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

Related Podcasts by Energy Capital

* How Texas Plans to Serve ‘Infinite Demand’ with Eric Goff

* Who Pays for the New Grid with Pablo Vegas

* Is Texas Ready for Winter Now? with Will McAdams

Related Posts by Texas Energy & Power

* Energy Policymakers Grapple with Reliability, Fairness, and Flexibility

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.

In 1999, a rancher walked into a Sweetwater, Texas law office with a 50-page wind lease from landmen in South Dakota. The lawyer, an oil and gas attorney named Rod Wetsel, told him to throw it in the trash. The rancher insisted he take another look.

That lease became the first of an estimated 10,000 that Wetsel and his firm would negotiate across Texas. At one point, the line of landowners waiting to get into his office stretched two blocks down the street.

Wetsel is a founding partner at Wetsel & Lederle, co-author of the first treatise on Texas wind law, and a recipient of the Ernest E. Smith Lifetime Achievement Award from the Texas Journal of Oil, Gas and Energy Law. He teaches wind law at Texas Tech University. On this episode of the Energy Capital Podcast, Wetsel talks with host Joshua Rhodes about how wind, solar, and data center development changed Nolan County and the surrounding region.

In Nolan County, where Sweetwater is located in West Texas, the tax base grew from around $500million in 1999 to $2.7 billion in 2024. County commissioners who once debated whether they could afford to cut the grass now fund new schools with turf football stadiums. Young people are moving back to towns that had been losing working-age residents for generations.

Wetsel explains what makes a lease work for landowners, how townhall-style group negotiations give ranchers bargaining power against developers, and what data center companies are paying for land. He describes how electricity transmission lines, built more than a decade ago, added 18,000 megawatts of power generation capacity and enabled a wave of new energy projects across the region. And he shows why the Permian Reliability Project — a new transmission initiative that’s now in the siting phase — is poised to do the same for solar in far West Texas.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction and Rod Wetzel

* 00:52 - How an Oil and Gas Lawyer Found Wind

* 03:08 - The First Wind Lease vs. an Oil and Gas Lease

* 04:47 - Ten Thousand Leases and the Town Hall Model

* 07:20 - What Landowners Fear About Wind Development

* 08:24 - What a Wind Turbine Actually Pays a Rancher

* 11:50 - Solar, Storage, and Data Center Leases

* 12:33 - What Makes a Good Lease

* 14:36 - Hybrid Projects and Triple Landowner Income

* 17:42 - When Lease Negotiations Break Down

* 19:24 - How the CREZ Lines Transformed West Texas

* 22:57 - Who Wants Development and Who Doesn’t

* 27:29 - Tax Base, Schools, and Rural Revitalization

* 31:17 - The Bar and the Workforce Boom

* 34:30 - What This Industry Looks Like in Ten Years

* 37:13 - Australia, Global Parallels, and Closing

Resources

People & Organizations

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website)

* IdeaSmiths (Website)

* Energy Capital (Website - LinkedIn - YouTube)

* Texas Energy & Power (Substack)

* Rod Wetsel (Firm Bio)

* Wetsel & Lederle, LLP (Website)

* Texas Tech University School of Law (Website)

* RWE (Americas Website)

* ERCOT (Website)

Company & Industry News

* Texas OKs Permian Basin Reliability Plan, Option for State’s First 765-kV Transmission Lines

* AEP Texas Set to Construct One of the First 765-kV Transmission Lines in Texas

* Texas CREZ Lines: How Stakeholders Shape Major Energy Infrastructure Projects

Books & Articles Discussed

* Wind and Solar Law by Roderick E. Wetsel and Becky H. Diffen

Transcript

Joshua Rhodes: Hey everyone. I’m really excited today to have Rod Wetsel on the podcast to talk about the work he does as a clean energy lawyer. Rod is a founding partner of the law firm Wetsel & Lederle and based in Sweetwater, Texas, where he’s practiced law for over 36 years. He’s received the Ernest E. Smith Lifetime Achievement Award in Energy Law. He got his BA and JD from UT Austin and he’s previously taught law at the University of Texas at Austin and he currently teaches law at Texas Tech. In 2011, Mr. Wetsel co-authored the first treatise on Texas wind law and really has been someone who has helped write the legal playbook for how wind has developed in the state. Rod Wetsel, welcome to the Energy Capital Podcast.

Rod Wetsel: Thank you very much. I appreciate you having me today.

Joshua Rhodes: I just really wanted to kind of start off talking about, I’m not a lawyer, but I know in Texas, like a lot of laws based around energy law and particularly oil and gas law. So how did you get pulled into being basically the go-to lawyer for wind law in this state?

Rod Wetsel: Well, that’s actually a pretty interesting story. I had practiced all kinds of law because we were in a general practice here in Sweetwater. But primarily for the 25 years before wind came along in about 1999, I had primarily been an oil and gas lawyer. And I’d heard rumors about wind farms. In fact, once upon a time, I had a girlfriend in California and I went out to Palm Springs and I saw the wind turbines out there and of course at that time they looked more like windmills. They were lattice towers, very small. It struck me at the time that that looked more like Disneyland than anything that would ever happen in Texas until about December of 1999, a rancher client of mine, a longtime friend of the family came in with a very thick sheet of papers and said he had a proposed wind lease on his property. And that was the very first wind lease that I did. And that sort of kicked off an avalanche of wind leases and projects in our area west, right out from here all over Texas. Even at the time when he came in, I was a skeptic that he was the kind of guy that was always looking for a new way to make some money, know, cut mesquite wood and sell it to aunts or any kind of innovative idea. He told me he had a wind lease from some landmen in South Dakota about erecting wind turbines on his land. I said, I think I would just pass on that one. He said, no, I want you to look over the lease and see if it doesn’t have some viability and be as hard on them as you can. Just don’t kill the deal. Cause I think they might actually be onto something. So that’s what I did.

Joshua Rhodes: When you were looking over that wind lease, how different was it from the oil and gas leases and everything else that you had been looking over?

Rod Wetsel: Well, it was similar in some respects. In one respect, it was all energy biased. There weren’t really any provisions in favor of the landowner. Was more like the old producers’ 88 oil and gas leases. But those are two pages long. This was like a 50-pager. Yeah. And he asked me to look it over and after a few days he came back said, what do you think? said, I’d throw it in the trash. Because it’s really completely in favor of the wind company and those people are going to tear your place up and you’ll never make any money. And that’s when he urged me to go ahead and try to make a deal with them, which after a number of months, we were able to do that. And the company was actually out of California. It was GE wind, which at the time was part of Enron, as you know, had its own stigma involved. We managed to get it done and the good news about him, the guy’s name was W.A. Oatman, we were able to get the lease negotiated. That was the very first lease I did. It’s on the Double Heart Ranch, is, it’s up on the Callahan Divide. It’s a ridge just south of Sweetwater where the elevation goes up about 500 feet. Wind really blows up there. And he was able to eventually get about 33 turbines built on his property, so.

Joshua Rhodes: How many wind leases have you done since that first one, you reckon?

Rod Wetsel: It would be hard to calculate. I would say probably somewhere in the 10,000 range maybe. Some of these projects would have as many as three or 400 landowners that we would all represent. And that made it really a challenge for lawyers and that how do you meet with 300 people at the same time? You have to find a convention center or a church or a barn or whatever. And that began the concept of having sort of a town hall meeting of landowners to negotiate wind leases, which turned out to be a very efficient way of doing it because everybody got the same terms and we had more bargaining power with the wind company.

Joshua Rhodes: After that first lease kind of showed up and you worked through it, when did you do the next one? How did that part of your business grow?

Rod Wetsel: Well, the good news about a small county like Nolan County, which is only about 15,000 people, they had approached many of the landowners in that area. A lot of it had been clients of mine already for years. Okay. Once the word got around that Wetsel had worked out a wind lease for the Oldman family and they got paid some money and looked like it might be a real deal. No joke. This is a fact. One day I looked out, the secretary said, what are we going to do with all these people? Because I went downstairs and there was a line of people that went about two blocks down the street waiting to try to get into my office. So that’s a real good problem for a lawyer to have. Yeah. And, you know, it just exploded from there in that we were the only firm around for a good while. That were representing landowners and wind leases and so when the word spread we didn’t need to set up a billboard, they just came.

Joshua Rhodes: Yeah, that makes a lot of sense. I that’d be interesting to have folks lined up around the corner. Be like if you were selling the newest iPhone or something.

Rod Wetsel: No, exactly. It was a fun time for sure and it just spread like wildfire. Mean, that was the first wind project in Sweetwater. And after that, many other companies started coming here and setting up projects. And then at one point in time, we had the three largest wind projects here in Nolan County in the world.

Joshua Rhodes: Yeah, I know it’s something like added billions of dollars to like the tax base and things out there and just Nolan County alone. But then there’s a lot of other counties in Texas that are also doing wind deals. When someone comes to you with a wind lease from a developer, like what’s the biggest misunderstanding do you think that landowners have whenever they’re first confronted with the possibility of having a wind farm?

Rod Wetsel: Well, I think what all landowners are concerned about is the life change. Yeah. And that when you have wind turbines installed on your property, it’s never going to look the same. You know, the topography is going to be different. You’re going to have to work around the turbines being placed there. And you’re concerned about the location. If you live on the property, you’re going to have to look out and see the turbines. Whether or not they were noisy, workmen being on the property, all those sort of issues that landowners that were used to living way out in the country had to deal with things they had never dealt with before.

Joshua Rhodes: Yeah, but I guess the flip side of that is they’re generally getting compensated for having those wind turbines on their property though, yeah?

Rod Wetsel: That was the driving force. The fact that the money was good, or at least had the promise of being really good, they actually arrived at the right time because about the ‘99, 2000 period of time, hadn’t rained here for about seven years. The cattle market was bad. We’re located on the Eastern shelf of the Permian Basin, most of the oil production. Was at a low ebb. And so people were faced with the dilemma that if they passed away, their property would probably have to be sold because their children had moved away to the big cities and could no longer afford to keep the ranch in operation so they had no income.

Joshua Rhodes: Yeah. Guess your wind turbines make a difference, right? Can you give a feel for kind of what type of income a wind turbine could provide a rancher these days?

Rod Wetsel: Well, actually that’s gone up a lot. One of my best stories I always tell my class is, had a high school friend. I’ve grown up here. I was born here in Sweetwater and father did, my grandfather did. So we’ve been here for a long time. But my friend came in, he owns a really large ranch south of Sweetwater in an area of a lot of this development. His father had passed away and he said, mom and I decided that We just don’t want those wind turbines cluttering up our land. We’ve got a big cattle operation. We don’t want any interference. We don’t want them there. So don’t even ask me about it. So I said, okay. Well, in about six months he came back and he said, well, mama said that if we’re going to have to look at them, we might as well take the money. Each at the time, the size of those wind turbines were about from one and a half megawatts to about 1.7. They kicked off about eight to $12,000 a year per turbine income for the landowner. Today, turbines are now being repowered. Almost all of those have been repowered with turbines as large as anywhere from three and a half to six megawatts. Oh, wow. With corresponding much more money for the landowner. I mean, as much as probably $25,000 a turbine per landowner.

