to make the business decision to locate those generation resources in the state, ensuring we have enough power for all residents and all businesses in Texas. Yeah.

Matt Boms: You keep mentioning this idea of keeping the grid affordable and reliable for Texans. You’re in this really tricky spot where you want to keep Texas open for major economic development, but still make sure that existing customers aren’t paying for speculative projects or stranded infrastructure, right?

Chairman Gleeson: That’s correct. And so what we’ve tried to do is come up as we look at interconnecting large loads with gating issues and thresholds for those issues that ensure if a project moves forward that it is real because those companies are going to have to put up real money in order to stay in the process to get interconnected. We’re hopeful that those gating issues and thresholds will accomplish that. But as always, as we’ve shown since Winter Storm Uri, if for some reason it’s not accomplishing its goal, we will analyze and iterate to make sure we get the answer right.

Matt Boms: Yeah, fix it on the fly. Right. Yeah. Okay. Well, I’m going to move into batch zero in a second here. But if you’re a large load customer in ERCOT, what do you need to demonstrate before the system starts planning major infrastructure around it?

Chairman Gleeson: Yeah. So the first thing you have to show is that you have the financial wherewithal to actually bring your project to fruition and energize it. So we’ve put in gating issues around the amount of credit that you have to put up that you show you have access to in order to move forward. The second major key element of that is site control. We want to make sure that these companies have an idea of where they’re gonna locate, that they have control over that site. So when they do get the green light to energize, they can move quickly. Because that’s the whole thing here. Once we have a plan. That is actionable. We need to ensure that the plan is being implemented in a way that those companies have certainty they can come here, but we also have certainty that they plan to be here for a long time. Cause again, we don’t want to overbuild this grid putting those costs on others. And so those are the main two things that we’re looking to accomplish that.

Matt Boms: Yep. And I think that leads us into Senate Bill Six, which passed the legislature last year. In plain English, what does SB six try to solve?

Chairman Gleeson: Tries to solve for the proliferation of large loads in this state and how to make sure we bring them online in a managed way. You know, again, post-2023’s legislative session, this was not a topic of discussion. And then probably around October of 2023, this became a hot topic through last session. This was about all we talked about. And so Senate Bill Six is really an attempt to make sure that we have guardrails around the processes we implement to make sure that. No one is harmed by these large loads coming here, but Texas is open for business. We want to ensure that economic development continues to see a pathway to Texas, but that the residents can be assured that they’re not causing these costs, so they will not be on the hook for them.

Matt Boms: Absolutely. Yeah. And there’s a reason right with why the private sector loves coming to Texas to build their project. So we had the batch zero process past the board of directors meeting this week. How does ERCOT’s batch zero proposal fit into this whole SB six implementation phase?

Chairman Gleeson: Yeah, it fits really well because for the first time we’re going to start committing capacity to these large load projects. And so that accomplishes two things. One, it gives certainty to the businesses that if they plan to come here and they can meet all of our gating issues, that once they interconnect, they will get the electricity that they need in order to fully energize in the state. So that is a huge thing. But secondly, it provides a path to ensure that all the loads coming here are real and not speculative. Because the financial gates in order to get into this process are really high, $50,000 per megawatt. And you have to be real, you have to be willing to put that skin in the game in order to move forward. And so I think it really helps ensure that the projects coming here are real. They’re not speculative. And so residents can really have a sense of certainty that we’re not overbuilding, that we’re not doing anything for businesses who don’t actually plan to locate in Texas.

Matt Boms: Right. Yeah. And that and that’s a huge point because that’s not true in other parts of the country as far as, you know, guaranteeing to some of these companies that we will have the energy that they need. And in a quick fashion, because Texas the you know, that’s the hallmark of our state is speed, right? Speed to pass.

Chairman Gleeson: That’s right. And and the other thing that this process does is we will marry this up with our transmission planning process. And so even if a company maybe doesn’t get the power on the rate that it wishes, it there we will have a six-year build-out of transmission that allows that company to know within that six year period, there will be transmission bill to ensure they are fully energized. And so that is a big selling point of this process and for these businesses locating in the state.

Matt Boms: And can you hammer that out for us? So the old approach was more of a one off, right? Where a large customer worked with the transmission provider, the studies would happen project by project, and then things move from there. But why is that no longer enough?

Chairman Gleeson: Yeah, so that was changed maybe a little over a year ago to where now ERCOT has a really, you know, front and center focus on this and they’re involved in that process. And again, previously we had a lot of capacity on the system. So it really wasn’t that big of a deal now because there is no excess capacity on the system. We have to make sure that ERCOT knows where these loads are locating, that they can do an integrated transmission planning process to ensure that they can ultimately provide the services that they need. They work with the transmission companies to ensure that they have what they need to build out the plan within six years. And we think six years is an appropriate amount of time to have all of the transmission upgrades and new builds done in order to energize these types of facilities.

Matt Boms: Right. And six years in the national context is still very fast, right? Even though some of these data centers are looking to interconnect tomorrow.

Chairman Gleeson: That’s right. And it’s a maximum of six years for full deliverability. So the hope is it can be done even quicker.

Matt Boms: So what from the PUC perspective, what does the Commission need from batch zero in order for it to be useful?

Chairman Gleeson: Yeah. So the first thing we need is we need to make sure that the number that gets out of batch zero is something that is actionable. So the idea behind, you know, there are two parts of batch zero, one that we’re calling kind of base, which those companies that get into that bucket, they’re going to get the energy they need on the ramp rate, on the schedule that they that they have requested. Then you’re going to have batch zero studied. Those projects will be a part of the first process to have that six year plan associated with them. To get fully energized. And so the first goal of batch zero, the first really need of it is what comes out of this, the number of projects in megawatts is actionable first within batch zero base, something that can be actionable today. And then within that studied or allocated piece, something that can be actionable with additional transmission upgrades over the next six years.

Matt Boms: Great. So we’re gonna move on from batch zero in a second. Sorry to grill you on. This is just a hot topic and everyone wants to know the details. So last question this would be how do you avoid both mistakes over building for projects that never show up, but also underbuilding for growth that is real?

Chairman Gleeson: Yeah. So, you know, the first thing is getting a better sense of what’s real comes from asking questions to the companies to make sure that they really have an intention to be here. Again, those gating issues around what comes in. But then we do a load forecast and we continue to try to find ways to refine that process to ask the right questions to make sure the numbers in that load forecast are a true reflection of projects that look to locate here in the near and midterm. So I think as we continue to go through those rules and look at what needs to be done to refine that process will accomplish that goal. Cause you’re right, you know, there is always the one that gets talked about the most is overbuilding, but businesses won’t come here if we underbuild. And so we have to ensure that we’re not doing that either because we want these businesses to come here, to come here in a way that is managed and doesn’t hurt reliability. And and in all the conversations I’ve had with these hyperscalers looking to locate here, they are bought in on this idea.

Matt Boms: Okay, that’s great. There’s been a lot of discussion about large loads riding through temporary grid disturbances. I know that’s a major concern from ERCOT, rather than instantly tripping offline. So how should we think about that specific reliability issue in this broad context of

Chairman Gleeson: As you see a continued increase in large loads, I think this becomes a bigger problem. I’m glad ERCOT has looked at addressing this issue. You know, the board approved this action going forward at the last board meeting a few days ago. It’ll now come to the PUC. I will say that there have been some issues brought up around the jurisdiction for URCO to require this of folks. That’ll work its way through some type of litigation potentially. So I don’t want to speak to that. But I think as a as a broad policy goal, it’s a really good goal because we have to ensure that one of these facilities tripping offline does not lead to a cascading blackout on the system. You know, I think the feds that FERC is going to tackle this as well at a national level. But as we’ve seen coming out of Winter Storm Uri and our weatherization efforts, we have the ability in ERCOT to address these issues first before the feds even, you know, take a look at this. So that’s what we’re going to try to do. We’re going to try to solve this problem. And hopefully that’s a model that can then be used and socialized around the country.

Matt Boms: Right. And which again gives us a competitive advantage over other states because we’re able to move so quickly and you know, we’re really the first state to start figuring out these tough questions.

Chairman Gleeson: That’s right. And because we have a very robust stakeholder process, my hope is always that what comes out of that is something that everyone can live with that is actionable and achieves its intended goal. And I think that’s what we’ll find coming out of this discussion as well. Yeah, I agree.

Matt Boms: So the basic principle, if I’m hearing you correctly, is that very large customers need to behave differently than ordinary load because they can affect the bulk system.

Chairman Gleeson: That’s right, because their singular impact or failure causes a much larger problem than it previously has. So we have to ensure that whatever the behavior of that of that facility is, the system is not impaired and cannot recover from it.

Matt Boms: Yeah. So how do you from your position, how do you create performance standards that protect the grid without prescribing one narrow technical design for every data center, every large campus?

Chairman Gleeson: Yeah. So I think what you try to do is be adaptable, right? And we’ve talked about this a lot over the last five years since Winter Storm Uri. The idea that we set a policy goal here, ride through, you know, events, and then work with the stakeholders to come up with a plan that achieves that goal while understanding that most of these facilities are not going to be exactly situated the same way. So allowing for the nuanced differences between these facilities, coming up with a regulatory framework for compliance. That works for everybody. And that’s and that’s what we’ve done here. Again, to the jurisdictional issue, we’ll have to kind of work that out. But I think the policy goal is a good one. And I think the plan that was approved by the ERCOT board is one that is actionable and we can move forward with.

Matt Boms: Yep. And though so for some of these large loads that say that they’re flexible, right? According to whether it’s true or not, this that’s what some large loads are telling us. How important is it that the rules and telemetry and all those incentives actually make that flexibility real?

Chairman Gleeson: It’s extremely important. I think for us to solve this, you know, we talk a lot about building transmission. But I think the other two key components are going to be bringing generation for these facilities to bring their own generation and then allowing for them to be flexible. So they will have those attributes. Like you said, that’s what we’re hearing from a lot of these facilities that they can be flexible. I will say what flexibility means is maybe not always the exact same facility to facility, but allowing that type of behavior to benefit the grid. Is really something that has to be a part of this solution because, you know, most of the time we’re not worried about the reliability of the grid. 99% of the time, the grid has plenty of capacity online. We don’t have an issue with resource adequacy. We don’t have an issue with ride-through issues. But there are going to be those times that we do having loads that are flexible that can react to the real world kind of operational situations on the grid and do that in a way that benefits the state as a whole. Is really something we need to try to find a way to incent and this is just one of those ways. Yep.

Matt Boms: That’s huge. On the reliability issue, we have something here in Texas called the reliability standard. You know, how would you explain that to someone who follows Texas energy issues but may not live in the modeling detail?

Chairman Gleeson: Yeah. So, you know, a reliability standard very colloquially is really a way of saying how often are you okay with the power going out with having some type of system outage? And so previously we had, you know, a measure of that that wasn’t really written in stone, but we were always trying to have a certain level of reserves on the grid. Now we’re doing something completely different. We’ve adopted a three-prong approach to looking at when there is an outage, how long is that outage? How often does it happen in a given year? And then what is the magnitude? Magnitude meaning how many megawatts actually have to be taken offline. And so this three-pronged approach, I think, really gives us a chance to have a holistic view of the system and what we and the citizens of Texas are willing to live with. And then what comes out of that is really simple, hopefully, I’ll say hopefully, is, you know, if we are short of the standard that we’ve selected, then we have options to provide incentives to either bring more generation. Increase flexibility of existing and future loads on the system in order to achieve that reliability standard. But the key here is we will do this on a cost basis. We’ll look at the costs and the benefits of any changes that we make. We have to ensure that the benefits outweigh the costs. We’re never going to put additional costs on the system that don’t achieve the outcomes we’re looking for. So that will be a key as we look to what the outcomes of that reliability standard are and then ultimately what the commission looks to do to achieve our reliability needs. Mm-hmm.

Matt Boms: And the load assumptions there matter so much, right? And how and can you expand on that and how we model out the reliability?

Chairman Gleeson: Yeah. So, you know, if you take the load numbers that have, you know, been talked about, say 410, you know, gigawatts, obviously trying to solve for that type of system is different than say 150 gigs. To your point, it’s very important to understand what the real load number is going to be in 2029. And that determines what the outcomes are and what levers we may have to pull to achieve that level of reliability. And so as we look to the batching process that we were discussing, you know, right now. ERCOT has out for comment two ways to maybe adjust their load forecast. One is kind of looking at history and how much of this load has come on in a given year and using that historical look back. The other, which I would give preference to right now, as I’m sitting here, is to look at what gets into the batch, how many megawatts, because those should be actionable, right? Those are going to be real projects that have a transmission plan around them. So I think solving for that for reliability standard makes a lot of sense, is incongruent. Across all different aspects of the ERCOT planning process.

Matt Boms: Absolutely. And is there a risk that we treat reliability as a supply side problem without looking at the demand side?

Chairman Gleeson: I think there is. I think we tend to think of it as a supply side problem, but I think you’re dead on. You know, there are demand solutions that can help us achieve this because again, the megawatt we don’t use is just as important as the megawatt that we generate. And so I think you have to attack it from both sides.

Matt Boms: Okay. That’s great. The market itself, when you look at the market we have here in Texas, which is robust, how should it value resources that could help during those hours where the grid is most stressed? So whether that could be generation, but it could also be storage, demand response, flexible load, right? Like how how are those tools working in the market?

Chairman Gleeson: Yeah, in kind of the value hierarchy of what we’re doing, those should be valued extremely high. And again, the way that this market is set up is we should put out as the commission and at ERCOT what we’re solving for and then allow the private sector to find a way to meet that need. And that’s what we’re gonna do here as well. So you’re right. We can look at supply side issues. Do we need to change incentives in order for more, say, gas generation to come on? Do we need to look at kind of how batteries are functioning and do we need To look at incentives for more long duration batteries? Do we need to empower residential customers to participate in demand response programs? Do we need to look at our incentives for the in current industrial demand response programs and do those need to be changed? So you have to address it comprehensively, holistically, in order to achieve this outcome because one thing is not going to fix everything.

Matt Boms: We have the ADER pilot here in Texas. So I’m really curious to hear your perspective on what we have learned so far. I mean, obviously there’s a cap on it, so it’s you know, it’s limited in scope, but what are the key lessons learned from your perspective?

Chairman Gleeson: Yeah. So the first thing we’ve learned from our ADER pilot is there is a lot there that we can win on, I think, which is key. That was the goal of the pilot was to see how much participation could we get and really was the juice worth the squeeze? And I think it’s clear coming out of the pilot that the juice is worth the squeeze. The question now is how do you scale it appropriately? Right. And so again, I think the more you can look To these different types of answers to this problem. ADER, distributed energy resources is going to be a big key for this. We just have to figure out the right policies to incent the behavior we’re looking for. You know, we’ve been working for, you know, five years on all these different issues. ADER is one that, you know, I think really needs to be brought more to the forefront and have more oxygen in the room for that type of discussion because it can’t just be bringing on new dispatchable generationly, because we don’t know if we can get prices to a point. To incent that type of behavior. I think the ADER pilot project has shown there’s a lot of desire for this in Texas. We have a lot of private companies looking for how to aggregate distributed energy resources. We should provide them with the incentives to do that and then we all reap the benefits.

Matt Boms: No question. And and there are virtual power plants now that exist outside of the ADER program, right? So I’m hoping you can unpack that for us. The one that comes to mind is the NRG renew home VPP that they’re working on, which they say will reach a gigawatt, you know, in a relatively short amount of time, just working with smart thermostats. So, like what do you see as the future here in ERCOT?

Chairman Gleeson: The best thing about that program is it is it proof of concept, right? And so having NRG, having, you know, the companies that are out there that benefit from this as well, right? Providing those incentives, looking for ways to scale this so that their customers win and they win. Again, then the whole state wins. I think proof of concept is really important. As we look to scale this up, how do we do it in a way that makes sense for the state to achieve the right outcomes? That is a great example of a private company. Looking at that, seeing a risk, but also seeing an opportunity, helping to empower their customers and then their customers and they reap the benefits. So I think the proof of concept of an issue like that is amazing. And I hope that’s something we can build upon going forward.

Matt Boms: That’s great to hear. And this conversation customer side resources, whether it’s backup generators, residential batteries, rooftop solar, smart thermostats, what needs to happen for those resources to provide real grid value at scale? Because to me, it sounds like that conversation, like the ADER pilot, started in 2022, I believe, right? Before this whole data center conversation started. And now we’re in a situation where we could really use every megawatt available on the grid. That might help us alleviate some of the strain that we’re seeing, especially on specific substations where we know if we had some, you know, some distributed batteries around that substation, we would be able to alleviate some of some of the stress. So where do you see those resources playing a role here moving forward?

Chairman Gleeson: Yeah, I think that, you know, as we talk about affordability, they’ll continue to play a really big resource. And I think an ever growing, you know, part of the discussion because the other thing they do is when you get those types of localized generation or demand response programs, it alleviates the need for transmission to be built. And so you’re doing both, right? You’re bringing megawatts onto the grid. You’re also reducing costs by not needing as much transmission. And so with affordability kind of being front of mind and, you know, everything something that everyone is looking to solve for, I think these new types of ideas like distributed energy resources, looking to use batteries in different ways, are going to continue to have to proliferate because we have to have an all of the above mentality when it comes to addressing the issue.

Matt Boms: Yeah. The the question around interconnection, I want to make sure I get that in before we move off of the DER topic. So the most common complaint that I hear from our member companies and from the private sector in general is it’s a very inconsistent interconnection process across the state, right? Because depending on which utility you work with as a DER company, you might have a completely different process for interconnection. Even within one utility, you might get different answers with within that specific TDU. So Do you have any answer to how we solve the interconnection problem here and establish some uniform rule? Because you the companies that I hear from are saying like, We’re just tell us where the goalposts are and we can do it, but like don’t move them around. Just give us some clear structure.

Chairman Gleeson: Yeah, no, I think standardization of the interconnection process is key to this. And what I’ve committed to, and I’ve had a lot of the same discussions, I’m sure you have with the companies. What I’ve committed to is once we have, you know, some of these other issues kind of, you know, in motion or dealt with, we will look at this because again, I think it does have to be a part of the solution. I’ve heard the same frustrations around not knowing company to company, or to your point, even within a company, depending on who you’re talking to, what the rules of the road are. That is Prime for us to have rules around to ensure that there’s standardization that again meets the needs of the companies, but also of the utilities who are looking to ensure that they have full visibility onto what’s going on in their grid, that any type of interconnection is done in a way that doesn’t impair reliability. We can solve for both. And the right venue to do that is through PUC rulemaking. Yep.

Matt Boms: Yeah, completely agree with you. We’ll move off the DER topic, but on the ADER program specifically, is there anything that you would need to see before it moves from a pilot? Like can we just lift off the pilot label at this point or is are we waiting on some final details?

Chairman Gleeson: There’s nothing that I’m looking for. Like I said, I think it has proven really successful. And so my hope is that we can move beyond that and really look to maximize the benefit of a program like that.

Matt Boms: Okay, that’s great to hear. Let’s talk backup power package, which is another one of my favorite topics. So the rule has been approved by the commission, which was great to see. Can you just give us an intro for folks that maybe haven’t been following us closely? What problem is that program designed to solve?

Chairman Gleeson: Yeah, so that’s really coming out of Winter Storm Uri and looking at at critical facilities and allowing for those facilities to have a cost effective way to have backup power to serve their local needs. And so the state allocated $1.8 billion in the Texas Energy Fund to address this. You know, and I had testified to this many times. My thought was and hope that this was going to be the easiest of the programs to actually implement. It has proven not to be so. Because there’s a lot of different ways you can implement a program like this with a lot of different constituencies. We wanted to make sure that we heard from everyone. We heard from engineering firms around what the specifics around a program like this needed to be to ensure it’s achieving the goals the legislature had when they passed the bill. And so we’ve done that. Like you said, the rules have been passed. Looking forward to seeing what we get in so that we can start providing grants out in order to get this backup power on the grid. Cause I think when we do get tight, when there is, you know, another really strong winter storm. I think it is helpful, even though I am secure in my belief that the grid is resilient and can respond to any type of grid you know, any type of weather condition at this point. I think it provides peace of mind knowing that those critical facilities on the grid also can isle in and have backup power just in case something were to happen locally. That’s right. And it’s and it’s one again, the state is willing to partner with those companies because they see the critical need to ensure they have twenty four by seven reliable power.

Matt Boms: It’s a last line of defense for them. Yeah. And so for Texans that are listening to this conversation, how should they think about the difference between resilience for a critical facility, maybe out in rural Texas, versus reliability for the ERCOT system as a whole?

Chairman Gleeson: Yeah. So, you know, I think of reliability as we want to make sure that the grid is reliable at the highest level, that when you turn that power switch on, you can ensure that your lights are going to turn on. Resilience is when there is an event like a Winter Storm Uri, like a winter storm [fern?], like a Hurricane Beryl, honestly, that if something happens that does affect the grid locally, right? Not again at the ERCOT wide level, but a local issue, that those critical facilities that everyone counts on. So think. Wastewater plants, right? We want to make sure that those stay up and are providing the service they need to, that if that a facility like that continues to have power even if there are localized outages that have to be addressed by the transmission distribution utility.

Matt Boms: Great. And longer term on the backup power program, is there a conversation to be had about whether some of the these backup assets at critical facilities could provide some grid value or is that outside of the scope of the program?

Chairman Gleeson: So I think right now I would consider that outside the scope. And all honesty, I think we need to really focus primarily right now on ensuring that power is there in order to serve the local need. But I think long term, again, as you continue to analyze and iterate, I think it’ll be important to see, yes, are there times when those facilities can provide power back to the grid? I just don’t know if the first iteration is the right place for that. Okay.

Matt Boms: Yeah, that makes a lot of sense. And I want to make sure we hit on four CP because we made it this far without without mentioning four C P. It was really one of the major rulemakings that came out of SB6. And maybe you could just lay out, you know, what four CP has done historically on the grid, why it may not be the best solution at this point and where the commission wants to take it from here.

Chairman Gleeson: Yeah. So four CP. So the CP stands for coincident peak. So when you think about these large customers, the way that they get their transmission costs allocated to them is when the grid during the summer months, June, July, August, and September is at its highest usage, what are those facilities using on the grid? And so that’s how we allocate transmission to those facilities, which back, you know, in 2001 made a lot of sense because we were most concerned about reliability at those gross peak times. Now, because of the proliferation really in batteries and solar, during those really gross peaks, the reliability on the grid is really solid because you have people at home running their air conditioners. The reason they’re running them is because it’s hot outside, because the sun’s also, you know, out. And so the behavior there I think has has worked itself out. What we’re trying to do now is ensure that if a company can reduce its its load during those peak times, that they don’t avoid you know, a large portion of their transmission costs. Cause again, those transmission costs have to be paid by someone. Most likely, if those large industrial customers aren’t paying some portion of their costs, those those costs are then being borne either by other industrial facilities that cannot reduce their usage at those times or by residential and small business residential customers and small businesses. And that’s not an outcome we want. We want to try to adhere to cost causation principles as much as possible. So we need to find a way to ensure That those facilities are paying for the transmission that they need. So what Senate Bill Six said is we have to, by the end of this calendar year, pass rules to look at moving away from 4 CP. The commission recently published its proposal for that rule, which included the idea of moving from a 4 CP to a 12 CP model and other things, such as a minimum demand ratchet, so that you couldn’t avoid all or most of your transmission costs.

Matt Boms: Right. And that’s I won’t make you say this. I’ll put it in my own words, which is there is an industry out there around predicting when those peaks will happen and then right the avoiding the cost of transmission essentially. So that’s what we’re trying to solve for here is you know, make sure everyone pays their fair share.

Chairman Gleeson: That’s right. And and you’re trying to solve for two things, right? Because you still want that coincident peak response. You want that demand response because the grid benefits from ensuring at those times of highest peak that of highest usage that those companies can take their facilities offline, therefore, thereby reducing the stress on the grid. But again, if you allow that too often and too easily, then a lot of these costs get shifted to other classes of customers. And that’s something that we don’t want.

Matt Boms: So we’re talking about potentially moving from a four CP to a twelve CP, which would mean if I got this right, the twelve you know, taking the f the intervals out of each of the twelve months of the year and those would be the that’s how those are the coincident peaks that we’re basing the transmission costs on.

Chairman Gleeson: So that’s the current proposal. I think we’ll endeavor through the comments to look at other ways of doing that. You could have 12 peaks, say, you know, kind of floating on the months just in the summer and the winter, if you want. You could look to have them weighted differently. So if we’re looking for more of a response in certain months, you could look to weight them differently. They don’t have to all be say one twelfth of the total. So I think there’s there’s a lot of nuance in that discussion that we have to work through between now and December when these rules finally get adopted. But I think this will be one of the more heavily invested in rules that we pass at the commission this year. And because there’s gonna be a lot of interest in how we do this.

Matt Boms: Yeah, no rest this summer for for any of us, I think.

Chairman Gleeson: That’s right. There’s there’s a lot of money at stake here and so a lot of interest in the outcomes.

Matt Boms: Well, great. And to wrap up the twelve CP conversation, you mentioned the minimum demand charges. So one thing that I’ve been thinking about is you want to keep this tool effective for the grid, right? So if if you’re a data center and you contract 80 megawatts and there’s a minimum demand charge of a hundred percent, then essentially you have no incentive to go down to sixty when the grid really needs it. Right. So how do you balance that as far as the minimum demand charges? You want to make sure the data center’s on the hook for something, but Maybe not all of it.

Chairman Gleeson: That that’s right. And so I think again, we have to look at the comments that come in because, you know, the companies and all the interested parties in this will have the best kind of line of sight on what the different options are. But I think you’re a hundred percent right. We have to balance the need to see coincident peak response to bring down demand with the idea that we can’t have these costs borne by other customer classes. And so there’s a trade-off in that, right? There’s not going to be a solution to this. There’s going to a trade-off when you solve for one thing, you’re also solving for something else and it’s having impacts. You know, as I sit here now and I think about the best way to really think about this, you could have a graduating scale based on size. You could, you know, look at other potential options for how you allocate those costs over the year to help ensure, again, that we’re not providing disincentives to the behavior that we’re looking for. Another thing in all honesty, I think you’re going to start to hear a lot of people talk about is in some of these policies, do we need to start differentiating, say, between a hyperscale large load and electronic large load? And a traditional industrial facility because, you know, historically we’ve done everything based on the amount of load on the system and kind of put everyone in one bucket. But it’s clear to me that your traditional industrial facilities behave differently than these electronic large loads. And so I think it’s time to at least have that conversation in certain policy areas. Does it make sense to have different policies for the different types of large loads?

Matt Boms: Yeah, depending on the behavior of the load, right? That that’s what really

Chairman Gleeson: That’s right. The behavior of the load and what their ability to respond to these types of things is, right? I mean, a Bitcoin miner is different from a hyperscaler, is different from a steel mill or a chemical plant. I think again, having rules that have nuance in them around the different attributes of those facilities is something we really have to start thinking about. Yeah.

Matt Boms: Agree. And I think it’s one of those things where like, you know, two things can be true at the same time. For all the criticism of four C P it still is maybe the most effective tool that ERCOT has right now as far as, you know, how you limit that peak load on a really hot summer day, right? There’s really nothing better than four C P at this point.

Chairman Gleeson: That’s right. And you can actually see when you look at the graphs of usage during those days that the companies assume will be a four C P day, you can actually see usage go down because they’re they’re chasing that interval for for that four C P reduction. And it does. It provides the grid a lot of benefit is the risk again is on the private company, not on the citizens. They chase that four C P interval and we get the benefit multiple times a month of their desire to come offline during those coincident peaks. Yeah.

Matt Boms: Well, we made it through the marathon of rulemakings and all the different topics and thank you so much because I know you got a busy schedule. I’ll let you go. I just want to close with a couple of questions about the future. And with all of the work that’s on your plate right now, like is there one topic where if you had the time and the resources and you could just sit there for a few days and actually create something new or think about things outside the box? Is there like one thing that comes to mind that you would like to spend time on?

Chairman Gleeson: You know, I don’t know if there’s one thing. I think what I would like to spend time on is we have done so much change over the last five years. I would like to be able to take a breath and see how all of these policy changes really work together. I think, you know, as as I think about if you’ve ever heard Bill Flores, the Eurocop board chair, he ends almost every conversation he has with someone with what keeps you up at night. I think if anything keeps me up at night right now, I’m proud of all the work that we’ve done. I just don’t know what the interplay between all the changes is and how that’ll work together. We want to make sure that we’re not adopting policies in one area that counteract a positive impact from a decision in another area. So my my hope is that as we head into the twenty twenty seven legislative session, we get to take a breath, look at all these changes we’ve done, be proud of the work that’s been done, but really take some time to see how they all work together before we look to make any, you know, real significant changes again.

Matt Boms: Yeah. You know, we’ve had previous commissioners and chairmen of the commission the podcast before, folks like Pat Wood have come on, Barry Smithherman. When people look back on this specific period of Texas energy policy, what do you hope that they’ll say?

Chairman Gleeson: That the challenges were great, but we were up to the challenges. I think Texas has always shown a resilience to anything. And I think history will look back upon this period and say they went first on almost everything dealing with electricity in the nation and maybe even in the world. They were up to that challenge. They met it. And then the work that they did was then used to go around the world and make sure that everyone could rise to the challenge. Couldn’t.

Matt Boms: Agree with you more and just so proud to work in a state that can attract all that investment and really meet the moment because again, I think a lot of other states, probably forty nine other states are looking at Texas right now as far as how we meet this specific moment and accommodate all this new demand.

Chairman Gleeson: That’s right. You know, as I go around the state and really the country and talk about everything we’re doing, one thing that I it reminds me of is how far ahead of everyone else we are and having these discussions and coming up with solutions. So yeah, again, my hope is we get this in a place where everyone can look at it and take it elsewhere, implement it, and everyone can be successful.

Matt Boms: Awesome. So we’ll end it there. Thank you so much again, Chairman Gleeson, for coming on the podcast, for your years of service to the state of Texas. It’s a pleasure to have you with us today.

Chairman Gleeson: Absolutely appreciate the opportunity to have the discussion.

Matt Boms: Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make sense of the energy world, share the episode with a friend and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis each week, subscribe to the Texas Energy and Power newsletter at TexasEnergyandPower.com. That’s where you’ll find every episode, every article, and all of our latest updates. We’re also on LinkedIn. X and YouTube, where we post clips, insights, and ongoing commentary. Big thanks to Nate Peavey, our producer. I’m Matt Boms and I’ll see you next time. Stay curious, stay engaged, and let’s keep building a stronger, smarter, energy future.

Right now, connecting a data center to the grid works like Texas hog season: no defined season, no bag limits, first-come-first-served, file as many interconnection requests as you want. Travis Kavulla’s recent essay in American Affairs argues the power industry needs something closer to deer season, with defined rounds, allocation rules, and prices that reflect what grid access actually costs.

The mechanism he favors is an open season, borrowed from interstate gas pipeline regulation. Rather than processing interconnection requests on a rolling basis, a grid operator would design an engineering plan reflecting realistic demand and tender it to the market in a structured bidding process. Winning bidders receive transferable property rights to grid access, comparable to water rights or spectrum licenses, rather than vague regulatory permission that reverts to the grid operator if a project fails. That difference matters for financing: a transferable property right holds residual value even if a data center company does not survive the artificial intelligence boom.

Kavulla has worked as a utility regulator at the Montana Public Service Commission, on market design at California ISO, in policy at R Street, and in regulatory affairs at NRG. He now leads policy at Base Power and teaches at the University of Chicago.

The conversation also covers three other mechanisms:

* Data center prepayments for discrete capital costs are, in Kavulla’s framing, the most direct fix for protecting existing ratepayers. Utilities resist them because prepayments erode the rate base growth that regulated utilities depend on for earnings.

* Transmission service agreements (contracts requiring upfront financial commitment before interconnecting), widely adopted across the eastern United States, rank a distant third. They base the commitment on average embedded rates rather than actual incremental cost, which overcharges some projects and undercharges others.

* Bring your own generation addresses a separate problem: demand growing faster than supply pulls the clearing price higher for all customers. Data centers that source their own capacity or pay for flexibility elsewhere ease that pressure. Utah and West Virginia are among the first states opening pathways for large loads to do this.

On ERCOT, host Joshua Rhodes frames the gap: the batch zero process rations grid access but does not price it. Kavulla affirms the distinction and argues cost-of-service regulation has been stretched past its breaking point. How Texas resolves these issues will shape its next interconnection rules and what current ratepayers carry as load climbs.

Timestamps

* 00:00 - Introduction & Travis Kavulla

* 01:59 - The Essay’s Core Premise

* 03:45 - Open Season: From Hog Season to Deer Season

* 08:07 - What Actually Gets Auctioned

* 09:45 - Data Centers Fronting Capital, and Why Utilities Resist

* 13:37 - Transmission Service Agreements and Their Flaw

* 17:41 - Do Data Centers Raise or Lower Rates?

* 22:55 - The ComEd and Dominion Problem

* 25:14 - Bring Your Own Generation

* 26:53 - Reforming Monopoly States: Utah and West Virginia

* 30:51 - Batch Zero vs. Open Season in ERCOT

* 35:43 - ERCOT’s Flexibility Tools and Speed to Power

* 42:08 - Which Idea Has the Best Shot

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Travis Kavulla (LinkedIn)

* Base Power Company (Website)

* American Affairs (Author page)

* Energy Capital (Website - LinkedIn - YouTube)

* Texas Energy & Power (Substack)

The Essay at the Center of This Episode

* How Will Data Centers Pay for Power? — Travis Kavulla, American Affairs (the essay this conversation is built around)

Studies, Cases & References Discussed

* Factors Influencing Recent Trends in Retail Electricity Prices — the Lawrence Berkeley National Lab / Brattle study on load growth and rates, explained by a Brattle researcher (the North Dakota “headroom” finding Kavulla references)

* FERC Rejects the Amazon–Talen Co-location Agreement at Susquehanna — the co-location dispute Kavulla cites

* FERC Upholds the Amazon–Talen Rejection on Rehearing — the March 2026 follow-up

* Kavulla Outlines His Data Center Interconnection Proposals — RTO Insider coverage summarizing the open season, prepayment, TSA, and BYOG ideas

Related Energy Capital Episodes

* How Texas Decides Which Data Centers to Connect — Tiffany Wu on ERCOT’s Batch Zero process

* Who Pays for the New Grid with Pablo Vegas — ERCOT’s CEO on load growth and who pays

* Texas Growth Is Running Into Power Grid Limits with Katie Coleman — large load interconnection and cost allocation

Transcript

Joshua Rhodes: Hey everyone and welcome to another episode of the Energy Capital Podcast. I’m really excited to have Travis Kavulla here to talk about an essay that he recently wrote in American Affairs, where he’s the energy editor about how data centers will pay for power. It’s a really hot topic right now, and I’m excited to dig into that and how it kind of ties in to what ERCOT is doing for data centers. Before that, if you’re in the energy nerd space like you would be if you were listening to this podcast, you probably know Travis already, but He’s got a pretty impressive background that I’m going to go ahead and go through now. So Travis went straight from Harvard to the University of Cambridge, which I found funny that you went from one Cambridge to another, I guess. I guess that was easy for the well, I guess postcard you’re going from Massachusetts to the UK, but still.

Travis Kavulla: The imitator to the original.

Joshua Rhodes: Yeah, fair enough. Should I call this New Cambridge? But that’s not a thing. That’s not what we call those. Anyways. After that, you spent some time in the media with National Review and some freelance work in the UK, East Africa, and the US. But then I did not go back and look to see what you wrote for National Review. But at this point it looks like you kind of pivoted into energy and in particular the regulatory space around energy, which is what we’re gonna talk about today. But you started out as a board member for the Western Electricity Coordinating Council before becoming a commissioner at the Montana Public Service Commission, then jumping over to California to work on the energy and balance market with CAISO, the California independent system operator. Then going to R Street, where you’re the director of energy and environmental policy. And then I think your longest period of time, and probably most people know you as the VP of regulatory affairs at NRG. NRG is big in Texas, and so that brought you into Texas quite a bit. And so we were very happy to have you here. Currently a lecturer at the University of Chicago and the head of policy at Base Power, also based in Texas and Austin actually, Travis Kavulla. Welcome to the Energy Capital Podcast.