Joshua Rhodes: Wow, that could be pretty significant. I guess you have to look at them, but you don’t have to water them or do anything else to them,

Rod Wetsel: That’s right. One of the famous quotes from this same gentleman was when we were interviewed by a foreign news service, they asked him, they said, when you hear all those turbines turning on your property, what does it make you think of? And he said, a cash register. That’s a pretty good answer because they’ve made a substantial, in fact, saved their ranch.

Joshua Rhodes: Hahaha!

Rod Wetsel: from sale or partition because their income from wind really was greatly out of proportion to wind income from any other use of the property.

Joshua Rhodes: Gotcha. Know, wind was one of the first ones that you’ve gotten into, but I imagine you’re also doing solar leases and energy storage leases these days.

Rod Wetsel: Exactly. About three to one on solar now. Solar is really a wind just from the standpoint that they don’t require as much acreage. You can deal with a lot fewer landowners. They’re cheaper to build, they’re quicker to build. And those and then all kinds of new technology like data centers and battery storage facility. Have really put a shot in the arm of the industry for anybody that’s in that field.

Joshua Rhodes: When someone comes to you with a lease or whenever you’re negotiating a lease, wind or solar, storage or data center lease, what makes it good in your view?

Rod Wetsel: the landowner is going to say is how much money am I going to get? And so the compensation is probably the number one issue. And that’s driven in the case of wind turbines by the number of megawatts that’ll be installed on the property. Okay. Because you don’t want to lease and have two turbines put on it and make no money. Yeah. You get paid by the acre. So you’re going to want to get the majority of the acreage that you can to get paid more. Or if it’s a data center, generally you’re going to sell the property, but you want to get the very highest price, which lately has been astronomical. I mean, almost unbelievable the amount of money that companies are paying for what we would call a small tract of land, like 1200 acres. It’s not unusual. For the starting price on 1,200 acres to be $50,000 an acre or above. We’ve seen as high as 100 or highest I’ve seen is $350,000 an acre, which is when you add it up on 1,200 acres, that’s fantastic sum of money.

Joshua Rhodes: Wow, and that’s for a data center you’re talking about?

Rod Wetsel: Yes, for a data center. So that’s sort of the new thing. We still have wind, we’re still doing a lot of wind leases, but like say more solar than wind. But now data centers have come on the scene and we’re doing a lot of those. You know, the great thing for our firm is that we started out doing wind leases here and now we’re pretty much nationwide. We do A lot of work in different states, including Texas. So it’s really been a good deal for us and the legal community as a whole.

Joshua Rhodes: Gotcha. That makes a lot of sense. I’m glad you brought up data centers because I feel like I can’t talk about energy these days without talking about data centers. And so I guess that probably makes sense that you’re seeing the same thing. Are you seeing any hybrid projects like people wanting to build wind farms with solar and plus data centers and other types of things like that? Are you seeing any of these hybrid projects that people keep kicking around?

Rod Wetsel: Absolutely, we’re seeing those all the time. You have developers that come in and say, we want to build, for example, I have one client where they’re going to build a really large solar farm about 600 acres or 600 megawatts, that is, it’s on a large number of acres, 600 megawatts of solar, a data center that will use all the power from that solar farm. We’ve had other data center projects where they build both wind and solar projects to furnish the power for the data centers. So the landowner then gets triple the income. They get the income from the solar, they get the income data center, and then from the wind project as well. So some of these have been extremely lucrative for landowners that really have hard scrabble property that’s worth a lot more than it used to be, but the income is just staggering in comparison to any other uses like cattle ranching or farming.

Joshua Rhodes: Yeah, but their acreage fees are better than dry land cotton and scrubbage fees.

Rod Wetsel: I can assure you that’s the case. We’ve had occasion where people get really proactive. They have some pretty good looking property. They have it in the area of transmission or a good area that might be suitable for a data center or wind and solar. And they actually go out and try to market the property. And we’ve been successful in doing that. Early on, one of the projects, the Roscoe Wind Farm, which is about 781 megawatts, it’s a really large wind farm. It’s in the top 10 in the world. One time, I think it was the largest wind farm in the world. No developer wanted to build there because it wasn’t located on the elevated land. It was on farmland that’s north of Sweetwater toward Lubbock. And there were lots and lots of landowner small farmers and they just didn’t want to deal with it. And those people got banded together and managed to find a developer that ended up selling out to a larger developer. It’s now owned by RWE, which is big German company and it’s a huge wind farm. So that all came about on behalf of the landowners who to the vision to go out and try to find somebody to build the project and they did.

Joshua Rhodes: That’s really interesting that it’s kind of coming from both sides. We’ve talked a bit about what’s a good lease and what types of lease and things are going on. Have you been in any situations where negotiations break down? Where does that happen typically?

Rod Wetsel: Unfortunately, that does happen. Mean, there are cases where the parties simply can’t get together on the money. Most often, it’s where a landowner sets a bar that’s just simply too high for the developer to meet. For example, a landowner may say, I’m not going to encumber my property with wind turbines unless you build. 60 megawatts or you build 100 megawatts of wind on my property and the developer just says, we can’t guarantee that and the negotiations break down. Or if, you know, the parties can’t get together on other essential terms of the lease. But that’s fairly rare. It’s typically a win-win situation. It’s pretty rare that projects don’t get consummated. But it does happen, unfortunately, from time to time. It’s just like any other business, some deals work and some don’t. We’re in the early stage of this business, as opposed to the oil company. The oil business has been around for 130 years. Wynn’s only been really around about 25 years. And so we’re still in sort of the honeymoon stage where usually it’s a win-win deal. Everybody’s happy to get it done and looking forward to getting the money.

Joshua Rhodes: Yeah, speaking over kind of that 25 years, you’re talking about still being kind of in the early stages, but Texas wind is in particular has gone through a couple of phases. In particular, about a decade ago or so, we kind of are a little bit more than a decade now. We finished the competitive renewable energy zone lines or the CREZ lines. How did the CREZ lines change what was possible to do out in West Texas in terms of energy development?

Rod Wetsel: Actually, the change was really monumental. You know, at the time, we began to run into the issue of having curtailment and not being able to build additional projects because the transmission had been filled up or the existing transmission was filled up. And that added an extra 18,000 megawatts of transmission so a lot more projects could be built. Plus, it allowed for projects to be built in the panhandle area, which is in a different grid system. The grid system from Lubbock South in our area is a totally state-owned grid system, ERCOT. Whereas north of that, up into Oklahoma, the panhandle and so forth of Texas, is the Southwest Power Pool, where the prices weren’t nearly as good. Well, the CREZ system allowed that power to be brought back into ERCOT without FERC jurisdiction, without the federal jurisdiction, and really sort of gave a huge shot in the arm to the wind business. Kind of in the same shape now, most of the CREZ lines are getting filled up. So probably gonna need another CREZ or some upgrade system before too long. To upgrade the transmission to accommodate all the new developments.

Joshua Rhodes: Yeah, I was going to ask about if you’re keeping an eye on the Permian Reliability Project, those big 765 KV lines that are going to run through the region and further out into the Permian and Delaware basins. I mean, when I look at maps, the solar resource and other types of things, I mean, the solar just gets better the further west you move because they’re building these lines nominally to move power out to electrify oil and gas operations. But when I see them, I just see us pushing further into solar territory. Are you seeing the same thing?

Rod Wetsel: Exactly. Yeah, just today. I mean, I’m having landowners come in. Mean, it’s a double deal for us because we’re representing landowners on that are in the path of the huge transmission line project. And as you know, these transmission lines are twice as big as any existing power line we have at the moment. So these are going to be gigantic lines that are going to be erected. Sometime in the next few years, but they’re locating those lines now. So you have a lot of landowners who either want the lines or they don’t want the lines and they want to hire a lawyer to deal with that issue. And then you have the fact of those transmission lines in the future is opening up all kinds of new areas. As you say, particularly for solar in far west Texas, which prior to now would have been a inaccessible because of lack of transmission or distance from the Metroplex or Metropolitan Load Centers.

Joshua Rhodes: Yeah, you mentioned some landowners wanted them and some might not. What’s usually the divide there?

Rod Wetsel: Well, the divide usually is scenic area. Mean, they’re around here. Most everybody, I’d say in central West Texas, it’s hard to find somebody that doesn’t want to winter solar farm or data center. But if you go down in the hill country or you go to, there’s certain areas are just completely off limits. You go down to Fredericksburg, you’re going to get run out of town or you go to certain really touristy areas. You’re going to have difficulty, particularly with wind turbines, because they don’t want you to affect the scenic beauty of the area and have lots of visitors and recreation and so forth. And they just don’t want the development. And then there are other areas that are a mystery to me, like the Brownwood area, very much like Sweetwater, it’s sort of a dividing line, but you know, the central west Texas and the hill country. And they have signs up saying no wind turbines here. So I’m not sure, but a lot of it just depends upon the area. And then there are other areas, Abilene is a good example. They have other industries or air bases or something there and they don’t want those to be interfered with. Abilene in particular has Dyess Air Force Base. They’re fixing to do a $26 billion renovation of that military installation to put in the new large bombers to be, you know, they already have the B1s, they’re going to put in the B2s. And they really don’t want a lot of turbines up close where it’s going to bother the low-flying airplanes and so forth. Some areas just aren’t conducive, others more. And particularly the really rural areas are the areas that really want the development the most.

Joshua Rhodes: Yeah, one of the things like in my observation and maybe you can tell me if this is right or not. It seems like for a lot of landowners, if you’re trying to make money off of the land, if you’ve got a ranch and you’re trying to feed your family, your kids to school, like off of what you can make off of the land, you’re generally more in favor of this type of development. But if you made all your money in the city and you’ve bought something that you just want to look at, like it’s generally going to be opposed to these types of things. Am I oversimplifying that too much or?

Rod Wetsel: I don’t think so. I think if you’re a doctor in Dallas and you want to get as far away from Dallas as you could and you come out to Sweetwater and you buy an area and you want to have it for a hunting preserve, the last thing you want to have is a bunch of wind turbines on it, unless they’re going to pay you enough money. Then the adage is, well, if I get enough money, I’ll just buy a different place. But those are folks that sometimes are opposed. We’ve had folks on the other side of the coin. That have said, have this really beautiful place here, we don’t want any wind turbines on our property, we have plenty of money. But for your average folks who are worried about having money to get by, they can’t make money from the land anymore like they used to, farming and ranching is much more difficult way of making a living than it was. We have a lot of folks in agricultural here that are really embracing all things renewable and oil and gas as well because as they say the one thing that Texan wants is an oil well and a wind turbine or a solar panel, you know, to make as much money as possible from their property.