Travis Kavulla: Thank you for having me, Josh. Great to be here.

Joshua Rhodes: Yeah, so we wanted to bring in and talk about this essay where you’re talking about of how data centers should pay for power. And really this essay, we’ll link to it in the show notes. It’s brilliant. And I think it’s getting read pretty widely, including I saw on LinkedIn from FERC Commissioner David Rosner. So that’s great. One thing I was gonna say when I was going through your list of things is that I’ve already put my money in Polymarket that one day you’ll be a FERC commissioner. So I don’t know. It’s a pretty good bet right now. Just kidding. Not not the case. But at least your work’s getting read by them, so that’s great. So and I’ll go ahead and try to lay out the premise of your essay, and you can tell me where I get this wrong. But essentially, it’s like that the US should stop treating hyperscale data centers demand as just another low class to be included inside traditional utility rate making, with a core idea that scarce grid access should be explicitly allocated and priced, and new data center loads should pay its incremental cost, and that new generation, the bring your own generation, should be essentially required. Other than, you know, socialize through the utility rates. Did I get that roughly right?

Travis Kavulla: You got it down and you didn’t even need ten thousand words, Josh. Yeah. I mean the basic premise here is that the typical utility business model, which involves estimating what load is going to be on the system in the future and beginning to make capital outlays in advance of that load showing up in a lack of knowledge about whether it will appear, is not a good fit, given the amount of uncertainty over which loads are going to show up, or in terms of cost allocation when you have obviously an inflationary price environment. Where serving the next unit of demand is so costly. So it’s compounding risk and costs that need to be better tied back to the future users of the system. That’s the fundamental insight.

Joshua Rhodes: That totally makes sense. I mean, you know, I’ve been steeped in ERCOT for a long time and I haven’t believed these large load numbers for years, right? And they just keep getting bigger and bigger and bigger and bigger. And I know in other regions that we’ll get to like PJM are also, you know, experiencing these large increases. And so one of the things you do is you kind of argue for a few different ways around if we’re going to try to connect as many of these large loads as possible, you argue around a few different concepts. One of them is like an open season for access. And I just wanted to translate this into Texas Speak just for the audience. So open season. So right now it feels like that connecting large loads is kind of like hog season, where there is no season. And it’s just anyone all the time, as much as you can, please, like first come, first serve, whatever. But kind of moving more to like a deer season, where there’s an actual like defined season and bag limits in terms of you can’t have all of them, you can only have a certain amount of them. Did I get that right?

Travis Kavulla: That’s right. Yeah. I’m from Montana and I’m trying to think of the parallel to hogs. I’m glad we’re not cursed by that particular infestation up where I’m from. But that’s right. Having a defined process and season where people both put in requests, and then I guess if we’re going to layer on another hunting metaphor, it’s sort of like how certain jurisdictions reserve a few out of state licenses that can be auctioned off or paid for by a premium to the hunting authority. Well, normal users of the hunt, people who are lucky enough to have a Texas driver’s license, operate by a somewhat different set of rules.

Joshua Rhodes: That makes sense. And so that’s kind of your like your preferred method. So could you talk through kind of how that might look in practice? Like how might that be set up? Let’s just take a step back and kind of talk about what is the problem it’s trying to solve. Like why do we need an open season for grid allocation right now?

Travis Kavulla: Yeah. So right now the power grid, both on the large load side and the generator side, works on kind of a first come, first served basis. And if you want to interconnect a new data center or develop a new power plant, you file an interconnection request and you take a spot in line. And the people who file these requests realize that there’s a lot of uncertainty involved about whether the project will ever get developed. There’s a lot of uncertainty about the price will be quoted to interconnect to the system. And in view of those uncertainties, you begin filing more and more and more requests, hoping that one or two of them pan out. And it leads to this sort of gold rush mentality, which is where we are today, with interconnection queues that express way more demand and way more power generation than are ever realistically going to be connected to the grid. So an alternative approach is an open season. They’re used actually in the natural gas pipeline industry. Okay. And there, you know, the pipelines will assess the amount of incremental interest in shipping gas on pipelines that exists in the market. They’ll then take back those informal expressions of interest and they’ll take it upon themselves to design an engineering plan, you know, which sort of reflects their best judgment of the actual demand that can be served within a reasonable amount of time, within a reasonable amount. Of capacity expansion. And then they tender that plan back out to the participating public, the market participants, in what is called an open season. And it’s left to their bidding behavior to determine whether or not the pipeline is going to have adequate revenues or more to the point, what kind of optimal configuration of off takers results in the highest net present value relative to the project’s costs. And then that configuration is the thing that subscribes the pipeline. So it’s a process by which you both efficiently size an expansion of a grid as well as creating a cost allocation mechanism to pay for it in one fell swoop. But think of it as a utility planning exercise that’s subject to a strong market based check.

Joshua Rhodes: Okay. Sticking with the natural gas side of things, is that more in the interstate pipelines? In Texas we’re always having to distinguish between interstate and intrastate because there’s wildly different, shall I say, regulatory constructs that govern those two. So where is that happening?

Travis Kavulla: There are, and this is what I’m describing as the FERC procedures for interstate gas pipelines. Though certain intrastate uses them as well, as well as facilities like gas storage.

Joshua Rhodes: Okay. So in your ideal design for an open season, in the electricity sector, can you tell me what is the actual unit that is being sold or auctioned? Like what is interconnection priority, withdrawal rights, substation capacity, transmission upgrade rights? What is the actual thing that would be auctioned off?

Travis Kavulla: Here, what I have in mind and subject to permutations would be a denominated quantity of withdrawal that you would be able to say, Listen, I participate in this open season, and as a result of my successful bid, I have the ability to withdraw four hundred megawatts of power at or about this location. But it ties closely together to the concept of interconnection priority as well. Because with an optimal plan in mind, it becomes the sort of engineering and construction plan basis on which the utility proceeds. And an important part of the economic logic is defining the likely timing of utility infrastructure’s construction in order to facilitate the bidding process.

Joshua Rhodes: Okay. There’s a lot of parallels here to kind of the ERCOT batch zero process and other types of things, which I’m hoping to get to a little bit later, although there’s differences here. I just want to put a mental pin in that to come back. ‘Cause there’s like roughly four mechanisms that you talked about. So there’s open season, kind of an auction based process. It sounds like a point of interconnection size, right? Yeah. It means like I can take this much, maybe I can also push that much. I don’t know. There’s permutations, like you said. The second I don’t know if it’s second best or if there’s really an order, but like the data centers would front capital to build this stuff. But utilities might be resistant against that. Why would that be the case?

Travis Kavulla: Yeah, so you’re right. The second one I propose in the essay, the second approach to paying for incremental grid costs is just a data center which knows enough to flash a wallet to raise their hand and say, Listen, you know, utility, you’ve studied my interconnection. You’ve estimated it’ll be these three facilities that need to be constructed at a cost of three hundred million dollars. We, the data center, and maybe even you, the utility, think there are probably some spillover benefits to other customers of the grid by virtue of you constructing those. But nevertheless, we’re just going to offer to prepay that amount of money. And you know, utilities don’t like this candidly because the utility business model since the industry’s inception in the United States at least has been really a spend more, make more type of business model. I mean, we’re all familiar with the fact that TND utilities are, you know, legally instituted monopolies, but that’s sort of a short way of expressing what they really have and really want a monopoly on. Which is the opportunity to invest capital in their system to the exclusion of others because it is those capital expenditure opportunities that create the so-called rate base on which utilities earn a return. And if you have customers prepaying for capital expenditures the utility would make, that actually erodes their opportunities for earnings growth, which for them is a bad thing. I mean, any other business in the American economy would be tickled pink. At their customers saying to them, listen, we just want you to write a check right now to pay for all of the capital needs that you’re going to incur to serve us. But in the bizarre world of utility incentives, that incentive is exactly the opposite in utilities. So in order to make this work politically, it might not be, even though it is sort of the first best in terms of protecting other customers, I would say it may be necessary to continue to allow utilities to have that investment opportunity. Nevertheless measure the discrete incremental costs and then convert those costs into some kind of data center specific facility charge that they would pay as well. So I note, you know, there’s a proposal that Microsoft put in front of the Public Utilities Commission of Nevada that kind of closely tracks this idea. It just coincidentally kind of came out the week after I wrote my essay. But I think those guys have sort of an inspired approach. The the trade-off here is that in an open season In a data center rich environment like ERCOT, you know, you would be able to actually plan efficiencies and economies of scale around infrastructure build. So the prepayment approach probably makes more sense in jurisdictions like Nevada, where it’s in all likelihood ones, two Z ad hoc stuff, as opposed to larger utility systems that are seeing a ton of data center development and which should be planned for more jointly.

Joshua Rhodes: Yeah. And this is probably gonna show my ignorance when it comes to more kind of regulated entities. One of the things that popped into my head is like in this kind of front end capital, the if the utility wants to spend CapEx because it make a regulated rate of return and that’s what they’re going after, I mean, could the data center offer like a zero percent loan to them such that then they could spin the money, get the regulated rate of return, and then does that math even math?

Travis Kavulla: Well, usually, I mean, the issue right is that these are cost of service regulated industries. And usually if the utility accesses a loan at a particular stated interest rate, then the regulator will use that for the purposes of rate making. Uh-huh. I mean, the utility, if it is going to invest its capital, should raise capital in a economically efficient way and try to tie off the cost and risk of that financing facility to the particular customer it’s spending on behalf of, but All of this conversation ties back to the kind of Looney Tunes way we regulate the utility industry in this country, which is cost of service, which spawns a bunch of weird incentives, including this one.

Joshua Rhodes: You already mentioned the Microsoft deal, which I assume they were inspired by your essay since it came out after. But in my head, that was more around like kind of the third thing, the the transmission service agreement. I was actually having a little bit of difficulty kind of pulling these two apart. So what’s the difference in the fronting capital versus like the third argument there, the transmission service agreement? I know you’ve been critical of a bunch of them, but maybe there’s one or two that are popping up that look all right to you.

Travis Kavulla: Yeah. So the Transmission Service Agreement is something that utilities in the eastern United States have been prolifically using. And basically there, it’s a way to get data centers to pay up big table stakes before they’re interconnected to the grid. So it does, like the other two, it eliminates some of the gold rush that has occurred on load interconnection queue. It’s big failing, I think, is that TSAs to date. Have all been based on the kind of backward looking average embedded transmission rate. And so let’s imagine that I build a data center on an electrically robust brownfield, maybe where a big industry has, you know, retired a manufacturing plant and which may not need a lot of capital upgrades to the transmission system. I mean it’s, you know, 500 megawatt data center. And then imagine I build the same 500 megawatt data center. In a green field, that requires hundreds and hundreds of millions of dollars of utility infrastructure spending to accommodate. Under a TSA arrangement, I would be quoted the same take or pay collateral requirement for either of those projects. It’s tied, in other words, to the size of my project and not to the actual incremental cost to the utility to serve that project. So it fulfills one ambition, which is winnowing out kind of wheat from the chaff. Yeah. But it fails to send an efficient price signal. And it may not be adequate in the case of all projects to guarantee a sufficient amount of revenue to actually cover the incremental cost of the build. So I’d put it in a pretty distant third place, but it’s better than nothing. It’s better than returning to the status quo ante, where utilities are just outlaying capital based on pure speculation about where we’re going and not expecting anything. Upfront in the form of commitments from data centers to take service from the grid.

Joshua Rhodes: No, that makes sense. I mean, I’ve historically when I was looking in other areas, I think correct me if I’m wrong, one of the first take or pay kind of contracts, it’s kind of similar here, I think, was in Ohio around data centers. And it sounded good to me, I guess, until I read your essay where you talked about how I guess the problem there is they’re using these average embedded rates, like they’re historical looking, but it looks like the future is gonna be different than the past. So can you explain like how would looking to the past for this in the current day and age not be adequate? I guess. Can pull that thread a little bit further.

Travis Kavulla: Right. Yeah. It’s really as simple as the fact that the cost of service implied by the rates you pay today is all based on infrastructure that was costed out over the past several decades. And that infrastructure costs less than new infrastructure does today. It might not be the case if we were not in an environment where poles and wires and switch gear and copper and everything else weren’t rapidly inflating in price. But that is where we are. There’s a lot of macroeconomic inflation. There’s even more inflation in this sector, specifically because of the demand growth and the inability of supply chains across the sector to keep pace. And so when you have people pay an average embedded cost rate for the service, you’re not actually acknowledging the trend that building something new is more expensive than, you know, the thing you own free and clear. And at a basic consumer level, you could. Extrapolate this. But most people, most businesses, you know, wanna make use of capital assets as long as they can because they realize the new thing that they turn around and have to buy is, you know, going to cost a lot more money.

Joshua Rhodes: Yeah, which is I mean, I think this brings us to there’s been a lot of studies that have been coming out recently about the impact of large loads and data centers and particularly on electricity rates. I remember about a year or a year and a half ago or something, like it was in the span of one week I got contacted about being a part of like three or four of like these large I mean, everybody was trying to figure out what is gonna be the impact, what is gonna be the impact, what is gonna be the impact. You know, it really depends on, you know, where you’re drawing the box around that. You know, there’s a Berkeley lab study showing low growth can sometimes reduce prices when they point to places like North Dakota and places that had headroom to move into, and you’re increasing utilization rates and that can, you know, reduce the per unit cost. And then you’ve got VJM’s market monitor saying, you know, the data center low is materially increasing, you know, capacity auction revenues and other other types of things. So it’s like, is everybody right or is everybody wrong?

Travis Kavulla: Yeah. Both of those things can be correct, right? And in the essay I try to separate the industry into two parts, you know, sort of the regulated grid costs that are still cost service price regulated by utility commissions, and then the more commoditized supply of power that works on the basis of marginal cost pricing in economics. And to just spend a moment to talk about each of those, I mean the regulated grid costs, it’s a pretty simple division problem, right? The utility sector typically has a bunch of fixed costs of infrastructure divided by the amount of throughput on that system. And that division problem spits out a quotient, which is the rate that you pay. Right. Now, if you have a lot of headroom in a system and you can fit additional volumes into the denominator without triggering a growth in the fixed cost numerator, then rates will go down. Right. Right. And that’s exactly what happened in North Dakota. In that Lawrence Berkeley lab study, which is really good. But you need the conditions present that allowed that to happen in North Dakota, which had been overbuilt infrastructure from a previous oil boom. And so you could end up fitting a lot of megawatts, a lot of new megawatts under the hood of that earlier vintage capital spending. And meanwhile, on the commodity side for power generation, it is what the market monitor in PJM says, which is that. If demand rises more quickly than supply, then the kind of classic curves of where the supply and demand intercept point occurs is going to shift to the right. It’s going to end up using more expensive supply in order to furnish power to the grid. And in commodity markets, and specifically in electricity markets that are governed by sort of a logic of uniform clearing price, that last megawatt. Needed the most extensive megawatt needed to serve incremental supply is the thing that the price equilibrates around. And that’s the same in gasoline, in eggs, in other commodities. And so until supply catches up with demand, you end up exposing everyone to higher priced supply costs on the commodity side, which gets into the other recommendation of the paper, which is bring your own generation, a requirement. Basically that new loads furnish additional capacity to try to reestablish the equilibrium in the commodity market.

Joshua Rhodes: Yeah, so I want to get to BYOG here in a second. There’s a couple I want to camp out here for just another question or two. You know, one of the strongest official critique of the current TSAs, maybe that Commissioner Judy Chang’s warning that Commands agreements will can still roll these transmission upgrade costs into formula rates for everyone else. If they have these transmission service agreements, like how is it getting snuck in, I guess? We kind of talked about in embedded rates and other types. Is that just what it is? Like how can they still get kind of sucked in here?

Travis Kavulla: Yeah, in I mean, in a very literal way, when a utility in PJM goes to build out new infrastructure to serve data centers or anyone else for that matter, that infrastructure just goes right into its rate base, the costs of it. Yeah. And that rate base, you know, is broadly socialized to the consuming public. And utilities that have adopted TSAs are simply hoping that the incremental revenue pledged, but based on the kind of socialized average rate from a new data center will be adequate to defray the cost and the risk of the incremental capital spending. And the record that Commissioner Chang is sort of referring to out of Commonwealth Edison, Illinois’ large load tariff, contains a lot of data that suggests that half of data center projects probably impose incremental cost requirements that well exceed the revenue that’s pledged out of a TSA. And half of the projects actually are located in places where the utility wouldn’t have to build out as much incremental infrastructure. And there the TSA probably overcollateralizes the obligation from the data center. Whereas a TSA or a prepayment arrangement that was predicated on tying off the incremental cost of capital spending to particular data centers is a more elegant way of dealing with this particular problem.

Joshua Rhodes: You also mentioned Dominion’s Virginia’s Dominion structure. Like, you know, you kind of criticize it for using kind of these embedded cost issues. Like, is there anything different between, you know, Comed and what’s going on in Dominion?

Travis Kavulla: It’s very similar. And the one difference is that Dominion is not a fully restructured utility like Comed is. Comed doesn’t have a role in furnishing supply to customers. So Dominion has taken the TSA idea and tried to extend it to power generation. And basically says, listen, there’s going to be a take or pay arrangement where data centers at sixty percent minimum of their contracted load has to furnish revenue associated with the prevailing generation rate that we charge all of our customers. And that actually is even more problematic than doing it on the transmission side, I think, because candidly it would be easier to tie off incremental capital additions on the supply side to incremental causers of the cost. There’s one other thing that is a real bother about Dominion, and I talk about it extensively in the essay, but I won’t get into it here. Virginia Is an interesting market in the sense that it has some degree of retail competition where large users of the system can select a third-party provider to provide them power. Yeah. In what Dominion has proposed, and the Virginia Commission approved it, any customer taking service in the Dominion service territory would have to pay this toll to them for generation costs. Even if you’re being provided power capacity and supply by a completely different third party. You would also have to pay this VIG to Dominion. So ironically, in the name of customer protection, they’ve actually used it as an opportunity to re-monopolize their system. And they’re basically saying, hey, in the name of consumer protection, we’re going to be the ones to serve every megawatt hour of demand needs related to the data center. Whereas ironically, the easier way to protect consumers would be to insist that third-party suppliers who don’t have a captive ratepayer base. To backstop their business deals instead would be the people serving them. So again, it’s topsy turvy in D in Virginia and Dominion, and I don’t think they’ve landed in a particularly good place, despite many advertisements to the contrary.

Joshua Rhodes: Okay. So that kind of brings us o we’ve been dancing around BYOG, bring your own generation here for a little bit. That’s the fourth thing you kinda bring up in the essay. Tell me what you mean by bring your own generation. I mean I maybe it seems obvious, but tell me what you mean by it and then why is it not possible currently in a lot of places?

Travis Kavulla: Yeah, it really is pretty straightforward. If I’m a one hundred megawatt firm demand in a new data center, I should be furnishing the system with a hundred megawatts of capacity that has energy production roughly matched to my load factor or consumption of energy. And my doing that both promotes investment and generation in a time of uncertainty around generation investment opportunities. And it also is re-establishes that equilibrium we were talking about. And, you know, this ordinarily is one of those things that would not be a good idea. We would expect and want commodities to trade in a homogeneous way, in an undifferentiated way. But I think circumstances have kind of overcome that moment. And you can look to the PJM market, which operates a capacity market, where, you know, the cost of new entry clearly exceeds the price cap. Now in the capacity market. And so the design of that market has made it a foregone conclusion that new capacity is going to have to be added to the system if it is needed through something other than this normal market. Not that the capacity market is particularly normal, but that kind of all signs then point in the direction of bring your own generation, bring your own capacity, call it what you will, in order to solve that problem.

Joshua Rhodes: Again, this is going to be a bit dangerous. I’m always down in, you know, steeped in Texas. And so getting into, you know, more regulated areas is always dangerous for me. But in a monopoly supplied state, what’s the minimum legal reform needed for that? In my head, my brilliant idea was what if we just do a reverse PURPA? Right. Whereas like if you can generators of a certain size or a certain size or below, if they can come in below the utility’s cost of service, like the utility has to buy the power from them. If a third party generator could come in at lower than the cost of the utility, like what if the data center could take that power instead? It’s kind of a reverse concept. Does that even make any sense whatsoever?

Travis Kavulla: Yeah, I’d have to think about that one more, Josh. It’s an interesting idea. And utilities, vertically integrated utilities, should be open to third party procurements, especially if those third parties end up bearing, you know, the development risk and the risk of their projects, you know, being in or out of the money relative to the market. I would say what I’m proposing here is almost more simple, which is in a majority of states today, I as a customer am literally forbidden from buying power generation from a third-party supplier. I have to go through the utility. And that utility will tend to serve me out of sort of an undifferentiated system of power generation assets at these sort of average embedded cost rates. So a way of getting it right for new large loads is not only to expect them to kind of offset the incremental costs of generation to supply them, but require them to do so. And it is probably simplest, or if not simplest, then at least sort of the most attractive on a policy basis to have some kind of modest opening of retail competition in some of those states to facilitate that happening. And there have been a couple of states kind of dipping their toes in that water lately.

Joshua Rhodes: Yeah, and I mean, I want to ask about Utah and and West Virginia. I know there are some states that have they may not have full retail competition for every single rate class, but some have for commercial, not residential, other places like that. And so maybe there are some avenues there. But it does seem like there are some cracks kind of forming in that towards the BYOG. Utah is allowing large loads to contract with large scale generation providers. West Virginia, just next to Virginia, has some micro grid, which is kind of funny to call these data centers microgrids because, you know, they’re the size of some macro grids, here nor there, but some framework that carves out these special service pathways. So are we squeezing the balloon and this is where it’s kind of popping out here and like in other places? What do you think about these approaches for these states?

Travis Kavulla: I think they’re great approaches. And you know, this is a new topic for a lot of these states. So the state laws that we’ve seen written about this are not necessarily the most elegant. They’ll need some redoes and iterations. It’s a step in the right direction. And again, what’s really at stake is do you really want your regulated utility with obligations serving legacy customers and their balance sheet to be used chasing data center load? Or as a first principle. Do you expect data centers to come up with their own deals with third party providers and have the costs and risks of those deals exist wholly within those contractual relationships between two parties that do not have a captive customer base to use as a plaything to chase data center growth? So I think that’s kind of what’s happening. You do see electric cooperatives and smaller utilities. Be pretty positive on this stuff because they don’t want that stuff on their balance sheet, right? They realize that it’s a big risk to try to serve a data center that might be as big as the rest of your customer base, but they don’t want to get in the way and they’re happy to facilitate grid service to those entities. But they are the people who are kind of at the vanguard of expecting BYOG as a requirement just because they don’t want to have much to do with that side of the business, which comes with its own set of risks.

Joshua Rhodes: Yeah, no, totally. I mean, co ops in particular, I think a lot of them are member owned. And so it’s like if you end up in impacting like the rest of the rate base, you probably know them or see them at the corner at the diner or whatever. Okay. I want to bring this back to Texas. This is the Energy Capital Podcast. This is like steeped kind of in Texas. And we’re talking about paying for data centers. We’re talking about allocation of infrastructure. I mean, Texas is also going through this process, right? And I’m very actively going through this process. And by now I’ve had at least one, maybe two podcasts have come out. By the time this one drops on ERCOT’s batch zero process. And so there’s a bit of a difference here. Batch zero is kind of like this large load backlog triage system. You know, while your open season is more of an economic allocation system, they converge on rationing, but they’re diverging on price formation. Should ERCOT be open to doing? I think the batch zero is just trying to fix like a big problem right now that we’ve got. But a batch zero indicates maybe there’s gonna be a batch one, batch two. Batch three, batch next, I don’t know what we’ll call it. Should ERCOT consider doing this open season process instead?

Travis Kavulla: They certainly should. I think a lot of the stakeholder conversations that have existed in the context of the batch zero process almost gesture to why they should. Okay. Because most of the lobbying that I’ve seen around batch zero has been people trying to get into batch zero. Okay. Yeah. By having administrative criteria drawn just so that includes them on the right side of the line to get into the batch and excludes others. And that unfortunately, you know. If only there were a social science that used pricing to try to make those determinations rather than the judgment of RTO bureaucrats about project readiness. I mean, having more of an economic signal for conferring interconnection rights gets RTOs out of the game of deciding who’s more ready than the other people in order to get into the batch. There’s arbitrariness in all of these designs, but Judgments about project readiness are historically have been easy to game and are really difficult to do well in terms of where to draw the line. That being said, I’m very sympathetic with the problem that ERCOT faces and sort of like the other con sort of like the discussion about TSAs, going from a first in line, first and right ad hoc process, gold rush type of thing, to actually trying to group projects into batches. Is a positive incremental reform. I just don’t know if it is meets the moment given what we’re seeing on the grid.

Joshua Rhodes: Yeah, no, I mean it seems like they’re calling it this transitional thing. It’s like, you know, we went from the first come, first serve. There’s some folks that were already in that process. I also like, you know, sympathetic towards like it’s a big, sticky process. There’s trillions of dollars at risk here. I don’t know, whatever we’re valuing all the tokens are or at. And that’s always been the hard thing for me to figure out. So what are the gating criteria? What are the inclusion criteria? And then there’s gating criteria. But my understanding of the way the batch zero process is if you don’t meet The inclusion criteria, you’re not included. And then if you don’t like the allocation you get after the first study, then you’re just kind of dropped out of the system and you forego like 80% of like the cost you paid to get into the whole process. And so it’s kind of like use it or lose it. But I believe one of the concepts you have for open season is that you could sell that right. You could sell that place. Like it’s place in the queue or what it’s a place in the batch, but you could transfer that if you needed to. Is that right?

Travis Kavulla: Yeah, that’s right. I mean, the benefit of an open season, I think, is that it really does confer an actual property right to the use of a public network. Yeah. And in that sense, it’s sort of like a water right or shippers’ rights on natural gas pipelines or the people who buy spectrum out of the FCC’s electromagnetic spectrum auctions. And that’s valuable because ultimately in all technological revolutions, right, we see a lot of also rans like. Everyone and their grandpa wants to be AI and a data center company. And a lot of these people are not going to be around at the end of the day. Even a lot of the big names might not be around at the end of the day. Yeah. And so actually having a property right that in the event of a business model going away, in the event of a default, can be residual value to the estate makes everything a lot more financeable. And that differs that kind of right. Differs from simply having like vague regulatory permission to use power at or about a certain place. And if you go away, that right is sort of recouped to the house, which gets to determine how to reallocate it. So yeah, creating rights and property in exchange for value, it is really not a mind-blowing insight, but it is something that is really not present in the power grid.

Joshua Rhodes: Yeah. No, that it sounds like you worked for a place like R Street or something at some point in your career. I love those guys. I mean, one of the things also that ERCOT is trying to do is like increase flexibility for data centers by offering a couple different approaches. And ERCOT is doing this, they’re kind of borrowing from two approaches they already have. They’ve got this provisional controllable load resource that says, okay, we’ll give you a certain amount of point of interconnection. And if the grid can support it, we’ll let you take more, but from time to time. We’re gonna enforce your point of interconnection. So maybe, you know, your point of interconnection is 200. When the grid’s not stressed, you can go up to 400. But when we tell you to go back to 200, you better go back to 200. And that’s controlling the load. And then there’s also kind of this, they’re calling it the BYOG SFL, like self-limiting feature. I don’t know if the acronyms are killing me here. There’s two approaches that basically enforce like a point of interconnection limit. And then there’s a couple different ways of dealing with it. One, you can have your own generation. Behind there to keep your computers running or keep your GPUs running, or, you know, you can turn them down. You talked about flexibility also in your essay. Is ERCOT ahead on these processes? Like would these fit well elsewhere too?

Travis Kavulla: Yeah, they would. And a real credit to ERCOT for considering these. And we’ve seen similar developments in how FERC resolved a dispute between Amazon and Talen for the co-location of resources, though the policy implications are broader than that, as well as in the Southwest Power Pool. But yeah, the bottom line is if you are not demanding firm service from the grid. Then what that really means is that you are not necessarily imposing the same incremental capital expenditure costs on the grid. You’re especially not doing that, you know, if you’re bringing adequate generation to kind of net out your impact onto the grid at a particular location. Or for that matter, and here I put in a plug for base, you know, paying for other people’s flexibility at or around that node or elsewhere on the system to furnish flexibility or capacity. So All of doing any of those things should almost get you like to the very front of the line. If there’s going to be a batch zero, maybe it’s batch minus one. But people in that batch really should be the people who are not requiring long lead time incremental capital expenditures. And really the regulators and RTOs looking at this issue deserve some credit for thinking about that as a speed-to-power solution. Yeah. And also to the degree it is tied back to the purchase of. Battery aggregations or bringing on a new gas power plant, even in a restructured market, conditioning the get for speed to power interconnection on the give of bringing new generation capacity that usually would not be considered in tandem with a new large load for the purposes of grid interconnection is a really positive step. And if people read the whole essay, they can kind of see in the economic logic of the open season how I’ve tried to make sure that. People who are flexible get good treatment under these systems, even if the system is intended to resolve in favor of incremental capital expenditures and the assignment to those costs.

Joshua Rhodes: Yeah, no, mean I think flexibility is key. You know, the more flexible things are, the more megawatts that can get onto the system. They’ll be operating more of the time, right? Which can help the utilization factors and other stuff of infrastructure to try to drive that stuff down. You brought up the Amazon Talen thing. I was gonna say a couple of years ago, I was also in a room with some big generator developers who were talking about, you know, a data center wanting to take, you know, one of their units off the system and they were getting pushback. Regulators and they’re like, well maybe we’ll do it flexibly, but the data center doesn’t want to be flexible. And I was like, well does the data center have to be flexible? Can you get that flexibility elsewhere? Does it maybe close by? So I was going to say, does that BYOG have to be on site or that can that

Travis Kavulla: Yeah, it should not have to be on site. In fact, you know, I understand why the co-location debate has occurred, but it’s weird to expect these customers who have the highest value of loss load of seemingly any customer on the planet to be the ones from whom we’re sourcing power interruptions. Like that doesn’t make a lot of sense. There should once again be a market for this and they should be able to pay other people to be flexible on their behalf. And the same thing goes for co-located generators. Typically, there are a lot of good reasons why, you know, you would not want your load tied into all of the weird outages and contingencies that happen in power generators, which are finicky machines. And so being able to kind of broadly source your supply, even while expecting to pay incremental cost associated with new sources of that flexibility or capacity. You know, is kind of a North Star that we need to live by.

Joshua Rhodes: Yeah, I mean, I think that’s one of the great things about the way that base does things too is like, okay, if you’re going to interconnect a lot of things and you can move a lot of little things to look like a big thing, that can be useful. And you’ve already basically got the interconnection at every single house or commercial or business, whatever it is, you know, maybe we can move faster there. And you’re doing great things in the ADER and the ERCOT programs. So just kind of tie this back, like, you know, Texas is trying to build this plane even as it’s well taken off. Like in the state is you were building an ecosystem of around, you know, speed to power, but it’s conditioned on, you know, financial commitment and emergency flexibility. Is that necessary but not in your eyes necessary but not sufficient without that price discovery?

Travis Kavulla: It’s a good way of putting it, Josh. I mean, so far, we’ve probably tried to extend really beyond the breaking point some of the traditional mores of cost of service regulation and this belief that a utility in the current moment can plausibly serve all of the possible loads that are supposedly coming onto the system. And if we really want to get serious about speed to power and efficiently integrating. Compute onto the system, there does need to be some price discovery for those loads that are kind of the highest value, the most flexible, the ones that are able to be built and served by the grid in the fastest possible timeline. And that’s fundamentally what some of the ideas that I propose are in search of.

Joshua Rhodes: All so if you had to choose one of your ideas, I think it would probably be an open season. But like if you had to take one of your ideas, what is the most likely one that would act that could get some traction? Just given the regulatory landscape that exists, like who’s your second favorite child here?

Travis Kavulla: Yeah. I mean, I’m just hard pressed to say that if I’m a data center and I get quoted a number that reflects all of the incremental costs of serving me on the system. And the data center says, That’s great. Let me write you a check right now. And by the way, I’ll also pay the existing rates to offset the costs of everything else you’ve invested in over the years. Yeah. The answer should be a thousand times yes. I don’t see it despite the utility business model being devoted to spending capital on behalf of their customers, it solves instantly the problem of cost shifting and speed to power in a way that should be really attractive. And the downside really is shouldn’t we take a beat and try to plan these systems more efficiently so that the joint costs can support more joint uses? But again, in a small system for a one off project that generally should be an ECS, but I’m holding out my help for open season.

Joshua Rhodes: Yeah, I mean shut up and take my money, like you know, type situation, which yeah, I think a lot. Travis Kavulla, thank you for coming on the Energy Capital Podcast.

Travis Kavulla: Thank you, Josh.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

ERCOT now has roughly 445 gigawatts of large loads asking to connect to the Texas grid, a figure so large that Joshua Rhodes says it might as well be infinite, because the system cannot physically build for all of it.

To sort real projects from speculative ones, ERCOT is launching a new screening process called batch zero, and stakeholders voted to advance it at last week’s Technical Advisory Committee meeting. On this episode, Rhodes walks through the mechanics with Tiffany Wu, an energy markets and regulatory consultant at McAdams Energy Group and a former adviser to Public Utility Commissioner Will McAdams.

The mechanism traces back to SB6, the 2025 law that standardized how large loads connect to the grid and set a 75-megawatt threshold for what counts as a large load. Wu describes a sequence built to thin the field at each step. ERCOT screens which projects qualify and studies what transmission they would require, then puts the survivors through a financial gate that filters out developers unwilling to commit real capital before final studies on whatever clears. The first batch is not expected to finish until late 2027.

Running alongside the batch process is a fight over who pays for the transmission. PUC staff want to charge large loads based on their contracted peak capacity rather than the four coincident peaks that currently let flexible customers shave their bills. Wu says this shift would make much of the demand-response incentive evaporate.

The episode explores:

* How ERCOT separates base load projects already in the queue from those still being studied and allocated.

* Why the shift from 4CP to a contracted-capacity charge changes who pays for transmission.

* How loads can use ERCOT pathways to pull more power than their allocation while transmission gets built.

ERCOT is moving to approve the framework now and tweak it as the first batch works through. (It’s the same build-it-in-motion approach ERCOT CEO Pablo Vegas described on an earlier episode.) The vote sets the rules. The studies will decide who actually connects.

Timestamps

* 00:00 - Introduction & Tiffany Wu

* 01:47 - Why SB6 Exists

* 07:42 - Batch Zero Status

* 10:03 - Who Gets Into Batch Zero

* 16:49 - Financial Obligations and Commitment Gate

* 22:44 - Batch Zero Study and Timeline

* 27:49 - Load Estimates and Flexible Load Options

* 31:37 - Transmission Build-Out and 765 kV Lines

* 35:46 - Batch One and Future Batches

* 37:43 - Transmission Cost Allocation and 4CP Reform

* 46:43 - Reliability Standard Study

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Tiffany Wu

* McAdams Energy Group (Website - LinkedIn)

Company & Industry News

* ERCOT’s TAC Sends Batch Zero Guidelines to Board

Books & Articles Discussed

* Texas Senate Bill 6, 89th Legislature

* PGRR145 - Batch Zero Process for Large Load Interconnections

* NPRR1325 - Related to PGRR145, Batch Zero Process for Large Load Interconnections

* PUC Project No. 58481 - Large Load Interconnection Standards Rulemaking

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Transcript

Joshua Rhodes: Hey everyone, and welcome to another episode of the Energy Capital Podcast. I’m really excited to have Tiffany Wu here to talk more about what all is happening in ERCOT, particularly around SB6, large loads, transmission cost allocation, all of the hot topics right now. Tiffany Wu is an energy markets and regulatory consultant with McAdams Energy Group. And for more background with McAdams Energy Group, you can go back and listen to Matt Boms’s interview with Will McAdams just a couple months ago. So before working at McAdams Energy Group, Tiffany was a DOE Solar Energy Innovation Fellow and also an advisor to Will McAdams while he was a commissioner at the Public Utility Commission of Texas. But between that, also was a senior project manager at TEPRI, the Texas Energy Poverty Research Institute, which is, I think we actually met. We had our first conversation when you were at TEPRI, and I was asking you questions about how these 9.9 megawatt batteries, what they were paying for electricity and how much they got paid for electricity, because that was a big deal for a while.