Joshua Rhodes: Yeah, like you said, I think you mentioned some scene. I’ve heard of folks making money above, on top and below their property, right? Whether they got wind and maybe some solar and I guess maybe now data centers and then below with oil and gas. Doesn’t seem too bad if you got it. Yeah, so you mentioned, you know, you work in Texas, you work in other places. You advise counties and landowners in dozens of jurisdictions. I mean, in general, do you think you can sum up like what drives most local support or opposition now?

Rod Wetsel: Not true.

Joshua Rhodes: If that’s changed in the 25 or 30 years you’ve been doing this, what drives local opposition or support now?

Rod Wetsel: Well, that’s changed somewhat. In the beginning, a lot of the counties, especially in our area of West Texas, were so economically deprived that actually the county commissioners around here argued if there was enough money to cut the grass. I mean, they didn’t have any money to spare. They needed money for road repair. Schools were becoming dilapidated. At the time, you could get money for both abatements on schools and governmental entities. And so they were very much in favor at first. In fact, always bidding wars about who gave the best to get the wind companies to be attracted to that area. Now with lots of development, you know, there is some opposition and some people that are on these county commissions are figuring we’ve got plenty of development in the county. We’re not gonna be quite as generous as we were in the past. But that’s not always the case. I think most of them are still, they wanna get a better deal for the county, but I think they’re still in favor of trying to make a deal. You mentioned before Sweetwater, just to give a really good example that I always talk about. Sweetwater’s tax base and 1999 was about 435 million. Today it’s about 3.5 billion. So you take a look at that and now we actually have remnants of civilization in our part of the country. Hotels, restaurants, liquor by the drink, you know, whatever. You’ve got all kinds of things that you normally wouldn’t have except in the big city have all come to the rural areas and that’s because of wind. Plus, for the time that existed up to 2022, the tax abatement on schools for a while there was pretty relaxed and they were able to put a lot of money into schools, rural schools. You drive around areas of rural West Texas and you drive through a little bitty town in the middle of nowhere and it has a brand new high school with a football stadium that has Astroturf. You know, that afforded without the wind business. So that’s kind of neat and that we’ve been able to really revitalize the area. And one other deal I’ll mention that I think is really important is we really had a declining age population in West and lots of areas of West Texas and other states as well in rural areas where in the past when there were lots of family businesses, the young people would graduate from college and come back and take over the family business. Well, after the Walmarts and the K-Marts and the big conglomerates came in, they ran all the small shopkeepers out of business pretty much. And the young people didn’t have any jobs unless they were professionals to come back to small town. And so you had, you know, your average age in a lot of rural areas was 65 or above. Well, today, with jobs in the wind industry, solar, all these data centers and so on, you’re having a lot more young people either live off the income and find things to do around here. So we have a lot more, a younger population base than we’ve ever had. In many years, I’d say since I was in high school.

Joshua Rhodes: Is one of those things that folks find to do is now is to go to your bar?

Rod Wetsel: Well, I guess you could say that’s a spinoff of the wind business as well. There were a lot of workers hanging around that needed a place to go after hours and no place existed. So we had a half of our building was vacant and we decided to, we’re first going to put in a coffee and a bookshop. And when I found out that only probably last about six months before went broke. Somebody suggested maybe ought to put in a wine and beer bar and you’ll make money and it’s worked out. We did that. So there are lots of workers from these wind farms that stop in and they stay at the hotels, you know, and a good example right now is, as you know, they’re building a really large data complex in Abilene and I’m told there’s not one single place hotel anywhere in Abilene to stay now. They’re all filled with workers. There are 1,500 workers on that project. There are no hotels, there are no rent houses, there are no houses to speak of at all. And even the outlying communities, people are living as close as 35 miles away in Sweetwater driving over to work. So that’s a big plus too.

Joshua Rhodes: Yeah, that reminds me when the fracking business was just getting off or just getting started. And there was a lot of folks that were coming into West Texas when back when you needed like 12 Roughnecks per well, I think they’ve economized that down where you don’t need as many necessarily. It just reminds me of that time when basically couldn’t find a hotel room and the liquor store would run out of beer on a Friday, right?

Rod Wetsel: Exactly

Joshua Rhodes: One of the things that I’ve heard on that project, particularly the data center project in Abilene, that electricians are making the equivalent of like three, $400,000 per year working double overtime or whatever it is, just because they just need so many of them right now. Have you heard that too?

Rod Wetsel: I’ve heard that too, and what I’ve heard is those poor guys are working like, I heard they’re working like two weeks on and a couple of days off full time, and they’re planning on being there for couple of years. And that’s where it was here. First, we’re building all these projects. One of the requirements in the tax abatements that were granted by the county was that they use local goods and services if they were comparable in price. And therefore all the dirt contractors, all the local electricians, everybody was just swamped. And you had that trickle down theory where they made money and they went out and spent money and bought more clothes here, did more things here, more businesses opened up. And it’s just been good all the way around. It’s made life a lot more comfortable in rural areas than it’s ever been in my lifetime.

Joshua Rhodes: Gotcha. If you can imagine Texas 10 years from now, kind of what does this industry look like?

Rod Wetsel: Well, the good news, and this is another thing I tell my students, you know, because I have a lot of people always wonder if I’m an easy grader or if they really are interested in the subject matter. But I teach a course on wind and solar law, and I usually have about 50 students in there. And, you know, amazingly, at the beginning of the semester, they know absolutely nothing about what the course is about. They just heard it was fun. And by the end of the semester, they’re saying, hey, I really want to go into this area. And what I tell those people is the good news is as maybe wind and solar are still there, but de-emphasized, now we’ve got green hydrogen plants, we’ve got data centers, we’ve got battery storage facilities. Who knows what we’re going to have in the future, probably small nuclear plants. We’re have all kinds of things and there’s always something new. So I’ve been doing this now for going on 26, 27 years. Consistently, that’s basically all we do. We do some oil and gas as well, but we’re hiring more and more lawyers because it’s just too much work. And I tell people in the class, out there and get those jobs because there’s still, after 25, 26 years, not enough persons who are trained in this industry, either in the legal aspects or the other aspects to get the job done. So people are paying really good salaries. The salaries at the industrial part, the developers paying are comparable with a really large law firms in the big cities, which is sort of amazing to me.

Joshua Rhodes: Yeah, no, absolutely. I think I shared the sentiment that Texas is the energy state and renewables, wind, solar, storage, small modular nuclear, new stuff. It’s all just other forms of energy that we’re gonna use as a state. Rod, I really appreciate you coming on the Energy Capital Podcast today.

Rod Wetsel: Well, thank you. It’s been a real pleasure. And I can tell you, as you know, our trip to Australia, we’re not the only place in the world that is really looking at renewables for the future. I think it has a great future. I don’t think anybody can go wrong about getting in this area of law or industry, either one. I think it’s going to be here for many, many years to come.

Joshua Rhodes: We first connected over some work that I was doing on landowner payments and taxes and things like that associated around wind and solar and now storage across Texas. But I don’t think we ever actually met in person until we met in Australia. And I’m pretty sure it was at a bar or maybe it like a beer house or something like that.

Rod Wetsel: That’s a fact. The one thing about this industry is so many of the folks that you deal with, you deal with remotely. So you know them on video or on the telephone, but you never meet them in person. And it’s always great to say, well, that’s what that person really looks like, you know, and then you get to have a visit. And so I think our trip to Australia was a really fun one, but just very indicative of there’s so many areas in the world. Including Australia, South Africa for one, that would really be benefited by all the benefits that we’ve had. So I’m really happy to be on.

Joshua Rhodes: Yeah, I think one of the things in particular and you know, we... The building out of the transmission that the state does from time to time, whether that’s the CREZ lines or the Permian Reliability Project, like really acting as an economic enabler for the rest of the state, whether that’s new forms of energy or allowing us to have cheaper forms of energy to support other industries and things like that. And yeah, we think we’re doing the same thing in Queensland, Australia. They’re trying to figure out if they can do that kind of thing. I think it’s a good model. It’s fun to be here. I’m pretty sure you feel the same way.

Rod Wetsel: Yeah, you know, it’s great to go to an area where it’s like going back in time. You take a look at that area and they’re where we were 25 years ago. And so you think, wow, wouldn’t it be fun just all over again? So I think there are many areas of the world that they’re still where we were 25 years ago. And that’s great. That leaves it a big opportunity for folks to go there and help those people do what we did and have the benefits we have.

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. We’ll see you next time.

ERCOT’s current rulemaking process will shape the Texas grid for decades, driving infrastructure investments that last 30 to 50 years and cost billions of dollars.

During this year’s SXSW Texas Future’s Summit in Austin, ERCOT Chief Executive Pablo Vegas sat down with Energy Capital Podcast hosts Josh Rhodes and Matt Boms to explain the grid operator’s approach.

ERCOT has added more than 60 gigawatts of new supply since the devastating Winter Storm Uri blackouts in 2021, and battery storage resources have grown from a few hundred megawatts to more than 16 gigawatts. Vegas said the grid is more reliable today than it was three years ago. The challenge now is to plan for what’s coming. Last month, ERCOT announced that load interconnection requests now exceed 410 gigawatts. For comparison, existing load has peaked at around 85 gigawatts in recent years. New data centers drive much of that growth.

In this episode, Vegas described how ERCOT determines which projects in the interconnection pipeline are likely to be built. Even a fraction of those projects could reshape the system, especially if data centers arrive in the concentrations that some projections suggest.

Vegas also walked through ERCOT’s proposed batch study process for reviewing large load interconnection requests, and why the current one-review-at-a-time approach is inadequate given growing load projectionsAnd he discussed residential demand response — and why it may be a faster path to reliability than building new generation or transmission.

The ERCOT grid is growing like never before — yet demand is growing even faster. ERCOT’s response to this challenge will shape our grid and our economy for generations. Check out this week’s episode to learn more about what that response will look like.

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction and Pablo Vegas

* 03:40 - Lessons from Winter Storm Uri

* 05:42 - How 60 GW of New Supply Changed the Grid

* 09:18 - Filtering the 230 GW Load Forecast

* 13:28 - Why Data Center Load Broke the Old Process

* 19:15 - How ERCOT’s Batch Study Process Works

* 22:02 - DERs and the Distribution Grid

* 26:57 - Real-Time Co-optimization and RTC+B

* 30:11 - Battery Duration vs. Flexibility

* 33:26 - Residential Demand Response

* 36:41 - How ERCOT Is Using AI

* 40:35 - What Texas Should Learn and Export

Resources

People & Organizations

* Pablo Vegas (LinkedIn)

* ERCOT (Website)

* Joshua Rhodes (LinkedIn)

* Webber Energy Group (Website - LinkedIn)

* IdeaSmiths (Website - LinkedIn)

* Matt Boms (LinkedIn)

* Texas Advanced Energy Business Alliance (Website - LinkedIn)

* Energy Capital (Website - LinkedIn - YouTube)

Company & Industry News

* ERCOT Goes Live with Real-Time Co-optimization Plus Batteries

* RTC Deployed, ERCOT Takes on New Challenges in 2026

* New Batch Study Framework for Large Load Interconnections

* Texas Task Force Aims to Tear Down Barriers to Virtual Power Plant Pilot

Programs & Processes Discussed

* ERCOT Large Load Integration

* ERCOT Large Load Working Group

* Real-Time Co-optimization Plus Batteries Task Force

* Aggregate Distributed Energy Resource Pilot Project

Related Podcasts by Energy Capital

* Who Pays for Texas Grid Growth? Roundtable Discussion

* Is Texas Ready for Winter Now? with Will McAdams

* Flexibility Driving Reliability and Affordability with Matt Boms

Transcript

Joshua Rhodes (01:37.714)

the most in the first few years leading our cup?

Pablo Vegas (01:40.878)

I guess what’s been really interesting learning is, and when you work in the utilities space, and I worked in the utility space in Arcox, back in Albuquerque, Texas, but I’ve worked in the utility space, as you said, for quite a while, for over about 20 years.

Pablo Vegas (01:56.908)

I was surprised how different grid operations is from what it looks like inside of the utility. So the issues that the grid operator deals with in contrast to what a utility company deals with is pretty stark. And while there’s a lot of kind of overlap on elements of it, of course, but kind of the focus of what we’re looking at, which is, you know, looking at all of the issues across all the different components and players in the system, it’s a lot more complex trying to consider all of the

Pablo Vegas (02:26.67)

needs of the different stakeholders that are part of the process. When you’re a utility company, you’re always laser focused on your customers, you know, directly, and you’re serving them and you’re making sure that you are working constructively with, you know, your regulators and policymakers to serve your customers. At the grid operator level, the customers are still a very critical part of the conversation, but you’re doing that through one layer removed in helping to oversee the processes.

Pablo Vegas (02:52.354)

that govern the utilities and the power producers and the retail electric providers and the brokers and traders, the large industrials and the small consumer, everything in between. And so you’re really thinking about kind of the policy making that affects each one of those segments in a different way. And that’s what surprised me a little bit in terms of just how complex that can be, how in many cases, how political it can be. We have a very unique environment in Texas where, you know, we govern, legislate all the policy for what happens in the wholesale power markets.

Pablo Vegas (03:21.624)

which is different than what happens in other states. And that’s something that adds to the complexity inside of Texas, but it also gives us benefits, gives us the agility, the ability to make change. And we’re seeing that realized today at the pace of change that’s happening.

Matt Boms (03:34.9)

And I think you came in at such an interesting time

Matt Boms (03:37.373)

after Winter Storm, Yuri. We just had the five year anniversary of Yuri recently. Do you still feel like that’s hanging over our heads or do you feel like we’re now entering this new chapter? We’re going to talk about low growth and data centers and all that. But you came into the job during that kind tumultuous period. Do you feel like that’s behind us now or do you still feel kind of the shadow of Winter Storm, Yuri hanging over us?

Pablo Vegas (03:58.754)

Bye.

Pablo Vegas (03:59.48)

firmly believe that the memory of Yuri is going to remain with those who experienced it for years and years to come. I don’t think it’s something that is gonna be forgotten and put into the past and nor should it because it has taught us lessons across so many different facets of the work that we do, the importance of great communications. That’s something that was, I think, a very early lesson learned in the process that there needs to be so much better transparency

Pablo Vegas (04:29.424)

in terms of the role that our cop plays, what we do and how we do it, why we do it, who we work with in delivering the general service that everybody experiences. It was clear that it was not well understood as we went through the whole URI experience. we’re still working on that facet of it. But beyond that, the lessons learned in terms of just how critically important and dependent.

Pablo Vegas (04:52.738)

we all are on electric reliability is something that we can’t ever forget or should put in our past. And that’s something that should remain at the forefront as we think about policies, as we think about protocol changes, as we think about how we’re going to manage the growth that’s ahead of us, how we’re going to manage the transition to the different supply resources and everything in between. So it’s something that I want to continuously be helping people understand the things that we’re doing.

Pablo Vegas (05:20.428)

to change the circumstances that allowed Yuri to happen and we have made a lot of progress on those fronts. But it’s never gonna be gone from the memories of those who experienced it and we’re always gonna keep the lessons learned in our forefront because those lessons have to.

Joshua Rhodes (05:35.214)

Yeah, so since Yuri there’s been quite an addition of capacity. It’s been a bit of a different type of resource mix that we have. think during winter storm Yuri there was just a couple hundred megawatts of solar. Now there’s tens of gigawatts of solar and like an energy storage. And can you speak to like how the system has kind of changed since then, Yvette?

Pablo Vegas (05:58.338)

Yeah, it’s changed quite a bit. Over 60 gigawatts of new supply added to the Earth Hydrate since winter storm Yuri. That’s a huge number. Last year, we helped connect a record amount of generation supply to the Earth Hydrate, over 16 gigawatts in one year. And we’re on track to have a record first quarter, this quarter in terms of interconnecting new supply. So it has been changing rapidly. As you pointed out, the majority of the supply coming online

Pablo Vegas (06:28.178)

is solar resources and energy storage resources. That makes up the large bulk of the supply that’s connected in SINCE-URATE. And what that’s doing is it’s helping grid reliability through several lenses. So, you know, the battery storage has such a unique flexible characteristic where it is able to be responsive instantaneously when it’s needed on both being able to discharge as a supply source or for charge.

Pablo Vegas (06:56.438)

in terms of balancing for load need. And it can do that instantly at any point in time. And you’re right, back during Yuri, we had in the hundreds of, low hundreds of megawatts of energy storage. And today we have over 16 gigawatts installed, well over that in terms of gigawatt hours, because most of our storage is between an hour and a half and then two hours now. So that’s a fundamental change. And what batteries can do, if you remember,

Pablo Vegas (07:23.182)

during the summer periods of 2022 and 2023, those are some fairly hot summers. 2023 was, I think, the second hottest summer in Texas history. And that’s when we reached our peak. We hit the peak of a little over 85 gigawatts that summer. And we were experiencing conservation calls. We were pretty concerned about the levels of consumption in contrast to the supply we had. A short two years later,

Pablo Vegas (07:49.198)

with the additions of the solar and battery storage that we’ve seen in the last two years, we’ve had similar levels of demand and have not seen any kind of scarcity issues related to that. And so it’s completely changed the tenor and the risk profile of summers in Erickaht. That’s been a tremendous benefit. The batteries also have been a tremendous help during the winter in terms of managing the transitions of the early morning hours and in the solar sunsets in the evening as well. And so it’s really helping with those

Pablo Vegas (08:17.72)

periods that are now emerging as those peaks, it has changed the reliability picture. If you look at where the grid is from a probabilistic perspective today, we are more reliable in terms of the risk of emergencies today than we were five years ago or three years ago. Now, all of that is dependent upon how much load we have today and what the mix is. So when you look into the future, that can change. And so we can’t sit back today and say, we’re good.

Pablo Vegas (08:45.538)

because all these additions have made us more reliable. It’s really our job to look ahead three years, five years, and 10 years ago, is the trajectory gonna continue to remain improving or is it gonna change? Is it gonna become less reliable? And those are the things that we are focused on right now because the growth story ahead of us is significant and sitting back and just kind of looking at what’s happened over the last five years and thinking that will serve us for the next five, I don’t think works.

Matt Boms (09:13.102)

I think you teed that up perfectly. We want to ask you about load forecast. We want to ask you about data centers, load growth. And I think you hit the nail on the head. There’s 49 other states that love to have the grid we have in Texas right now as far as the diversity of our resource mix, the reliability. When you look at costs as well, we have some of the lowest costs in the country when you look at one hour. But when we think about five, 10 years from now, the load forecast that we’re seeing, I guess the first question is, how do you look at that load

Matt Boms (09:43.116)

forecast, do you take any it with a grain of salt? How do you figure out what’s real and what’s not real? And then when you have that number, how do you plan a grid of the future given all of the, not just data centers, right? The population explosion, industrial loads that are coming Texas, how do you plan for all of

Pablo Vegas (10:00.485)

Yeah,

Pablo Vegas (10:01.146)

and if you look at the population, just in the last five years, we’ve seen population grow from 25, 26 million in the state to over 31 million. Tremendous growth. The economic growth from a GDP perspective has far exceeded the U.S. economic growth for the same period of time. So it’s across all the measures. It’s people, it’s the poor economy, and it’s the new economies, the digital economy that are coming, are driving some of the fastest growth measures anywhere in the world right here in Texas.

Pablo Vegas (10:28.654)

As we look at that, the forecast that we received last year, if you all recall, we got a load forecast that was 230 gigawatts for about the 2030 time period. today we peaked at, we have around an 85 gigawatt peak. So it’s almost tripping the size of the aircraft grid if we believe that that’s gonna be the trajectory. I do take that with a grain of salt. We recognize that with these interconnection processes we have today, that

Pablo Vegas (10:56.854)

really it’s very simple to start a process to think about connecting a large load into the grid. It literally takes a computer and a relatively straightforward submission and you can be in a large load queue. Of all of that load that’s out there, about 200 and plus gigawatts of load that’s there today, the vast majority of it, over half of it, hasn’t begun any process at all with formally interconnecting into the grid, other than just submitting an application.

Pablo Vegas (11:25.216)

half of it you take off right away. Then you’ve got like another 70 gigawatts that’s out there that has some start process started but has not advanced far enough to have what’s considered planning studies ready to go. So you’re very quickly down to a level that’s I think a lot more reasonable where those projects that are serious that have backing behind it are moving forward. And that’s what we’re really trying to focus on today. There’s policy discussions going on around how to...

Pablo Vegas (11:52.972)

define the requirements to be inclusive in this forecast in our cod. There’s rulemaking going on, more so actually more than policy rulemaking. And that’s going to be a really important outcome that I think everybody who’s interested in this space has to watch closely because the requirements around that are going to drive everything else. It’s going to be inclusion requirements for being studied in this new batch process that we’re talking about. Sure, we’ll talk a little bit about that. It’s going to drive the inclusion in the

Pablo Vegas (12:21.294)

planning forecast, which is used for transmission planning. And that’s a super critical element. If you think about that, we need to get that number right because transmission investments are extremely long dated. They last for 30, 40, 50 years. They are very expensive. They can cost billions of dollars. And so you have to be building a system that is going to be rationalized and reasonable for the load and the consumers that are out there. And that’s an important part of that forecast.

Pablo Vegas (12:49.23)

But I also just want to add, you this forecast is also used to schedule and plan outages on the system for generators. We use the load forecast to create the space for generators to take outages in the future. And they need that in order to maintain their plans. We use the load forecast to set our budget at ERCOP, what everybody pays for ERCOP to do its job. So it’s such a critical part of all of these facets of what we do. And so...

Pablo Vegas (13:15.97)

Getting that right is critical and this rulemaking that’s happening right now around it is going to be very consequential.