Tiffany Wu: That’s right. Yeah, I remember that there are a lot of questions around whether or not those batteries which support the grid, whether or not we should be paying for some of those distribution level costs as transmission level costs. Yes.

Joshua Rhodes: Yeah. Anyways, we probably won’t get into that, but we can leave that as a thing. But that was super helpful back then. Thanks. And I know you you also spent 10 years with Mitsubishi Heavy Industries as a process engineer, commissioning engineer. I’m really excited to have another engineer on this podcast. That’s kind of rare, to be honest. Well, thank you. You got your BS and chemical engineering at UT Austin before getting your masters at the LBJ School of Public Affairs. So Tiffany Wu, welcome to the Energy Capital Podcast.

Tiffany Wu: Thank you. Thanks for having me.

Joshua Rhodes: Yeah. So the day we’re recording this podcast, we we just released a podcast with Eric Goff where we talked we hit on some broad topics around how ERCOT policy is made. And we talked a lot about the large load process. I’d encourage folks to kind of maybe listen to that podcast first in terms of like kind of setting the broader goal. But with this one, I think I’d like to get a little bit deeper in this conversation around some of the intricacies of the process, kind of where it’s at. And to be fair, this kind of fits in my teaching philosophy of any time I give a lecture, I try to say the same thing three times in three different ways as a way of like some people learn one way versus the other way. So there will be some overlap between this and and the podcast with Eric, but I still think there’s so much there that I think this is gonna be, I think we need to be having a lot of conversations around this. But we’re gonna get deeper into some of these things. But let’s start bigger picture, maybe for folks who haven’t had the one with Eric. So The whole reason we’re having this conversation about large loads and batch zero and transmission cost allocations based on SB6 or Senate Bill 6. Can you lay out what problems Senate Bill 6 was looking to solve and kind of how the batch zero process, you know, fits into that effort?

Tiffany Wu: Yeah, sure. So Senate Bill 6 is trying to balance a few different things. So previously in ERCOT, most of the large loads were coming from the cryptocurrency industry. It wasn’t until recently that more of the data centers have been looking for interconnection into ERCOT. So historically, the way that you would connect into the system is you would go and talk to your transmission provider or your distribution provider and ask them, hey, I want to set up a business. Can I connect to the electricity system? And they would figure it out. But because there are so many loads coming in now, there was some concern that with the size. Historically they were working on one project at a time and TSPs were conducting the studies, but ERCOT started to see that there may be a reliability issue with how many loads are coming onto the system and how big each of these loads are. The other issue is that with the cryptocurrency miners, you may remember that a lot of people were worried that they were not paying transmission costs because the way that we paid transmission costs historically is based off of the four coincident peaks during the summertime. And so if you’re able to avoid that, then you don’t have to pay transmission costs. So, so in SB6, what they’re trying to do is provide more guidance and more standardization around how you interconnect into the system. So that would support business development. And on the other side, they’re also trying to make sure that whoever does come into the system will pay their fair share of the interconnection costs.

Joshua Rhodes: Yeah, no, totally. So there is that distinction in SB6 and I know there’s this distinction of like seventy five megawatts and above that defines kind of the large load. And I know the public utility commission can change that number in the future, I think if they want. Where did that number come from? Do we have a feel for kind of where that seventy five megawatts came from? I

Tiffany Wu: Honestly not sure where seventy-five megawatts specifically came from. But I think that what they’re trying to do is make sure that this is capturing the data center loads, which we know are potentially like hundreds of megawatts to gigawatts to even multi-gigawatts now. Yeah. Versus some of the traditional loads that are like the oil and gas industry, petrochemicals manufacturing. So not making it more burdensome for those traditional loads to interconnect into the system still. But PUC did try to reduce that threshold to twenty-five megawatts. They’re allowed to reduce the threshold that they think that it’s necessary. They originally wanted twenty-five megawatts for the load forecasting rulemaking, but that was gonna capture so many things and that was going to be so burdensome that multiple people push back against that.

Joshua Rhodes: Got it. When the seventy five megawatts like threshold kinda came out, a lot of people said, Well, we’re just gonna see a bunch of seventy four point nine megawatt, you know, data centers show up. Are there any of those? Are we seeing a bunch of those pop up under the radar now? Or I guess maybe we’re not seeing them. Do you know if they’re there?

Tiffany Wu: I think they are there and I don’t know for certain, but ERCOT had posted or filed a graph of load forecasts recently. Okay. And it had two bar graphs next to each other for multiple years and there’s a huge gap between them. And the bigger gap does include those medium loads that are less than seventy-five megawatt, but still fairly significant. So I am curious how much of that just wasn’t covered because we’ve been so focused on all of these larger than 75 megawatt loads.

Joshua Rhodes: So the latest numbers that ERCOT put out are around like of large loads. Got my cheat sheet up here too, because the numbers keep changing. Is four hundred and forty five gigawatts. So is there even more than that number, given that like these smaller just under the seventy five megawatt threshold? I

Tiffany Wu: I think that the four forty five gigawatt number that you’re talking about is the number of large loads that are trying to interconnect into the system, right? So that’s the number that would be included in batches. Cause there’s a portion of that, about three hundred and thirty gigawatts that likely won’t be included in batch zero, but want to interconnect. Okay. But yeah, I mean anything that’s less than seventy five megawatts is not gonna get captured from that table chart.

Joshua Rhodes: interesting. So these numbers that I’ve been making fun of and saying I don’t believe, like they’re even bigger. Possibly.

Tiffany Wu: Possibly. I don’t know. I wish that I knew

Joshua Rhodes: I mean, in my head, it might as well be a million. I just I think Eric put it well. He’s like, it’s just the numbers just infinite, right? Because we’re not going to be able to connect all of this. And so like the numbers just might as well be infinite. Okay. Well, that’s interesting slash terrifying. But we’ll we’ll see like kind of where where we go. All right. So let’s get to the batch zero process. So the batch zero process is kind of like, you know, how we’re potentially going to try to clear this backlog and connect these large loads. Now I think before we so hit record I said, Hey, the batch zero is not finalized, but then you said actually it kind of is so why don’t we just say, what is the status of batch zero? It was recently tabled to the June meeting, but can anything change between now and then or is it pretty locked in?

Tiffany Wu: so yeah, so it has to work through the stakeholder process. So it’s been approved through the PRS and ROS. And yesterday was the technical advisory committee meeting, the TAC meeting. Okay. And that’s when the stakeholders voted on batch zero. Okay. And leading up to that, there have still been a number of requests to change certain Parts of batch zero and ERCOT was pretty resistant against any changes, which makes sense because we’re getting up on the deadline. There was a move to try to have an alternate revision request language, but that was shot down. Only 30% of stakeholders approved that alternative. Then they brought up the ERCOT revision request, and that got 100% approval.

Joshua Rhodes: Okay. And so did anything change in the TAC meeting the other day or did it just get kind of approved there?

Tiffany Wu: No, nothing changed at TAC. Well, the latest revision was from May eighteenth. Right. Basically a new revision has been coming out every few days for the last few weeks, I feel like. And at the end of this, ERCOT was pretty resistant to even like small changes. And so that’s what’s been approved. So next it will move to the board of directors meeting and that’s scheduled for June first. Okay. And once They approve, which I assume they will approve, the revision request, then the PUC has to approve it.

Joshua Rhodes: Okay, so hopefully all the research I did on batch zero this weekend still holds as we talked about it.

Tiffany Wu: Welcome to my life.

Joshua Rhodes: Yeah, no, no, no. I’m just here to cosplay. So I want to get into some of the stages of kind of the batch zero concept. So there’s like five steps as far as like I understand. And tell if anything that I say has actually been changed, because I didn’t check yesterday. Maybe I should have. So the first step is like, okay, figuring out how much load actually gets into batch zero, how much are we going to study? There’s these the first step is like the inclusion criteria. So which large load projects are going to be included. So So what do we know about what these are? Do we have a feel for kind of like how is ERCOT gonna say which projects are in batch zero and which projects are not? Mm-hmm.

Tiffany Wu: And there’s two categories within batch zero too. So there’s the base load and then there’s going to be the studied and allocated loads. Okay. What ERCOT has been saying is that the only thing that they know is whether or not the transmission service providers have filed studies for those loads and whether or not ERCOT has approved those studies. That’s the basis of which ERCOT is using to approve. Specific loads for either base or batch zero or you just didn’t make it at all.

Joshua Rhodes: So baseload here, the term base load is used in electricity in a bunch of different ways. But in this specific case for batch zero, so are these projects that went through the previous way of getting large load connected? Like they went directly to the TSP and they got the study and they’re like, they’re just now part of they’re good to go, but they just need to be included.

Tiffany Wu: Yeah, so there’s history there. Okay. So last year there were multiple pathways to be interconnected into ERCOT. Okay. So one was the original way, which was you work with your transmission service provider and then they do a an RPG process. They go through the RPG process, which they study the loads that are necessary and the transmission projects necessary. To support specific loads within a specific region. That was one pathway. The other pathway was because ERCOT was now transitioning to also approving large loads, that’s called the large load interim process. And so they created a process to review those TSP analyses. And I’m not an electrical engineer, but there’s certain studies, steady state studies.

Joshua Rhodes: None of us are.

Tiffany Wu: Yeah, stability study, short circuit ratio study that they have to do for each of those loads. And so if a load went through that process by a certain time, then they were approved for base load. And they also had to sign an interconnection agreement with the utility as well. So it was two things whether or not you were approved through the ERCOT large load interconnection process. And you got a interconnection agreement with the utility, basically. What’s giving some people heartburn and was part of a lot of the controversy leading up to the TAC vote is that the other process, some utilities were telling their customers, we need new transmission in order to serve your load. So we need to go through the RPG process. And so they told those loads, hold on, let’s not do the large load interconnection process. Let’s go through the transmission process. Yeah. So that was totally okay until I guess December 15th when they transitioned to a large load interconnection study, the LLIS process, which is also known as PGRR 115. Is approved December 14th or December 15th. And I don’t think it was clear at even at that point that going through the RPG process was going to be enough to get you interconnected.

Joshua Rhodes: Okay. That is quite a bit of backstory on some of these. I mean, I know some of these loads are valuing the, you know, a megawatt not connected for a year in the billions of dollars or whatever, or a gigawatt not connected in the billions of dollars. So these are I guess loads that are being grandfathered in, but they’re not currently connected to the system. So ERCOT’s gotta study them as if they’re coming online. And then there’s like the studied and allocated load, and these are the loads that have not been approved just yet, but are try to work their way through the batch zero process. Is that right?

Tiffany Wu: Yeah. So first from ERCOT’s perspective, they were looking at two specific things for being eligible to be considered baseload, right? It was whether or not you were approved the studies were approved and if you had an interconnection agreement by a certain time frame. But the PUC also had criteria that were given to them by SB6, which includes financial obligations, site control. Whether or not you’re trying to interconnect at another location and developing a different project, whether or not you’re bringing backup generation and all these things. So there are other things that the loads are gonna have to attest to. And that I think it’s in July, they’re gonna have to provide that information. The biggest open question right now is the financial obligations that will get you into base load eligible. And then another thing that you mentioned for the base load. They have an agreement in place. So their utilities already told them, like, we’re going to be able to give you this much power by this time frame. And there’s like a certain schedule. So they’re going to be studied based off of that schedule. And then those that don’t meet all of the criteria to be included in base load, but are included and studied and allocated, they will be allocated a certain amount of additional load within the five to six year. Transmission planning process that’s gonna be evaluated as part of batch zero.

Joshua Rhodes: Okay. All right. So we gotta figure out who gets in. That’s contentious. None of this is gonna make everyone happy, right? But this is just the way it is. I mean, when we had Pablo Vegas on the podcast, he basically said, like, we’re gonna have to figure out something, we’ll tweak it as we go, but like we gotta do something. It’s probably the case that if like, you know, not everyone’s happy that it’s probably a hashed out process. And I won’t make you comment on that. But so step two. Yeah. All right. So it’s like

Tiffany Wu: Yeah, who are the winners and losers?

Joshua Rhodes: Yeah, but it’s like the electricity sector can only move so fast. I mean it’s real steel in the ground that that’s gotta go. Okay, so we got inclusion criteria, who’s gonna get in, and then they’re gonna do the batch zero study, which I presume is like a big electrical engineering stability, like we’re gonna run some power flow models to figure out like what is it gonna take to get all of these loads connected. Is that right? Did I get the second step right?

Tiffany Wu: Yeah, that’s right. And before we get there, there is a financial obligation for you to get into batch zero. So you have to pay a fifty thousand dollar per megawatt financial security. Not pay, sorry, post a fifty thousand dollar per megawatt financial security. And that’s before they perform any study, right? But in the PUC rule right now. There’s a possibility that after they’ve run the first initial batch study processes, that you’re not gonna get a very good allocation. So then you’ll get to choose whether or not you wanna move on to the next steps. So in the first step, it’s going to be studying all of the loads together, the steady state analysis and the stability screening. And then ERCOT’s gonna have to work with all the TSPs. There’s gonna be a lot of back and forth between them. Also For just a plug, if anybody wants to work on this, ERCOT just said they’re hiring like so many FTEs for this. So any electrical engineers out there. Okay. Yeah. So yeah. So they’re gonna do the studies. At the end of the studies, you’ll know what you’re allocated and then you’ll get to decide whether or not you wanna stay in the process.

Joshua Rhodes: The third step is the they’re calling it the commitment gate. So in the second part, they do the electrical engineering studies that you said, maybe you’re only getting so much load per year, right? Maybe you want five hundred, but you can only get a couple hundred per year, maybe. Do you know how far out that process is going? Like if they’re gonna allocate a certain amount, are we looking five years out? Like how far is this process?

Tiffany Wu: Yeah. So originally they were thinking that they would be looking five years and then within in the sixth year, magically you would just have all of the transmission that you need. But now they’re working on something else that is considering all six years. And I don’t think they’ve decided yet how they’re gonna figure out that allocation yet.

Joshua Rhodes: Okay. So there’s five, six years, something like that. We’re gonna look forward. And then I guess like if you like your deal, if you like what you get out of the study, then there’s like this commitment gate. So what does that commitment gate look like? So you’ve posted fifty K per megawatt. Does that mean that like you push that into escrow? Like how do you say yes to the commitment gate?

Tiffany Wu: Yeah, so that’s a big unknown right now. Okay. Yeah. So great question. Everybody’s asking that. So the PUC is working on rulemaking for interconnection standards. It’s project number 58481. And the latest proposal for publication for that was filed March twelfth. Okay. So that was the last, I would say, official guidance from the commission on where that rule might go. And in that proposal for publication, there were two agreements that you would sign. One is the intermediate agreement that you would have to sign and post the $50,000 per megawatt financial security before the start of batch zero. Okay. And then at the financial commitment point, you would have to sign an interconnection agreement and you would have to pay then the $50,000 per megawatt. Financial security becomes a fee. So you that’s a cash payment of fifty thousand dollars per megawatt, plus what we call a contribution in aid of construction, CIAC, which pays for the specific equipment that gets you connected to the transmission system. So it’s just what we call the driveway.

Joshua Rhodes: Yeah. The Gintai if we were talking about generators, right?

Tiffany Wu: Yeah, yeah, exactly. Exactly. So that was in the March twelfth proposal for publication. If you ended up backing out at the financial commitment deadline, only twenty percent of that fifty thousand dollars per megawatt would have been refundable. So you basically gave yeah, it’s a big financial commitment. So staff had Been getting a lot of feedback from stakeholders. Like that is a huge risk, right? We don’t know anything at that, especially think about like future batches. At least in this case, a number of these large loads that are going to be in batch zero have already done some amount of studies. Right. But in future batches, they’re going to be coming in for the first time and they would have to post that. So PUC staff did provide some guidance. As part of PGRR 145 and the interconnection process, but it hasn’t been written into the rulemaking and it’s not included in PGRR 145. And so we’re still kind of in no man’s land around how this is all going to work.

Joshua Rhodes: Okay, but we’re still voting on this thing in like a month, right? So it’s like

Tiffany Wu: Yeah. Yeah. So what we’re voting on for PGRR 145 is just that you have to post a financial security. Okay. But how much of it is refundable, what happens if you don’t get your full allocation? Yeah. None of that is detailed.

Joshua Rhodes: So we’re we’re voting on the process, but there’s still ongoing rule making and discussions and stakeholder and putting the meat on the bones of the process, as it were.

Tiffany Wu: Right, but you’re still putting a lot of capital at risk by doing it this way, right? It’s basically like, Yeah.

Joshua Rhodes: Well, I mean, when you’ve got four hundred and thirty, four whatever, a million megawatts, you know, trying to connect to the system, you gotta separate out the wheat from the chaff somehow, I guess. But that is a lot. That’s fair. If you’re only getting twenty percent of that back, I mean that’s you know, you’re essentially you’re any up forty K per megawatt. If I’m doing the math right in my head, I can see how that would be a hard pill to swallow. Fair enough. Okay, so that’s step three. Commit me gate. Yeah. Or step four is basically okay, so commitmigate

Tiffany Wu: Yeah. Sorry.

Joshua Rhodes: We see what clears and then I guess it sounds like we redo the study we did in step two, but now with just the loads that have cleared the commitment gate, which would have to be equal to or less, I guess.

Tiffany Wu: Correct. Yes. And part of the reason why we’re going down the batch process method instead of doing the serial study process, which we had been going through, is because the serial process, if you got on before or somebody else got on before you did, you’d have to get restudied. And so the hope is that after you we go through the financial obligation gate and there’s only so many loads left over for the batch refinement period. That this is not a full restudy because otherwise we’re just codifying restudies, but instead it is an actual refinement period of just like, okay, those loads went away. So the transmission projects are likely gonna be more like this.

Joshua Rhodes: Okay. All right. So in step four, we study the loads that make it through the commitment gate. And then, you know, maybe all of the upgrades that were identified in step two, maybe we only need a certain percentage of those because there’s presumably potentially fewer loads in the refinement study. But then there’s actually a plan that’s sent out to the regional planning group or RPG to say this is the transmission that we need to build to support this much load. And I think one of the things that Eric mentioned in the podcast was like this is a new thing than the previous ways, because the previous ways said like it’s possible to build this transmission, but there’s never a plan that was created. And so is that the whole reason for this thing is to get that planned RPG to be able to build?

Tiffany Wu: Yeah, so before there were so many different pathways to do this, but just stick to one. So let’s say that you went through the LLIS process and the transmission provider told you that you were able to energize within a certain time frame and you’re gonna need the like transmission project A to get to 200 megawatts, transmission project B to get to 400 megawatts and so on. So you’d be like, okay, cool, great. Maybe at the same time. That utility would be going through the RPG project to get those transmission projects approved. So they could either be going sequentially or at concurrently, which also goes back to like the controversy around who should be included in batch zero, because for the ones who went through the large load process, they were studied, but there was no transmission project behind it. And then for the projects that went through the RPG project. They have transmission projects, but they weren’t studied one by one by ERCOT.

Joshua Rhodes: Okay. I got a few questions. Say that it gets approved at the next meeting and this process kicks off. I know there’s some rulemaking that has to flush it out as it goes, build the airplane as it’s flying, but like how long does it take to get to here’s a plan RPG. How long does this process take, presuming that it gets approved, for the first batch to go through?

Tiffany Wu: From start until you know the results of the RPG.

Joshua Rhodes: Yeah, but what is the hope, anyways, of how long this take? Are we talking six months? Are we talking a year? Are we talking five years? Like what how long is this batch zero process gonna take?

Tiffany Wu: Yeah, it kind of depends on how they study years five and six. Like how detailed are they going to get around the transmission projects? Are they going to try to study like a ton of different transmission projects, or is it just what’s reasonable? That all takes time. So it could extend depending on like the amount of studies and the projects that they need to work through, it could extend the process another month month or two. So right now the schedule is if we had only just thought like, okay, we’ll study for five years, and then in year six, magically you have all of the transmission that you need. July was gonna be start of batch zero, and then it would be completed, like the RPG comment period and board approval would be in September. But if we’re doing more analysis around the future years for transmission projects. Then that could extend into December of next year. Wait. December of twenty seventh.

Joshua Rhodes: December of twenty seven. Okay. That’s a pretty big delta between like two months or

Tiffany Wu: no, no, sorry, sorry. I maybe that was confusing. It was either gonna be September twenty twenty seven or it’s December twenty twenty seven.

Joshua Rhodes: okay, sorry. I thought you meant it was g they’re gonna figure this out over this summer. And I was like, wow, that’s fast. Okay, that makes way more sense. I could just hear all the computers like running all the dynamic simulations in my head. All right, so we’re never gonna get off this first question, which is great. Yeah. All right, so it’s gonna take I mean we’re looking at mid to the end of twenty twenty seven. Do we never feel for how much load is gonna make it in the study? Like As base load or as like studied and allocated load, do we have a feel for how much load’s gonna get in the front of this?

Tiffany Wu: Now it’s looking like the maximum amount that would be base load is around thirty gigawatts. And then the amount that would be in a studied load would be about like 90 gigawatts. So in total, 130.

Joshua Rhodes: Okay. Okay. One thirty. But then we’ve forgot five or six year process and we’re maybe we’re kind of spreading that up. Okay. So this feels better than the chart with like the four hundred and thirty-five gigawatts by like twenty thirty or whatever. So that’s great. But ERCOT is also gonna create a couple of different kind of potential, I guess, ways you can do this. There’s this thing called the provisional controllable load resource, which ERCOT has these controllable load resources that can bid their load into SCED, the same program that makes generators go up and down, can make load go up and down. But there’s also this the ability of these loads to say I’m willing to be a provisional, controllable load resource. Can you kind of walk me through like what is that and what would be the advantage of doing that for these loads going into the batch zero process?

Tiffany Wu: Yeah, so there’s two potential pathways. One is the provisional controllable load resource, PCLR, or there’s what they’re calling the Withdrawal-Limited Private Use Network, WL-PUN, and that’s basically if they’re bringing their own generation.

Joshua Rhodes: That’s the B Y O G L that’s the other okay, yeah. Okay. Yeah, there’s two, right.

Tiffany Wu: Yes, there’s two. Saying that you are PCLR or a WL-PUN is not going to get you into the batch process faster. You still have to meet all of those other requirements that we had talked about. But what being a PCLR or WL-PUN helps with is that let’s say the transmission provider tells you you’re only getting a hundred megawatts in year one. You could say like, could I actually get 150 megawatts? And in tight periods, I promise to come down to a hundred megawatts or okay on the bring your own generation. It might just be like, okay, my net use from the grid is going to be that amount, but I still have my own generation. So it’s just a way for them to increase the amount of energy that they can use on a timeline that’s more business friendly.

Joshua Rhodes: Yeah, totally. One way is like I’m willing to like let some of my load be curtailed or I’m gonna bring my own generation and make it up from that on the other side. It seems like no one likes either of those and they really want this third option called like a netted network. But ERCOT is saying that it’s kind of not feasible for the batch zero because it my understanding of the netted network process, and you can tell me if I’m wrong, is that you still have like the limited point of interconnection. So you still have like a hundred megawatt limit, but You have load and generation behind that point of interconnection, but both of those things can fully play in the ERCOT market. You can be a CLR and have generation that can maybe get ancillary service revenues or other types of things. Cause my understanding that these other ones, these PCLRs and the provisional controllable load resources, the BYOG PUN type thing, you do not have access to the ancillary service markets, but people want that. Am I getting that right?

Tiffany Wu: So that’s beyond what I know at the moment.

Joshua Rhodes: Yeah, no, it’s fair. It’s like this is coming off of some slides that I was kind of looking at and just talking to some folks in the space. They’re like, Yeah, this is kind of what we wanna do. This is where we wanna get to. It’s my understanding that ERCOT says like, yeah, maybe we’ll get to that. That sounds great, but like

Tiffany Wu: Yeah, for them right now it’s one or the other and that’s something that they did clarify is you have to choose basically are you WL-PUN or are you P C L R?

Joshua Rhodes: Yeah. We’ve talked about batch zero for like a while. And so we have a study process. It’s either we’re gonna get through it by September twenty-seven or December twenty-seven, depending on how we decide to study like the latter years of that. Then it’s gonna take a while to build this transmission. We’re gonna have the plan, but then you know, it may take four or five years to build out that transmission. I guess it’s probably too early to say like how much transmission that’s gonna be. I mean, that would be the result of this whole thing, right?

Tiffany Wu: Yeah, exactly. Yes. What do I want to say about that?

Joshua Rhodes: I’m putting you on the spot, like, admittedly. So it’s like you don’t have to have an answer for that ‘cause I sure as heck don’t.

Tiffany Wu: No, I do want to say something about it. So a question around the batch process and why you wouldn’t just allow every load that wants to be in it to be studied is because there’s a limited amount of transmission that will be able to be built. And I think that the transmission service providers probably have the best idea around what they need, what’s possible, what could be the potential routes after the RPG process. A lot of these transmission projects are likely going to need permits. They’re gonna have to go through the CCN process at the commission to finalize what the routing is ultimately going to be. And so that will dictate what the final cost will be and which transmission projects are actually gonna get approved and built. So yeah, there’s still a lot to do after this batch.

Joshua Rhodes: The commission’s getting a lot of experience right now on routing of transmission with all the seven sixty five stuff going on. Those are pretty some of those dockets are chalk full of things.

Tiffany Wu: Can I say something about the 765 KV lines? So I think some senators sent a letter to the PAC recently asking them whether or not all of the 765 KV lines are even necessary for the Permian Basin reliability plan. So I do think there is a risk that if there’s too much discussion, and there has to be the right amount of discussion around like what’s a real load, what’s not a real load, how Far are we constraining the batch zero process? Like the reason why we need transmission is for these loads. There has to be a balance for that.

Joshua Rhodes: I mean, we historically we’ve built, you know, transmission for load in ERCOT while other regions have built it for generation or and load, but in we’ve always built I mean, pulling that thread a little bit though, I mean, but the seven sixty five like lines, like they predated a lot of this AI data center boom and other types of things, right? I mean, I remember that S&P study that came out about electrification of oil and gas and like the Permian and Delaware basins. I mean, it was blowing everyone’s mind that we were gonna get ten gigawatts of growth and now that would feel nice. It feels like if that were all, i am I getting that right?

Tiffany Wu: It is so strange how fast the industry is moving right now, because you are right that it was mostly the oil and gas industry that was pushing the transmission need in the Permian Basin region. And I think even within the industry, they were questioning whether or not seven sixty five KV lines were necessary because in Texas we’ve only gone up to three forty five KV lines. But The benefit of the seven sixty-five KV line is that eventually we’re going to want a backbone of electric highway, basically, right? So that was just the first step, but I think the ultimate plan was to connect all of Texas with these seven sixty-five lines.

Joshua Rhodes: No, totally. I mean, I think like and it was the thing that Eric said on the podcast last time is like the nice thing about seven sixty-five is you actually need fewer lines. If we were just stuck with the three forty five and we had all this load, like that would be more lines and more routes and more dockets. All right. So a little tangent there, but like is also a thing going on. It’s my fault. Okay, so we talked a lot about batch zero. But batch zero presumes that there’s a batch one or a batch next process. So is there any coalescing on like or thought about does that look similar? Does it look different? Like what would be different about post batch zero?

Tiffany Wu: Yeah, we need to talk about batch one or batch N, whatever we want it

Joshua Rhodes: we don’t even know what we’re gonna name it, right? Like we should come up with something.

Tiffany Wu: And actually they’re gonna be talking about it tomorrow. So I don’t know when this is gonna get posted, but at the May 21st LLWG meeting is when ERCOT will be presenting a framework, I think, for what batch one will look like. I think it will be very similar to batch zero. I think they’re gonna have to make some tweaks, though. I hope they’re friendlier to some tweaks of the criteria for inclusion since batch one won’t get started until I think the spring of twenty twenty seven or something like that. So there’s time to make that a nice policy.

Joshua Rhodes: Do you want to expand on that? What do you think would be a better approach for batch one or batch in or batch next or I don’t know what we’re gonna call it?

Tiffany Wu: Yeah. I think that with batch one, there was a lot of confusion around the LLIS process and the RPG process. I think with batch one, they’ll need to talk about what do we do with RPG and the other transmission planning process, the regional transmission plan RTP. How did those two conventional transmission planning processes work with the fact that we’re going towards studying large loads? or any load in batches going forward. There needs to be consideration for that. So I think hopefully there will be less confusion then since we’re talking about the policy for the future rather than building the plane as we’re in it. So yeah. So I think that that’ll be a big piece. The other thing is I hope we’ll know what financial obligations are required to get into future batches. By that point, right now those rules are still being written when we’re trying to get batch zero started. So it’s just kind of messy, confused time right now. So there’s time to make batch one clear.

Joshua Rhodes: True. Again, that’s what Pablo said is like, we’re gonna do something, we’re gonna move forward. You know, it’s not gonna make everyone happy, but we’ll tweak it as we go. I think I referenced that podcast a whole bunch every time I talk to folks. All right. So also part of SB6 was it told the PUC that hey, you need to study the transmission cost, like allocation issue. This whole thing with batch zero on connecting all of this load is like we gotta figure out how much transmission we’re gonna build, where it’s gonna go, because that’s what we need to do and well, we’re just gonna let the market worry about generation. But we need the transmission right now. So right now we allocate the cost of transmission with four coincident peak. We’re discussing how that may change. Tell me about four C P, what the issue is, why are we looking to study it and what should we be paying attention to?

Tiffany Wu: Sure, yeah. So historically, transmission infrastructure is based on the maximum potential size of the amount of electricity that we would use at any given point. So if you think about a pipe, it’s like what’s your maximum flow rate through that, right? But everybody is using electricity at different times. So I’m not necessarily switching on my dryer the same time that you are. And it’s the same thing with industrial loads. Like there’s going to be moments when they use a lot of electricity and moments when they don’t.

Joshua Rhodes: I’ve got a one year old at home, so the dryer’s always on because they’re just there’s always dirty clothes. Anyways.

Tiffany Wu: Like you know, there’s always something to be cleaned, yeah. Yeah. Okay, well maybe not you. You are

Joshua Rhodes: I base I’m base load dryer, yeah.

Tiffany Wu: Yeah, you’re a hundred percent capacity factor. So in the summertime, that’s when in Texas we’ve historically hit our peak, right? Everybody has their air conditioning on, the cooling towers are probably going crazy. Everybody’s at work, people are I don’t know, going to camp. I don’t know. Whatever else requires a lot of energy during the summertime. Probably mostly air conditioning. Yeah. Yeah. It’s air conditioning. Yeah.

Joshua Rhodes: It’s air conditioning, yeah.

Tiffany Wu: But with 4CP, what we do is we look at who was a transmission customer during the summertime. And in those four 15-minute periods that were at the highest use across the system, what percentage can be associated with each customer? And then that’s how we allocate transmission costs for the next year. And so For industrial customers that are transmission customers, they could be reducing the amount of their electricity demand if they can forecast when they think that’s going to be. So a lot of the steel mills do this. They just don’t run their arc furnace during those times, for example, to reduce their percentage requirement. I think it became a huge issue because of the crypto miners. And I think Eric talked about this too. Like, they could just shut off, right? It’s not like you’re producing anything that people are can’t just be shut off like that. And so they were able to avoid their transmission costs. But residential customers, we don’t have the option in competitive areas to avoid 4 CP. And so we end up paying for the transmission cost based off of our energy use. And it doesn’t matter what time we’re using electricity. So that’s Part of the reason why they’re thinking about shifting from 4 CP is to make it harder for people to avoid the transmission costs. Yeah. But there’s a trade-off because the point of the demand response is to reduce that peak load so that you don’t need as much infrastructure. They’re thinking about going to 12 CP with 30 minutes. And I think that there’s going to be discussion around whether or not that is the right call. But what is more

Joshua Rhodes: Yeah.

Tiffany Wu: impactful in the transmission cost allocation policy discussion is that the commission staff is proposing that rather than chasing these coincident peaks, the large loads are going to be charged based off of their contracted peak capacity. So if they’re going to come in at 100 megawatt or if they want 100 megawatts at any point of time, then that’s what the basis of the transmission cost is going to be. Even if in the summertime they could like reduce down to fifty megawatts or something like that. So it almost makes like the demand response piece of it completely evaporate.

Joshua Rhodes: Yeah, I wonder if there will be some kind of hybrid approach. Before maybe I try to pull that thread, do we know what it would look like for like a PCLR or these other because like a PCLR, going back to the batch, we can’t get out of the batch zero process, but like if you have a hundred megawatts, but you can flex above that if like the grid’s not stressed. So maybe you can actually pull in 150, but the grid’s under stress and they’re like, you gotta crank it down to a hundred. Do you know if they’d be charged on that hundred or the hundred and fifty?

Tiffany Wu: So a PCLR is a temporary. So it’s just to allow you to use electricity above your allocation until you have transmission built to your site. So your contracted capacity, like say for a large load that is 200 megawatts in size, and you’re only gonna be allocated 100 megawatts. And you say, I’m a PCLR, can I use 200 megawatts sometimes? I think that you’re still going to be. Charge at the 200 megawatts. Okay. But that rule’s not written yet, so it’s possible it may be different, but that’s how I expect it would go.

Joshua Rhodes: Okay, and so would the transmission cost allocation change for everybody or is it gonna just be different for the loads that are above seventy-five megawatts?

Tiffany Wu: So for the change from four CP to twelve CP, that’s going to change for everybody. But the minimum transmission charge, I think, will only be for the large loads.

Joshua Rhodes: Okay. And I think Eric was talking about there potentially also could be like the minimum transmission charge could even be a fraction of what your contracted is. So it could be fifty percent, seventy five percent. I’m assuming that will be a number that will be highly contested and argued over.

Tiffany Wu: Yeah. So in the interconnection standard rulemaking, I think there was a range between fifty percent to eighty percent as the minimum. So if you only used forty percent of the demand during coincident peak, you would still have to be charged fifty percent. If you use more than that, then it would just be based off of the coincident peak. But it’s basically like setting a minimum for the transmission charge.

Joshua Rhodes: Okay. So if the minimum transmission charge was like a hundred percent of your allocation, then there’s no reason to try to do any four C P demand reduction. But if it’s like fifty percent or well, if it’s below a hundred percent, then there would still be some, maybe not as much as it has been in the past, but there’d still be some incentive to do some DR. Yes.

Tiffany Wu: Exactly. And the other thing is that the reason why they want the minimum transmission charge is so that the large loads will pay for their portion of the transmission system that they’re causing to be upgraded. Right now, in the five eight, four, eight, one rule, which is the interconnection standard rule that I had mentioned, there’s the intermediate agreement and then the interconnection agreement, and that $50,000 per megawatt. Becomes a fee. Purpose of the $50,000 per megawatt fee, I think, was also to make sure that the large loads pay their fair share of the transmission system. Yeah. So if they’re going to be considering a minimum transmission charge going forward, then likely they don’t need the interconnection fee then. Cause then you’d be paying up front and you’d be paying after you’ve connected as well for, I think the same thing.

Joshua Rhodes: Okay.

Tiffany Wu: So they’re gonna have to work through that.

Joshua Rhodes: Okay. Or would it also maybe just be a difference in how much would be refunded? I guess like

Tiffany Wu: It could be, yeah. Yeah. There are so many ways that this could go, right? And y you brought up a good point. The fifty percent to a hundred percent, that’s gonna be heavily contested or debated. One of the other aspects of this is that the transmission cost allocation proposed language might require that minimum transmission charge for fifteen years. The first fifteen years of the large load is in operation, the number of years will also be negotiated. For debated.