Joshua Rhodes (13:22.894)

Yeah, I was talking to one transmission service provider and they said a few years ago, like three years ago, they had.

Pablo Vegas (13:29.504)

one

Pablo Vegas (13:29.828)

large load.

Joshua Rhodes (13:30.254)

study

Joshua Rhodes (13:30.754)

in their system. you know, last month they had 100 current large load systems like large load studies going on. And this is one of the really only big four big ones in the state, but that’s one of the big ones. And these loads, to my understanding, are quite different, right? It’s different than having diffuse load, like just population growing and overall, because these loads are also points of like, they exist in a particular location in a particular place. And that has particular implications for all the infrastructure and how to get power in and out.

Joshua Rhodes (14:00.12)

to them. And then plus like when you do like a large load study on one, it can impact what the large load study would look like for another one across the system. Because like we can’t scale the infrastructure infinitely. So can you just talk a little bit about what this batch process is? There are cuts like that you’re having rulemakings and proceedings and like meetings and all this kind of stuff. Like what will that do that’ll be different than how it’s done before?

Pablo Vegas (14:21.762)

Yeah, let me back up a little bit and talk about kind of how we used to manage some of the grid stability issues prior to this whole scenario evolving. So we would have what’s called our largest single contingency defined for the system where we plan for the eventuality of a very significant loss of supply in this case. And it would be around one of the nuclear units that operate in the state of Texas. We have large nuclear facilities that are over a gigabyte

Pablo Vegas (14:51.766)

watt in size at a unit level. And what we need to be able to do is there’s the possibility that if something goes wrong in the system, you could see a nuclear unit drop offline. so you have to be able to have the reserves to be able to manage the stability of the grid and the eventuality that something like that happens. And so that was always the way we talked about you manage the eventuality and risk associated with very large changes in a supplier.

Pablo Vegas (15:19.374)

Well, then now comes in the data centers. And data centers, like you said, are concentrated loads in a location. Today, a large data center might be 60, 80, or 100 megawatts, a very large data center under current definitions. In the future, what we’re looking at is sites that are going to have one gig to potentially two, three, or four gigs in kind of a concentrated area. And so that takes that whole paradigm of

Pablo Vegas (15:45.998)

planning for stability and single contingency issues to a whole different degree. Because now it’s not just a potential supply unit coming offline. You now have loads that have the same risk where they could trip offline and they’re larger than your otherwise previously defined single contingency. So now we have to start thinking about planning the grid differently with reserves in order to be able to manage that eventually. that just to add that dimension into the planning, that’s one thing that is

Pablo Vegas (16:15.83)

really fundamentally changed and why it’s so significant, the fact that these very large loads at a single site add a lot of operational complexity. So that’s something I think that’s important to understand. The batch process that we’re moving towards is necessary because today when a load comes, like you said, historically we’ve had, know, a transmission company would have one, two or three large loads that they’d be working on over the course of a year. And today there’s dozens of them and sometimes hundreds of them depending on.

Pablo Vegas (16:44.622)

company we’re talking about. And what’s happening is that our process effectively works closely with the transmission operator. And we do these planning and stability studies to ensure that the grid and the transmission system can stably connect a large load into the grid and can serve it reliably across 8,760 hours. We analyze literally every hour of the year to make sure that that site can receive energy reliably and stably throughout the

Pablo Vegas (17:13.678)

entire year’s period. And so when we do these studies with a transmission company, we go back and forth over a period of time. It could be six, 12 months worth of work to do that. And then they will get a planning study approved. And that’s kind of a stage in the interconnection process. The planning studies are approved, ERCOT has signed off on it, the transmission company has signed off on it. And effectively then what the customer does is then they build their site. And so then they build a site that could take one, two or three years to build a site. And then right before they come online, they go through one more check.

Pablo Vegas (17:43.278)

and they go through us all energy stabilization check essentially. And so we just make sure that if nothing has changed, you know, since the couple of years before when the planning studies were approved, now we have the as built so we know it’s actually there. And so we do a last table of stabilization study and give them a green light to energize. That’s the way the process has worked for the last 20 years. Well, imagine what’s happening now with data center that gets in a planning study approved, they start constructing a site.

Pablo Vegas (18:11.886)

they’re building their site starting at, let’s say, 120 megawatts in the second year, and then they’re ramping up to, let’s say, 800 megawatts over the next five years. While they’re doing that, 10 other projects within the same geography are doing the exact same thing. So the planning study that was approved for that company two years prior, all of sudden the topology of the grid looks vastly different than it did when the study was approved. And we’re sending them into this never-ending re-study loop.

Pablo Vegas (18:40.718)

where we have to go back and say, the study, the planning study you just had approved has changed materially because the entire transmission system in your geography has changed based on all of these other projects that have come in. And so we recognized pretty quickly that this was the bottleneck we were heading towards and the uncertainty that that was creating for loads was really very, very destructive to the stability that you need for massive investment. So these data centers are huge investments.

Pablo Vegas (19:10.626)

The batch studies is intended to solve that issue. So what it does is it takes, and basically we’re working towards what we call batch zero, which is to establish a baseline where all the projects that are getting ready to come online in the next couple of few years are going to go through this batch study and establish essentially the requirements and demands on the transmission system in order to serve all of these loads. It will then create an allocation of transmission that’ll be held for those projects.

Pablo Vegas (19:40.37)

Because historically we’ve never held transmission. Nobody in the US holds transmission for a project. You do a study and then you build and you assume the transmission capacity will be there when it’s ready, but there’s no holding of an allocation of transmission. Well, in this world we have to do that because with this Batch Zero we’re going to have a bunch of projects that will get approved, the transmission will be allocated for them to build over the next three to five years, and then every year we’re going to have subsequently more data centers coming in looking to interconnect and looking to grow.

Pablo Vegas (20:09.71)

or manufacturers or other industrial customers or any large load. And so we have to do that with the knowledge of what’s been committed historically, so we don’t derail those projects. Then we have to be able to support the new ones coming in and then define the transmission investments needed to serve all of them. So that’s what this batch study is gonna do is effectively do all of them together on a cycle of somewhere between six and 12 months and then each year rinse and repeat.

Pablo Vegas (20:36.814)

come up with the study, evaluate what’s available on the system, determine what needs to be built to serve, and then continue to remove that cycle during the period.

Joshua Rhodes (20:45.89)

That’s follow

Joshua Rhodes (20:46.91)

up. When I teach like electricity markets and electricity systems at UT,

Pablo Vegas (20:52.086)

I use

Joshua Rhodes (20:52.174)

just to skip, really kind of skip over the part of like, if there’s too much generation and not enough load, like that never happens. That’s not a big deal. That data center trip, gigawatt data center trip offline and PJM and like creating havoc, right? And then you’re right to bring that up. That is a new operational paradigm, right? It’s like, it’s not just like losing supply. It’s like losing demand.

Pablo Vegas (21:13.59)

It has the same electrical effect. What’s unique is that the way large electronic loads often behave is that when they see a fault on the system, what they’re designed to do is to protect the assets behind the meter, right? Because you’ve got super expensive GPUs and equipment behind the meter. And so they’ve got UPS systems that they can flip to instantly when they see something like that to protect those assets and then a couple cycles later reconnect to the grid. So we need to make sure that we understand when they’re going to do that and what are going to be the performance requirements

Pablo Vegas (21:43.545)

so that then we can plan around that. Because like you said, once we start to see a lot of these gigawatt sized facilities spread throughout the state or clustered in areas on the state, that becomes a very unique risk.

Matt Boms (21:57.282)

think the next logical question here, Bob, is we’re talking a lot about the transmission grid. I think Josh and I have spoken about this at length on the podcast and how.

Matt Boms (22:06.508)

We have this really successful experiment in Texas that’s called deregulation. And we’re coming up to 25 years, almost, of deregulation in Texas that I think most of us would agree is a resounding success given all the generation that we’ve brought on. However, on the distribution grid, that’s where I want to ask you a couple of questions because it feels like as a side effect of that experiment, we have utilities that are responsible.

Pablo Vegas (22:33.112)

for

Pablo Vegas (22:33.71)

capital expenditure.

Matt Boms (22:34.734)

And

Matt Boms (22:35.214)

we’re telling them not to dip their toes generation, right? They can’t, the T.D.’s in Texas are not allowed to generate. And what that means is, and I think you deserve a ton of credit for this because you’ve come out and spoken about the importance of demand response. You’ve spoken about the importance of DERs, behind the meter technologies, energy efficiency, all of this. And I think that’s probably even more important now given all the low growth that’s coming. So not feel so hard to crack given the regulatory structure we have in place.

Matt Boms (23:03.266)

The fact that we know that substations will be overloaded in the future because of all the load growth that’s coming. In your mind, is there the magic wand solution to this problem or where do you see this going over the next few years as far as DERs, demand response, energy efficiency, all that?

Pablo Vegas (23:19.084)

You started the question with kind of the recognition of how important the competitive market has been to the success Texas has experienced economically. And it is because it’s driven low cost energy that has helped the economic growth in this state for the last 20 plus years. And it’s continuing to do that. So that’s something that has been an incredible benefit, I think, to all Texans because of that construct. I believe that construct can be.

Pablo Vegas (23:45.096)

extrapolated deeper into the grid at the distribution level to leverage competitive forces on solutions and services that are now becoming more viable than they ever have been in history. Those types of solutions and services are distributed resources that are going to be at premises, and that could be batteries at a home, can be smart thermostats and smart coal pumps.

Pablo Vegas (24:14.218)

It can be rooftop solar. It can be electric vehicles. All of these components that are behind a meter at a residence or at a commercial site can provide a functional resource service to the grid at large, especially when it’s aggregated in total. And that’s something that we have proven already with our ADER program, which is our Aggregated Distributed Energy Resource program, that I think has been highly successful. We just recently

Pablo Vegas (24:43.842)

doubled the cap on that program and we’re looking to increase it even further because we’re starting to really see momentum pick up on these types of resources proliferating throughout the Texas grid. And when you think about that, I mean, it’s almost like the business model of an Uber or an Airbnb where you’ve got distributed capital. So consumers and business owners are investing in energy resources.

Pablo Vegas (25:11.682)

to help them manage their reliability and manage their costs. And those same assets that are providing those benefits to the consumers can be double leveraged by the grid operator to provide services to the grid and provide another income stream or economic incentive for those same assets. So they’re making the capital investment in putting rooftop solar on or buying an electric vehicle, but with the proper integration and aggregation, they can become a meaningful part

Pablo Vegas (25:40.75)

of a supply or demand response mix. And that’s really unique and it’s growing. We’re seeing the evidence of it working. We actually have these aggregated resources inside of our energy only market providing energy. We also have them in our ancillary services. So if you think about that, those are our reserve services that we are really protective of because we lean on those in order to keep the grid reliable. Yet we’ve seen that the reliability and effectiveness of these aggregated resources

Pablo Vegas (26:10.862)

can perform under the ancillary services requirements too, in the ECRS and in the non-STIN services. So it’s really a tremendous, when you think about the potential, we’re just getting started with that. And we’re just starting to see companies that are in this space start to really take hold and grow. So I think we’re in the very earliest innings of this trajectory. And I see a future where the grid operator is really moving out to the edge of the grid and working with

Pablo Vegas (26:39.756)

consumers and the retailers and the aggregators and those that are interested in bringing that competitive creativity to this space and finding ways to actually be very economically successful with them.