Joshua Rhodes: Okay, yeah, there’s a I can see why this framework of this is gonna be I mean likely approved and then we’ll really see how the sausage is made as it goes down. Okay. I’m gonna talk about SB6, batch zero, transmission cost allocation. Is there anything else going on at ERCOT? What else do you do? I mean, with all your time.

Tiffany Wu: Yeah, there are other things that are going on. You brought up resource adequacy earlier and you were like, yeah, the markets is gonna deal with that. But actually this year is the first year that we’re going to be performing the reliability standard study. Yeah. And so the load forecast is going to matter. How much are we going to be planning for? Right. So the reliability study is there to determine the probability of an outage, right? So we’re looking at how many resources. How many generation resources do we have? And how much demand do we have? How much demand response do we have? All those things. And so the assumptions really matter. And so what they have decided is to wait until batch zero process kicks off so that they can use that as the load forecast for the reliability standard.

Joshua Rhodes: Okay, that makes sense. I’m a consulting firm, Ideasmiths, is an independent market registered entity and I got that notice from ERCOT the other day. It’s like we’re not gonna put out our assessment ‘cause we’re gonna wait to figure out like how much load that goes in this. So okay, that makes a lot of sense.

Tiffany Wu: Yep. And at the end of the reliability standard, the PUC and ERCOT may decide that we need additional market changes in order to meet the reliability standard that Texas has set. Yeah. So more changes to come.

Joshua Rhodes: More changes to come. I mean, we’re not the only grid that’s looking to change things. I know PJM just put out a big white paper on a big some big changes they may make too. They’re the other grid that’s also dealing with a lot of load growth and data center alley and other places like that. But it the numbers feel bigger in Texas. I mean, everything’s bigger in Texas, but we’re figuring it out, right? At least we’re going through the process. So

Tiffany Wu: Yeah, the good thing is we can move fast, we’re innovative, everybody knows each other for better or worse. So

Joshua Rhodes: is it better or worse? Which one?

Tiffany Wu: Yeah, the rest of the country will be able to learn from our successes and mistakes.

Joshua Rhodes: Yeah, totally. Awesome. Well Tiffany Wu, thank you for coming on the Energy Capital Podcast.

Tiffany Wu: Thank you.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

Texas has spent decades building transmission to serve load growth. The pattern worked when growth rose steadily with new homes, oil and gas operations, and the gradual expansion of the state’s industrial base. It is being tested by a different kind of customer: data centers requesting interconnection at a scale that exceeds what the grid can physically deliver.

Eric Goff, founder of Goff Policy and a long-time participant in the ERCOT stakeholder process, walks through how the system is adapting. The current large load queue sits above 400 gigawatts, a number Goff describes as effectively infinite because the constraint is infrastructure, not demand.

In an interview with host Joshua Rhodes, Eric covers a lot of ground, including:

* How the batch zero policy, now working its way through ERCOT governance, would replace one-off utility studies with a single, system-wide study and a constructable transmission plan.

* How the decision to build 765 kV transmission compares to the 138 and 345 kV shifts of past generations.

* How Senate Bill 6 gave ERCOT and utilities multiple tools to disconnect large loads before emergencies.

* Why artificial intelligence hyperscalers behave differently than the crypto miners that came before them, with a value-of-lost-load above the wholesale price cap.

* Whether a minimum transmission charge can protect existing rate payers as new load arrives.

Goff argues the infrastructure decisions Texas makes now will determine whether the data center build-out lowers per-unit costs for everyone or shifts them onto residential consumers.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction & Eric Goff

* 02:36 - How Policy Gets Made in ERCOT

* 06:35 - What’s Actually Driving Load Growth

* 09:18 - Is the 435 GW Queue Real?

* 10:41 - Inside the Batch Zero Process

* 14:21 - Building Transmission for Load, Not Generation

* 16:56 - Large Load Flexibility and Controllable Load

* 18:18 - SB6 and the Power to Curtail

* 22:38 - The Dispatchable Campus Idea

* 27:27 - Does Transmission Planning Need to Change?

* 32:32 - Paying for Transmission: 4CP, 12CP, and a Minimum Charge

* 39:39 - Five Years Out: Betting on Infrastructure

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Eric Goff (LinkedIn)

* Goff Policy (Website - LinkedIn)

Company & Industry News

* ERCOT files Planning Guide Revision Request 145 for Batch Zero

* ERCOT Board approves $9.4B 765-kV Eastern Backbone project (RTO Insider)

* PUCT approves first 765-kV transmission lines in ERCOT region

* Texas lawmakers push back on 765-kV transmission plan (KXAN)

Books & Articles Discussed

* Texas Senate Bill 6, 89th Legislature

* ERCOT Planning Guide Revision Request 145, Batch Zero Process for Large Load Interconnections

* ERCOT Permian Basin Reliability Plan Study

* PJM proposal to transition away from capacity market

Related Podcasts by Energy Capital

* The New Rules Behind ERCOT Prices, with Andrew Reimers

* Texas Growth Running Into Grid Limits, with Katie Coleman

* The Data Behind Texas Reliability, with Max Kanter

Transcript

THE ENERGY CAPITAL PODCAST Eric Goff, Founder of Goff Policy Host: Joshua Rhodes

Joshua Rhodes: Hey everyone, and welcome to another episode of the Energy Capital Podcast. I’m really excited to have Eric Goff, the founder of Goff Policy here, to basically tell us how ERCOT works. Eric is one of the smartest people out there when it comes to kind of the current comings and goings in and around ERCOT. Deeply involved in a lot of the policy and a lot of the procedures and a lot of other things happening. Eric founded Goff Policy in 2019. Before that, he had seven years at Citigroup in energy trading, market operations, earlier roles at NRG Energy and Reliant and Constellation. He’s been a longtime participant in the ERCOT stakeholder governance system. He serves as past chair of multiple ERCOT subcommittees and working groups and up until just recently served as a sole representative for Texas residential consumers at the ERCOT Technical Advisory Committee appointed by the Office of Public Utility Counsel. The firm has grown significantly in the past couple of years. You’ve been spreading into Western markets. You’ve been hosting symposiums and all kinds of things. Eric, welcome to the Energy Capital Podcast.

Eric Goff: Thank you so much. It’s great to be here. I appreciate the invitation.

Joshua Rhodes: Yeah, no, absolutely. So as I do with most people when I’m going through their LinkedIn before talking, I actually came across something I did not know about you is that did you really co-found compost peddlers?

Eric Goff: I did with my friend Dustin Fedakko.

Joshua Rhodes: Okay, so I don’t know if we’ve talked about this. Maybe we have. I was in East Austin at around that time and I saw your guys, maybe you, I don’t know, like riding these modified cargo bikes with basically blue barrels carrying compost around. Was that you?

Eric Goff: That’s right. That was us. We had, we called everyone the peddler. And I did some of the compost shifts, but we had part-time and full-time peddlers and launched it before we had municipal composting in Austin. And I think that maybe the best thing to say is that we accelerated the city’s own plans to municipal composting.

Joshua Rhodes: Right, right, right. It was just funny. Just, remember one time thinking, and this was also with like PediCab folks around that time before like e-bikes really kind of made it into where they’re the most fit people in the world riding tens of miles a day carrying heavy loads. It was insane.

Eric Goff: Yeah. Some of the hard part too is because it’s just pure literally inertia with another maybe grid thing, but you have to stop the bike and start the bike and stop the bike and start the bike with many, many pounds of compost in that barrel.

Joshua Rhodes: It was insane. All right. So I’ve already burned enough of our precious time talking about, but inertia is a good tie in. We’re going to get to the grid. So Eric, you do a lot of policy, a lot of policy consulting, a lot of policy work in ERCOT. For folks that either don’t live inside the ERCOT stakeholder world, which is the vast majority of people on this planet, how does policy actually get made in ERCOT? Where does it start and where does it continue?

Eric Goff: Sure. It’s a unique system that doesn’t exist in many other locations. And it’s changed some. I’m sure we’ll get into that since Winter Storm Uri happened. Historically, the energy companies in Texas, going back to the 90s at least, I wasn’t in the business then, so I’ve been told, were active in working together to establish what ERCOT would be and do. And they established this stakeholder process. At the time, it had a stakeholder board and it operated by having like a balance and continues to have a balanced group of buyers and sellers that many recommendations at the time of decisions. And if anyone doesn’t like something, you can appeal that to the public utility commission. But the process drives consensus because you have to get along long-term with your peers. Right. And so many things don’t end up being appealed to the utility commission. They just kind of get worked out. Everyone leaves a little bit dissatisfied, but it’s an effective process. Since Winter Storm Uri, for good reason, people were upset about how the process was working and, you know, there’s a lot of finger pointing. And so there was significant change to the process. So now everything goes to the utility commission ultimately. And the stakeholder process is more of like an advisory role to the commission.

Joshua Rhodes: Okay. And so are these the groups, the technical advisory committees, correct me if I’m saying these wrongs, and these working groups like the large load working groups, is this kind of where all of this is the negotiations happen and things are made?

Eric Goff: So ERCOT has offices in Austin and those meetings are technically open to the public, but they’re also broadcast online. State law has required that TAC, which is the senior stakeholder group, as well as the ERCOT board, have been accessible on the internet so anyone can follow along. During COVID, some people just kind of dialed in for fun. But the process has dozens of people in some cases, for many of these large load questions, hundreds and hundreds and hundreds of people that dial in to listen. But it’s many of the same people that speak that are kind of established figures in the stakeholder process have been around for a while.

Joshua Rhodes: In general, like, is the policy that comes out of these things, I mean, there’s negotiations, there’s consensus or some form of consensus or some things like that. How quickly are these groups able to move? I know there’s a lot of pressure right now on figuring a lot of things out that I want to get to, but how quickly are these groups able to move to make new policy?

Eric Goff: It depends on the issue. Historically, when I say historically, I’m going to typically mean like before Winter Storm Uri and after Winter Storm Uri. But before Uri, a lot of it was stakeholder driven and led. Then when the new commission and new board and new CEO came in to kind of right the ship with ERCOT and the grid, a lot more became.

Joshua Rhodes: Three years ago. Okay. Yeah

Eric Goff: led by ERCOT staff. Today it’s largely similar to how other independent system operators work, where the staff will recommend something, bring it to the stakeholders and ERCOT board and to the commission. And there’s back and forth dialogue among all three groups. I don’t think it’s more efficient than it used to be, but it is more public process.

Joshua Rhodes: Okay, well there’s some trade-offs there, I guess. I want to jump into probably one of the biggest, the hottest button issues that’s being worked out right now. And this is, you joked about hundreds of people dialing in, probably straining WebEx to the point where it’s not able to function anymore. I think I’ve been one of those flies on the wall a couple times. I want to get into, okay, everyone’s talking about load growth right now. What is actually happening?

Eric Goff: Right.

Joshua Rhodes: Let’s level set on kind of what is actually happening before we get into kind of like what the process we’re trying to build around this.

Eric Goff: Great. So ERCOT was the only North American market that had growing demand for electricity year over year for decades. And many others had stable load growth or very minimal load growth. And I think that’s driven in part by kind of state policy as well as just kind of the wide open spaces, lots of natural resources that are low ground and above ground, and there’s opportunity to grow. And also a growing population because of that. And so a lot of the growth was in new home construction, right? And that kind of stuff too. So ERCOT’s been used to needing new generation, not just to replace existing generation, but to serve demand. And a lot of that was happening and continues to happen from wind and solar and recently batteries and less so with more traditional natural gas and coal. Although that’s been happening too. And in the past couple of years, there’s an opportunity that was created, I think, because of the Texas market design, which is a lot of cheap electricity, or as is the trendy way to say it, either it’s an abundant amount of electricity or a dominant amount of electricity. Yeah, that’s right. And so that cheap electricity was an opportunity initially for cryptocurrency miners.

Joshua Rhodes: Come one, come all.

Eric Goff: where their main input is energy, right? Then with scale, other data centers, and we’re seeing cloud and increasingly AI data centers that the capabilities to do machine learning have been around for a long time. But to do it at the scale and with the incredible outputs that we are getting today, it’s using essentially the same process we’ve had since at least the 80s or not before. But you can do a lot more with when you have energy to apply to it.

Joshua Rhodes: Yeah, no, as a lot of folks, they’re surprised to find out that like the concept, the artificial neural network that underlies the large language model, we’ve known about these since the 1970s. It’s just like we finally figured out how to shove the entire internet into it. But when you shove that much information into it, takes a lot of energy to hold all of that information, particularly in like the training side. And speaking of like a lot of energy, was trying to find the latest numbers from ERCOT. Numbers just go up as far as I can tell. And so I haven’t believed them for years, but I think the latest one that I saw out there was something like 435 gigawatts of large load in our so-called large load queue. What is your sniff test on this? I mean, like how much of this is real? Like so.

Eric Goff: I have a crazy way to say it that I think is clippable, but then I’ll explain it. I think right now, the amount of demand for new data centers in Texas is infinite. Okay. And that’s because there’s no way to serve the amount of load on the grid that is desired by developers. Yeah. And so it’s just above the number that the grid can serve. So it might as well be an enormous number, right? And the constraint is the infrastructure side, not the demand side. So until we figure out how to serve that demand, it’ll continue to be more than we can possibly serve. And the difficult part of that is which one of those projects are going to get built and how do you know when, how do you plan for that infrastructure, and how do you make sure that those data center developers are paying for that infrastructure and not anybody else?

Joshua Rhodes: Yeah, and so that brings us into one of the processes that’s trying to be worked out right now is this whole batch zero process around, okay, which tranche of these new large loads are going to make it through. We’re setting aside transmission for these, we’re setting aside transmission capacity for these for like the first time that we’ve ever done anything like this before, as far as at least from what my understanding of what Pablo Vegas said to me the other day on the podcast. Can you talk me through where the batch zero process is right now? Like how much is in there? What’s it looking like? What are the milestones we’re at and where are we headed?

Eric Goff: Yeah. So we are a couple of weeks away from establishing a rule for Batch Zero. And Batch Zero is the one process to connect a large load in Texas. And that’s 75 megawatts or more, which is these days a small amount of load. Right. And so the reason we’re moving to a Batch Zero process is because

Joshua Rhodes: Seems quaint.

Eric Goff: There’s loads of big enough that they were affecting other load studies. And so they’d have to be restudied and restudied and restudied, which wasn’t leading to many approvals, which doesn’t help with that infinite demand problem. And so many of the developers and ERCOT collectively and the utilities all kind of came to this idea that we need to have a single system wide study. And the hard part is how you transition from individualized studies to a singular study. There are other challenges we can get into, but that’s the big one right now is you can’t study all 435 gigawatts or whatever it is, right? And so how do you pick which ones to study and which ones to ignore?

Joshua Rhodes: So I mean, one of the things we’ve had a generator interconnection queue for a while in a very like consistent process. Everyone knew what the steps were. We’ve recently been talking about this large load interconnection queue, like we actually had a queue in a process, but this like, actually didn’t, we just had a word we could put on there and we called it a queue and people thought it had a process. But you mentioned that before, it’s like, you can’t go from all these individual studies. So I mean, like, how was it done before this batch zero process?

Eric Goff: So the funny thing about governance is it just means making up rules in a way that we agree to make up rules, right? And so before the cryptocurrency growth that I mentioned earlier, it was just done by utilities. You requested an interconnection and they said, okay, it’s available in this timeframe. And that was generally within like the capital planning horizon and it was fine. The crypto facilities could build really quickly. And so we’re requesting really tight timelines that was shorter than the transmission planning timeline that ERCOT was used to. So it couldn’t keep up. And so for that reason, ERCOT tried to create this substitute process to plan for a transmission on a one-off basis. And that didn’t really work for a variety of reasons that, in the past, were not worth getting into, but quickly, for example, they didn’t actually create a constructable transmission plan. They just said, it’s feasible for a transmission plan to exist. And so one of the things that I’m excited about from this batch process is we are going to have a constructable transmission plan. And ultimately, I think all the problems are infrastructure problems in this energy market. There are secondary questions around like, market design and incentives and those are really important and I care and many other people care a lot about those but today it’s just about constructing infrastructure.

Joshua Rhodes: Yeah, I know that there’s like parallels in there with like the connect and manage that we’ve done for generators in there a while, right? Like you said, there was no transmission plan. Here’s an affirmation that it can happen or something. I’m just putting words in your mouth. Yeah. But it’s an interesting parallel there because, it seems like, correct me if I’m wrong, but like in general, we’ve often built transmission for load in ERCOT. Whereas like other grids, like in PJM, if you have a capacity construct, you’re often building transmission for generation. And you put the cost of those deep network upgrades like on the generator cost. Now, they’re having all kinds of issues and I’m going to talk about PJM with someone else later, or I hope I am. But like, this kind of feels like a little bit moving towards that kind of construct if we’re actually going to put together like transmission plan for these loads. But we’ve kind of done that in the past. Am I understanding that right?

Eric Goff: You are historically with one exception. We built transmission to serve load growth. And there’s this belief out there because of the one exception that a lot of the transmission is to build for like renewable generators. And we did that once and it was successful in getting a bunch of wind that was, you low cost energy. But the issue with that is how we pay for transmission. When we added new transmission costs from that and consumers pay for transmission costs, we didn’t add new consumers. We just added new wind generators. Energy costs went down, but transmission costs went up and people noticed another bill. What could be different about it this time is we’re adding new transmission costs and we’re also adding new giant consumers that will have giant energy bills to pay for that transmission. I don’t know which way it’ll go yet, but it’s entirely possible for the development of these new large loads to lead to lower energy costs and lower per unit transmission costs because you have more payers now than the increase in transmission costs. So I think that should be a goal of the state is to let’s make sure that as this change is happening. We do it in a way that benefits everybody and not just the new giant loads that are coming. We hear all these complaints and well-placed fears about what does this mean for me. There’s an opportunity through policy to fix that. So we should do it.

Joshua Rhodes: I mean, I think it can happen. I don’t think it’s a foregone conclusion that it’ll happen that way, but I think it’s possible. I’ve got some ideas on that, but this is a podcast where I’m interviewing you, not you interviewing me. We get to talk about that. I wanted to pull a thread a little bit on, okay, so you brought up crypto miners a couple of times. And one of the things about, particularly like when crypto was getting big, they talked a lot about their flexibility. About being controllable load resources, about being able to consume energy, you know, pay for infrastructure, but then like we’ll go away whenever things get tight. So one of the big debates right now around large loads is, you know, how can they participate in the market? Do they need to be flexible? Do they need to be controllable load resources? There’s these things around, if you have onsite generation, can you net that generation against like your consumption to appear to be flexible on the system? Are you bringing your own generation? My understanding of the way that it works right now is that if you are a load and you want to be a controllable load resource, ERCOT actually wants to turn the load off. They won’t allow you to net against local generation. And for crypto, that was fine because they were like, okay, just turn off the ASICs and whatever. They’re like, we’ll just hash them back up, not too long. But with a data center, they’re not so fine with that. Can you summarize the current thinking around like large load flexibility in Texas? Like where are we at right now? Where might we go?

Eric Goff: I can definitely do that. And I want to start with the bill that the Texas legislature passed last session with SB6. The legislators were very concerned about the growth of these new data centers. The time is very new. We weren’t nearly at the hundreds of gigawatts that we are now, but it was during the session, there was a giant new load forecast that was published and it made people very nervous. So peppered throughout that bill, the Senate and the house made sure that there are multiple ways that ERCOT and the utilities could turn off large loads before an emergency happens. Either by controlling the generation or requiring the installation of a disconnect device or technology, having a couple of different programs to do that. Whether you net against an existing generator to establish conditions so that ERCOT can take back control of that generator before an emergency. So, Before we get into the flexibility, the state has established rules to turn off all this new load if it gets to a crisis. And if, as I believe will happen, this also results in new generation, if you turn off all that new load but have all the new generation, all that new generation can serve the existing load. And that’ll keep the traditional native customers in a more reliable position than they were because this excess generation is there to serve these giant data centers that are offline during the emergency. But there’s also the question separate from like that operations thing for emergencies of like, how can we create incentives for them to turn off before we get to an emergency? So we don’t have to take those like strict, you know, mandated government functions. So the crypto guys, what’s different between them and the AI guys is they’re value of lost load. So like how much money do you make by consuming a megawatt hour of electricity? And for the crypto guys, was hundreds of dollars, sometimes less. And for AI, it appears as though it’s above the cap for electricity prices. And so they’re not going to turn off unless they have to. And that have to could be in two ways. One is we get to the emergency. Or two is there is some electricity available for you, but not 8,760 hours of electricity for you. And so you might be willing to say, sure, cut me off sometimes if it means I can use power three quarters of the year or four fifths of the year. It doesn’t appear as though that’s a super attractive option for these hyperscalers because while they definitely want speed to power, they also want to install these very, very expensive computer chips in a place where they can be used and useful. So if they can be used for four fifths of the year or be in a warehouse gathering dust, they might pick the four fifths option, right? But I think they’re hoping to find a place where they could be used like 99 % of the time. So we’ll see. The other issue is that ERCOT, like you said, wants to control the load directly. And that’s just how their systems are set up. Where they have separate resource entities for each thing and they want to measure what the thing is doing. I do think that there is an opportunity to use energy storage systems to provide that flexibility for these sites. I don’t know that every staffer at ERCOT agrees with me. This is an area of active debate. What is a uninterruptible power supply versus a battery? If it’s only behind the meter, it functions as a part of the load, never puts power onto the grid. It’s just consuming electricity and it’s a consumer. So I think that is and will be allowed and is kind of the next iteration of how do we have load flexibility for these data centers. Because the energy storage systems can be the flexible part of the load so that the data center facility doesn’t have to be.

Joshua Rhodes: Yeah, I mean, it seems like that would be a rather obvious step here. Correct me if I’m wrong again, but haven’t we had this issue with renewables and storage? People wanting to build batteries behind like one meter for like a solar farm and a battery. They’re required to be on two meters. Is this like the legacy of the policy we got right now?

Eric Goff: It’s a legacy of the policy and the systems. So the ERCOT IT systems expect these to be different things. They want to be able to model one thing. Even within a wind farm, 90 % of the turbines have to be the same vintage and variety. If you replace it with a modern turbine, you have to create a separate resource. It’s antiquated, but this is a problem we’re going to have to solve to think about like what is a dispatchable campus.

Joshua Rhodes: Okay.

Eric Goff: where you’re just putting out power at the point of interconnection. We’re more than capable now of having more than one kind of thing in a dynamic model. And so there’s no reason not to do it. And as these facilities are using as much power as cities, we’re going to have to figure out a way to have a dispatchable campus approach. And that’s going to take some thinking and policymaking, but I think we need to do it. And it could lead to innovations around microgrids. Micro is a funny word in this context, but it’s how we think of it.

Joshua Rhodes: Micro relative to what? You just defined dispatchable campus for me, but just.

Eric Goff: Yeah. So a dispatchable campus might be a data center or advanced manufacturing facility or a neighborhood maybe that has batteries, DERs, solar, maybe a natural gas or SMR, who knows what the future holds that are all dispatched at like a common point of interconnection to the grid. And the campus operator would be responsible for making sure that what they tell ERCOT they can do is what they actually do. Just like what we have with a generator today. It’d just be a more complicated arrangement. And ERCOT will probably still want to know, like, okay, if I’m relying on you to do something and you’re relying on a bunch of batteries, I want to know the state of charge of all those batteries behind or inside that campus and stuff like that. The technical details to work out. Another issue for the policy nerds that I know listen to the podcast is like, do they get a nodal price or do they get a zonal price? Here we go. Yeah. So stuff like that.

Joshua Rhodes: Yeah. I thought when I was talking to, had a recent interview with the folks at Austin Energy talking about the load zone and we went through that, generators get paid where they inject power, but load pays the load weighted average of the load zone that they’re in. And if you’re buying and selling both at the same time, or it does open up a real debate on where should you be netted at. I know you’re in a couple other regions as well. Like how is Texas doing relative to other regions in this? I think there’s a lot of data centers trying to come here. Our numbers are huge. So we’re kind of forced to try to build this plane as it’s going. Like how are we doing relative to other places? Are other places doing anything? And we’re just the ones that are figuring it out. How’s that look?

Eric Goff: Other places are doing kind of one-off things. We’ve seen some announcements of like fully integrated utilities like the Louisiana Entergy Meta deal, right? But that’s done through a bespoke arrangement, right? What happens here, because we have competitive wholesale and retail markets, lots of land, no zoning rules in the counties, and abundant solar and wind and abundant natural gas, you can just kind of move quickly. You don’t need to ask nearly as many permissions as you do in other places. And then I can’t wait for you to get to your PJM conversation soon because here the people that are doing the things are the ones that pay for the things for the most part. And in PJM, when the capacity market is being set by all these new data centers, everybody pays for the new data centers. It’s a crazy, crazy system. It’s not functional and they know that and so their market system in quotes is breaking.

Joshua Rhodes: Yeah, I mean, we won’t get into it on this, PJM just put out a paper where they have broached the idea of getting rid of the capacity market and going to like an energy only market. May do something like, remember the LSCRO thing that we considered briefly like years ago? They do something like that to soften the blow. I don’t know.

Eric Goff: Yeah, they may. Yeah. I can’t wait to watch from afar, but ultimately the reason that we’re here is just because it’s worked, you know, and it’s not perfect. We haven’t figured out the ideal energy market and you can’t go down to the corner store and buy a bag full of megawatt hours. Right. So we have to have a construct. Totally. Yeah.

Joshua Rhodes: Exactly. Yeah, totally. And we’ve touched a little bit on this. One of the big things, you said infrastructure multiple times and a lot of that is transmission. That’s one of the hardest pieces of the system to build. I mean, traditionally we’ve planned transmission around reliably serving load. We tell ourselves we have an economic test for transmission, but then every once in a while we build these big tranches. We referenced the CREZ lines earlier. We’re doing it with this Permian reliability project, STEP project, you know, East and West. Even the current set of like, you know, 765 backbone was really pre AI and data centers. I mean, a lot of it was focused on serving oil and gas load out in the Permian. Does transmission planning need to change with this current set of drivers being new massive loads outstripping historical growth rate?

Eric Goff: Yes, and it is changing, but it needs to change even more. So ERCOT has said multiple times that it’s time for a new era of transmission planning. That’s the phrase they use. And this 765 decision is a generational shift in how we build and plan for transmission. I’ve heard long time veterans of the industry say that their earlier generation was

Joshua Rhodes: Okay, tell me about it.

Eric Goff: So happy, so like two generations of engineers ago were so happy when they went from 138 to 345 because it made such a big difference. This is very much like that where it’ll enable moving a lot more energy across the state a lot more efficiently with fewer big power lines because you can move so much more energy on a high voltage line. So there’s a lot of growing opposition to these lines that you mentioned from people that don’t want to see them on Pretty Vistas. The alternative is more lines, not fewer lines. So that’s one thing where ERCOT is looking to do this unified approach to transmission planning that integrates all of the variety of transmission planning they do today into one process that’ll be modeled on this batch process. But when we do that, we need to modify the way we look at how consumers benefit from these transmission lines. One of the things that’s held up investment in transmission in the past is skepticism over changes to how we say that a project is economic. Because you’ve talked about connect and manage where a generator can build wherever they want and suffer or benefit from the dispatch they get. And so if we have a system where a solar generator can build in the desert in the middle of nowhere on a 69 kV line, and then suffer curtailment, then consumers pay for the transmission line to help them reduce the curtailment. It’s just not something that was persuasive to many of the large companies here in Texas that pay a big share of the transmission lines. And maybe it could be economic or maybe it couldn’t, but when the people that are pushing for it or the generators that would directly benefit, there’s just intense skepticism. Is this for you or is this for me? I think the way we solve that is just by saying the reason we plan transmission economically is to benefit consumers. If you can prove the consumer benefit, great. And if it so happens then that the way we save consumers money is by paying for a transmission line that increases the amount of solar output from that far away generator, great. We prove that it’s benefiting consumers. And then incidentally benefiting the solar generator. So we have to do that.

Joshua Rhodes: Yeah, I’ve often cast CREZ and the New Step projects. It’s not even just about the electricity sector. It’s really a total economic enabler for the state, right? It’s like the state runs on energy, oil, gas, electricity. And so it’s like the better the sandbox is, the more efficient that system is. Like it’s not just getting the cost of electricity down. It’s the cost of everything else that we use the electricity to build the thing that we sell around the world. I don’t know. I’ve been more framing it that way. I don’t know. What do you think about that?

Eric Goff: I think that’s really true. Another related issue is like we’re having all this interest in co-locating generation and giant data centers in ways that will like impact communities because you need the data center near where the jobs are, which means you need the generator near where the people are. And transmission doesn’t exist at the scale to move a gigawatt of power a few hundred miles away to the data center near where the jobs are. So we can’t have a financial arrangement to have like a power purchase agreement to buy a thousand megawatts of power from some random place. And if I can’t physically consume the energy at my location, and that’s why I keep coming back to infrastructure. Once we have investment in transmission, we’ll have investment in generation. It’s a necessary predicate with this scale of large loads.

Joshua Rhodes: Yeah. And tying together a couple of those before we move on is like, we’ve done connect and manage for generation. It’s possible maybe to use some of that inertia to connect and manage for load as well. Like if we can get this like behind the meter netting issue thing. Cause I agree with you. I don’t think the data centers just don’t want to turn off, right? It’s just the perceived value of the tokens and the product and everything they’re making is just so high. They’re just like, no. So talk about infrastructure. We’ve talked about transmission. Do we need to plan it differently? But also, I mean, we’re also talking about it, we’re going to pay for it differently, right? I mean, this is like just the Public Utility Commission staff just released their recommendation to go from a 4CP where we calculate how much of the transmission year owed from the four highest 15 minute intervals of ERCOT serving load in June, July, August, and September. And they’re recommending a 12 coincident peak. So all the months in the longer time, a 30 minute period, why do we need to change or do you believe we need to change how we pay for transmission? Why are we going down this path?

Eric Goff: Yeah, so this can get really complicated really quickly, but essentially the way that it works today with 4CP is you look at how much people used and the peak moment of June, July, August, September compare that to how much everybody else used in that same peak moment. And then it creates a ratio of you versus everybody else. And we have assumed demand charges for small commercial and residential. We don’t measure the actual demand. But it’s effectively that. And that ratio is how much you have to pay for all of the transmission costs for that year. So there’s been this incentive for large users to reduce how much they’re using during those four times, and they all have to do it momentarily, and it doesn’t substantially change the amount of spend that we have on transmission, certainly not in that year. Maybe hypothetically, over time, if that happens every year, reduces the amount we need five years from now, maybe. So it’s cost shifting. And, you know, the utility commission staff and their analysis and then the analysis of the Office of Public Utility Counsel, who represents residential and small commercial consumers in this state, residential consumers are paying today more than they should be. So the fear that the legislature had... Because of how the crypto facilities were operating when they were curtailed during those time periods, is that we would spend billions of dollars on more transmission and the data centers would curtail and avoid paying for it. So the last section of SB6, the bill that is regulating the data center construction, is to evaluate 4CP and consider changes to it. And so the PUC, I think, is very interested. The legislature is very interested in making sure that they’re protecting consumers against the existing issues that are already there, as well as this potential for it to be even worse. And so in response, many of the large data center developers or trade associations, my clients, I’ve been proposing on behalf of some of these people, a minimum charge for transmission. Which would be instead of based on the amount that you actually used, it’d be based on some percentage of the amount you contracted to use from the utility. If you have a thousand megawatt data center and we have like a 50 % charge, then it can be no less than 500 megawatts of charge no matter what you use in that equation. We’re working on analyses to figure out what the right level of minimum charge is in order to protect all the other ratepayers in the state from increased costs. And, you know, hopefully we’ll have some good evaluation from that in a few weeks. That’s kind of a really pending question. And so with that context, 12 CP or 4 CP doesn’t really matter. In each one of those measurements, you’ll use the minimum transmission amount instead of the actual transmission amount. So there’s no incentive to try to avoid the cost, right? They could still choose to curtail and connect and manage based on the energy price, right? We want them to respond to energy prices, avoiding transmission charges that other people have to pay for. Yeah, I don’t know if that’s an incentive that we want, right?

Joshua Rhodes: I get it. But I mean, recently, the peak demand and the energy price are divorced, right? It’s like, we used to, oh, 4pm on the hottest day in August is coming, like, ERCOT’s going to peak out, prices are going to be in the thousands because we have scarcity pricing and now we’ve got 35 gigs of solar and it’s just $5, $10. Like, even ERCOT’s peaking and like prices are nowhere near the cap. And so people have talked about moving it to net, but we’re trying to pay for transmission. This is when we’re actually moving the power across the system, right? It’s like,

Eric Goff: Exactly. What a great problem to have is when you’re peaking out the system, energy cost is five bucks. That’s a great problem to have.

Joshua Rhodes: No, it’s better than the alternative, right? But it does seem like it kind of misaligned some of those incentives. I guess we’ll see how it shakes out. I wanted to drop down into the distribution area, but I think we’re kind of running out of time. So I know you’re a huge fan of like the energy only market. Do you think that it can survive all of this? All of like low cost, like the zero marginal cost generation, hyperscale load, the increasingly sophisticated financials that are happening around it? Can the energy market still work here?

Eric Goff: I think it continued to work and perform admirably because when you have zero marginal cost units that are sharing the price most of the time, that’s a great problem for consumers to have. And that’s what led to this opportunity for growth is there’s a lot of cheap energy. And when there’s not enough energy, the price gets very high. And so that’s a strong incentive to keep the existing stuff working. Or to not use energy during that time. And if it happens often enough, then it creates an incentive to build new generation or to better maintain existing generation. Right now, the cost of new entry for a new generation is being set by the hyperscalers, where they’re paying whatever it costs to get new generation to co-locate because they don’t have the transmission they need yet. And so we don’t have a market that’s meeting kind of the old cost of new entry, let alone the new cost of new entry. But functionally, that’s okay because we’re getting the investment in generation, right? And so I’m really curious what happens next. Will we have merchant generation that can pay the price of the cost of new entry? Not until we have transmission where you can transact across it and like deliver via financial PPA, just to connect something to some local listeners. Maybe now is not the best time to be a utility buying a turbine. But that’s a separate question.

Joshua Rhodes: Now we’re really tying together a couple of different podcasts. All right, so last question. Looking at these load forecasts, these load forecasts are really interesting because like, if you look historically, we grew at like two and a half percent or something like that. It’s like the next five years that everything just goes crazy. And then, I mean, forecasts are hard, especially about the future, but then it basically kind of returns to like a pre now crazy, like normal. Now I don’t know that I believe any of it.

Eric Goff: Ha ha ha ha ha.

Joshua Rhodes: So five years from now, if you’re looking back, you’re traveling in the future, you’re looking back, what will people say about how Texas beat the odds and did it and kept the Texas miracle going?

Eric Goff: It’ll be because we paid for infrastructure. And ideally, when I say we paid for infrastructure, the state allowed it to happen and made sure that the significant substantial payers of that are the new loads that are coming in. And we can totally achieve that. And we just have to try and it’s going to be a significant infrastructure challenge. To the extent we don’t build enough infrastructure, though, we’ll just get fewer data centers, we’re still going to get as many data centers that the infrastructure can support. And so the real question, and I don’t think anyone knows the answer to this question yet, is like, what is that actual demand for new data center facilities? And AI, whether you like it or not, is being integrated into every part of our lives, and that is going to take energy. And so I think from a public policy perspective, it’s like, OK. With this enormous investment in the grid, how can we make sure that sure we get what the AI companies want, but we also are benefiting every single use of electric grid at the same time. And that’s how we can get that miracle.

Joshua Rhodes: I think if anywhere is going to be able to do it, I think it’ll be Texas. I mean, we built the CREZ lines to get the wind, but then that allowed us to electrify oil and gas. And so now we’re building these Permian reliability projects, electrify oil and gas. That’s just going to get us more solar territory. But it’s just building that whole thing. We seem to every once in a while get it. OK, a big tranche of infrastructure now that’s bigger than any one particular project would be a good idea to let everyone to let the markets go and let the miracle continue. I think I agree with you on that. I think if we’re able to look back in five years and say, did we beat it? It’s because we built the infrastructure that let the market do it. Eric Goff, thank you for coming on the Energy Capital Podcast.

Eric Goff: My pleasure. This was a great conversation.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

Austin Energy’s power generation hit the 65 percent carbon-free level in 2024, and the municipal utility is targeting 100 percent carbon-free load by 2035, one of the most aggressive clean energy targets of any utility in Texas.

Austin Energy is one of the largest municipally owned utilities in the country and one of the few vertically integrated utilities operating inside ERCOT’s deregulated market. As the utility plans for load growth and rising ERCOT market exposure, it is also preparing the community to weigh the trade-offs that entails.

In this episode, Joshua Rhodes speaks with Stuart Reilly, general manager of Austin Energy, and Lisa Martin, the utility’s chief operating officer. Reilly and Martin walk through how the muni model shapes new load evaluation, renewable contract structure, and community engagement. They describe a resource plan that combines local generation with utility-scale batteries, distributed energy deals, transmission upgrades, and demand response.

Joshua, Stuart, and Lisa discuss topics including:

* What it means to operate as a vertically integrated muni inside ERCOT’s competitive market.

* The 500 megawatts of plausible new load Austin Energy is planning for, and why most of it is not data centers.

* How load zone price separation has changed the hedging value of distant renewable power purchase agreements.

* Why the resource plan calls for new local generation alongside more clean energy procurement.

* A new 100 MW battery deal with Jupiter Power and a 40 MW distributed deal with Base Power.

* How the utility returned over $100 million to customers from Winter Storm Uri.

* How Austin Energy communicates reliability, affordability, and clean energy trade-offs with its community.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Intro, Stuart Reilly and Lisa Martin

* 01:11 - Austin Energy as a Non-Opt-In Utility

* 05:47 - Planning for Load Growth, Why Gas Peakers

* 09:25 - Sizing Real Load vs the ERCOT Forecast

* 10:49 - New Loads, New Costs, Who Pays

* 12:13 - Load Zone Separation, Explained

* 14:02 - Decker Retirements and Local Generation

* 16:51 - PPAs, Hedges, and the $850 Problem

* 18:26 - How a Gas Peaker Fits a Carbon-Free Goal

* 23:53 - Why Local Power Enables More Renewables

* 26:43 - Communicating Complexity to Customers

* 31:19 - Jupiter Power, Base Power, and Local Storage

* 36:08 - Distributed Batteries and Distribution Costs

* 40:25 - Closing Thanks and Outro

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Stuart Reilly (LinkedIn)

* Lisa Martin (LinkedIn)

* Austin Energy (Website - Executive Leadership Team)

* Other Oganizations Mentioned

* ERCOT (Website)

* Jupiter Power (Website)

* Base Power (Website)

Company & Industry News

* Austin Energy signs Battery Storage Deal, Advancing Climate and Reliability Goals

* Austin expands renewable energy push with major solar generation investments - Community Impact

* Texas grid operator’s demand forecast likely an overestimate - Texas Tribune

* Austin Energy 2035 plan sees challenges and successes one year after adoption - KXAN

Books, Articles & Reports Discussed

* Austin Energy Resource, Generation and Climate Protection Plan to 2035

* ERCOT Preliminary Long-Term Load Forecast 2026–2032

* Aggregate Distributed Energy Resource (ADER) Pilot Project

Related Podcasts by Energy Capital

* All Energy Capital Podcasts

* Texas Growth Is Running Into Power Grid Limits with Katie Coleman

* Who Pays for the New Grid with Pablo Vegas

* Creating a Distributed Battery Network with Zach Dell

Related Posts by Texas Energy & Power

* Process is Killing Texas Data Center Projects

* Transmission Takes a Decade, Load Doesn’t — with Raina Hornaday

Transcript

Joshua Rhodes: Hey everyone, welcome to another edition of the Energy Capital Podcast. I’ve got not one but two guests for you today, both from the C-suite of Austin Energy, one of the largest municipal utilities in the country. It actually ranks as the eighth largest publicly owned electric utility in the U.S. And it serves about a million folks in the greater city of Austin. So today we’re going to be talking to Stuart Reilly, who’s a current general manager of Austin Energy. Stuart has spent about 20 years in service of the city of Austin, starting as assistant city attorney, before moving up to various roles at Austin Energy. Lisa Martin is currently the Chief Operating Officer at Austin Energy, but she’s also spent times before at SoCal Edison, going through energy supplies and contracts and other types of things. And also from her LinkedIn, found out that she had something to do with subsea surveillance at Shell, which I actually want to just throw out all of the questions I have for you guys and focus just in on that. So sorry, Stuart, if we don’t talk about anything that we were going to talk about, but having found this out today. I’m really excited to have both of you all here to talk about Austin Energy. So Stuart and Lisa, welcome to Energy Capital Podcast.

Stuart Reilly: Thanks Josh.

Lisa Martin: Thank you, glad to be here.

Joshua Rhodes: So in this podcast, we talk a lot about energy. We talk a lot about Texas energy. And a lot of times when we’re talking about ERCOT, we’re talking about the competitive regions of the system. And most electricity meters in the state of Texas are in kind of the power to choose region. But there are some parts of the states that are different, one being Austin Energy, the other being the City Public Service of San Antonio. And a lot of the co-ops are actually these things called non-optin entities. Stuart, can you explain kind of what those are and kind of how Austin Energy fits in the energy mix in ERCOT and in Texas.

Stuart Reilly: Yeah, absolutely. And Austin Energy has been around since 1895. Like you mentioned, we serve about a million residents, 580,000 customer accounts, homes and businesses. Not just in the city of Austin, but kind of in the Travis County region, we serve 11 other cities in our area and unincorporated areas of Travis County. Currently the third largest municipally owned utility, but operating in the ERCOT market as a non-optin entity. So because our history kind of goes back to this 1895 period when investor owned utilities didn’t want to come to Austin, our city decided to start this journey on its own, build a dam, build a powerhouse that served as the first street lighting system, the moonlight towers that we still have here in Austin. Even as the market evolved and even after the competitive market in Texas and ERCOT came to be, we still operate as vertically integrated utilities. So we still have generation, transmission, distribution, and retail customers. And we do all of the customer service functions for the city of Austin. And so while we’re a vertically integrated utility in Texas, we still have to compete in the ERCOT market. Our generation, we still sell all of our generation into the ERCOT market and we buy all the load to serve our customers out of the ERCOT market at the Austin Energy Load Zone. So even though our generation used to directly serve our customers, now it’s operating and bid into the market just like anybody else is operating in that ERCOT market. So really when you look at us as a vertically integrated utility in Texas operating everything from end to end, I think we have the ability to do more of what’s in our community’s best interest. Because if you’re just operating in the ERCOT market as a generator, your interest is in generating more and that’s where your income is going to come from. For us, it’s really looking at the whole picture of what is the best outcome for the customer leading with our values. We’ve been trying to sell less of the thing that we sell. So if we’re a generator, we’d be generating more. If we were a rep, we’d be trying to sell more. So that’s really enabled us to be ahead of the game when it comes to energy efficiency programs, rebate programs, solar programs, getting our customers to do things on the customer side that get to better environmental outcomes. Because we’ve been talking for years of decades, even in Austin, about how a kilowatt reduced is cheaper than a kilowatt produced. So if you’re looking at getting to cost effective environmentally friendly outcomes, we think we have that kind of advantage by looking at the whole picture by serving customers and operating as a generator in the market.

Lisa Martin: And I’ll just add in that I think being municipally owned has really helped us get where we are in terms of being a leader in the energy transition because our public and our city council are so engaged. And so, you know, for right now we’re implementing our resource generation and climate protection plan to 2035. And a lot of it involves going out into the community and talking to them and saying, Hey, what is being a good utility partner look like to you? What do you expect out of your utility? And so we get lots of feedback from the community and our city council, and that all ties into what we’re working on.

Joshua Rhodes: That makes sense and I want to dig into quite a bit of that, but Stuart, you actually brought up a really good point about some of the first uses of electricity in Austin being our famous moon towers. I just want to verify these are the same moon towers where the dazed and confused party at the moon tower be there comes from, right?

Stuart Reilly: Yeah, and we have a little history center here in Austin Energy that shows some of that. And I think Matthew McConaughey is playing there around the clock telling people that there’s a party at the Moon Tower. I think that that really sparked a new level of understanding and appreciation for our iconic Moonlight Towers, which we still operate after all these years and they’re designated as Texas Historic Places. We’ve been out in front of the energy transition, but we also hold on to our past in some ways. And that’s just kind of a fun example.

Joshua Rhodes: That’s great. So we’ve talked a little bit about energy transition. There’s an expansion going on because load is really looking to grow. Can you explain, like you touched a little bit on how Austin Energy sees things a little bit different than like a traditional generator. How would a place like Austin Energy be planning for like continued load growth? I’m thinking from like data centers and other types of these new loads. That are coming to the state. Know Austin’s kind of the tech hub of the region. And so we’ve had data centers before, we have data centers, but what are you seeing out there that’s different?

Stuart Reilly: Yeah, I mean, right now as we’re implementing our resource generation plan and we’re implementing our electric system reliability resiliency plan, we’re making upgrades to pretty much everything. It feels like there’s never been a time at Austin Energy where so many things have been all happening at one time and all the challenges are kind of stacking on top of one another. And as you say, the load growth and what the projections that we’re seeing. Just jump off of the page when you look at that and there’s a significant amount of uncertainty around that and that poses a challenge of its own. But whether it’s looking at customer side resources, transmission import capacity, adding generation, we think we need all of it. Our resource plan is an all in plan. Right now we’re looking to add gas peakers. Frankly, we wish we didn’t have to, but there’s really no other solution that could meet that need from a reliability and a market protection standpoint. But we know probably better than a lot of places that load growth is real. This growth is happening. The Austin economy, you know, the Texas miracle, all of this has been happening in the background. Think for years, it seems like the energy transition has been in progress. We’ve been moving along. We’ve been making great progress and it’s been happening in the background. People really haven’t had to think about it a whole lot. But if Winter Storm Uri didn’t change some of that, where a lot of people who never heard of ERCOT before now worry about it. So if that didn’t do it now, it’s AI data centers and the worries around that and where our power is going to come from. And so we know that it’s something we need to get ahead of. We’re probably behind the curve on this a lot. We expect that it’s going to continue. We have a team, our key accounts team, that fields calls from new customers all the time. Some larger than others. And it used to be that they were interested in larger and larger and these large load customers might’ve asked about 200 or 300 or even more. Now it’s how much power can I get and how fast can I get it? Many of them are looking outside of the Austin area because we have a pretty compact service territory. Even if they’re going to be outside of the service territory. The Austin Business Journal recently showed a map of all the planned data centers, for example, outside of circling Austin. Even if they aren’t within our service territory, they still pose a challenge for us in terms of how we’re operating in the market, what is going to happen in terms of scarcity and pricing and us needing to have the resources to protect our customers from that market volatility that that can bring. But as our team fields those calls from these potential large customers, we put these into categories of how likely those are going to come to fruition. Not just a study or not somebody who’s just kind of kicking the tires, but things that are really likely to occur here in Austin. And in that category, you know, roughly we’ve got about 500 megawatts worth over the next few years. And that’s on a 3000 megawatt peaking system. It’s. Not what some other utilities are up against, but it’s not insignificant either.

Joshua Rhodes: Would you be able to say like 500 megawatts? I mean, would you be able to say you talked about sifting out kind of the things that probably aren’t real. Can you say what the other side of that would be? Like how much is that 500 megawatts of 50,000 megawatts or what is it? I mean, we’re all trying to grapple with like how much of this stuff is real, right?

Stuart Reilly: Yeah, absolutely. And with the report of the ERCOT grid quadrupling by 2032, I mean, we all know that’s not going to happen. It physically can’t happen, but even if it’s only a third of that, that’s still the ERCOT grid doubling. So it’s that uncertainty does pose a challenge of its own. And one of the things that I’ll say about that is, you know, we have a really diverse customer mix in Austin. We’ve got obviously a lot of government. And universities, we’ve got the high tech. Some of that large load is large infrastructure projects that are coming to fruition or Project Connect, you know, is going to be a large customer for us. So a lot of what we’re seeing in terms of load growth that we’re preparing for is beneficial electrification that’s going to also have a very good environmental outcome that comes with it. I think people, when we talk about load growth at Austin Energy, people jump to the conclusion that it must be data centers and it’s really not. That’s not what we’re seeing here. It’s more of a healthy mix of the types of projects you would like to see.

Joshua Rhodes: And Lisa, when looking at some of these new large loads, is it changing how a place like Austin Energy has to make infrastructure investments? I mean, we’re a compact utility. Are any of these new large loads changing how the planning studies are going for y’all?

Lisa Martin: We certainly have a lot more of the planning studies because lots of people are asking the question to say, can you serve me? And we can’t just answer that question without doing some sort of analysis. But the fact is that we have an obligation to serve our customers, but we’re very honest with them to say, it’s not a matter of whether we can serve you, it’s can we serve you now and what kind of upgrades are necessary for that. And so a lot of times it’s let’s do the analysis and then they decide if they want to move forward knowing what the ultimate timeline is and what the cost is. I think this is an important part about the infrastructure planning is that additional infrastructure is going to ultimately cost more. And so we have policies in place to protect all of our existing customers from the added cost of that new infrastructure by making the new loads responsible for the cost it takes to serve them. And as Stuart said, in terms of our planning, it’s not just about what load is coming here to Austin. It’s also about making sure that we’re taking into account what loads are growing outside of Austin. We know for a fact that it’s going to change the way power flows across Texas. And so it’s one of the reasons that makes local resources so important to our particular service area.

Joshua Rhodes: I want to get to the resource management plan and other types of things. You’ve both mentioned how loads that are not even inside of Austin Energy but around Austin Energy can impact the system. Can you break down why is Austin Energy impacted as a load zone? Well, how is it impacted by these large loads around it? And where are the ramifications for the load zone? And what does that mean for customers?

Lisa Martin: Yeah, you know, when Stuart started, he talked about how diverse our portfolio is from an energy perspective. And that’s not only in technology and fuel type, but it’s also in geographic diversity across the state of Texas. And that’s one of the benefits of being part of the ERCOT market. But what happens is if we end up saying that all these resources act as a hedge, if you will, in the market to offset what our costs are to serve our customer’s load. And if we have a bunch of resources that are across the state of Texas and there’s not the power flows, the transmission capacity to bring that power here to serve our customers. And I don’t exactly mean how the physics are exactly flowing or the electrons are exactly flowing, but we run into a problem where we aren’t able to serve our load here locally. So if we can’t bring it in from the outside and or generate it here locally, then we run into a supply demand problem that really becomes very hyper localized. And so when we talk about large load growth across the state of Texas, we know that’s going to change the way power is flowing. There’s also a lot of transmission upgrades that are happening across the state, but the fact is the grid is highly, highly dynamic, and all of that’s going to play a part in determining how our customers are served in the future. So we have to care just as much about what load growth is happening outside of our area to make sure that we can reliably and affordably serve our customers within our service area while also still advancing our clean energy goals.

Stuart Reilly: And Josh, one thing that I will just add to that, we had the Decker Creek power station in East Austin, and there were two gas powered steam units at that power plant. And we retired the first one, 300 megawatts, I think, in 2020. And the second one in 2022, that was 425 megawatts. So 725 megawatts of local generation retired. And so once that happened, we started to see our load zone price separate from the rest of the market, because then it becomes a question of how much the transmission lines, how much import capacity we have to bring the power in once we can’t make up any kind of difference with local power generation. And so we have a lot of projects underway to increase our transmission import capacity, about a hundred million dollars worth of projects per year for the next five years on our CIP plan to increase our transmission import capacity. But some of that is not going to be inside our control because we could move the bottleneck somewhere else. The pinch point moves somewhere further upstream, and then we still have that constraint of the amount of power that we can bring in. And so that’s why we’ve been talking a lot with our community about local resources.

Joshua Rhodes: Maybe I can get y’all to correct me if I’m wrong, but just to kind of like level set for like, a lot of folks don’t realize that like generation and load pay different prices in ERCOT, right? A generator gets paid at the node at which it’s injecting power in the system. And there’s like 10,000 nodes across the whole system. There’s thousands of generator nodes. Theoretically, each of those could be a different price, but load pays like a load weighted average of the load zone, right? So there’s certain number of like nodes that kind of are grouped. There’s a couple of big ones. Couple big load zones, north and south and west, but then there’s like Austin Energy has its own load zone. And so like the price paid for electricity by Austin Energy is like a load weighted average of the nodes within the Austin Energy load zone, right? And so if those nodes happen to be higher than other places, then prices would be higher in the Austin Energy area, right? And so I know we have a lot, I know Austin Energy, I’m saying we because I should probably remind everyone that I’m a commissioner on the Electric Utility Commission for Austin Energy.

Stuart Reilly: And thank you for your service on that. We appreciate you.

Joshua Rhodes: Yeah, I appreciate it. But like a lot of the power plants that like Austin Energy has contracts with wind, solar, all these stuff, like, you know, the wind’s not super great here in Austin and we have a lot of other projects elsewhere. Can you talk about the difference in kind of like what you’re getting paid for that electricity versus what we’re paying here? tried to lay it out a little bit, but you do this every day. I just pretend to do this.

Stuart Reilly: So yeah, we end up talking to our customers and our stakeholders a lot about this issue where we’re receiving a different price at the generator from what we’re paying to serve our load. So for example, if we have a wind farm or actually let me say a solar farm out in West Texas, if we’re paying under a PPA for that solar farm $50 a megawatt hour and we’re receiving $50 in the ERCOT market at that node, then we’re even. That’s been a good hedge except that we then need to buy at our load zone to be able to serve our customers. And the whole reason we own generation is to act as a physical hedge against ERCOT market volatility. So if our load zone separates from the rest of the market, let’s say in the solar ramp down period of time in the summer, 9 PM and prices are at $850, that distant renewable that’s earning $50 versus what we’re paying at our load zone, it’s not acting as a hedge anymore. We can’t use those types of resources to offset our customer load anymore. And the challenge there is if, unless we have something that can collapse our local load zone price, it’s very hard for us to add more and more and more renewables because then you just end up adding more and more of a cost, but you can’t use those renewables as an effective hedge. So if we can collapse our local load zone price with local resources, that actually enables us to add more renewables throughout the state, throughout ERCOT, that could effectively hedge what our market exposure is and protect our customer bills.

Joshua Rhodes: Austin Energy has set some really strong clean energy and climate targets and along with the city and other pieces. But as we’ve mentioned, one of the things about the latest generation plan is that it calls for a gas peaker and it’s related to this issue of this load pocket price separation and other types of things. So can you just lay out how you see it working in the system given the clean energy goals in the climates? We’ve touched on it, but how does it fit here?

Lisa Martin: How do natural gas peaker units fit into the system? Is that what you asked?

Joshua Rhodes: Right, yeah. So in particularly like the one that’s being proposed in the resource management plan, how does it fit in terms of like Austin Energy’s goals?

Lisa Martin: Yeah, so Austin Energy does have very advanced clean energy goals. We are industry leading on that front. And one of our goals is to be 100 % carbon-free generation as a percentage of load by 2035. And that’s a lot of words that sometimes gets confusing. And so how I like to explain to people is that our objective, our goal, is to be able to serve 100 % of Austin Energy customer usage with carbon-free generation in 2035 and beyond. And so that doesn’t necessarily preclude other resources from being part of the portfolio. We definitely look forward to the day when we don’t need any emitting resources in the portfolio, but we recognize that technology has to be an enabling factor to get us to a place where that’s the case. And so right now, natural gas peaker units remain a very key part of the energy mix, especially as the energy landscape continues to evolve. Stuart just talked about the load zone price separation. That’s literally the ERCOT market telling us that we have a reliability issue. It’s an economic market that is suited to create a reliable grid for Texas. They use price signals to say, you don’t have enough supply to meet your customers’ needs. And that becomes a physics problem for us. If we can’t get the power to serve our customers, then we run the risk of having local controlled outages. And that’s the situation where we have to turn off people’s power here. Because there’s no other way for us to serve them. And the rest of customers across ERCOT would be fine. It’s because we have a local reliability issue. And the story really goes back way further than this. But even if I just go back to the beginning of this decade, Stuart also mentioned that since 2020, we shut down two of our largest local resources. That’s 725 megawatts of local generation that’s no longer available. We absolutely needed to do that because of age and wear and tear. And in support of our clean energy goals, taking those units offline removed our highest emitting local sources from the area. But the trade-off is that now we’re basically operating at a deficit. And so that’s at a time when now we’re seeing year-over-year new demand peaks, both in winter and summer. And then there’s also other changes in the air-cut market. We talked about the load growth, the large loads, and things like that. Also, extreme weather happening. So the natural gas peaker units are one of the various tools that we think we need in our portfolio. We sometimes call this all the tools in the toolbox to mitigate various risks. So natural gas peaker units, when it comes down to it, they provide the grid reliability when the demand threatens to exceed the supply. That’s really what’s signaled by load zone price separation. They provide for your long duration energy needs, especially for extended time periods and extreme weather. And then most importantly, they provide black start capability. And that means that if the worst case scenario happens and the entire ERCOT grid goes dark. You have to have certain units that can start up from nothing. And we have some, but they’re aging. And I wouldn’t want to rely on them for too long if the worst case happens. So we need natural gas peakers in use as that resource.

Stuart Reilly: Austin Energy, I think if we can solve the reliability piece, we can get back to what we do best, which is clean energy. That’s sort of in our DNA. And so what we’re looking to do is solve the reliability equation and get cleaner and cleaner and cleaner and keep executing. We’ve been setting records in recent years with local solar demand response records, you know, adding batteries. We’re bringing more batteries for, we’re already about to exceed our brand new battery storage goal and we’re going to even add more. And so that’s kind of been the history of Austin Energy is setting targets and then exceeding them. But in terms of how gas fits into our goals, I think they can actually enable us to more effectively meet our goals. And part of the reason why I say that is I think it’s been 2016, 2017 is about the last time when we did a large renewable energy PPA for Austin Energy. And I used to work on those contracts. In that market for new clean energy resources, it was easy. There were a ton of bids, the prices were very good. They acted as an effective hedge for us. And now what we’re seeing is the pricing isn’t as favorable. There aren’t as many projects coming to fruition looking for off-takers and they don’t act as a good hedge for us because our load zone is separating from the rest of the market. So that signal of that supply and demand equation, where if you can do something that solves for that reliability piece, then we can get back to executing on more clean energy projects, which is just what we’d love to be able to get back to.

Joshua Rhodes: One of the key things I think you said in terms of, you if we’ve got this load pocket price separation between Austin Energy and the rest of ERCOT, having more renewable energy contracts, more PPAs isn’t really helping out. Did I hear you say that having the plant lets you get more renewable energy? Can we pull on that thread just a little bit more? Because I think, I don’t know, that’s a bit counterintuitive perhaps.

Stuart Reilly: Right. And it’s counterintuitive that it wouldn’t actually do anything negative towards our carbon free as a percent of load goal, because the goal isn’t whether or not you have peakers available or not as that reliability backstop that you might need. The goal is, do you have enough renewable energy, carbon free energy to cover your load, to serve your customers? And so pulling on that thread a little bit. Having a resource that can turn on at the time when our load zone has separated from the rest of the market can immediately collapse that market price and those critical times. And then those contracts for those renewables that we have cited elsewhere can actually function the way that they’re supposed to in terms of being a good market hedge and providing a market resource for our customers that doesn’t merely add more costs on top of other costs. It’s almost like think about how we can pay a premium once. In my example in West Texas, if we’re paying that PPA price, but maybe the market’s not giving us that full PPA price back, we’re paying a premium for that renewable energy. But then we’re also paying a premium again in our load zone. And at some point you just butt up against your affordability goals and we’re trying to balance everything. Our goal at Austin Energy is to safely deliver clean, affordable, reliable energy and excellent customer service. I mention that because in our mission statement, we have clean, affordable, reliable, and we’ve spent a lot of time talking to our community about there’s no perfect resources. There’s resources that all have their pluses and minuses. There’s no silver bullet. So figuring out the trade-offs between affordability, environmental sustainability, and reliability, what trade-offs can we live with? It’s finding the right mix. And it gets us back to our really diverse portfolio. And once we get that mix right, we can execute best. I mean, we spend a lot of time talking about the challenges of the clean energy transition. And I hate that because it can sound to some people like it’s negative, but really we’re not going to win this race in the clean energy transition. If we’re not honest about the challenges that we have ahead of us in executing on it. And so we have to kind of hold simultaneously the understanding of where we are on reliability while we also believe in the direction that we’re going. And that direction is the right long-term direction. It’s compelling for so many reasons. And we’re still on that path, regardless of what kind of local resources you need to help out with that.

Joshua Rhodes: Yeah, it’s one of the questions I’m often asked when I’m talking to media or other things about Texas in general is like, Austin Energy, notwithstanding, like people ask, why do we have so many renewables? And it’s like, well, because of the cost, they’re cheap. I mean, they produce a lot of low cost energy. It’s also clean. They produce a lot of low cost energy, which in our market structure is valued. One of the things you talked to a little bit about was like communicating these issues with customers, with stakeholders and other types. How are you trying to communicate that? Like we’ve talked about some like very complex things from load-weighted average prices to the ability of local generation to offset premiums across the state. How do you communicate this to the public? I guess I’m asking you to communicate this to the public right now.

Stuart Reilly: Yeah, yeah. I’ll start and then Lisa can jump in because she does a lot of this. It feels like being the chief operating officer at Austin Energy is probably a chief communications officer most of the time because we end up having so many of these conversations. But I think we have to start with a common set of facts because if there’s not a shared baseline understanding about why we have energy resources to protect our customers, we don’t make money off of energy resources. We merely use them to reduce our customers’ bills. We need to start there at those kinds of things because if we don’t start with that common understanding of some of the basics, it’s just going to be a very frustrating conversation for everyone. But we end up having to show our work a lot. I mean, like I said before, energy isn’t as much in the background as it used to be. It’s not as invisible supporting Austin as it used to be. People have to think about it more. Even though we still probably all wake up, unfortunately, the first thing I do is I grab my phone that’s been on the charger, you know, make some coffee, all these things that nobody’s thinking about unless your power is out and it’s all you can think about. And so now people know a little bit more about some of the challenges. It can be a little bit frustrating and trying to help them understand what some of those challenges are with the added nuance and complexities of the ERCOT market, because when you’re a public power utility like Austin, you have to show your work and you have to bring the community along in that conversation.

Lisa Martin: Yeah, I think that for the community and our customers, especially when it comes to complex topics, we definitely have to take them on the journey with us. We have to, as Stuart said, show our work and help explain to them what we see in our daily work lives. For example, Winter Storm Uri back in 2021, we had resources that ultimately, because they were running during that time, the net, Stuart’s been talking a lot about costs, it ended up being net revenues of over $100 million that we ended up passing back to our customers. And since then, we’ve retired a lot of our older gas generation that ultimately contributed a significant portion to that savings. And so people don’t really understand that. They think, oh, well, it was a statewide grid emergency. There’s not anything locally that really has an impact to that. We have to take the time to help people understand the complexities of those kinds of situations to help them understand where we’re coming from as we’re making expert staff recommendations. It’s the days of saying, you go take care of that situation. I just want to make sure that the lights come on when I flip the switch. For a large portion of the population or some portion of the population, that’s not the case. And so we have to really help them understand the trade-offs of every decision that we make. And then we take their feedback and we bake it into the work after we’ve educated them on the challenges. But I also have learned that there’s another portion of the population that doesn’t really understand everything we’re doing. Despite how many times we talk to them and we try to help them understand through, it’s really important to still talk to those folks, but just to listen to their values. Because you don’t really have to be a technical expert to have an opinion on what you want out of your electric service provider, out of your electric utility. And so we’ve spent a lot of time building up to the Resource Generation and Climate Protection Plan adoption and even here recently, talking to the community. And we recognize they want reliability, affordability, environmental sustainability. They want all three of those, but there are definitely trade-offs between those values. And so when we ask them to kind of help us prioritize, help us understand, because each resource has advantages and limitations, we’ve heard time and time again from our community that they want us to prioritize reliability, and they want us to make sure we’re taking care of the most vulnerable on all fronts. So there’s a lot to it. A lot of our job is communication, but it’s also really understanding the complexities of everything that we’ve been talking about here today.

Joshua Rhodes: Another thing about like local resources, there’s been a couple announcements around local energy, local energy storage resources. We’re going to talk about some of the big batteries and some of the small batteries that are coming to the area that might help with some of this.

Stuart Reilly: Yeah, first of all, we had a contract that we executed with Jupiter Power for 100 megawatt, four hour battery. We also have approval and we’re still in negotiations for 40 megawatts of battery storage with Base Power Company. And so we’re excited about that kind of on the home stretch of getting that contract done. So we had only a little bit of storage here locally in Austin, some really important work that had been done years ago, learned some really important lessons. And obviously batteries are improving and we’re investing quite heavily in batteries. We also have another contract that we’re bringing forward for authorization to negotiate on another 100 megawatt two hour battery system. So that’s coming soon. So a lot of people are excited about the base power company, 40 megawatts of battery storage that we’re in the process of working on. Hopeful that we’ll be able to announce more on that soon, but essentially, for us, it’s simple. We have 40 megawatts of battery storage that we can deploy just like it’s a large utility scale battery system. And we can charge it and discharge it when power prices and demand decrease and increase. And we’ll manage that resource in a way that helps us with our wholesale energy prices, peak load reduction. They can quickly put energy across our system. The difference of using the distributed model has another benefit for our community, obviously, and these residentially sited backup batteries that Base Power offers will be a resiliency solution for those customers as well. So there’s a lot of different attributes that different batteries have. We’re also doing a distributed battery demand response program with $500 rebate and then $300 a year based on the performance of that battery when called upon. And so if I remember correctly, I think we have 17 megawatts of batteries here installed in the Austin Energy Service Territory. And we really want to capture those batteries and make them part of our system. So offering customers an incentive to join our program so that we can use those batteries. It’s like a Ferrari parked in their garage that they’re never driving. And so we want to basically be able to leverage those battery systems and also provide a benefit to our customers. So a lot of different stuff going on in terms of battery storage, both at utility scale and distributed residential scale.

Joshua Rhodes: Yeah, can you speak a little bit? So one of the things around like getting to a point of interconnection or being able to site like infrastructure is becoming harder. We’ve talked a little bit about Austin Energy being a pretty compact area. I love the idea of distributed batteries in terms of just being able to deploy things quickly if we can communicate with them in a timely manner. Do you think that’s going to be like the way forward for places like Austin Energy because of just how much presumably easier it will be to deploy them everywhere? Those are my words, not your words, but I’ll let you say.

Stuart Reilly: Yeah, it’s easier from a siting perspective, but from a customer outreach perspective, it’s a lot of different customer relationships and a lot of sites to execute on. You let’s say over 2000 sites to get to that 40 megawatts, something like that. And so there are challenges and that’s why it was attractive for us to try to link up with somebody like Base Power who has that model already to do the customer outreach. They can develop their own customer base and then those customers are buying into a base power concept. Their bill with Austin Energy doesn’t change. And so there’s that kind of arrangement. So I think it is harder to find the space for, let’s say, a hundred megawatt battery. It’s harder to do the interconnection. There’s a lot more to that, but the flip side, there’s just a lot of legwork on that side as well. Something else I’ll point out is depending on the battery sizes, we could see some impacts to our distribution equipment, you know, in terms of transformer sizes and things like that. If I were an investor owned utility making a rate of return on my capital investments, I might like that a battery was sized such that I need to change out a transformer. But as a cost recovery utility here in Austin Energy, we’re just trying to protect our customers. So we’re trying to do it in a way that minimizes the need to make a lot of infrastructure change outs that could increase costs, thinking about how we do it smart, how we locate it well. But I agree with you that it’s very attractive because even if we have areas where we might need additional voltage support or something like that, batteries can really help out in those types of areas.

Joshua Rhodes: Yeah, there’s long been like this conversation around like deferment of distribution infrastructure for properly siding energy storage and things like that. It’s the incentives haven’t always been aligned with every utility. Would you say that they’re more aligned with Austin Energy than with other types of utilities like in Texas and around the country?

Stuart Reilly: Can you ask the question again?

Joshua Rhodes: Yeah, so one of the concepts that’s often talked about is distributed storage being able to defer distribution level upgrades. But a lot of times, utilities that are just making a regulated rate of return on capex may not want to defer distribution infrastructure investments because then they make a lower rate of return. But it sounds like the incentives may be different in Austin Energy than in other types of utilities. Is that the case?

Stuart Reilly: Yeah, I think so because like I said, we’re cost of service utility. So we’re going to set rates at cost. We’re not looking to invest more to make a rate of return. We’re looking at doing what the smart moves are to be the most cost effective for our customers. And so there do happen to be times that come around where distribution transformer sizes end up being undersized as development keeps coming and density is added and a lot that used to have one house has multiple houses or something like that. And we have to keep up with that. But I do think there are other attributes for the distribution system that batteries can help with just in terms of the amount of stress on the grid. It’s not just how much deferred maintenance are we avoiding through those. I think we can find some benefits to the distribution system as well. You know, pairing them with solar, pairing them with electric vehicles, you know, once you plug everything together and we’re smarter about things and we have the programs that deploy those resources at the appropriate time, our hope is that there isn’t a great amount of impact to the distribution infrastructure.

Joshua Rhodes: Yeah, I remember way back one of the things around like the Pecan Street project and is located in Austin and Austin Energy’s service territory. When we were looking at the Mueller development in terms of, you know, a lot of these homes had solar, there were some very early scale batteries out there. A lot of them had like electric vehicles. And I remember one of the big papers and or findings that kind of came out of there was like when you’re adding all of this stuff to the distribution network, like the transformers were running hotter. You’d have highly electrified homes consuming electricity all day, maybe they’re charging batteries, but then at night they’re charging electric vehicles. And so like the transformer never had a chance to like cool down. I think one of the things was like, you batteries could potentially help like with this, with shifting some of this stuff around. At that point, they were quite expensive, but it seems like we’re finally getting to that point where they’re going to be more easily justified in terms of putting on the system.

Stuart Reilly: And I remember some of those days kind of at the early days of some of our electric vehicle programs. And we had a program where we were having people register where they had EVs so that we could keep up with where they were all going so that we knew what we needed to do with transformers and other equipment. Well, EVs in Austin have taken off and we really haven’t seen those types of impacts here. There aren’t a lot of transformers bubbling out there. So I think 13 % of all new vehicle registrations in Austin are EVs and we’re not seeing those impacts. And honestly, it isn’t a list that we could have kept up with anymore anyway. But yeah, I remember when that was the concern, that concern hasn’t quite materialized. And I think part of that is if we have the behaviors right, it’s charging at the right time and those kinds of things helps a lot.

Joshua Rhodes: Yeah, I seem to remember this concept of Prius maps. People were looking like, okay, who has Toyota Priuses and where are they? Because those are going to be the people that are probably going to adopt electric vehicles first. I don’t know if Austin ever had any of those. I vaguely remember hearing them of them at somewhere.

Stuart Reilly: With batteries now, there’s kind of that you see your neighbor gets one and you ask them about it. It’s like solar and EVs and batteries are in the same category where maybe your neighbor does it and you ask them and then you start to see clusters of them. And so that is something that we just have to be mindful of. It can have impacts, but we haven’t really seen a great amount of impact on that so far, luckily.

Joshua Rhodes: Sounds good. Well, Lisa and Stuart, thank you for coming on the Energy Capital Podcast. I really appreciate it.

Stuart Reilly: Thank you. Happy to be here.

Lisa Martin: Thank you so much for having us.

Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

As the data center buildout in Texas accelerates, the public conversation has fixated on generation, interconnection queues, and gigawatts. But the firms actually structuring these deals see a different problem entirely: process.