Joshua Rhodes (26:52.046)

We’ve

Joshua Rhodes (26:52.176)

talked about low growth changing. We’ve talked about, you talked about ancillary services. We’ve talked about how the supply mix has been changing. And then on top of that, we also recently changed a pretty big fundamental market design, like a little while ago, in terms of doing this real-time co-optimization plus batteries, and kind of how we actually are dispatching resources and how we’re procuring those ancillary services we’ve talked about. Can you talk a little bit about what RTC plus B, real-time co-optimization plus batteries,

Joshua Rhodes (27:22.0)

what that is, how that’s a bit different and like, well frankly, how’s it going? It’s going for a couple...

Pablo Vegas (27:25.806)

It’s been months

Pablo Vegas (27:27.026)

now. It has. Yeah, we launched that went live on December 5th of 2025 and it’s been going really well. We saw during winter storm Fern the operational benefits of this that we hope to see because what effectively we’re now doing is rather than taking the commitments for the ancillary services the day ahead and effectively holding them in those positions throughout the day in real time.

Pablo Vegas (27:53.858)

What we’re doing is in real time evaluating at every interval of the market, whether it’s more efficient from a cost perspective to hold one of the reserves and ancillary service with this resource or that resource. And we take the lowest cost resource, move it into the energy service space so that the dispatch comes down in its cost. And then the more expensive resources we could actually hold in the ancillary services in the case that we need those.

Pablo Vegas (28:20.312)

We’re not losing anything in terms of the amount of ancillary service and reserves we have, but we’re really optimizing the cost effectiveness of that. We are forecasting to be able to save at the wholesale power market level more than $3 billion a year just by doing this type of real-time optimization between what’s serving energy and what’s being held for reserves. We’re seeing that financial trajectory realized. We’re seeing it during the periods of

Pablo Vegas (28:48.13)

more scarcity, which Winter Storm firm a few weeks back gave us an opportunity to see that from an economic point of view. We also, so I mentioned the operational benefit, what it does is it will take a look at where the constraints on the system are, our dispatch system will, and it will move around between energy and ancillary services, what is providing energy in order to solve those constraints on the system. So it’s gonna have the opportunity to help bring down congestion.

Pablo Vegas (29:17.074)

in the system as well. And we saw that when we were seeing some constraints coming up into the San Antonio area on that weekend of winter storm firm, there were some constraints on the transmission line feeding the San Antonio area from the valley. And we saw the RTC plus B optimization activate some of the energy resources north of that constraint to alleviate that transmission congestion. So it’s looking at the most economic way to dispatch as well as the most reliable way to dispatch in order to manage the overall congestion of system too.

Pablo Vegas (29:46.71)

And so it’s working extremely well. And then with the plus B, we built it from the bottoms up, thinking about the role that batteries play and optimizing how to dispatch batteries in order to, again, optimize the cost of serving energy and ancillaries. And batteries continue to be such a core part of that operational flexibility.

Joshua Rhodes (30:06.766)

Can I follow up with one question? There has been some disagreement in some of the players around which of the ancillary services certain resources like duration limited and storage like duration limited resources like batteries can play. Can you just speak to ERCOT’s stance on kind how that’s being implemented and like kind of how why y’all see it that way?

Pablo Vegas (30:28.046)

So to understand your question, we have always wanted to try to understand what the battery operator is going to do because we don’t control the dispatch, we don’t control the state of charge for batteries. What we do is we set a set of requirements out for what the various ancillary services need to be able to perform and how we’ll plan around them. So non-spending, you have to be able to come online in 30 minutes, you have to be able to run for four hours in order to serve that block.

Pablo Vegas (30:56.142)

ECRS, you’ve got to be able to come online in 10 minutes. And you have to be able to run through these different wheel-throughs. And we’ve changed some of those definitions to actually shorten the requirements. So at ECRS, now it’s really a one-hour product with the latest iteration. So what we were talking about with batteries before was, if there’s a two-hour or four-hour obligation, we need to make sure that you’ve got that in case you’re called upon to provide that service. A lot of that has been resolved with the way RTC works. And so with real-time optimization, it

Pablo Vegas (31:25.216)

knows what is available in the state of charge because it has to get updated and reported by those resources at every interval. And then it will make the decision based on what’s in the tank on what to put into the next, you know, the next dispatch stack. And so I think we’ve become more flexible with the batteries and it’s become less of a concern around some of these requirements. And frankly, we really like what we see in the batteries here in Texas. There’s a lot of talk about, you know, how do we get more duration?

Pablo Vegas (31:51.97)

We would love to see more duration, but we don’t want to lose the flexibility that we have. A one-hour battery that has one hour of, let’s say a one megawatt battery with one megawatt hour of energy means that it can take its entire charge and give it to the grid inside of an hour. A one megawatt battery with four megawatt hours of energy means that it can provide that one megawatt hour over four hours, right?

Pablo Vegas (32:20.97)

Sounds good and it is good. Duration is good. But if you wanted to put those four megawatt hours on the grid in one hour, you can’t do that. And so that’s why the Ercob Market with our very flexible rules, we’ve been attracting those shorter duration batteries because they have the most flexibility to perform when the grid needs them most. You know, during those solar sunsets where we’ve got an hour and a half to two hours of really, you know, peak need, the entire battery community can put all their energy on the grid at once.

Pablo Vegas (32:50.712)

Whereas if they were under the California model, they have to all have four hours of energy behind them and they can’t dump all that energy in a one or two hour period as needed. So you potentially are holding a bunch of economic energy behind a limitation on the inverter that can’t put it all out of the system. So we really like the flexibility that we have with the batteries today. It’s not saying we’re not looking for more duration. Duration is always good. Right now, the name of the game is really flexibility and the way we’re structured gives us the flexibility.

Matt Boms (33:20.878)

We’re coming up on time almost, and I wanted to make sure we asked you about residential demand response. But look, it’s worked its way through different subcommittees. And again, I think your leadership on this issue has been really important. And when folks ask, like, residential customers in Texas why the industrials have access to demand response programs, but for the most part, residential folks don’t, how do we solve that problem? And where is the challenge as far as just getting all the stakeholders on the same page and getting a new program out there that we can also

Matt Boms (33:50.882)

And it’s maybe that the solution is a Texas solution, which is like, it might not be perfect, but let’s fix it on the fly.

Pablo Vegas (33:56.334)

Pablo Vegas (33:56.794)

I couldn’t agree more with you with that last statement that you just said. Every time we introduce something new, there’s always the potential that it could be improved upon. And that should never prevent us from taking the step forward and learning through that experience. And I think that’s right where we are right now at the precipice of considering some ways to do residential demand response, where let’s start by clarifying, residential demand response is available broadly across Eurot. There are many municipalities that have

Pablo Vegas (34:26.388)

successful programs and competitive retailers are offering demand response incentives as well. But we believe that there’s a lot more that we haven’t tapped into yet and that’s where I think the opportunity lies. And so what we’ve been talking about is how can ERCOT step into that space, provide an economic incentive on top of what the competitive retailers and the municipalities are already doing in order to grow.

Pablo Vegas (34:52.002)

the share of residential demand response that’s available to the grid. And that’s the opportunity set. It’s not about replacing or substituting what’s already happening. It’s about augmenting it to make it more valuable and to bring more people into the programs. And so the issues with moving this forward are the issues that happen with almost any change in our market. There’s always very different stakeholder needs across the spectrum that are looking at, what’s the impact going to be on wholesale prices? What’s going to be the impact on

Pablo Vegas (35:21.314)

potential economic revenues down the road. And so I think we have to think through balancing all those different interests. But in the short term, what I would say is we know we’re going to be faced with challenges with this low growth that’s coming our way. We know demand response is a relatively low cost and absolutely quicker timetable of a product that could be developed than building new supply, as an example of building new transmission.

Pablo Vegas (35:48.418)

We spend a lot of time talking about building new supply and transmission, but we could create a demand response program in a matter of months and get it up and running and get the potential reliability benefit of it sooner. And that’s the approach I think we should come into this looking at, saying let’s put a tool in the toolbox. Let’s try it. Maybe it won’t be perfect. Maybe it needs to be improved significantly after we start it. Let’s put the tool in the toolbox and start learning from it. And then if we realize we need this and we need more of it,

Pablo Vegas (36:18.03)

and it needs to be better, then we can work on it and change it. But we’re right at that junction now where we have to kind of get over that hump in order to move it forward. And it’s really about a a stakeholder policy discussion happening across the stakeholders in the state. And we need to get to that decision.

Joshua Rhodes (36:36.844)

That’s it. Before we get to closing remarks, I kind of want to...

Joshua Rhodes (36:40.072)

ask a little bit of a different question because you get folks like us on the panel and we’re talking about energy and AI. We’re talking about, how are these data centers? But I kind of want to talk about like, how can the electricity sector use AI to maybe do its operations better? I think the implementation of AI and big systems is a little bit of a mixed bag right now. We’ve seen lately we’ve seen Amazon having to come to Jesus moments with their engineers saying you allowed AI to cost 13 hours of interruption. Now, if I don’t get my phone case for next to 13 hours, not a big deal.

Joshua Rhodes (37:09.936)

from Amazon, but if I don’t have power for 13 hours, that is a big deal. But then PJM has recently, another electricity market on the East Coast, has recently implemented more extensive dynamic line ratings. So they’re able to change like the ratings of their transmission network given ambient conditions. Like if the wind’s blowing and the lines are cooled down, you can move more power over them than you automatically would. And some of the underlying machine learning techniques and all those other kinds of things are similar across like these large language models, neural networks versus.

Joshua Rhodes (37:38.902)

other types of models. So I’m just curious to the extent you can, like how or can speak about it? Is ERCOT using AI? How can ERCOT use AI? Are you having talks about it? Like what is it in the use of AI of electricity you’re seeing?

Pablo Vegas (37:51.234)

Yeah, I think the really great irony of all of it is that the big challenge for talking about how to manage the growth and the power requirements, I think can help get solved by the underlying technology that is driving those demands. So in our world, we talk about AI through the lens of people-led AI. That’s the first thing is that this has to be people-led. We’re not going to turn over the systems and the controls to machine learning or to AI, but we’re going to keep it.

Pablo Vegas (38:18.156)

you know, inside of the central function where the people with experience are going to leverage it to help them do what they do better. We are looking at AI in a lot of different areas. So from the obvious load forecasting. using AI to take dozens of different weather forecasts and different load forecasts and be able to look at historical experience and then look at, you know, the probabilistic changes in terms of weather and load and be able to run scenarios.