In this episode, Joshua Rhodes speaks with Maura Yates, chief executive of Mothership Energy. Mothership is one of the most active retail electricity providers in ERCOT’s large-load market, managing more than three gigawatts of large load and writing more than 39 distinct data center contract templates to handle the variation across deals.

Yates says the technology to power data centers exists. The bottleneck for data center completion is the time it takes to sign contracts for electricity service and the time it takes to connect them to the grid. As Texas debates SB6 implementation, co-location rules, and demand-side management, that distinction is shaping which projects get built and when.

Joshua and Maura discuss topics including:

* Why Mothership has written more than 39 distinct data center contract templates.

* The difference between behind-the-meter, front-of-meter, and co-location deals.

* What the Crusoe Goodnight data center PUC ruling means for future co-location projects.

* Why most data centers are data center companies, not power companies.

* HowYates expects ERCOT to integrate large load without pushing costs onto residential customers.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction & Maura Yates

* 01:26 - Building Mothership from Both Sides of the Market

* 03:27 - The Problem Mothership Was Created to Solve

* 05:51 - White Label REP Model and Getting DERs into ERCOT

* 08:37 - Option One vs. Option Two Retail Licenses

* 10:42 - Selling the Residential Book and Pivoting to Large Loads

* 13:27 - Entering the Data Center and Bitcoin Mining Space

* 16:24 - How Mothership Structures Data Center Deals

* 19:13 - What the Market Needs: Process Over Technology

* 21:24 - Co-location, Net Metering, and BYOG in ERCOT

* 26:13 - Do Data Centers Actually Want to Be Power Companies

* 28:12 - Eclipse: Mothership’s Market Access Platform

* 32:01 - Forward Curves and Empowering Price Takers

* 38:07 - The Grid’s Future: Distributed Supply and Data Center Growth

* 41:03 - Closing

Resources

People & Organizations

* Maura Yates (LinkedIn)

* Mothership Energy (Website - LinkedIn)

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

Company & Industry News

* Mothership Energy and Atlantic Energy Complete Texas Customer Transfer

Related Podcasts by Energy Capital

* “The Name of the Game is Flexibility,” a Conversation with ERCOT’s Pablo Vegas

Transcript

Joshua Rhodes: Hi, everyone, and welcome to the Energy Capital podcast. I’m really excited to have Maura Yates here to talk about Mothership Energy in ERCOT. Maura Yates has over 20 years of experience in the power industry, starting in distributed energy resources at Arizona Public Service before moving to governmental affairs at Sun Edison and then becoming VP of sustainability at MP2 Energy, which was bought by Shell in 2017. In 2021, Maura co-founded and is the CEO of Mothership Energy Innovations with her business partner, Caitlin Brammer. Mothership is the 18th largest retail electricity provider in the nation and is contracted and manages over three gigawatts of large loads in ERCOT. In addition to being a rep, Mothership provides risk management, technology and consulting services to electric cooperatives in Texas and specializes in data center and wholesale procurement. Yates, welcome to the Energy Capital Podcast.

Maura Yates: Thanks for having me. Super excited to be here chatting with you all.

Joshua Rhodes: Yeah, and we’re again, super excited to have you. Before we dig into mothership and your current role, like looking back kind of where you’ve come from, your LinkedIn started in a regulated electricity space at Arizona Public Service before kind of going into more corporate with Sun Edison and MP2 and Shell. And now you’re CEO of like a company in the really competitive space. How were those different, those roles that you have in the different spaces where they

Maura Yates: That’s a really good question and it’s one I enjoy answering because ultimately it’s that background that has allowed us to create incubator Mothership Innovations to be the shop that it is. So when you look at the places, I’ve spent time at the utilities, I spent time at the development side, both a DER and large scale solar development shop, all the way then to a deregulated pseudo rep slash utility in ERCOT. And really just bounce back and forth from utility side. To developer or industry side, back to a version of the utility, back to the industry side. And now I’m back on quote unquote the utility side or the delivery side and supply side. And where we’ve landed with Mothership is really taking the learnings of participating and being a part of a company on both sides of the transactions, right? So you typically have the utility on one side and the developer on the other side. And so by jockeying back and forth between these spaces, between our regulated utility all the way into the deregulated market, it’s given us a really well-rounded understanding of how these different parties participate in the market, but also really what they find important and what they find valuable and like, what is it that the utility is trying to get out of transactions? What is it the developer is trying to get out of transaction? And when you better understand both sides of a transaction, you’re able to come up with a better solution for the transaction. Which is why, again, we’ve developed mothership in its latest stage to really be this deal shop and this service provider for both developers and other load serving entities and utility providers. And I should clarify, I’m using utility and like not the traditional ERCOT sense of TND, but really the one providing and servicing power to the end user.

Joshua Rhodes: Yeah, no, that makes sense. Like, can you kind of tease out a little bit like of that? I seeing both sides of kind of how things operate is super valuable. So as you were seeing both sides, can you kind of tease out what was the problem that mothership was originally created to solve? Talked about both sides, but what was that problem there?

Maura Yates: Yep. So the more time that we spent on both sides of these deals. So for example, I go back all the way to Arizona Public Service when we structured some of the first utility incentive programs and we were very aggressive, like in a very solar friendly way in terms of the incentives we were offering. So we worked really closely with the industry and the solar and battery developers. And our goal there was to better understand what is it that gets you to transact, right? Like if our goal as the utility was to get solar adopted by homeowners, what is it that the solar homeowners need to adopt? And what is it we as the utility then need to provide to enable this transaction? And we did a good job. Typically the utility or the load serving entities role is to provide some form of incentives and compensation. And we did that and we had success. We deployed a lot of projects, but incentives aren’t the most sustainable mechanism for growing an industry. So you have to continue to find value and way to extract value as you move away from incentives as the technologies become more competitive. When you start moving down the advancement and the maturity continuum, you start to realize that the challenge in getting these technologies deployed from both sides is really the customer experience. Something has to change in the customer experience. Everybody talks about it, both utility talked about the customer experience and the developer talked about the customer experience. But they talked about it differently and it’s the same customer. So our point was this customer is facing a very bifurcated customer experience. They would get a bill from their solar developer. They’d get a bill from their retailer. They said that solar developers sold them on one thing, but then when they got this bill, they can’t make sense of it. They’re speaking two different languages. And then all of sudden you have a bad customer experience and the customer’s not happy with their solar. Their expectations weren’t met because they were set the incorrect way. And so when Winter Storm Uri happened in 2021, this thesis really became a more apparent need. We observed that if more distributed energy resources had been in the market, they would have had a massive impact on what happened during Uri. And when you take that step back and say, why weren’t more DERs in the market? For us, the answer was the value proposition is too complicated. It’s still too much of a bifurcated experience for the customer. So our original thesis at Mothership was and is to be a white label retail electricity provider. However, in the beginning, we were focusing on these DERs. Since then, we’ve now migrated to the other end of the spectrum and do very large load. Yeah, kind of getting further from the beginning. But the idea with the original launch of Mothership and our first clients that we launched with were, hey, we need to get more customer-cited, residential-cited assets in the market.

Joshua Rhodes: We’ll get that.

Maura Yates: because that’s where we’re going to see reliability. In a market, we’re going to continue to grow to have challenges because that residential load shape is the one that creates that fall. And so as such, how do you do that? How do you get customers more comfortable with adopting? And our thought was we got to turn it into one. The solar company, it all has to be the same customer, the same economics that are all being balanced between one transacting party rather than a solar company and a retailer that both have their own value props and their own metrics. And so if you put it together, it starts to become a more seamless customer experience. Now, the challenge is when you’re asking these solar companies and these distributed energy providers who I’d spent my career working with to become a retailer and a market participant, that’s a really different risk profile than what they’re used to. You go from talking kilowatt hours to megawatt hours. You go from talking about, I need to deposit on your PPA, to I’m getting a margin call from the market, I got to post collateral. It’s a very, very different transaction world. And so when you think about it, if you’re trying to blend these two worlds together, you’ve got a DER company and you’ve got a traditional retailer, who’s going to embrace the other, right? Is it the retailer that becomes the solar company or is it the solar company that becomes the retailer? And it is our thesis that really these solar companies are best suited to become the retailer. Because it’s these solar companies and DER providers that have that long-term touch, that long-term anchor agreement. And more importantly, that’s what’s leading the conversation with the customers. So we need to figure out how to get them enabled. They’re not quite really prepared to be a rep. So, mothership, the origin of mothership is we would white label this to help them get into the market. We’d show them how to be a rep. We’d teach them. We’d help them understand where risk is, how to mitigate it, how to use their assets for it, and really understand what a P &L looks like, all with the anticipation that once we show you, get it set up for you, we want to send you on your way, you’ve grown up, and go do it on your own. So the original was really designed around a customer experience to figure out how to get more DERs in the market.

Joshua Rhodes: This actually brought me to something when I was researching a little bit more on Mothership, the concept of an option two rep, which I’ll be honest, I had to look up. I didn’t really know. Like when I think of reps in the Texas space, I guess I’m thinking of option one, that your general like retail electric providers that most people probably are signed up with or using. So can you explain what an option two rep is and kind of how it operates in the space and how it’s different?

Maura Yates: So Josh, the question around option two is really interesting because at Mothership, we actually operate a bunch of different retail electricity providers, a combination of option ones and option twos. Historically, majority of retailers in the market had been option one. Option one is what allows you to serve resi, small com, and everything that’s essentially sub one megawatt or even greater than one megawatt. But it’s really the universal type of license. And at Mothership, we operate several of those. And I should clarify, under each license, you’re also able to do these things called sub-LSEs and even further segregate and divide. And it’s a key thing that we do at Mothership for risk isolation, but also data. It gets way more clear and pristine data that’s not co-mingled when you do this type of segregation. So that’s the option one piece, but then we also operate some option twos, as you’ve noted. And with an option two, Historically, it’s been used for really large, more sophisticated industrial loads that have come into the state and didn’t necessarily need to go through a retailer. They had enough load, or a traditional retailer in option one. They had enough load themselves. They perhaps had enough sophistication. You can become your own, with an attestation, a retailer designed for just one megawatt and above loads. So a load will attest that they will be serving and employing power themselves under this setup. And as a result, it’s less regulatory requirements because you’re just really focusing on that load that has attested that this is their option rep. So from a regulatory standpoint, a lot lighter, but again, really geared towards these larger facilities. So we anticipate seeing a growth of option two retailers in the future.

Joshua Rhodes: That makes good sense and I think it’s actually a pretty good transition point into kind of where Mothership is. So it looks like in 2025, like Mothership actually sold a large book of retail customers to Atlantic Energy. And can you explain that pivot and kind of like where you were looking to go like with that?

Maura Yates: Yeah. Great question. I hope this doesn’t offend everybody in the resi space, but those in the resi space know exactly what I’m talking about. Resi is just a different beast to serve. The risk profile is different. In ERCOT, historically, when you serve resi load, you are short the market. You’re always short the market. And the reason you’re always short the market is because it’s what resi load that was driving this volatility. The load shape, the elasticity, resi is super volatile. And it’s really hard to reliably serve that and also do it in a cost effective manner for both the retailer and the load. I mean, I can create a retail rate for a resi customer that has me de-risked, but that’s not a rate a resi customer is gonna pay. And so it’s really the question of for the rate the market will bear, how much can you de-risk it? And it’s hard to de-risk it given where the market pricing is. So we chose to exit the resi market for the general challenges of resi as a result of us receiving a very large influx of requests from very large loads. So as you can imagine, the book that we sold to Atlantic was a rather large book of RCEs and it seems like 100,000 meters. We can serve that same capacity with maybe one or two large meters customers. So for us, it just became an efficiency standpoint. However, I will also say super grateful and appreciative of our time of doing resi because they’re a huge piece of the market. And unless you understand how resi behaves in the market, what that load does to real-time SPPs, what it does to the load forecast, until you understand how resi behaves, you don’t fully understand the market. So we understood it. It’s innate. We felt it. We’ve hedged it. We’ve worn that risk. And it gives us a good idea of how the ERCOT market behaves as a result.

Joshua Rhodes: Yeah, that’s one of the things I’ve always said and like in a lot of my research and stuff at the University of Texas and other places, like the residential consumer was a swing consumer and it was the one that increased the most whenever the temperatures either got really cold or really hot. I hear you, got to understand kind of residential in Texas just because of our air conditioning load, electrification of heat, all these other types of things. So you sold a large book of retail customers and you mentioned it just a second ago where you can serve the same amount of load with just one or two large meters. Versus hundreds of thousands, potentially, of smaller meters. So can you talk about where that pivot went to in terms of what are you all up to now?

Maura Yates: Yep, great question. So a lot of the same thesis that caused us to start the business of changing the customer experience, bringing more nimbleness and innovation into the resi space was what allowed us to gain a reputation outside of the resi space at the same time. A lot of really complex conversations started coming to us. Folks knew us from our past lives when we spent time at MP2. And they were looking for a lot of really complex deals and feedback on how to do something boutique. And they knew that we did that in our past life. So they asked, hey, can you guys start doing it again? And it was a really important time in the market. So post 2021, that’s when you started seeing a lot of the Bitcoin mining and the data or the crypto market moving to town. And at first, I think my initial response when someone said, do you guys want to serve Bitcoin? was like, We’ll catch it on the second round, you know? We don’t want to do it right away, but we’ll catch it on the second round. We were still a small shop and money, like that’s a big position to put on. And so we passed on the first couple and we started to educate ourselves just through more dialogue. And through education, we learned about how to de-risk these and the appropriate ways to de-risk these. And we became really disciplined and okay, these are our risk parameters for doing a deal. And if a deal will do it under these parameters, we’ll take it. But we’re not willing to go beyond our risk parameters because This is a big project and one thing going wrong could be chaos. And so we got really disciplined and being disciplined and also really good at the boutique structures allowed us to get into some deals that were so nuanced that we were the only ones who could possibly structure and put it together. And so as a result, our risk conditions could be met in this complex structure. And we started papering transactions that required, you know, seven, eight different documents to be transacted at the same time in order to make the power flow. And so after we did a couple of those, people knew that we had this reputation for being the shop that will kill a lot of brain cells, spend a lot of time, and think really creatively about how to get a solution. Because this all goes back to, OK, the goal is to get our customer a really good customer experience, but not expose ourselves to risk. And so we migrated into this large load space by way of these Bitcoin mining data centers, which arguably felt the riskiest. And on top of that, the market conditions at the time. This is back in 2023 when we had summer 23 pricing and summer 22 gas. And so the risk was just a multiple. And so the tools that we used to come at these creatively to manage risk and meet the needs of the market, which were they didn’t have much cash, right? Like they were cash constrained. So how do we manage risk on a low cash portfolio and not make any compromises that we need from a risk portfolio? And that’s what led us to really start forging into the space and really get a reputation in the data center space.

Joshua Rhodes: Right now, if you look at the ERCOT space, I mean, you get two people like us in the same room or on a panel or a podcast for that matter. We can’t talk about energy without talking about data centers, right? And that’s just like how everything is. Like, can you speak to what the structure of a deal means for a data center? Like, I don’t know if someone came to you now. I mean, they’re probably late in the game now, but like the data center comes to you now. Like, what does a deal look like to them?

Maura Yates: Good question. Where my head starts going is pick your flavor, right? So as much as we want these data center deals to be standardized, because you’re like, everybody’s just building a data center, right? They’re all just like, it should be really simple. They’re all just, you know, trying to compute. It becomes really nuanced and it becomes really different because who sits behind that developer, not only as tenant for the data center and whose machines will be in there, who sits behind them as a lender comes into play. So you have a lot of parties with really nuanced needs. So certain lenders like to see something a certain way in a contract. Sometimes the relationship between the developer and the tenant and the actual occupant of it are really different. And so traditionally what will happen is they’ll come to us, they’ll give us an understanding of who their tenant is. And more importantly, they tell us how they’d like to provide power to that tenant. That’s where we start. What do you guys want to do? We don’t start by telling them this is what we’re going to do. We want to go back to the customer experience. Tell us what you guys want to do. Let us figure out how to do what you want to do because that’s going to make you happiest and that’s important to us. So tell us what you want to do. We’ll figure out how to do it within the means that we have and deliver on that. That’s what we’ve really been focusing on. When I think about the number of contract templates we have, so this will blow your mind. The last time I calculated, we had over 39 templates of data center contracts. Because one, there’s an evolution and as you keep learning, you learn little things. It would do better. But more importantly, some are co-located behind the meter, some are in front of the meter, some share part of the behind the meter. Some are behind a POI and have two data halls. Some have two tents behind a single POI. Some want to curtail, some don’t want to curtail. You know, so everybody’s got these different requests and all these different requests impact different parts of risk. And so the elements that we have to put in to control those are very different across our contract. So when we think about one of the areas that really distinguish mothership and our retail side of the business, we absolutely call out our data center contracting services as one of the things that distinguish us. We’re fast, we have really good templates, and we have really good templates that work for customers, because we’ve worked with most of y’all. We know what you like to see. We know if your lender wants certain step-in rights, etc. So a really solid set of templates to work from, though none of them are totally the same.

Joshua Rhodes: When you look at the market structure as it is and your 39 templates and all the things you need to do, how could the system be doing it better? What would make your job easier or make you only need, I don’t know, say 17 templates instead of 39?

Maura Yates: That’s a fun question to answer because if you ask that they’d say, Maura doesn’t want to simplify this. She loves the chaos. There’s a part of us that loves the chaos, right? There’s ways to figure out how to do things better and constantly doing things better. Now there are things that can be done that don’t need to add to the chaos. When I think about like where innovation needs to happen in the market, we frequently look to technology for innovation. I think I get asked this question a lot and I think my answer is always the same. I don’t think it’s technology. We have wonderful technology. We have a lot of people working on promoting really good news. You guys had the hardware software side covered. What we need to evolve and innovate on is process. What’s killing these projects is the time to contract and the time to power. If you ask any of these large load developers, what’s killing them is that they’re just waiting to interconnect. There’s no technology that you can put out there that necessarily changes it. What needs to change is how we process things, how we move through things. It’s very inefficient. Now, I say that, but at the same time, I don’t necessarily have a great solution because we’re in this place where our market’s undergoing a massive shift and they don’t want to knock ERCOT because ERCOT’s working really hard amongst a bunch of moving pieces and it’s really hard to keep organized. So I certainly don’t envy them and I think they’re doing the best that they can with a really large project. But that’s it. The key piece of this is it’s creating, it’s innovating in the space of process, because process is time, and that’s what’s keeping us from deploying these data centers more rapidly.

Joshua Rhodes: Yeah, as we’re recording this podcast, just released a podcast talking to Pablo Vegas, CEO of ERCOT, where he talked about different types of tools and he was making a case. We really need tools, even if they’re not perfect. We’ve got to get some stuff out there and just learn from them. Even if it’s not the greatest tool, you can hit a nail with a wrench. It’s not going to work great. And you can figure out how to make that wrench better and turn it into a hammer to actually hit the nail. He didn’t say that. I just said that. But anyways.

Maura Yates: Yeah.

Joshua Rhodes: Yeah, iterate and such. So one of the things like last week I was at a grid lab event in California and one of the things that I learned about ERCOT that I didn’t really understand and you’ve mentioned this kind of before in terms of what you mentioned, similar to something like this. With large loads that want to bring generation as well, whether that’s batteries or various types of behind the meter generation, it’s my understanding that the current way things are structured is you can’t net on your point of interconnection. And so like if you’re like a 500 megawatt data center, but you have a 300 megawatt battery or 300 generation, you can’t net and say, want just 200 necessarily from the grid, or you can’t operate that away. Is that the case? Am I getting that wrong? Did I misunderstand that? Or like, how does that work with large loads kind of bringing their own generation? Cause a lot of, a lot of folks are talking about that these days.

Maura Yates: Yep. So a question if you got something wrong, amidst the constantly changing updates, comments, depends on the point in time. Yeah, it’s very hard to keep straight. And by the time that this podcast airs, everything we’re about to say will already be updated because they’re having a workshop tomorrow. So whatever we say now might have changed. The bring your own generation, the net metering, the co-location.

Joshua Rhodes: That makes me feel better, thank you.

Maura Yates: This is a really, in my eyes, this is the next big topic that’s being discussed as part of the SB6 proceedings. The conversation that’s sucking the air out of the room right now is the Batch Zero process, which is the PRR 145 to change the interconnection process. That’s kind of getting into a spot where we see that the end of the road or a light at the end of the tunnel. Okay. The next thing that the commission and PUC and ERCOT are starting to take up are projects 58, I’m gonna maybe get this wrong, 482. The demand side management. In the last couple of meetings and workshops, they’ve already started signaling, hey, we need to have this conversation. It’s where the curtailable load, the CLR conversations coming in. It’s where we expect conversations around voluntary early curtailment loads to come in. It’s the demand management piece of Senate Bill 6. That’s just getting kicked off. So we would fully anticipate more conversation around net metering of these resources going forward. Now, that said, there’s a couple pretty important kind of rulings, or I should say one important milestone really just was promulgated and that’s specifically around the Goodnight Project with Crusoe out in West Texas. And that’s a co-located facility with thermal and renewables. And. It’s interesting because it’s perhaps setting a precedent for the conversations in that 5842. And as a result, what came out of that Crusoe filing were some pretty interesting comments. One, it stated that that load, that data center, needs to be able to fully shed and come off. And all of the native generation, the wind and the thermal, need to be available to push to the grid in their full capacity. Now that’s a little bit contested because the spirit of SB6 was really, think the understanding is maybe it was more designed towards dispatchable generation, not necessarily renewables. So I think there’s still conversation going on about that and that will likely be picked up in that demand management conversation as well. But that was one of the first things that came out of that net metering docket. And the second most important piece is that they told the loads, you’ve got to be available to curtail in an emergency. And you can’t participate in any demand response or ancillary service programs. So it seems like it is setting the precedent for the things that will be decided around what the large load requirements are, agnostic of whether or not you’re co-located. But I think at the end of the day, we are going to continue to see a huge drive and push for co-location and behind the meter, simply because the perceived bottlenecks there are less.

Joshua Rhodes: Got it. Think the thing I was trying to say earlier is one of the things I brought up when I was at that meeting was there was a couple of hyperscalers in the room and we were talking about like, well, it’s like, can’t it just be a CLR, a controllable load resource? That’s where it was coming in. It’s like, well, they won’t let us net at the point of interconnection, which you’re talking about. But of course that may change, I don’t know, tomorrow. Like as you pointed out.

Maura Yates: And it gets tricky too, because some of the ways that loads apply in these co-located applications are they apply to be like a load only resource so that they aren’t netted, some want to be netted, some can’t be netted, some are looking for exclusion. So it’s a tricky space, but a pathway to netting, there will still be pathways to netting in several of these interconnections, but there’s also pathways for non-netted resources.

Joshua Rhodes: The deals you’re looking at in the various contracts, like, do these data centers actually want to be power companies? I get the feeling that they don’t necessarily want to. They’re kind of being forced to just given like maybe how slow the rest of the system is running.

Maura Yates: So I think the answer would differ based on the hyperscaler you’re talking to. There are some hyperscalers that currently have incredibly built out power desks and power teams. However, I will flag not super heavy in the wholesale market transaction. They’ll sign a lot of bilateral VPPAs per se, but not necessarily papering a lot of the short-term hedges or cash positions and not as active as a true power marketer would be. They’re set up and I think those intend to take a more aggressive role as kind of like a power marketing participant. However, there are others and sometimes it kind of blows our mind because it’s your number one expense outside of your hardware is electricity. So you guys should have this really dialed and do you guys understand everything that’s going on here? And I think several data center companies are data center people, not power people. And so they kind of take what is given and take what they hear everybody else has and that’s acceptable, rather than really pressing for ways to refine terms.

Joshua Rhodes: Yes, one of the conversations I’ve had is, you know, these data center companies, do seem wanting to move so fast and maybe have buckets of money that they’re willing to throw at this. But I do think eventually, where you bring some real value in this, they’re going to get to the point where they’re going to have to be smart about electricity. I mean, right now, speed to power, right, just got to build data centers. But at some point, there’s going to be a competition for how cheap can I make a token for the next word in when my students are cheating on their homework or whatever it is, know, or like, you know, writing code, they’re going to have to bring those unit costs down. So they’re eventually going to have to get smart on electricity and how they structure these deals, right?

Maura Yates: They are. And what happens is sometimes it’s something bad that prompts them to get smart. I remember back in summer of 23, there was a really large publicly traded data center company that just got raked across the coals by their shareholders for their price of power. And when the market, they had done a poor hedging strategy. I don’t think they were well informed on what they should have done or what they advocated for in their contract. And as a result, they were not position to take advantage of the economics in the market. And so in a market where, let’s say, real time was clearing 70 blocks, they put on $120 hedge and that showed up to the street. And so they need to get more sophisticated and the challenge is sometimes they try to get more sophisticated, but not with the right tools. And so what we really focus on, I’ll keep saying it, but back to our original mission, which is customer experience. We focused originally on resi, now we focus on our large loads customer experience. And getting them data and teaching them how to use the data is one of our biggest drivers. So as a result of serving these large loads who are sophisticated, we have some that are very sophisticated and some that are very hands off. We treat them all the same. We treat them all at the same level of sophistication. And so for these large loads that are super sophisticated that need to provide very precise sub billing allocation, cost allocation down to different tenants, getting them data is huge. We launched a new platform internally at Mothership called Eclipse. We’ve now taken externally because it was our market access platform. We wanted to make sure that our data centers saw the market the same way we see it. Because if we see something that they need to take action on, we want them to see it too. For the example you noted, a lot of data centers right now want to run on index. And I get it, you see me roll my eyes on that because it’s Works until it doesn’t work, right? Index is good until it blows up. There’s always a right price to hedge and there’s always a right way to liquidate hedges. Some get that. Right now, most of them are writing index. But as we’ve experienced before, the market changes. When the market changes, all those guys want to hedge. We give them the visibility to understand when that market is changing every day. Every hour we give them this visibility by logging in. And they’re able to see, okay, now is the time I should take action to hedge because I’m seeing this forward curve just crawl up, which is giving me an indication that real time and my cash position is probably going to have the same increase. And so it gives them the idea of like, now’s a good time to hedge. And more importantly, maybe I’ll just hedge these hours. Maybe I’ll hedge the nighttime. Maybe I’ll hedge the daytime off peak. It gives them the ability to make educated decisions to improve their company economics. Beyond that though, this again, all goes back to the customer experience. If you give them a bunch of data, but they don’t know what to do with it, then that doesn’t matter. And digesting this data is super important. So we’ve taken Eclipse one step further to digest this data and actually make the recommendations and say, hey, hedge now, hedge this price, or hey, wait, this is what this would synthetically look like in your portfolio. And more importantly, let me pull all of your historics, give you all this detailed level clearing information on your historics to say, maybe we should, maybe we shouldn’t. Big thing there is data to give them the sophistication that they lack because they’re not power people, they’re data center people. But they need to be power people, so we need to give them that access. And if you think about that same conversation, that same conversation we had with the DER player saying, you need to be in this space, but you’re really not equipped to be in this space, so let us enable you and let us teach you how to be in this space. And that’s what we do now for our data centers and large loads.

Joshua Rhodes: Yeah, I’m glad you went there. That’s exactly where I was going to go next is you’ve talked about, you know, delivering data and delivering tools. You built a tool and I believe you told me that like, so you built Eclipse originally for in-house use, right? It was just going to be mothership was going to be using it. But then you were using it so much or sending screenshots to people or something like that. Like, we want this. So I just went to the website just a little bit before. It looks like anyone can sign up for free right now if they want to check it out. So there’s like a trial period going on. And so we’ll put a link to it in the show notes. But yeah, so you talked a little bit about kind of what it does, but can you give me any specific use case? How would someone come to the conclusion that I need to hedge? Like what would they be seen on your tool right now if they looked that would give them an indication of that.

Maura Yates: Yep, so to level set our tool, like if you picture in your head, there’s a sidebar and on this sidebar, there’s a bunch of different modules and these modules are different ways that mothership operates. So as you mentioned, Josh, we built this not for anybody else. We built it for ourselves. We built it because this is how we needed to see the market, how we needed to ingest data, how we needed to interpret it. And we kept screen sharing it with all of our data center clients saying like, hey, look how your load settled or hey, like look at this. And showing them what we saw. Showing them, this is the read we got from the TDSP. This doesn’t align with your telemetry. Let’s go see if there was a meter read error. So we start showing them and all of a sudden they’re like, you spend most of our time now showing, we should just get you a login because it’s going to be way more efficient. Let’s teach you to fish rather than keep feeding you. So we decided to turn it into an external facing platform where we started by just putting our data center customers in there. It’s where they could retrieve invoices. Retrieve their interval level report. So we give all of our customers interval level billing data with a massive spreadsheet behind it. Knock on wood, I’m going to get challenged by some other rep when I say this, but we’re pretty sure it’s the most in-depth interval report because it’s really complex math to pull together. But that all sits in this platform and they’re able to take that interval level report and push it up against our other unit, which is our forward curves unit and our settlements unit. And one, they can shadow settle themselves and say, did they get built everything correctly? Hey, where did I incur this charge? Hey, does this look like what my telemetry looked like? They can do a bunch of validation themselves, which typically that data for validation is totally gate-kept by an REP. That’s REP data. That’s not data that the load typically gets because that’s part of a transaction statement that we get from a TND. But we push it all out there because, okay, you can see your load data. You should know what you consumed. So we put it all out there. They go look at their historic position. They can shadow settle it. Or more importantly, the question you immediately asked. We’re talking about your open position and we’re trying to figure out should you hedge? And a lot of these large new data centers are coming with this demand for a physical tie to power. So that’s why they’re going to behind the meter. But for those that can’t go behind the meter, they’re wanting asset specific physical hedges to say, I’m buying, I know you exist. You’re selling that to me for 15 years. If I can’t locate next to you. I at least want to make sure that I have somebody whose blades are going to turn. And so as part of that transaction, we will tell them to like, we’ll go in and say, okay, if this is the hedge that we want to do, let’s go price it on the forward curves. So we’ll go into our Eclipse platform. One of the free units that you mentioned right now is our forward curves unit. These are the forward curves we use every day. This is our exact pricing platform for forward curves. It has ancillary services. It has every ancillary. It has basis hub for all the load zones. It’s got more pricing curves than you would get through any other kind of publicly available curve tool because it’s our curves. It’s literally what we price all of our deals on. So we say, hey, come in here and let’s go price up what this hedge should be. I check my curves every day in market. I know our curves are good. So this is what the curves are showing as the hedge price. Then let’s go shop this and let’s go see if we get this as the hedge price because if somebody comes back two, three, four, $5 higher than this, they’re out of market. Don’t hit that. But it gives you the ability to gauge. When you should hit, whether you’re getting close to your price target, and if the numbers that you’re getting are good. Because if you think about it historically, this is a really big piece of why we made this public. You guys have, by saying you guys, the data centers and the generator, like the renewable generators, you guys have been price takers. You’ve been price takers because you haven’t had the visibility into the wholesale market to know how to price your asset on these wholesale desks. So I remember back in the day when I was at Sun Edison and we were going into one of It doesn’t exist anymore, but one of the very large utilities and going into the generation arm and saying, hey, we want to sell you our PPA down in Southwest Texas. And we didn’t say we’re going to sell it to you for this price. We said, what would you pay us? And like how weak to have to go in and say, well, what would you pay us? Right? Like I want to go in and at least know my value and say, I know that I’m worth at least this much. And so that’s rampant across the industry is. Solar developers, even it’s improved today, but I’d still argue solar dev shops do not have price on real time pricing. Pricing moves a seven by 24 and even an on peak product for a five year term that can move two to $3 overnight. And if you’re a solar developer, you’re not capturing that two to $3 price movement unless you know what’s happened. So our forward curves tool gives developers the ability to have power and some control in these. Pricing scenarios and not just be price takers. So it’s a really good way for them to optimize that procurement as well.

Joshua Rhodes: Sounds like it unless you come to the table with a much stronger bargaining position than you had before,

Maura Yates: Yeah, and all the tables you’re probably going to are tables that we talk and trade with. So it’s very easy for us to call BS if they show a number that’s out of the market. We’re like, that’s not right. We know you just hit something at this price point. So definitely empower.

Joshua Rhodes: Totally. I know combined we’re probably at the 40 minute time for the three chunks or whatever, but I do want to ask a final question. You’ve seen this market move and right now it’s in a, we’ll say turmoil, but it’s like, it’s bubbly right now. There’s a whole bunch of things going on. You’ve built a tool that allows you to make a little bit more sense of kind of maybe what’s going on. But as you look into the future, like what technology excites you right now? Like, what do you think when we get beyond this kind of place where we’re at now? What are you dreaming about for version two of this?

Maura Yates: Man, it’s so funny. I was telling somebody, it’s hard to turn on my creative brain outside of the creative immediate world that we’re in. When I think about the grid in the future, I absolutely still am of the hard belief that we repeat history and we are moving away from centralized grid to a decentralized grid. And I think when we originally thought and expected this to be happening in higher volume, this was five years ago, what we described as distributed energy were these like tiny 10 megawatt or less like DER projects. I think we’re talking about it now like distributed at the transmission level too, where it’s bring your own generation. We’re back to a different era of power plants and supply, right? We are a place where we’re have to have way more localized supply. There are parts where it’s probably gonna get more expensive for that need to bring it into more local areas. I think we’re gonna be in a world where I do think ERCOT’s gonna figure out the large load issue and they’re gonna do it in a way that doesn’t add liability concerns. That’s their number one concern. They’re going to figure that out. They’re not going to put all the other rate payers at risk. So I think we’ll figure that out. I think a lot of vols going to exit the market. So we’re going to get a lot of batteries that are deployed, batteries that are going to come. And when they have to curtail, it’s going to allow them to shift over to this four gigawatt hour battery and not impact the curtailment. Because ERCOT’s going to say you have to curtail. And so data centers are going to be left with no other option than go install your battery. Go install your on-site gen. So we’ll see a lot more battery. I think it’ll be more strategic. I think the services might still be called ancillary services of some sort, but I think they’ll look a little bit different. I think some of those will be mandatory. And I think maybe we’ll start getting some more back to like smaller data centers, like localized data centers. But here’s the reality. We are a society that uses data and compute everything. So whether the AI bubble busts or not, data, we just keep driving more data. So a data center, I don’t care if it’s AI, it’s going to have some occupancy as long as we continue to consume data. So I see the data center world growing as well, perhaps more efficiently, but still growing too. So I don’t know if I avoided your question or if I gave enough of a look at like the imagination. It’s a little more of the same, probably moving more in that distributed, more distributed pathway, especially as we bring the BYOG becomes more of a prominent requirement. So.

Joshua Rhodes: No, absolutely. Mean, I’ve heard people say all kinds of like things like peak oil, maybe even peak gas, but I’ve never heard anyone say peak electricity. Like you said, I think we’re going to continue to use more data. It’s going to be electrified. It’s a great place to stop. Yeah. Maura Yates, thanks for coming on the Energy Capital Podcast.

Maura Yates: Thanks for having me. Appreciate it. Thank you.

Joshua Rhodes: Absolutely. Thanks for listening to the Energy Capital Podcast. If 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

Texas generators and grid operators used to spend a decade or two planning for new power plants.

But as Gin Kinney, chief administrative officer at NRG Energy, told Energy Capital Podcast hosts Matt Boms and Josh Rhodes at CERAweek in Houston this year, the company’s planning horizon has collapsed to 12-18 months.

The company’s activity reflects the dynamic growth of the ERCOT grid. Kinney said NRG has sourced 5.4 gigawatts of natural gas turbines, secured a labor arrangement with the construction company Kiewit, and begun construction on three gas plants funded in part through the Texas Energy Fund.

ERCOT’s demand forecasts, which should inform the plans of developers such as NRG, have been hard to pin down at best.

Yet while no one can say for sure how much of the new load is actually coming to Texas, it’s clear that demand is going to rise substantially and very quickly. That’s why, as Gin explained, NRG is focused on the assets, not the timeline of the load they’ll serve.

This rapid growth means grid connection — speed to power — has never been more important. In this episode, Josh describes a 350-megawatt data center going up near El Paso, outside of ERCOT, that’s being powered by roughly 800 small generators — because larger generation units weren’t available on the data center’s construction timeline.

Such behind-the-meter, bring-your-own-power projects are what happens when speed-to-power is a grid’s binding constraint.

They also show the vital importance of load flexibility. Every megawatt of flexible load is a megawatt of generation that does not have to be built, financed, or fought over. In this episode, Gin discusses NRG’s work on virtual power plants and new hyperscaler contracts as steps toward a more flexible grid.

The question is how to scale such efforts. This episode points to ways that grid participants are working to answer it.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction & Gin Kinney

* 04:42 - NRG’s One-Gigawatt Virtual Power Plant

* 06:07 - Affordability, T&D Costs, and the Smart Home Strategy

* 09:09 - How NRG Uses AI in Operations and the Home

* 12:49 - Texas Market Outlook and Speed of Development

* 20:07 - Texas Energy Fund and NRG’s Construction Progress

* 21:06 - Hyperscalers, Bring Your Own Power, and Community Investment

* 27:41 - Post-Conversation: VPP Mechanics and the Gentailer Difference

* 34:13 - Load Growth Numbers and What Is Actually Real

* 38:57 - Data Centers, Bridge Power, and Speed to Grid

* 42:39 - SB6, Legislative Hearings, and Who Should Set the Rules

Resources

Guest, Host, and Organizations

* Gin Kinney (NRG Profile)

* NRG Energy (Website)

* Reliant (Website)

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Matt Boms (LinkedIn)

* Texas Advanced Energy Business Alliance (Website)

Organizations & Individuals Mentioned

* Pablo Vegas (LinkedIn)

* ERCOT (Website)

* ERCOT ADER Pilot Program (Website)

* ERCOT Long-Term Load Forecast (Website)

* Public Utility Commission of Texas (Website)

* Texas Energy Fund (Website)

* SB6 Implementation Rulemaking, Project No. 58317 (Website)

* Columbia University Center on Global Energy Policy (Website)

* CERAWeek by S&P Global (Website)

Company & Industry News

* NRG Energy Completes Acquisition of 13 GW of Power Generation and C&I VPP Portfolio from LS Power

* Sunrun and NRG Energy Announce Partnership to Harness the Power of Distributed Energy in Texas

* ERCOT’s Large Load Queue Jumped Almost 300% Last Year

* NRG Completes Acquisition of Vivint Smart Home

Related Podcasts by Energy Capital

* NRG’s Gigawatt VPP in Texas with Travis Kavulla

* Who Pays for the New Grid with Pablo Vegas

* Who Pays for Texas Grid Growth — Roundtable Discussion

Related Posts by Texas Energy & Power

* More Power that’s Faster and Fairer — Roundtable Discussion

* Connecting the Regulatory Dots Shaping Texas Energy

Transcript

Matt Boms: So we are here live at CERAweek in Houston, Texas, and we have a very special guest with us today. Gin Kinney is Executive Vice President and Chief Administrative Officer at NRG Energy, where she leads marketing, communications, and customer experience. She brings more than 20 years of experience, including over a decade in the energy sector, and has played a key role in building NRG’s brand and shaping a more customer-focused digitally driven organization. She’s also active in industry and community leadership with a focus on sustainability and advancing women and energy. Gin, thanks so much for joining us today.

Gin Kinney: Hey, thank you. It’s great to be here.

Joshua Rhodes: Yeah, so one of the things from your background is you really came from renewable energy development before joining NRG. How is that path shaped like your role or what you see your role is at NRG?

Gin Kinney: Coming from a startup environment to a comparative behemoth, right? You definitely learn a lot on the fly in the entrepreneurial world. You definitely learn how to be scrappy, have a lot of grit, say yes a lot to challenges. You also learn how to manage things at a different scale, be really close to the customer. And I think also coming from that entrepreneurial world where you’re working on project finance or you’re working on project development, well, this is how we’ve always done it before. And so I try to bring that mindset to NRG where we’re much larger, but the excuse of we’re not going to change or we’re going to, instead of innovate or sort of take chances, we’re going to protect the status quo. I think the other piece of that too is this competitive nature. When you’re a startup or you’re entrepreneurial, you’re competing every day for dollars. You’re competing for space, you’re competing for customers. And when you have this highly competitive spirit, you’re always playing to win. And that’s what we try to bring to NRG too, is that play to win, not protect the status quo.

Joshua Rhodes: You think that fits better in Texas with other places given like the competitive nature of like the generation market in the retail space you operate in?

Gin Kinney: Texas certainly provides us the opportunity to move fast. Policy and regulators clear the pathway to get things done, get things built. And in Texas, in the competitive markets we serve, every day we have to earn the trust. We have to fight for those customers and we have to show up for them. We’re not just about rate basing a solution. We have to figure out how to put that on our balance sheet and also satisfy the demands and the expectations of our shareholders.

Matt Boms: They’re also very savvy customers in Texas. Find that compared to either parts of the country, Texans really know more about their energy bills than the average American. Can you speak to that? And where do you think that comes from? Is that like a Winter Storm Uri consequence, or is that just the fact that we have this really competitive retail market?

Gin Kinney: It is, and you have to choose. When I first moved to Texas a few years ago, I had to choose my energy provider. So I had to get smart on what I was looking for, the type of services, the type of value I wanted. And certainly after Winter Storm Uri, there’s a heightened sense of ERCOT. My 80 something year old mother who lives in Georgia knows what ERCOT is. I mean, I don’t think we ever would have thought about that five years ago or 10 years ago. Right. And so. That heightened sense and heightened awareness just by having to elect your energy provider. And again, in Texas, I think things are just different. Like we demand more, we expect more. Back to that competitive nature, sitting here with a UT grad, know, football is big, bright lights, you know, I think that competitive nature comes through in kind of everything and how we operate in Texas.

Joshua Rhodes: Yeah, absolutely. In that space, mean, energy just doubled its generation fleet with a 12 billion LS Power acquisition. You know, at the same time, you’re managing a CEO transition and navigating a global energy crisis. Given all of these things happening in a hyper competitive space, like how do you prioritize, you know, what gets your attention?

Gin Kinney: Well, first and foremost, we do everything in service of our customers. And if we keep that in mind, all of these other issues that we see around, we always think about it from, how is a CEO transition going to shape how we serve our customers? How are the changing dynamics in economic environments going to change how we provide services to our customers? If you look at it through that lens, it’s easier to focus and drive towards those business outcomes. Then let all of the myriad of issues kind of dilute the value that we can drive across all of our stakeholders.

Matt Boms: And I also wonder, keeping on this topic of the savvy Texas customer, we talk about things like virtual power plants and flexible demand and people’s eyes gloss over because they don’t quite know what we’re talking about. But NRG actually is building a one gigawatt virtual power plant here in Texas. Can you talk more about that and give us the details?

Gin Kinney: Well, that’s enabled through the trust we built with our customers and even customers in general. So it’s kind of taken a step back. I think customers today are still accustomed to automation. They’re accustomed to letting machines decide. This is just a natural segue because we’ve done the hard work to build the relationships with the customers. We’ve talked about the value we can deliver to them. And then when we talk about savings, particularly in a time where affordability is top of mind, customers are willing to trust us with their energy usage. They’re willing to enroll in VPP. We set a pretty high bar, I think, in Texas for the amount of VPP we wanted to achieve. And we more than what, 5x that last year? Gonna have to check that stat. But because that just shows that customers want what we have to offer and they value it and they trust us. And who wouldn’t want to ease congestion on the grid? Who wouldn’t want to be a good steward of their community environment? And then bottom line, who doesn’t want to save on their energy bill as other costs of the household are increasing?

Joshua Rhodes: Yeah, it’s an interesting point you kind of bring up in terms of paying for the grid, because I mean, NRG sits, like other gentailers, sits in an interesting space, right? You’ve got the generation and you’ve got the retail, but not really the pieces that connect the two in between. Like those are fully regulated monopolies, transmission service providers, distribution providers. And in the topic of affordability, a lot of focus is being put on electricity prices. Affordability of electricity, but the large part of that that’s increasing is that fixed cost system, is that transmission, the distribution costs. And so like, how are y’all handling that with your customers who may not fully understand that you may have two out of three of the pieces, but you’re not handling like the part that’s actually increasing the cost the most.

Gin Kinney: at the end of the day, customers don’t care. They don’t care. So I think it’s our responsibility to partner, like partner with Centerpoint, partner with the grid, the T &D companies so that we can find comprehensive solutions to ease that pain for consumers. And if we can demonstrate savings, or we can demonstrate value in other ways, you know, you mentioned like getting closer to the customer and that dynamic, you know, we bought a smart home company a few years ago. We did that because we knew that the closer we can get to the customer, the more we can automate and help them understand usage and look at things like, the home occupied at this hour of the day when maybe power prices are the highest and can we turn it down half a degree? Those are the things I think we took an extra step to think through. How can we create a very seamless, easy digital experience for the customer? so that we can provide value, even though we know we don’t control that one, we’re only one line item on the bill, right? We’re just that supply line item, both in Texas and outside of Texas. So what are the other things we can do with our whole home to help them ease that cost at the end of the day?

Matt Boms: And is there pushback from customers? Cause one thing we hear a lot is Texans don’t want anyone messing with their thermostats. What have been kind of the findings from NRG as far as customer behavior and where is that price point where customers are willing to provide some flexibility?

Gin Kinney: If we can make it so you don’t feel it, that’s the important part. If we’re all out at dinner and we can dial down the thermostat just a little bit or dial it up depending on the season. And by the time we get home, we’ve pre-cooled your home or preheated your home. You didn’t feel a thing, but we’ve managed to save you money and we’ve managed to ease the grid and that peak time, that it’s a win-win. But we have to have the intelligent tools to do that. And I think that’s where our focus on equipping homes with smart thermostat, motion sensors, things of that nature, things that you can put on hole pumps and AC units and understand and predict. That’s the other key piece of this is utilizing AI and analytics to predict times when you’re going to be away from your home when that coincides with super high energy prices.

Joshua Rhodes: Yeah, that brings up an interesting, there’s something we talked to Pablo Vegas at ERCOT about this past year or so, whenever you get energy people in the room talking about AI, it’s all about how do we build more power? How are we going to connect these data centers? Like how are we going to grow that? But I do want to talk about like, to the extent you can, like how is NRG utilizing AI or learning from AI? And you’ve already kind of gotten there, but is any of the way you’re using it and you can talk about it in either operations or in these kind of smart home applications.

Gin Kinney: Okay, well that’s a very layered and complicated question. Mean, part of it is just using one of our areas of secret sauce is our market operations team. We really understand, we look at everything from weather to day ahead pricing to how things are going to be looking in the markets a year from now. So we use AI to do a lot of that predictive analytics for us and help shape like how we can actually control our cost of goods, like how we control our cogs and how we can put some of that, extend some of that benefit to our customers. And then, you again, from the technology that we’re continuously improving of all of the technology that we have in customers’ homes, how do we make that smarter? How do we make it faster? How do we get data points that really going to drive a difference when it comes to cost and that monthly bill?

Matt Boms: Yeah. And I think if you draw a straight line from the Vivint acquisition to where we are today, there was criticism back then, right? And now I think that energy is making the case that flexibility is really where the value will be moving forward with all the low growth that’s coming. Because that happened at a time where we really didn’t have the low growth in place that we have now with data centers and AI. So can you speak to people poo poo, VPPs and flexibility, but we’re talking about a one gigawatt virtual power plant. So how much of a role moving forward do you think? flexibility we’ll have in meeting the demand.

Gin Kinney: It’s going to have to continue to play a huge role, right? And we think about bringing on load, which is all the load that’s coming into Texas, all the load that’s coming into the U.S., whether it’s hyperscalers, on-shoring, other types of development. Having a solution at every point of the value chain is going to be increasingly important. That’s why we’re building power, we’re building three power plants in Texas right now. We’re looking to partner with hyperscalers and our point of view is like, we’re going to bring our own power to those deals, right? So we’re going to solve for the load piece of it. And then the end use customer, what are those new technologies we can bring to them that are going to be easy, seamless, help control their usage or whatever is valuable to them. But I do think it’s going to be this all of the above approach. And because we have a point of entry at scale and every single part of the value chain, our customers are going to be the winners.

Joshua Rhodes: So around the virtual power plant that allows for flexible or turning downloads at homes and businesses and things like that, it seems like that could be paired with if a data center that wants to run more or less at a flat load, if you just need a little bit of flexibility, maybe the flexibility doesn’t have to come from the data center, it can come from somewhere else. So I was just wondering if that’s part of the conversations that y’all are having.

Gin Kinney: I think certainly, mean, our approach is very bespoke to the end-use customer and where our end-use customers will be willing to provide some additional flexibility in terms of either load reduction or putting some of that power back onto the grid. I think it’ll be up to those individual contracts, end-use power purchase agreements we sign with our customers. Back to making things very personalized to the customer need, even if it’s a residential customer, mom and pop shop, or a hyperscaler.

Matt Boms: So if we step back and think about this moment in time, we’re five years out from winter storm Uri, certainly politically energy had its moment in Texas. And now we’re in this load growth moment. Where do you see the market heading here in Texas moving forward? Do you think that our state is open for business? Are we going to be able to meet the moment? I think a lot of folks are asking questions over at ERCOT and the public utility commission, trying to figure out. If we’re going to have enough generation to meet the load because the transmission takes time, right? It’s not going to get built overnight. It’s going to get built over the next five to 10 years. So what’s NRG’s perspective on this and where do see the market’s heading?

Gin Kinney: Well, we used to think about power generation or power plant development in spans of 10, 15, 20 years. And now we’re having to think about it in terms of 12 to 18 months. Our residential customers are thinking about it in 30 day increments, right? And so in Texas, the markets have worked, right? We did have a lot of issues during winter storm Uri, but they weren’t market design issues per se, right? So these markets are designed. To benefit, I think, all areas of the energy value chain. And so when we think about how we can scale up or scale down or meet the needs, because Texas is open for business, because permitting, interconnection, all of these things that really matter and can be some of those long lead times, we’re gonna be able to meet the needs of our customers and we’ll do that either through bringing on new generation. Utilizing battery technology and other forms of storage, we still have what are the largest renewable state in the country, right? So we have all of these elements. And then when we bring solutions like one gig of VPP, that’s one gig of electricity that’s not needing to be put onto the poles and wires across the state.

Joshua Rhodes: So one of the things about looking at the horizons that different customers look at or different market participants look at, I one of the things right now with the current events in the Middle East is, you know, gasoline prices are high and, you know, there’s a lot of talk about, well, if you want to be insulated from, you know, gasoline prices, maybe just switch to an electric vehicle. I know it’s probably a little too soon to see very much movement in that space, but like, how do you see the electrification of transportation with your customers moving forward?

Gin Kinney: Well, you know, it’s going to impact us twofold. One, more electrification is going to require more generation. It’s going to require more electrons created, but we are also going to be able to use those batteries in those electric vehicles to ease during times, maybe flow energy back, store energy. So I think it’s going to be a compliment to how we think about serving customers. In addition to smart home, EVs are part of a smart home. And so part of our strategy is to partner more with the EV companies, partner more with those third parties to figure out how we can continue to leverage those as a load resource.

Matt Boms: Yeah. And the generation mix like Josh just alluded to has changed so much in the last five years. Like it’s pretty mind blowing that you mentioned the role of renewables in Texas. Think it’s about 90 % of new generation since Winter Storm Uri has been wind, solar and batteries. How do you see the grid here in Texas? I mean, when we hear from reporters, they look at Texas as like the blueprint for how you build out a really diversified grid. Would you agree with that? Do you think that it needs any tweaks or changes moving forward, making sure that we’re reliable and affordable grid?

Gin Kinney: Yeah, reliable and affordable and reliable is a key piece of that as well because we’re going to have to have thermal load because thermal load is going to be there when the wind or the solar is not performing as it can be on the highest peak days. So having this great energy mix, think one is what keeps prices pretty low in Texas compared to other parts of the country and certainly helps us with the diversity of how we think about providing solutions to customers that meet their needs, adhere to their values.

Joshua Rhodes: So one of the things that’s been talked about with some other folks from NRG is that like, you know, if oil stays high, then the chip supply for things like Vivint could be affected. It’s part of your portfolios. How are y’all game planning that?

Gin Kinney: Well, using AI and thinking through our supply chain, and then also if our costs are going up to put these components in people’s homes, what are other ways where we can increase value? What are other ways where we can lower our costs? And so just being really thoughtful about how we balance across the entire value chain and portfolio of NRG. And one of the things that we want to figure out if we’re going to have to increase costs for a product or a service, How do we mitigate that with one of our other products or services? And I think the notion of saving money on your energy bill through enrolling in a VPP program is one of the ways that we can help mitigate some of those cost increase that we may need to adjust for a variety of reasons, whether it’s inflation, whether it’s not getting the chips through or other increased costs in the value chain.

Matt Boms: That’s something that we talk about all the time on this podcast is how important flexibility is and how undervalued it is sometimes in the market. Because of the transmission and really mostly distribution infrastructure that gets deferred because you have all this new flexibility, can you speak to where the real value is and how we maybe unlock some of the value stack that maybe isn’t quite available, at least in ERCOT, maybe in other markets where the utilities are more vertically integrated? But here the fact that we have our utilities on one side, generators on the other, gen tailors like NRG. Can you speak to maybe where some of the obstacles might lie and how we can unlock some of those parts of the value stack?

Gin Kinney: One way is just to increase the partnerships that we have across the energy stack. Let’s partner more with the battery providers. Let’s partner more with the solar providers. We announced a partnership with Sunrun a few months ago. So how do we get renewables into individual homes, right? So I think the value of partnerships is really one way to unlock some of the additional value for customers.

Joshua Rhodes: So one the things I did a lot of my research on was around for like Smart Grid 1.0. I there was a back in the early 2000s or whatever. And I remember there were a bunch of pilots and a bunch of things that went well and a bunch of things that didn’t go so well. I was curious if you’re able to speak to and it’s fine if not, y’all are trying a lot of things. Is there anything you’ve tried in the last couple of years that hasn’t worked out as you would have expected it to?

Gin Kinney: I think scaling, you know, you start with a pilot, like this is a great idea. And then perhaps whatever pilot you’ve tried didn’t scale. And I think that’s one of our biggest lessons learned is how do we start things in a pilot phase, test them out, see what works, take a lot of learnings from that, and then either pivot or trash the idea, which I think that’s also, you know, in a bigger company that maintaining that ability to be agile and flexible. That’s one of the ways. Test the product service, see if it works. If it doesn’t work, if customers don’t love it, then we’re not gonna do it.

Matt Boms: Yeah. Texas energy fund were a few years removed from that would have been 2023 session that the Texas energy fund passed officially governor Abbott signed it into law. And the idea initially was try to get more dispatchable power out there on the grid. So from NRG’s perspective, how are we doing on the TEF, any progress being made or anything that folks should be aware of?

Gin Kinney: All right, well, we’re actively in construction on three projects and one at T.H. Wharton is pretty far along and we’re bringing power to the grid in a very short order of time. And we did that by just making a bet. We placed our bets that we are going to be able to construct generation in the state of Texas in the near term. And so we had turbines available, we had labor available, we had all the necessary permits. Everything that we needed to start construction immediately. And so for us, we’re on track, on budget, and we’ll be ready to put power on the grid.

Joshua Rhodes: One of the things that the hyperscalers, those that are building some of these large data centers, are kind of garnering some criticism for are around some of their environmental goals that seem to maybe be taking kind of a backseat to a growth. Can you speak to NRG’s kind of like sustainability goals and how those have needed to change, if anything, to kind of meet the challenge that we have today?

Gin Kinney: First and foremost is our commitment to providing affordable energy to our customers, whether they’re households or hyperscalers. And then also hyperscalers need to pay their part, right? So if we’re gonna build generation, we’re not gonna pass that cost on to small businesses, existing businesses, consumers. So the hyperscalers are gonna have to come ready to pay their part in constructing that new generation. When you think about the natural resources, We’re going to take that into account every time we construct anything. Even in our TEF projects, we’re going to think about water, we’re going to think about lands, we’re going to think about the community, we’re going to think about emissions. And it’s no different when we’re thinking about partnering with the hyperscalers. And what I’ll commit to today is every deal we do, there’s going to be a community investment associated with it. I don’t know what it’s going to look like. Again, it’ll be bespoke for where the plant is sited. What the conditions are and what the community needs are. But community investment will be a really important part of every data center deal we do.

Matt Boms: Yeah, that’s great to hear and is so hard to build in general, Like transmission is hard to build, data centers are hard to build, community involvement is so important, I think more than ever. And what we’re hearing here at CERAweek has been a lot of BYO generation. That seems to be the buzz.

Gin Kinney: BYOP. Bring your own power.

Matt Boms: Is that kind of where NRG sees the market headed as far as data centers bringing their own power?

Gin Kinney: Absolutely. And that is our key strategy is bring your own power. Again, we want to make sure hyperscalers own their part in this and then those costs and the unintended consequences are passed down to our consumers.

Joshua Rhodes: Do we still need better messaging around that? Because there is a lot of angst around the cost of the infrastructure passing on to electricity. And I know like there’s a lot of the hyperscalers have come out with these pledges and things and we’re talking about bring your own power and the infrastructure and the community benefits. Is that getting through?

Gin Kinney: I don’t know. I’d like to say that we’re going to be able to change the narrative around it. But until we put one in the ground, until we prove ourselves, then I think we need to be held accountable. And if the media or consumers or consumer protection agencies want to challenge us, they should. And it’ll be up to us to deliver on our commitments and promises.

Matt Boms: Yeah, because at the end of the day, folks see their bills going up and they may not know where all the chargers are coming from, even as savvy as our Texas customers are. And I think that messaging is so important because moving forward, it’s, this is the new boogie man in town, you know, for a while it was renewables. Seems like now data centers and who knows who the next boogie man will be. But I think you’re right. The underlying message here is how do we help folks pay for their energy bills? How do we make things more affordable, right? At the same time, more reliable. It’s a hard message to sell, but it’s going to be really important, I think, over the next few years.

Gin Kinney: Yep, you’re absolutely right. And again, we’ve got to show up. You know, when we think about how we show up for our customers, how we build trust with our customers, they need to see it in their bills. We need to come through on the commitments we’re making to them.

Joshua Rhodes: And I can’t help but asking since you talked about, we got to put one of these things in the ground and kind of see how it goes. And if you don’t want to answer this question, that’s fine. But if you look at like ERCOT’s top level numbers for how much data centers and large loads, it’s like triple, quadruple. I think there’s bigger numbers coming out. I’m shooting for 500 gigawatts because just why not? But companies like NRG have to build the power to be able to support that. And so, mean, are you able to shed any light on like what’s reasonable? How fast can we actually grow?

Gin Kinney: That’s a great question. On the timeline, I don’t know. I think we need these in the ground, you know, 2030s, right? If not before. We have the benefit of being uniquely positioned that we have 5.4 gigawatts of turbines. Like, so we’re not going to wait on a turbine. We have an arrangement with Kiewit for labor. We’re not going to wait on labor. So we have those commitments. We have a great regulatory team. We have a great environmental team. I feel confident that we’re going to be able to move as quickly as we can, but we have all the right pieces in the right places.

Matt Boms: Yeah. And at the end of the day in Texas, the rate payer is not on the hook. Ultimately, it’s the investor that’s on the hook for generation, which is really different in other parts of the country, right? That’s what we have in Texas that’s very unique. And I think the three of us are all champions for this great market that we have.

Gin Kinney: That’s right. That’s back to that competition. Competition creates that innovation. Creates, gosh, I’m going to say this, the need for speed. Anyone old enough to remember that movie? And I think that competitive nature of the way that we do things here in Texas are going to help us get solutions on the ground faster.

Joshua Rhodes: Yeah, it was part of a roundtable with Columbia University the other day. And it was the third roundtable that they had kind of had. It was in Texas and they had had the other ones were in New York and Washington, DC. And one of the immediate takeaways was like, how much more positive the Texas people were about electricity growth and data centers and incorporating this. Wasn’t a bad thing this was coming. We might not know exactly how it’s going to work out, how it will work out, but we’ll figure it out.

Gin Kinney: Yeah, I think in partnership with all of our stakeholders, we’ve created an environment that invites this type of development that understands the needs for power, that understands the needs of our customers and wants to really be that center of growth in the country, that center of innovation. And that’s where I see a lot of the positivity coming through. And in Texas, it just seems like there’s a little less uncertainty about how we’re going to get it done. I think that should provide a lot of confidence not just our customers, but also to our shareholders.

Matt Boms: Yeah, and the track record is there as far as how we built a robust grid over the past few decades, I think. You know, no state better than Texas as far as... That’s right. ...who’s built out a grid that could actually handle all this load growth.

Gin Kinney: And there have been a lot of lessons learned too. We’ve hardened infrastructure. We’ve learned to winterize, which really wasn’t a Texas thing several years ago. And then we’ve evolved our thinking too. And we also move, I think, at a faster pace.

Joshua Rhodes: Thanks for coming on the Energy Capital Podcast.

Matt Boms: Thanks so much, Gin. Thanks for spending time with us today.

Gin Kinney: I appreciate it.

Joshua Rhodes: Absolutely. Hey everyone. That was our discussion with Gin Kinney from NRG filmed at CERAweek. And this is kind of a discussion after that. It’s been a couple of weeks since CERAweek. And so Matt and I are here to kind of talk a little bit about that conversation as well as some other things that have happened that were talked about at CERAweek and things that have happened since then. Hey Matt, how’s it going?

Matt Boms: Hey Josh, I’m doing well. How are you doing?

Joshua Rhodes: Doing good, doing good. I actually just got back from London, so I’m a little jet lagged right now. So if I say anything that doesn’t make sense, I’m just going to blame it on that.

Matt Boms: Okay, so for you, it’s what like two o’clock in the morning right now

Joshua Rhodes: Yeah, I don’t know what time zone I’m in. Whatever. So one of the things we talked about with Gin was about their VPP, about their virtual power plant. Remind me like how NRG is structuring that.

Matt Boms: Yeah, sure. So for folks who may not know what a VPP is, it’s a virtual power plant. Some folks are calling it a distributed power plant, a DPP. So the acronym kind of depends on who you talk to. But NRG announced this years ago and essentially what it is, is an aggregation of smart thermostats for all of its retail customers in Reliant that sign up for this program. They’re essentially opting into this new virtual power plant program. So they’ll be seeing discounts on their bills for participating and NRG has projected about a gigawatt as far as the growth potential of the virtual power plan. Think the target year was about 2035, if I’m not mistaken.

Joshua Rhodes: Okay, so we got a bit of runway before we get there. Do you know how this like differs from like other smart thermostat programs? Like I remember I’m in Austin Energy and I know Austin Energy has had multiple iterations of smart thermostat programs. Like even before you had the smart Nest and Honeywell thermostats, like Austin Energy had, it was like a thermostat controlled by radio frequency. And so they would just like send out like a high frequency AM, I don’t know if it was AM or FM or even either one of those. But they would send out some kind of signal somehow and all these thermostats would just drop off. And so it’s like one way communication. They didn’t know exactly what, I mean, they could see reductions. Anyways, do know how this one differs in terms of like how it’s interacting with the ERCOT market?

Matt Boms: Yeah. Well, the idea obviously is to aggregate and bid into the market, right? Like so similar to what we’re seeing in the ADER program. And I thought that when we interviewed Pablo a few weeks ago, that was a really interesting part of the conversation, right? Because there’s a lot of potential out there. He referred to it as almost like an Airbnb or an Uber platform for virtual power, which I thought was interesting, right? Yeah. I think the biggest difference Josh is that this is a Gentailer that’s running the VPP. Right. Which is really unique if you compare it to like an Austin energy, which is vertically integrated or some other States that are running these programs, right? Like the example that comes to mind right now, because so newsworthy is this new special contract in Michigan that Google is currently negotiating with DTE with the utility up there and mostly renewable build out with some demand response included in the proposal. So. It’s really interesting to see moving forward with all this load growth, what role demand response and virtual power plants are going to play. Right? Of like, you can put some numbers to it. Like in this case, we’re talking about a gigawatt potentially of demand response. That once you get into the gigawatt numbers, think ERCOT takes that seriously and starts thinking about how big of a role it could play in, in grid reliability.

Joshua Rhodes: One of the things about turning something like these types of aggregations, to get those, like something has to be on before you can turn it off, right? The thing that’s different between like an aggregation of smarter distributed appliances and things is an appliance has to be consuming energy, say an air conditioner consuming five kilowatts, turn it off for a little bit of time to get that five kilowatts versus like a battery that’s sitting there that you’re able to turn something on. In my head, I’ve always put them in kind of different buckets. You know, we’ve seen like the ADER program, the ones that have actually move forward or that have been more successful early on have been more kind of the battery side of things because maybe utilities or maybe the aggregators see them as more better sense of the capacity that they’ll have.

Matt Boms: I think you’re right. Think that to really break this down, like VPPs are the orchestrators of distributed energy versus a traditional demand response program, which is just about changing consumption behavior, right? Like just getting into the way that we consume energy and trying to reduce that peak load. I do think that VPPs are exciting moving forward because they’re so local, like the ADER program in Texas being a great example. If they’re able to target specific substations and actively work to lower peak load at that substation, then it will make a significant difference, right? And like in those specific, we call them nodes, but in those nodal areas where we know that the substations are being overloaded. So I think there is a lot of potential there as far as not necessarily a traditional demand response model, but virtual power plant that has the effect of, you know, flicking a switch and turning on a virtual power plant.

Joshua Rhodes: Yeah, okay, that makes sense. One of the other things we talked a little bit about with Gin, but we also like heard a lot talked about at other panels in CERAweek is, you know, all the stuff still going on in Iran, right? There were people who were talking about like how long it was going to last, you know, as we’re recording this a couple of weeks later, it’s, you know, still going on. To me, it’s unclear how much is moving through or if anything is kind of moving through, although oil prices are still high. They’re talking about, you know, rationing jet fuel and things like that in Europe. It’s still a pretty big issue and the price of gasoline is high. When you were there and listening to other panels and other things like that, do you think people had a feel for what was happening or do think that they figured it was gonna lasting this long?

Matt Boms: I don’t think anybody did, right? At least you and I and most normal people who may not be in the weeds on this stuff, but I thought it was interesting at CERAweek to hear, obviously the shareholders are paying attention, right? So when companies go to CERAweek and they speak about load growth and data centers and the war in Iran and gas prices and all the above, it tends to lean towards like overstatements and it’s hard to distill really like what’s true and what will. Take shape in the markets versus how much of this is hyperbole. So like, would actually flip that question back onto you, Josh, because I feel like you’re more qualified to answer it than I am. Like you’re coming at this from a much more academic and scientific point of view. And we’ve had a lot of conversations on this podcast about the load growth numbers and how inflated or not inflated they are. But what’s your latest feeling on this? You think that we’re in for a bit of a cooling period as far as the numbers are concerned?

Joshua Rhodes: I think I learned pretty early on not to really opine on federal policy when it comes to some of these things. Sometimes it’s hard to see what is going on. Mean, if we zoom back down into Texas, like looking at the numbers around electricity and load growth and other types of things like that, I wouldn’t say they make any more sense, but it may mean at least we might have a better handle on that. Mean, I some of the latest numbers coming out of ERCOT in terms of large loads are now even larger. I think some of the latest numbers I saw was like 410 gigawatts. Of large loads come into the system. So that, again, we’re in 85 and a half gigawatt load. And so you’re talking about, you know, a 5X of the grid in the next few years. I mean, it’s not going to happen. There’s no way that the system can grow that fast. Even 20 % of that is still a significant chunk. Even like 20 % if I’m doing the math right in my head of the expected large load is like doubling the grid, right? It’s pretty insane. You know, it’s easy to look at the numbers and think like there’s no way, you know, that that kind of thing could happen. I was driving through the Hutto, like kind of Taylor area a few weeks ago and you know, there are some of these things being built. I mean, there’s some massive data centers and things like that being built out that way. I thought I was actually coming up on the Samsung plant, but then I realized I wasn’t even in Taylor yet. And I was in Hutto, you know, driving past a huge data center and a whole bunch of natural gas gen, you know, that’s coming along with it.

Matt Boms: Yeah. And like, not to mention the impact of Austin being surrounded by data centers and what that will bring in the future. But to your point, Josh, this is also happening across the country. Like the Michigan example that I mentioned, that’s a 2.7 gigawatt contract in a state that has like 20 gigawatts of summer peak load. So sometimes the numbers aren’t as eye popping in other states, but proportionately it’s the same effect, right? It’s like, how do you grow your grid exponentially that quickly? The thing about the numbers that you just mentioned from the ERCOT, like the most recent numbers, is that we had that bill HB 5066 a couple years ago on the Permian Basin. So, you know, people forget that that changed the way that we do regional transmission planning forecasts. Correct me if I’m wrong, but I think that’s where the numbers are coming from as far as utilities providing those numbers and then ERCOT being forced to adjust them based on their own projections.

Joshua Rhodes: Yeah, no, it did. Mean, it basically, ERCOT had to consider all unsigned load, like in planning processes. But then we had SB6, it also said, you know, you’ve got to say whether or not you’re shopping this around, and things like that. But yet the numbers keep getting bigger and bigger and bigger and bigger. And so I don’t know about you, it was like 410, like I was shooting for 500, like I was really hoping it’s going to be 500. I am still kind of confused, right? I mean, you know, how much of it to believe or what else because I thought that was going to have a little bit more clarity into the system, but the numbers just keep jumping up higher and higher and higher. I ERCOT has their adjusted load forecast, which is lower, but I mean, it’s still a pretty significant increase.

Matt Boms: Right. Yeah, absolutely. And you feel for some of the decision makers, like when we came away from the interview with Pablo, they’re putting a really tough spot, right? Because if you’re ultimately the grid operator and you have to plan for all of this loading, you know, some of it isn’t going to materialize, then you’re putting a really hard spot. And I think the same could be said about the public utility commission, right? Because they’re trying to map, like they want economic development, they want economic growth, but at the same time, you can’t build out for load that may not materialize. So. The numbers somewhere in the middle, at this point, think it’s anyone’s guess how much we actually end up with.

Joshua Rhodes: I actually ran these numbers the other day just using ERCOT’s long-term load forecast and other types of things. And I compared it to what we used to do, particularly for our own grid modeling purposes. If you took historical data and then projected forward based on that, just looking at peak demand, if you take the past few years of growth and you look at, say, 2030, you’re at about 100 gigawatts in terms of ERCOT in the grid. So between the next four five years, we gain another 15 gigawatts. Which is in line with kind of how traditionally we would have thought the system to grow. You look at, so ERCOT’s adjusted load forecast is about 140, know, about 40 gigs more of that. And then if you take the additional TSP, like, you know, all the unsigned load, it’s like 210 or something like that, which is a pretty big difference. It’s like historically what we would have seen to be about 100 and then the high line number being double of that. One interesting thing is this time period between like now and 2031 ish or so, where you just see this massive change in load growth and then it kind of flattens back out again. It grows, but then it grows at a more reasonable path. It means the next few years are going to be pretty darn interesting and the answer is probably somewhere in the middle.

Matt Boms: Yeah. Well, what do you think about this topic that we kept hearing at CERAweek, which is don’t worry, we’ll bring our own generation, right? Cause we heard a lot of that in Houston. Yeah. And I know some of it is true. Like absolutely some of these data centers are doing that, but what I hear most from experts is the cheapest electron typically comes from the grid, right? That’s not going to come from bringing your own generation. Like, where do you see that landing as far as these data centers coming with their own generation?