Pablo Vegas (38:47.326)

instantly getting you a spectrum of likelihoods of what could occur over the next five minutes. We’re starting to introduce AI into that process so that then as we experience what’s going on in real time, the learning occurs and it improves and we’re constantly getting better with kind of the process of being able to load and weather type forecasting to affect that part of our operations. In another area around queue management, there’s process of running studies, building cases,

Pablo Vegas (39:16.15)

and running scenarios, AI is very well suited to help facilitate and improve that because we take data from lots of different sources to build these cases, and then we run them through these stability or dynamic models. so AI can help with doing all of that data gathering, running these processes, analyzing the results, looking for anomalies, and giving the engineers, here’s the places you should look at in terms of these stability results or these dynamic results.

Pablo Vegas (39:41.91)

So we’re starting to introduce AI into the core planning and modeling of what we’re doing. So it’s starting to come into so many different facets of our business and it’s going to continue to grow its capabilities. There were some releases of the AI large language models in the last two months that have had meaningful step forwards in the autonomous capabilities in terms of how long they can actually run without a human intervention. And we’re starting to see the benefits of that in our coding, our development.

Pablo Vegas (40:10.542)

Because if you look at Erkop, we’re effectively a big tech company, right? We’re running a tech platform. The biggest part of our workforce are technology engineers. So it’s becoming a really important part of how we’re thinking about real-time operations and planning. And we’re going to continue to look at, to leverage that to get better on every level of reliability as well as possible.

Joshua Rhodes (40:14.659)

your

Matt Boms (40:30.606)

Well, I think we’re pretty much at top level. And Josh, I just want to thank you so much again. We know you’re busy and the fact that you took a few minutes out of your day to speak with us really means a lot. And anything you wanted to add at the end, I’m feeling optimistic. I feel like this is a huge challenge that we have here as a state, but probably no state is better positioned than Texas to meet this.

Pablo Vegas (40:49.582)

I agree.

Pablo Vegas (40:50.303)

I’d love to just get a quick perspective from either one of you. So you guys work inside of Texas, but you also have the opportunity to kind of look outside beyond our four walls. Are there things that you see outside of our four walls that you think are opportunities for us to learn from? Or are there things that, you know, perhaps we should be looking to export more of in order to try to help this endeavor? Because a lot of what we do is oriented to Texans.

Pablo Vegas (41:16.418)

We really are part of the national economy, we’re core part of it. I think we should always be looking broadly in terms of how we can help others in the industry be successful.

Joshua Rhodes (41:25.088)

I felt like I spent most of my time doing the opposite, getting called in from other places to talk about how we’re doing things in Texas, to be honest with you. Just given how fast we’re able to move and like, you everything from our connect and manage approach and just like this RTC plus B, how fast we’re able to move around. I’m going to kick it over to Matt, see if he has anything while I try to think on my feet really quickly.

Matt Boms (41:47.128)

Well, the one that comes to mind is there are states that do really good job on DERs through TND and deferral.

Matt Boms (41:54.284)

which looks different in Texas because of the problem we were talking about earlier, right, where we have our utilities responsible for just infrastructure, right, just hard transmission and distribution infrastructure. And I think Josh and I agree, like on the transmission side, we’re doing pretty well because you’ve got really good price signals there on the transmission grid, but you don’t have things on the distribution grid because they’re essentially regulated.

Pablo Vegas (42:17.71)

You

Pablo Vegas (42:18.429)

have to stay on that space.

Matt Boms (42:19.576)

Exactly. So I think that’s where we have some room for improvement. Like a study just came out showing, I think almost $2,000 per rate payer over the next 10 years, if you’re able to crack that T and D deferral piece. So I think that’s what I’m looking towards moving forward here.

Joshua Rhodes (42:35.212)

I guess the only thing is that I would say is.

Joshua Rhodes (42:38.178)

We talked about congestion and we talked about the price signals that we do see. Maybe the large loads and everything and all the transmission that we’re going to build will kind of alleviate this for a bit. I do think we can do a better job of leveraging the economic test for new transmission than we do. Because essentially, if we build a new transmission line, please correct me if I’m wrong on this, as I’m speaking to the CEO of Vircoq. We build a new transmission line on the economic test. It essentially has to pay for itself in one year’s worth of savings.

Joshua Rhodes (43:08.058)

mentioned earlier, transmission is a multi-decadal asset. so anytime that I’m talking about everything that Texas does great, I usually am like, well, there’s this one thing I really think we can do better. And that’s what I would say is like, if there’s any way the economic test for new transmission could be more, at least on the order of magnitude of the length or the lifetime of the asset that it’s paying back, like, I guess that would be my only feedback.

Pablo Vegas (43:13.078)

about

Pablo Vegas (43:31.63)

I think that’s really good point. And in fact, I’m glad you brought that up because it is something that we are working on right now. And there is another region, other regions use this concept of an MVP, a multi-value kind of a proposition for evaluating the effectiveness of transmission investment. And what you can do is you can take benefits across reliability, benefits across economics, and benefits across resiliency and look at the three components and say, okay, well, you may not hit 100 % on

Pablo Vegas (44:00.776)

one or the other, the combination, the multi-value combined creates enough of the hurdle, overcomes the hurdle to pass the requirement to build that transmission. We should be looking at transmission to that same ones because there is real value in resiliency, there’s real value in economics, there’s real value in reliability and combining those metrics to come up with a combined value proposition for a project is a much more effective way than trying to just fully clear one hurdle or fully clear another.

Joshua Rhodes (44:29.816)

Pablo Vegas, thank you for coming on the Energy Capital Podcast.

Pablo Vegas (44:32.13)

Thanks,

Pablo Vegas (44:32.422)

Josh. Appreciate it. Thanks, man.

Texas built its electricity market to react quickly to changes in demand, attract private capital, and protect ratepayers from private-sector investment risk.

A wave of large load interconnection requests is testing that model.

In this conversation, Katie Coleman, a leading Texas energy lawyer and partner at O’Melveny & Myers LLP, describes the pressure points facing the ERCOT grid. Officials are scrambling to determine which loads are real, how quickly they will arrive, and how the state should build transmission and other infrastructure to support them.

Coleman brings ERCOT’s challenge into focus. She explains how customers behave differently — signing different contracts, facing different operating constraints, and placing different demands on the system — and grid managers have to juggle those variables.

She also walks through a basic divide in the Texas market between generation and transmission. Private investors assume the risk of building generation. But with transmission, regulated utilities must get permission from the PUC to build power lines and then charge consumers for them (plus profit margin) over time.

As interconnection requests climb and forecasts shift, these infrastructure decisions will become increasingly important — for the ERCOT grid and Texans’ power bills.

The episode explores a range of issues, including:

* How ERCOT and policymakers should judge new load forecasts.

* Why transmission planning is a central constraint.

* How Texas can preserve market discipline while serving growth.

Coleman also points to the importance of regulatory stability. As large customers, generators, and utilities make long-term decisions about growth and investment, they need an energy market they can read.

That predictability becomes even more crucial, Coleman says, as Texas debates how to respond to unprecedented demand growth.'

Energy Capital Podcast is produced by ClarityForge Studios.

Timestamps

* 00:00 - Introduction & Katie Coleman

* 01:05 - Katie’s Energy Origin Story

* 04:01 - Why She Represents Industrials

* 05:55 - What Large Power Users Want

* 08:56 - Speed to Power in Texas

* 10:57 - How Industrial Demand Response Works

* 17:04 - Crypto, Data Centers, and Misperceptions

* 20:43 - How the Energy-Only Market Works

* 28:27 - Load Forecasts and Transmission Risk

* 36:46 - Bringing Generation With New Load

* 38:49 - Why Texas Needs Stability

* 40:32 - Final Reflections & Close

Resources

People & Organizations

* Matt Boms (LinkedIn)

* Texas Advanced Energy Business Alliance (Website - LinkedIn)

* Energy Capital Podcast (LinkedIn - YouTube)

* Katie Coleman (LinkedIn)

* O’Melveny & Myers LLP (Website - LinkedIn)

Related Podcasts by Texas Energy & Power

* Who Pays for Texas Grid Growth? - Roundtable Discussion

* More Power That’s Faster and Fairer

* Where the Grid Goes from Here | Reading and Podcast Picks - Feb. 4, 2026

* Another Winter Storm Bears Down on Texas | Reading and Podcast Picks - Jan. 23, 2026

Transcript

Matt Boms (00:05.198)

Today, I’m really excited to be joined by Katie Coleman, managing partner of the Austin office at Olmelvney and Myers. Katie is one of the leading energy regulatory attorneys in Texas. She has more than 15 years of experience representing large industrial energy customers in ERCOT and before the Public Utility Commission of Texas. She’s best known for her work representing groups like the Texas Industrial Energy Consumers, TIEC, and the Texas Association of Manufacturers, TAM.

helping shape some of the most important conversations around energy markets and policy in the state. Katie has also been deeply involved in the industry more broadly. She served as president of the Gulf Coast Power Association, and she previously led the state bar of Texas public utility law section. And across the energy community in Texas, she’s widely respected as one of the very best regulatory lawyers in our business. So Katie, thank you so much for making time for us, and thanks for joining the podcast today.

Katie Coleman (01:03.726)

Absolutely glad to be here.

Matt Boms (01:05.558)

I wanted to start with a layup and I wanted to ask you to just walk us through how you first got into energy. Like what is your origin story and how did you end up in this business?

Katie Coleman (01:15.182)

Yes, so I have no qualifications. I have no business doing this job that I’ve now been doing. My bio actually, I need to update it. This is actually the 20th year when I first started in the industry, which I count as when I clerked when I was in law school, which then turned into a permanent job. I spent the summer doing this, finished law school, and then came back in 2006. So it’s been 20 years now.

I went to UT undergrad. I was a liberal arts major. I did a small honors program at UT called Plan To, which people at UT are familiar with, but a lot of other people aren’t. But it is just an interdisciplinary liberal arts honors program. So I had no idea what I was going to do. And I did that very cliched thing where I took the LSAT to see how I did and then ended up in law school. Even in law school, I had no idea that I was going to end up in this field.

So I’m not from Texas. I’m actually from outside of Asheville in North Carolina. And Austin felt like a huge city to me when I was in school here. And in law school, I looked at jobs in Houston. I looked at jobs in Dallas. I actually split my summer in Austin and Dallas. And Dallas just felt unmanageable for me being from a very small mountain town. And so I really focused on Austin. And obviously there’s a big regulatory workforce here.

in Austin with the capital and all the state agencies. And so the firm that I clerked with, which was at the time Andrews Kerr, this was a big part of the work they did. So I tried several different sections and really liked the policy aspect of the energy practice. And the partner that originally hired me, I think took me around and met some of the clients, met some of the stakeholders that we were going to interact with regularly. And it seemed like a good fit. So he,

hired me on a little bit of a whim. And here we are. I feel really lucky. It’s been a really good fit and I’ve really enjoyed it, especially all of the people that we work with, I think make this a really unique, special industry. And I think that’s what I picked up on when I was looking at options. And so I’ve kind of learned it as we’ve gone and I’ve had great mentors that are very credentialed and do know a lot of things about power markets and

Katie Coleman (03:36.706)

just industrials in general that have taught me everything I know along the way. So that’s really been key.