Joshua Rhodes: I don’t believe that these data center companies, these hyperscalers want to be in the power business. And I’ve listened to a few other podcasts with some other folks from some of the big ones like Meta and Microsoft and other places. They’ve even said that, right? That they don’t really want to be in the power gen business. One, because the margins are much lower than they’re used to expecting, right? It’s not like they’re getting into this like they’re trying to make money. I the margins are single digit margins versus the double digit margins or triple digit margins, depending on who you are. That you’re used to. So this is not an attractive business for them to be in. It’s out of necessity that they’re trying to. And even some of the conversations that I’ve heard, it’s like they’re not even trying to do this in the long run. It’s just like, if you’re measuring every megawatt of data center that’s not operational in the billions of dollars lost every year, that’s a pretty big incentive to try to get your data center going as fast as possible. So you’re hearing a lot of things like bridge power and other types of stuff. Like we want to be on the grid, but we want to start generating tokens. Tokens being like the answer that the AI models give you, like every word or letter or piece of code being a token. We want to be generating these tokens based on the models that we’ve trained. We need to, because that’s how we make money, right? But it’s hard, right? Because, well, you’re competing for the same assets. Supply chains can grow and we can have other companies that build these power plants can increase and grow, but they can only grow so fast. And like I was just looking at the ERCOT data, it’s like the next five years are key, right? In terms of how many data centers and how they want to connect these supply chains, they can’t grow that fast. And so you’re seeing some really wild things out there when it comes to like how these data centers are going to be powered. There’s a big data center, roughly a 350 megawatt data center going up outside of El Paso. That’s going to be powered by something like 800 small units that are like 450 ish kilowatts each. But that’s like the only way that they’re able to get power to that region. And then there’s something going on at the Public Utility Commission about how those assets will eventually transfer over to El Paso Electric, like rate base or something like that. I don’t fully understand how it’s all set up. But in general, stringing together a whole bunch of really small things. To power a big thing. It’s like a symptom of like the thing that they actually want, which would be to connect to the grid is not available. The secondary thing that they want, which would be, you know, a multi hundred megawatt power plant is not available. And like there’s no other option, right? You’re going to go with 800 really small things with a whole bunch of moving parts. To me, that sounds like a logistics nightmare when it comes to maintaining these things and keeping things operational.

Matt Boms: Yeah, absolutely. I mean, there will be a wave of co-located solar and batteries. I think we’re already seeing it for a lot of these data centers. But I think you’re right. For the most part, this is like plan B for them, right? You know, if they had another option, they would just connect to the grid as soon as possible, but it’s all about speed to power, right? They’re all just trying to get connected as quickly as possible. And we’ve had a couple of legislative hearings since we were at CERAweek in Houston. So I wanted to get your thoughts on that. My takeaway really was like, I think SB6 is just the beginning of legislation around data centers and transmission cost allocation and all this stuff. It sounds like there’s going to be more coming from the capital next year, but what was your primary takeaway from those hearings?

Joshua Rhodes: I mean, yeah, this is a problem we’ve like never really had before, right? It’s hard to plan for what you don’t know or have processes in place for what you don’t know. Just an example, I was talking to one TSP a couple of months ago. I know everything in this space feels like a couple of years ago. I was talking to one TSP a couple of months ago and they said that in the previous years, they might’ve had like one large load study going on per year, but at that point they had like a hundred going on at the same time.

Matt Boms: That feels like a couple of years.

Joshua Rhodes: The system was not designed to handle that. And this is why ERCOT’s doing this batch zero process that Pablo talked about. It’s because we have a generator interconnection queue and there’s like a very well understood process upon which a generator moves from a dream to making electricity. When we talk about this large load interconnection queue like we actually had a process, there wasn’t really a process in place. This plane took off and then we’re trying to build it. As it’s going in the air. It had taken off and it was already over the Atlantic Ocean by the time we figured out like we needed to build it, right? I think there’s going to be a lot of policies and protocols and like things that we’re going to have to figure out. And we’re not going to get it perfect. I mean, I think we’ll do it better in Texas than they do in other regions. Other regions are just, think Maine recently just put in just a straight up moratorium on things and saying, no, we’re not going to build anything here. I think Texas is going to try. To build as much as we can because that’s what we do. But yeah, we’re going to have to figure this out and we’re going to figure out who pays for it, right? It’s one thing for that load to grow at like a steady clip that supply chains are used to handling. But if it grows many, many, many, many times faster, classic supply and demand means prices go up. We’re going to have to figure out how do we make sure that those that are putting the new stress on the system are the ones that are bearing the cost of that.

Matt Boms: Absolutely. Yeah. And I think some of that, the PUC is working out right now through these rule makings around SB6. It’s not perfect, but like you said, we’re kind of out front and center on this issue in a way that other states are not. Like other states are just starting to ask those questions and we were already implementing legislation. So I do see that we’re at least a year and a half ahead of most other states. The question is just like, how does the PUC implement those rules? And then what’s missing heading into the next legislative session? We’re like in this big kind of uncertain territory right now.

Joshua Rhodes: Yeah, mean, even companies will tell you like they prefer policy certainty, even if the policy is bad, because then you can just work around that policy uncertainty is like something that is the worst.

Matt Boms: I hear that all the time. Our companies are like, just tell us where the goal posts are and stop moving them. That’s all that they want. They’re just looking for a certainty, for sure.

Joshua Rhodes: Yeah, that’s what Pablo said when we talked to him the other day, right? He was just like, we’re going to implement. He was talking about something else, but he’s like, we just got to get going and then we’ll make it better as we do, which I think is smart.

Matt Boms: And also Josh, there’s always a reason to go pass more bills because Winter Storm Uri was the perfect reason, right? But then there’s always something happening. So now we’ve got the data center boom, we’ve got more legislation coming out of Austin, which just begs the question of like, when is enough legislation and maybe just time to let the market do its thing.

Joshua Rhodes: No, I totally. Mean, bless their hearts, but the Texas legislators, they’re not electricity experts. It’s a citizen legislature, right? I think it’s best done when they set high level goals and trajectories and let the Public Utility Commission has electricity experts sitting on the dais or as in the staff and all the other folks, let them do the job of taking that broad policy direction and converting that into workable statutes. And things like that and then let ERCOT convert those into protocols that actually govern how the market is structured. I think the ledge got a little too prescriptive after Winter Storm Uri because they wanted to feel like that they were doing something. I mean, I feel that but it’s like you get too prescriptive, it becomes harder to work in the system, right? The more prescriptive you are starting like higher up the chain, like the less flexibility that the Public Utility Commission has to maneuver and then the less that ERCOT does and like... Because we probably need the maximum amount of flexibility and maneuverability, I would hope we don’t legislate as strict or as granular as we did after Uri.

Matt Boms: Yeah, I think you’re totally right. Think like, you know, we don’t want the legislature creating new ancillary services, for example, that should be ERCOT’s job. And to your point, Josh, I think that this is the best version of the PUC and ERCOT that I’ve seen since I started in this role. They’re extremely competent and very smart and just have a ton on their plates right now. Right? So like the best thing that the legislature could do would be just let them do their jobs and give them some time to work out all these different rule makings, you know, cause right now they’re just trying to catch up. Get up to speed with all the statutory deadlines. They don’t have time to take on additional work that maybe ideally they’d like to be working on other things, but they just got to get through all these different deadlines that are on their plates right now.

Joshua Rhodes: Yeah, totally. All right. Thanks everyone. That wraps up the post conversation with Matt. Big thanks to NRG and Gin for being available and chatting during CERAweek. It was great and looking forward to seeing y’all next time. 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 Texas Energy and Power at texasenergyandpower.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, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

ERCOT’s all-time demand record is 85.5 gigawatts. Yet by the end of last year, the grid manager’s interconnection queue included 432 gigawatts of generation requests. ERCOT also received 225 gigawatts-worth of new large load requests last year.

The critical factor connecting the two: transmission lines. But the transmission improvements that would accommodate such dramatic grid growth aren’t growing nearly as fast. In a conversation with Energy Capital Podcast host Micalah Spenrath, renewable energy veteran Raina Hornaday describes transmission as a planning and construction constraint that load growth is no longer willing to wait for.

Raina has developed more than a gigawatt of renewable energy across Texas over the past 20 years. She founded Caprock Renewables and Fortress Microgrid, overseeing the creation of both utility-scale and distributed generation resources.

In this episode, she describes a shift in how generation and load projects are being created: she calls it, “the energization of land.”

She and Micalah also discuss how transmission lead times are prompting distributed generation resources to grow quickly, even as utility-scale solar continues to boom, and how institutional knowledge is moving from utilities to private developers, reshaping project delivery.

Raina also credits battery storage resources added in the past five years for easing the price volatility that used to define ERCOT’s energy market. She says market adjustments made in the past five months have created a tailwind for storage projects.

And she and Micalah discuss Senate Bill 819, a measure filed in the last legislative session that would have imposed strict siting requirements on renewables projects and likely hobbled Texas’s nation-leading renewables industry. While the bill drew widespread opposition and ultimately died, Raina expects a similar proposal to be filed again in next year’s legislative session.

She says education — about the tax base that renewables create for rural communities, the revenue that renewable energy projects offer landowners, and the workforce they create across the state — is key, both for blocking anti-energy proposals and propelling the state’s economic and energy future.

Timestamps

* 00:00 - Introduction & Raina Hornaday

* 00:54 - Caprock Origins: Family, Wind, and the Met Tower

* 03:52 - Why South Texas for Utility-Scale Solar

* 05:36 - The Landowner Pitch and Family Legacy

* 09:06 - Boutique Developer in a Shifting Policy Landscape

* 13:00 - Education, Powerhouse Texas, and American Farmland Trust

* 16:14 - Agrivoltaics and Solar Sheep as a Growing Industry

* 17:29 - ERCOT Interconnection Bottlenecks

* 20:57 - SB 819, Tariffs, and Real-Time Co-Optimization

* 23:21 - Testimony, Schools, and the Workforce Pipeline

* 28:55 - Distributed Batteries and Storage Economics After Uri

* 32:18 - Why Battery Projects Get Canceled

* 34:22 - What Texas Needs Next: Flexibility and Distributed Generation

* 36:50 - Closing Thoughts

Resources

Guest & Org

* Raina Hornaday (LinkedIn)

* Caprock Renewables (Website - LinkedIn)

* CleanTX - Raina Hornaday Board Profile

Organizations Discussed

* ERCOT

* Public Utility Commission of Texas

* American Farmland Trust - Texas Smart Solar

* PowerHouse Texas

* CleanTX

* Texas A&M AgriLife Extension

* Texas Tech University - Energy Commerce and Renewable Energy

Company & Industry News

* ERCOT’s large load queue jumped almost 300% last year - Utility Dive

* ERCOT Goes Live with Real-Time Co-optimization Plus Batteries

* ERCOT’s large load queue has nearly quadrupled in a single year - Latitude Media

* ERCOT Announces Strategic Organizational Changes to Support Grid Reliability

Books & Articles Discussed

* The Economic Impact of Renewable Energy and Energy Storage Investments Across Texas - Joshua Rhodes, IdeaSmiths

* Texas Renewables Interactive Map - txrenewables.net

* Supporting Expansion of Agrivoltaics Using Smart Solar Principles - Southern SARE Grant

* Texas Senate Bill 819 - 89th Legislature

Related Posts by Texas Energy & Power

* Texas Power Rush

* It’s a Transition and an Expansion

* Flexibility Driving Reliability and Affordability with Matt Boms

Transcript

Micalah Spenrath: Hi everybody and welcome back to the Energy Capital Podcast. I’m your host, Micalah. And today I have with me Raina Hornaday, who is a veteran renewable energy developer with over 20 years of experience advancing the energy transition across Texas, bringing more than one gigawatt of renewable energy projects into commercial operation. As the founder and co-owner of Caprock Renewables and Fortress Microgrid and Caprock DLE, a direct lithium extraction venture developed in partnership with Texas Tech University, Raina leads the development of distributed solar generation storage and microgrid infrastructure across the state. Super excited to have you on the podcast, Raina, and we’ll hop right in. So in case I missed anything in your intro, give us a quick introduction to your work and Caprock Renewables in general.

Raina Hornaday: Thank you so much for having me. This is one of my favorite podcasts of all time. So I’m really thankful to be a guest today. Caprock Renewables came from very kind of homegrown roots. My family homesteaded in Eastern New Mexico, 1906. And my dad started Caprock Farms in the seventies. His dad and his grandfather farmed dryland wheat farm, milo, things like that on the high plains of Eastern New Mexico. Starting in 1906 and then until my dad passed away a couple years ago, but he farmed his whole life and was a diehard farmer and loved the land. And he also was the executive director of Eastern Plains Council of Governments. And that gave him the opportunity to put up a small Met Tower on our edge of our farm, which is where the Caprock name comes from. It is the Caprock. There’s lots of Caprocks. It’s not the only Caprock. There’s a town in Texas called Caprock. But we had Caprock Farms and ranches. He put up the Met Tower. He and I would go get the chip, mail it to California, and we retained that data. And I took it to the Renewable Energy Roundup, which is a precursor of CleanTX, a TREIA. It was a TREIA event that was held in Fredericksburg, which I loved so much. And I think it was 2001. And I met with lots of folks there — rainwater catchment folks, but renewable developers. And that’s how the Caprock Wind project that is right there between our farm and ranch in Eastern New Mexico was born. So that project lived its life 20 years. It was decommissioned by Leeward Energy and repowered next door with the same substation. So that’s where Caprock Renewables got its name. I founded it 10 years ago and the goal was to do utility scale solar. We did 150, 200, and 300 megawatt projects in Texas. And during that time, that was really when the utility scale solar assets were being built out in Texas. And I had done this with wind, so it was really interesting to see how similar it was. But these, as you know, people from all over the world, the biggest companies come to do business in renewables in Texas. It’s just the best market. It’s kind of the easiest market, energy only. And so I’m a small developer, boutique shop. Then I started Fortress Microgrid to kind of see how the microgrid industry needs could be met and ended up doing small agrivoltaic projects in the Valley. And so I have one of the biggest projects and then I think one of the smallest projects. So that’s fun and just got into more meaningful, smaller projects. So doing a lot of things now, but that’s kind of how we got here.

Micalah Spenrath: Yeah, thank you so much for that history. So when I investigated, that might be too formal, when I researched Caprock Renewables, it seems like y’all did a lot of work in the South Texas area. So just curious what initially drew you to focus in that region, the South Texas region, but also utility scale projects in general. So you mentioned that the ERCOT market was particularly attractive. I imagine the business case was really persuasive at the time. So taken all together, what really spoke to you about South Texas utility scale solar projects?

Raina Hornaday: Well, the cost of solar just went down enough to make it feasible. And that’s one of the main drivers for this boom in solar we’ve seen. And our site selection for our projects is fully based on nodal data of where the best prices are for projects and substations and then where land is available. And that’s just such a big part of the development. Process is working with landowners. And as a landowner myself, I always advocate for landowners and just have some of the best landowners that I’ve been able to get to know. And it really is such a big process. The 300 megawatt project, we had to build a new substation. So it took two full years of construction on that. And we had the ribbon cutting and had a big tour and everything of that facility with everyone involved. And it was so rewarding to see it done. And the landowners just So appreciative because it’s such a great thing for the family and the community and he’s gonna have sheep out there. So that’s always if we can do dual use in these situations with land, we always try to do that.

Micalah Spenrath: Yeah, that’s amazing. So I’m a bit curious, as a follow up to that, can you walk me through your approach to a landowner when you’re thinking of partnering with them to develop a site for utility scale solar? What’s the value proposition there? What does the conversation look like?

Raina Hornaday: So we send a lot of inquiries out and so a lot of conversations. But this particular project, the landowner responded and many times they’ll have multiple bids because or multiple, we call them LOIs or offers on their desk. And this landowner came to our office and said, I have term sheets in front of me for these big companies. I went with you because I know that Even though you’re small company, with the bigger companies, they have a lot of different projects to pick from. And with you, I think you’ll really care for my project and get it over the finish line, which was really nice. And this landowner is in the energy industry as well, which is always interesting and helpful. But he just explained many times, but at the ribbon cutting that he loves the fact that it helps him keep the land and his family for generations to come. And his family had been there since the early, I think even late, 1800s. So many of these landowners are finding this as a way to continue the family legacy when children and grandchildren aren’t able to come and live remotely and farm and ranch like our parents and grandparents did. So it’s really just become an option for farmers and ranchers. So that’s one of the things, and then it’s making the land pretty much farming energy on your land, which is a funny way to put it, but it’s productive. And in this case, again, there was a coal plant retiring. So we took the place of the capacity that the coal plant was providing. And we went to a school board meeting and they were giving the coal plant award for being a good steward of, it was just so ironic at the time, but that’s how we’ve seen it happen. You know, coal plants we knew were retiring. So in New Mexico, same thing, lots of renewables have been added as coal plants have been decommissioned. So it uses no water, which is really great. And again, if you take care of the soil and the vegetation management correctly, you can grow crops. I’ve seen lots of balers baling big round bales in between solar panels, which makes me so happy because it’s really productive. And then of course there’s the sheep and then cattle voltaics is the... Next thing that’s coming. So I’m really excited about that. It’s happening a lot over the country, but we’ve seen a lot of interest here in Texas.

Micalah Spenrath: Absolutely. Mean, whenever I drive to the coast and you pass through the rural areas, there’s so many like cattle companies, just acres of cattle. I’m actually very interested to see if Texas will be an enthusiastic adopter of cattle voltaics. We certainly have a lot of cattle.

Raina Hornaday: and a lot of land and that’s really one of the drivers for utility scale solar here is just there’s 97 % of the land is privately held so landowners can do what they want to do with their land and everyone needs additional revenue and this is often a great option for large operations.

Micalah Spenrath: Absolutely. So something you mentioned, you are a boutique developer, if you will, so a small scale developer. So my question for you is, given the policy changes that we’ve seen with tax credits, federal policy adjustments, but also state changes as well, how does a small developer navigate those changes as compared to some of these larger developers with larger portfolios and presumably more resources?

Raina Hornaday: Well, for sure more resources. It works for us because we don’t have the commitments that the larger companies have. So I think it’s just a give and take, but I love how small and flexible we are because we can respond to a project at a local school. And we’re working on a couple of larger projects, but a lot of our projects are custom for a producer. I like those projects because they’re meaningful. The tax credits going away was obviously a change, but everyone kind of, you know, I was at the Capitol educating and talking to the decision makers when all these bills were on the line. And it was really a high stress time, as you know, in the industry, but everyone, we got through it and we’re just continuing to do projects and we just have to make those economics work. And we’ve always known that same thing with wind and tax credits with wind. So it’s just continuing to do what the cycle has always been, which we had to get there. And now we’re there and we have this huge need for energy. And so there’s a lot of energization of land and people coming in and saying, hey, how can I get the most amount of energy out of this land? Which is just an interesting way to look at development that I don’t know, I just hadn’t really ever looked at it the way it’s being looked at now, which everyone’s trying to maximize their land for a data center or batteries or solar. So it’s just creating an analogy I really like that was more for the wind industry because all this is based on our grid and how our grid can handle this, which it really can’t. We need a lot more flexibility and we need a better roadmap, but When my family homesteaded out, you know, they had a dugout, it’s still out there on our ranch. All the ranches out there had, there wasn’t transmission and they had wind chargers. And so they had distributed energy. They made their own energy. After that, they had every little ranch and farm has solar, I have solar panels that my grandparents had at wells and they’re so old and You can still get some juice out of them. And in the wind business, I was managing the development of Cielo Wind Power at that time after the Caprock project was built. And we put up, I think, 1100 wind turbines between Amarillo and the New Mexico state line on I-40. So we always made the analogy. There was 1100 wind turbines out there before, and now we’re just getting it back to where it was. I think we just need more. And Texans want, landowners want energy. Security and independence. So if you’re able to produce your own power, people really like that.

Micalah Spenrath: Absolutely. We hear a lot of the homegrown energy terminology and it sounds like that’s exactly what you’re doing. And you put it very succinctly, but also poetically, energization of land. And I think that that is really a huge opportunity. And like you said, a lot of landowners are looking to get the most out of their assets and partnerships with smaller developers like yourself that also value sustainability and stewardship. Match made in heaven, right?

Raina Hornaday: Yeah, it’s rewarding and it just needs to be done thoughtfully. And I always come back, whether I’m in a room with big policymakers or community folks, education is really what is needed across the board, even between me and partners I work with in the oil and gas industry. I don’t know what they know, they don’t know what I know. So education kind of going back and forth that way, but That’s one of the things I appreciate so much about Powerhouse Texas. And I’m so looking forward to being a part of this legislative session and just putting so much out there, which you and I might take for granted because we have the resources in front of us, but it’s hard to filter everything out and get to what’s helpful and what’s factual. And there’s lots of misinformation out there. So, Powerhouse, I love, of course, CleanTX. I’m the biggest fan of, and then American Farmland Trust is one of my favorite things that I help with for their SARE project. I don’t know if you read about it or not, but we’re training 25 agricultural and conservation professionals. So we’re helping and we’re training like local ag folks and people on the water side of things, farm bureaus, AgriLife Extension. NRCS staff, things like that. And so it’s good for us to get a consistent sharing of information and dialogue because that’s who the farmers go to, to ask. They go to their ag extension agent, say, Hey, should I do solar? Should I do batteries? So that is a really important thing that, that American Farmland Trust is doing. And they do extensive research. They do a lot of. Questionnaires to farmers. So they really are getting a lot of data on this energizing land and how landowners can take advantage of hosting energy projects and dual use. And one of their farmers and ranchers has a large utility scale solar project on her family’s land and her son went to Texas Tech and then they got the contract to manage the vegetation. Which is part of the operation and maintenance contract and their son graduated from Texas Tech and moved home. And he has a job because he helps manage the sheep under the solar. So we have this group of industry folks that care a lot are helping put together these best practices across the board for development, which is needed. And, you know, I’m doing battery energy storage projects as well now also, and I go to these co-ops and small communities and there’s not a standard operating procedure for these. There’s no real policy across all these different potential locations for these storage. So every time it’s like Groundhog Day, but I think eventually and I think we’ll see it a lot in the next session is just we’ll have some standardized policy for projects. So anyway, it’s an exciting time to develop in Texas and ERCOT for sure.

Micalah Spenrath: Yeah, and I think you mentioned agrivoltaics as not only being energy jobs and bringing energy jobs to rural communities, but also agricultural jobs. So I think that’s an angle that isn’t talked about very much. We do acknowledge that agrivoltaics and utility-scale solar can bring energy jobs, but it also creates opportunities for agricultural professionals as well.

Raina Hornaday: Yes, and that’s why like UTRGV and there’s lots of educational facilities like that that are doing real research on agrivoltaics for high producing crops. And vineyards, our first project was on a tiny vineyard in the Rio Grande Valley. But what probably has been one of the biggest industries that have come out of this dual use agrivoltaic, well, we call it agrivoltaic, is the solar sheep. You know, I have a good friend that has solar sheep and it’s just a really big business to run these sheep and move them from site to site. And then you have the dogs that protect the sheep. I mean, it’s just work and it’s an industry and it’s growing and there’s a lot of companies involved. And so it’s really cool. Like you said, it’s potential jobs for locals really.

Micalah Spenrath: Absolutely. So you’ve mentioned several different projects. So I do want to ask, from a development standpoint, what are the most persistent bottlenecks in getting some of these projects from early stage development into interconnection and operation in the ERCOT market today? An easy one for you.

Raina Hornaday: Well... Yeah, well, it’s just so interesting because the interconnection queue, I’m sure you know, at end of 2025, there was 432 gigawatts of generation request. And then the large load, think they, ERCOT had 225 new large load requests in 2025. So it’s pretty much, I think one of the ERCOT folks said it’s outgrown the process. Like that’s too much. So interconnection. Obviously is a big one. I mean, that’s why I got into doing smaller projects. So, you know, we do sub 10 megawatt projects for battery storage and a couple solar, but the reason we did that is just because you don’t have to do all the interconnection, the full studies for interconnection. You don’t have to go through that interconnection process. And it’s really been such a learning experience for the distributed energy, like I said, it goes back to kind of the original, it’s energy projects that are on site. And now with data centers, data centers want that. So they want behind the meter, they want as fast as possible. They want every electron. So that’s really interesting. It’s been not the fastest process because a lot of places that we go to do projects, it’ll be the first project for this municipality or co-ops. And then we’ve been delayed. Because we’ve worked with folks that say, I’m waiting for rulemaking to come out, for policy to be clear for us on what’s going to happen. And I’m like, wow, it’s hard to hear that because we have deadlines and we have project schedules. And then when something like that happens, the other thing that’s happened is a lot of the leaders of the utilities and munis and co-ops are the talents getting picked off and hired off. For other projects and big companies. And so then the people that know all the information about forever of their system and their needs and their really smart electrical engineers that have run the cities and municipalities, they’re all of a sudden gone. So it’s an opportunity for other people, but at the same time, it slowed processes down a little bit for us.

Micalah Spenrath: Yeah, so to summarize, some bottlenecks that you’re experiencing are first, if it’s kind and specific geographies. So you’re having to lay the foundation for some of those areas that haven’t had or hosted projects before. So there’s a learning curve with that policy and changes there, especially in the regulatory space. Those can also pose delays for you. And as a developer, time is money. So that can also be a challenge as well. And then loss of institutional knowledge. So like you said, some of the best talent is transferred from the public sector to the private sector, and that can also present challenges to developers as well. So do you think that sums up your thoughts?

Raina Hornaday: I think so.

Micalah Spenrath: Awesome. All right. So the policy environment for renewables in Texas has become more dynamic in recent years. How are regulatory and legislative proposals affecting your project pipeline and your investment decisions.

Raina Hornaday: We went through the SB, the 819 obviously was the biggest one, 388 and then SB 715 last year. So they didn’t make it, but we kind of know that they’re not buried. They’re probably coming back. So I think the fear of what could happen in the future and really the tariffs have been a big kind of jolt to the system, just direct kind of gas. When you have orders coming and then all of a sudden the price is completely different. And some of the orders might be in transition and some might be, it’s new problems and new challenges that we’ve never seen before. So storage, the real time co-optimization plus batteries that launched in December 2025, that really has given storage a lot of, you know, it’s a tailwind for storage. So it’s big upgrade. For that. And I think there’s a lot of opposition about storage out there in different areas. But it really is a great thing for the grid. And it’s a great thing for local communities. And it just provides flexibility and resiliency. And we go places and they think they’re anti-storage and we walk them through what it does because lots of people think, you’re taking my energy and are you paying me for it? And it’s just an understanding or misunderstanding of how battery energy storage functions and how they can potentially make money, know, ancillary services and how it benefits them and the local environment. So yeah, I think going into this next session, just seeing, being prepared for what’s going to come at these renewable energy and then battery energy storage. But I think with the AI infrastructure that’s being built, batteries are just they’re being added to many, many, of these big projects. It’s just going, everything that can get built is being built right now and it’s exciting.

Micalah Spenrath: Yeah. So you had mentioned some of the legislation looking to regulate the renewable energy industry. And some of that legislation, specifically Senate Bill 819, could actually dampen investment in that industry in Texas, which, as you mentioned, might be counterproductive given the demand that we’re seeing from large loads and data centers. So I recall during session, I think you personally testified on Senate Bill 819. But there were also, I think, over 100 other stakeholders that showed up as well, many of them landowners, some of them veterans, this really diverse group of folks. So my question is, with such a show of support for the renewable energy industry, what’s it going to take for lawmakers to get the message and for them to maybe pivot some of these renewable energy legislative proposals?

Raina Hornaday: Well, I really think it’s education and it’s also proof. Mean, so many of these large renewable developments have provided so much revenue for conservative rural communities. So it’s hard to ignore that after we have like Joshua Rhodes does the data gathering and has these papers on how big that figure is of the economic boom. To rural developments because of renewable energy. And a lot of these decision makers and policy leaders and legislators are landowners. So as I said, Powerhouse, which you obviously know very, very well, I just love that they’re getting together energy policy directors, staff, chiefs of staff, and bringing experts in, not at the fire drill that we did, which I loved because it was such a kumbaya, like it was just amazing. But this is preemptive. I mean, we’re starting this 12 week cohort for education. And I think that’s just so important because we have to get the facts and we got to get the facts to the policymakers, to the voters. I mean, in general. And so I really just think it does come down to education and then having really good, smart. That’s what I like about American Farmland Trust, having smart solar principles, going in with a real positive plan for the community and for the landowner and for the whole thing. So it’s very much a community engagement industry. It always has been. You always know that you meet the judge. You always meet the school district. You always go in front of the city council. I’ll often meet multiple mayors doing a project. And so it’s neat. Mean, Texas is incredible. I love it. It’s beautiful. And it’s a great place to be in this industry.

Micalah Spenrath: Can we explore the school connection a little bit more? I do know that renewable energy projects contribute to local economies, but you’ve mentioned school boards a couple times. So how do your projects interact with the educational system?

Raina Hornaday: Well, after I said it, I realized, you we used to have tax advantages through the school. So we would make deals with the school so they would have increased revenue. And so that got voted out of, I think it’s been a couple years. Yeah, it was, I think, three years ago.

Micalah Spenrath: And that’s chapter 313.

Raina Hornaday: Yeah, that’s 313, which was such a big part of the economics of our projects. It was such a big part of the development because, like I said, you go in and I think that’s why I mentioned it. It’s just very memorable to go to these school boards. It’s really cool to see all the different school boards in the Rio Grande Valley and Starr County and just see the gyms and meet all the people. And oftentimes the school board members, and I met with the landowner yesterday and he’s like, I’m on the school board. They’re landowners and they’re leaders in their communities. So those are the people that are really good to have advocacy standpoint for local projects. So because of 313 went away, we don’t, aren’t as active, but it’s still important to be every school board that I met with. Someone would inevitably say, do you have information that you can share? Do you have a poster about renewable energy? That always stuck with me. Like the science departments. Want basic information about renewable energy. And then we’re going and talking to legislators on renewable energy. So that’s why I’m just so interested in getting as much education as possible, which people are doing a really good job. There’s so many industry folks and nonprofits that have podcasts and gatherings and happy hours and luncheons and roundtables. So I think it’s happening, but it’s a big industry. It’s a big state. And we need a lot more of it.

Micalah Spenrath: Absolutely. So it’s certainly important to continue engaging schools and educational facilities, even if it’s not an economic partnership, as was the case in a Chapter 313 policy environment.

Raina Hornaday: And from a workforce perspective as well. I mean, this is a career path in Texas for students looking to what they want to do, whether it’s legal or trade school. Texas Tech, where I went, has a great renewable energy program and they work with a lot of developers and they have a lot of internships. So a lot of education comes out of these big institutions in Texas.

Micalah Spenrath: Awesome. So I did want to highlight some of your battery projects. So what’s been your experience deploying? Is it utility or distributed batteries?

Raina Hornaday: We have both under development. Mean, they’re the sub 10 megawatt batteries. And so they’re considered distributed generation, but 10 megawatts is a lot. When you think about distributed generation, you normally think about rooftop solar or something like that. So these 10 megawatt projects, think they’re massive, but yeah. So it’s very different, just the land, if anything else. Like when I developed wind, it was So many landowners, so many acres, and now I’m renting or trying to purchase square feet of half an acre, an acre, two acres. So it’s just so different from a land perspective, which is interesting. I mean, all the same development hurdles and SUPs and just working with the fire departments and working with the local permits and just depending on where you are, there’s different requirements in different places depending on how rural your projects are. So, it’s been good. I’ve enjoyed it.

Micalah Spenrath: So based on your vast experience in the state developing different types of projects including energy storage, what’s your impression? How have the economics of these projects changed over the years?

Raina Hornaday: Well, as so many batteries have been added onto the grid, it doubled with battery storage doubled in ERCOT last year again, and with so much increase into Texas, like our population is looking to increase significantly and potentially double. And the Permian Basin electricity needs are growing so fast, so we’re trying to add transmission. That’s a long time lead item, takes a lot of planning and a lot of construction time for all the reasons. So batteries have really become the stop gap that is needed. You know, if we can install batteries, that helps us utilize all the other energy supply sources to the grid, mainly solar and storage. And that helps us be able to deal with this long lead time we have for building out. The transmission that we need to support the growth. So it’s just a super stabilizer for the grid and we’ve seen that now since Uri, all these batteries have come on and we just haven’t had the volatility in pricing, which is a big part of getting these projects financed, but they’ve just become such an important part of being able to have really fast dispatchable power whenever we need it faster than kind of anything else. And this is a completely energy only, entirely market driven. It’s interesting, just like everything in ERCOT, it’s unique to the energy only market and people are slowing down the large developments, but then we have the AI data centers. So those are picking up a lot of behind the meter and bring your own power. And those type opportunities. So there’s still just significant development and build out in batteries in ERCOT and that’s going to continue.

Micalah Spenrath: Yeah, hopefully. So you did mention that maybe some projects haven’t come to fruition just based on different factors. That actually aligns with the most recent GIS report from ERCOT, so showing the interconnection queue. In that report, it also looks at canceled projects. And in that list, there are a number of battery storage projects that have been canceled, as recently as February 2026. So just based on your experience, what could be some of the causes to canceling some of these projects? Why are some battery projects not being built?

Raina Hornaday: I mean, I know some projects have been canceled due to inability to secure permitting. We all know there’s some areas and communities that are against developments. So that’s where siting is so important. You have to have the support from the local folks that will come to the site if they need to respond to something. And so it’s what I always go back to is education and just working with the local entities. For fire safety. That’s obviously one of the big ones. Noise is one, although these aren’t noisy projects. They don’t create a ton of noise, but it really is just site specific. So I think that’s probably one of them. Obviously, funding financing would be another that’s changed significantly. And there’s supply chain issues still. There’s lots of complexity to this and... It’s happening fast. So things can, what you think might be able to be done ends up not being able to be built for a very technical reason that you don’t know until you get farther down the line. So I think that’s why we see a lot of the drop-off, but I am optimistic about renewables being built in Texas going forward and smart solar, things like that, responsible siting and batteries paired with those, which is just kind of the magic puzzle piece.

Micalah Spenrath: Yeah, absolutely. And to be fair, there are a whole host of energy storage projects that are still in the queue and are poised to bring additional megawatts to the grid. So even though there are cancellations, they are vastly outnumbered by the projects that are still in the queue and seeking interconnection. So that’s always a positive indicator. But to your point, siting and permitting can be a barrier. That just, to your point, illustrates the importance of partnering with first responders, local leadership, community leaders as well, and members, and making sure that everybody feels that they have some ownership in some of these projects. So I think that that’s a really interesting point to make. So I do want to save some time. So, Raina, as we had mentioned, you have decades of experience in this industry in the state of Texas. What are you looking at towards the future? Where do see this industry going? What are some things that we still need to tackle in the state to make sure that renewables can still provide clean, reliable, and affordable energy to Texans?

Raina Hornaday: think the flexibility of providing flexible grid and a lot of that is distributed generation, like being able to do projects that meet demand right there instead of like the CREZ line, which provided renewable energy into big city centers that were very far away from the generation. So I think we’re already seeing a lot of that. I think it’s going to get better. Landowners are getting more involved and they have over the years, but having a smart option for things to do with your land and your legacy is going to continue to happen. Microgrids are happening quite a bit in the Permian Basin where all this oil and gas load is growing so quickly and with around data centers that bring your own power. I think there’s lots of solutions that only renewable energy can provide. In the timeframe that these builders need. So I think we’re going to continue to see a lot of growth and it’s going to get better. I think it’s going to get smarter. It’s going to get more localized, which is makes a lot of sense and with any energy supply that you’re doing, but being able to add batteries to solar really makes a ton of sense. So I think we’re finally going to see those co-located again and again.

Micalah Spenrath: Well, thank you so much for joining us on the Energy Capital Podcast, Raina. Your insights have been extremely valuable.

Raina Hornaday: It was great to visit with you.

Micalah Spenrath: Thanks for listening to the Energy Capital podcast. Thanks so much to Raina for a great conversation and to all of you for listening, engaging, and caring about how Texas powers its future. You can find us on Apple podcasts, Spotify, and all the usual platforms. For deeper analysis each week, please subscribe to the Texas Energy and Power newsletter at texasenergyandpower.com. We’re also on LinkedIn, X, and YouTube. Big thanks to Nate Peavey, our producer, I’m Micalah. Stay curious, stay engaged, and keep building a smarter energy future.