Matt Boms (03:42.978)

That’s awesome. And when you say 20 years, I’m sure it probably feels like where did those 20 years go? Cause the time goes by so quickly.

Katie Coleman (03:49.806)

You know, it felt like that for a while and then in 2021 it stopped feeling like that. From 2021 until now it feels like it’s been like another 20 years.

Matt Boms (04:01.036)

Yeah, well, I guess the last part of the origin story is like, did you come to represent the large industrial customers? Like, how did the door open for you and how did you take that path?

Katie Coleman (04:10.296)

So I inherited it, is the short story. The group of attorneys that I started my career with, who I still work with, have a legacy that goes all the way back to the original adoption of the Public Utility Regulatory Act, and back in the 70s. And at that time, there was a lawyer in Houston, he was at a different firm, Mayor Day Caldwell and Keaton at the time. Jonathan Day was involved in writing Pura.

along with some other attorneys. And when the bill passed, they sort of divided up, you know, who was going to take which sector of the industry, who was going to work with the utilities. And Jonathan in Houston, with the Ship Channel and with strong industrial relationships, decided he was going to represent the industrial users. And so he then trained another attorney who then trained another attorney who then trained me. And so we have kind of a lineage back to the seventies representing these same clients.

And I think that’s really been official for the group’s advocacy because we do have a lot of history about how we got to be here, how different policy changes have actually impacted industry over the years. And it just helps to have that knowledge base to draw from and sort of the institutional experience. So it’s a pretty unique thing. And actually, if you look in Texas, there’s a lot of groups that are that way, like the cities, the...

city’s representatives, they’ve had a lineage of representing those stakeholders back for a long time. Some of the firms that represent utilities, you know, like I think about the relationship with MakerBot and Centerpoint, for example, you know, that goes way, way, way back. So it’s actually a pretty common thing, but that’s how it happened. I sort of joined the group, inherited this legacy.

Matt Boms (05:55.768)

That’s also, it’s also a great reminder that you think that this current generation of folks that work in our industry just showed up one day, but it is great reminder that there’s a whole line of people that came before us in our current roles that really carved out these roles and like made the industry what it is today. I love that you mentioned that. Well, I want to jump into industrial customers that you represent and kind of talking us through maybe spelling out and explaining some of the misperceptions there are about large power users. So.

Just to kick this off, what do large power users prioritize when it comes to electricity markets in general?

Katie Coleman (06:32.248)

So above all, they want reliability. They’re not primarily in the power industry. They’re primarily making widgets of some variety to sell in global markets. The number one thing that they want is to make sure that they’re going to have a reliable source of power that’s not going to damage their equipment, not going to cause them to lose product or feed stocks, not going to cause health and safety risks to their employees. So that is far and away the number one concern.

But of course, they’re businesses and so they care about cost. And in particular, they care about the ability to contract, to meet their individual business priorities and all of my clients are different. They all have sort of different profiles. They’re all in manufacturing of some variety, but different products, different sectors, and even within a sector, different goals. And so one of the things that has been

A real driver for businesses to site in Texas has been the flexibility that the deregulated market provides because you can have one customer who just cares about having price locked in and wants to hedge and is agnostic about fuel source. You can have other customers who really care a lot about green certifications and things like that. They can contract in a certain way.

You have other types of customers that maybe are flexible and can turn off if prices are too high. Maybe they don’t want to hedge in the same way that other types of customers do. And so our market really provides an endless suite of options for large industrial users. So I would say reliability and cost. If you ever hear me testify at the legislature, I often start with, this is sort of like the time honored, Tam talking point on electricity.

Electricity for a manufacturer in Texas is typically one of the top three production costs. Often it’s number one or number two. And for some of our members, it’s up to 70 % of their production costs. So it really is a driver in siting and expansion decisions and which assets, you know, our company’s choosing to operate at any given time. And it’s something, like I said, that people look at when they’re choosing where they want to build, where they want to be.

Matt Boms (08:47.298)

Yeah, correct me if I’m wrong, but that’s been the secret to our success in Texas is the abundance of electrons and low prices compared to other markets.

Katie Coleman (08:56.236)

Yes, I’ll say another thing that’s come into the forefront lately, which is not something I focused on a lot until maybe the last 10 years, but it’s definitely accelerated is speed to market. So getting interconnected has become a lot more challenging, not just in Texas, but across the country. And it has to do with this data center AI boom. But of course my clients are competing with.

all of the transmission voltage large load clients are customers are competing to get interconnected. And there’s only so many utility resources, only so many crews, only so much capital, only so much infrastructure that can go around. And so being able to get a quick and predictable interconnection has also become a real priority in a way that it’s not something I probably would have talked about.

well, maybe five years ago, but not 10 years ago, certainly. And five years ago, really only in areas that were experiencing oil and gas booms, West Texas has been an issue. Trying to get service out there has been an issue because they really needed to upgrade the transmission system and the import paths into West Texas. But other than that, you didn’t really have issues with going to the utility and asking to be interconnected.

and getting an uncertain answer or a really protracted timeline. So that’s something that’s changing rapidly that, like I said, it’s happening around the country, but it’s become more of a focal point in Texas recently.

Matt Boms (10:28.758)

Yeah, absolutely. Yeah, that’s speed to power has become like our thing in Texas, right? In other parts of the country, it’s just not as quick as it is here. Well, I wanted to ask you about the kind of demand response issue and when we do have grid stress events in Texas, I’m just curious how industrial customers respond to those grid stress events. And if you can just dispel maybe some of the ideas there are around how that works. Can you explain it to us? Like a two year old, how does demand response work for the industrials?

Katie Coleman (10:57.326)

Yeah, so again, it’s not homogenous, but there’s different varieties of response that you see. I’ll start with, we’ve got one set of customers who are what we call high load factor, which they’re using 95 % plus of their maximum possible demand at any given time. And those customers tend to not be price responsive, they tend to not be flexible. So when a grid emergency occurs,

You know, they will try to do their part to the extent they can and try to reduce usage to the extent they can, but you’re not going to get major response out of those sites. They just don’t have that capability because the reliability is so essential. Some of them may have invested in their own generation at the site. And so that’s something that can sometimes be utilized to provide additional electrons to the market in times of need. You know, they might have a generator that they don’t typically run, but they can turn on.

And again, they might be able to curtail a little bit, but there’s a whole category of customers that are not able to provide a lot of response. I would say that is well over 50 % of industrial sites are in that category and are not actively participating in the market. I think that’s a misconception that all industrials have their own trading desks and are all offering an ancillary services and responding to price. For most of them, it’s around the margins.

So you might get some response. certainly watch it. They certainly, you know, are aware of market conditions, but they’re not actively responding. You have another category of customers who can do things if really necessary. You know, they can do things at their site. They can reduce their usage, but it’s really only when they, like a winter storm, you’re a event or, you know, something that’s kind of foreseen that they can prepare for.

Then you’ll have customers that can do things at their site to reduce usage even further. And then you’ve got this other category of customers who are really actively participating in the market in one way or the other. So some of them provide ancillary services as load resources. Some of them participate in a program at ERCOT called Emergency Response Service. The profile of those customers is a little different. So the ones that are in responsive reserve service have to respond really, really quickly.

Katie Coleman (13:23.062)

like within a few cycles when they get an instruction from ERCOT. So they’re able to ramp down really quickly. They have to offer into the ancillary service market, you know, in the day ahead market if they want to provide that service. ERS providers, they’re not called on as often. They’re contracted seasonally, so they don’t have to actively offer into the market. And they have a little longer response time, so they don’t have to respond quite as quickly as responsive reserve providers.

Then you have another category of customers who will opportunistically respond. So they may not be offering into a formal service like ERS or like responsive reserve service. But if prices are high and it looks like they’re going to stay high, they might reduce their usage for economic reasons. And so there’s a category of customers that actively does that. There’s probably some overlap in the ERS responsive reserve and price responsive. But again, I would say that’s probably like

25 to 30 % of industrial sites. It’s not monolithic and it’s not everybody. But the thing that I think people have a major misconception about is the ones who do that, there has been this narrative that it’s a moneymaker for them, that by selling into ancillary services when prices are clearing up the cap, that they’re making money. And that is so far from the case.

I’m not aware of any client that has ever actually made money on a net basis providing ancillary services. It is a mitigation tool for what is overall a major cost for industrial. So a typical manufacturer in Texas will spend hundreds of millions of dollars a year on electricity. Offering into ancillary services is a way to mitigate some of those costs, but never under any scenario are they profiting.

from making money in the market, if that makes sense. And so I think after, for example, Winter Storm, URI, and some other events right after that, there were narratives about large users profiting from an unreliable grid, and that’s just the furthest thing from the truth. They want reliability, but remember that price signals are there to elicit behavior. You know, if that’s an issue, you’ve got a fundamental issue with competitive markets and supply and demand, because the whole

Katie Coleman (15:49.07)

point is you send a higher and higher and higher price to encourage users to stop using energy, to stop utilizing that resource that’s being priced at scarcity pricing. That’s why you do it. And so our clients who are, you know, sophisticated global businesses will respond to that price, some of them in certain circumstances, and that’s what you want. And actually, I think we should really be aiming collectively as an industry to get more of that response, not just from

my clients, but also from residential and commercial clients. That’s sort of the key to a well-functioning market is that price elasticity.

Matt Boms (16:29.88)

really appreciate you spelling that out. And I almost wonder if the misconceptions around large load behavior, because the large loads themselves have changed so much over the last few years. Like you’ve been doing this for 20 years and I just wonder like how much the profile has changed of those large loads in the past couple of decades, right? Like you didn’t have crypto miners 20 years ago.

You definitely didn’t have the volume of data centers that we’re seeing now. So can you speak to that a little bit? Maybe that’s part of the reason why policymakers and regulators are a bit confused about the way large loads behave.

Katie Coleman (17:04.609)

Definitely. So the cryptocurrency build out a few years ago took things that industrials have typically done in moderation and took it to sort of extremes. And the reason for that is obvious and just purely financial. The whole crypto business is basically converting electricity to cryptocurrency. There’s no other real feedstocks or, you know, there’s nothing else in the calculation. Right.

It’s electricity in, cryptocurrency out. And that’s different from a traditional manufacturer where we’re also making other products and with other feedstocks and with customers that have contracted with, you know, my clients for offtake agreements that they have to fulfill or be subject to, you know, damage clauses. So it’s a much more complicated calculus for an industrial to decide how and when to curtail usage.

because you’ve got to balance all of those things. Like, how am I doing on my production quotas? How many times have I curtailed this month? You know, there’s all kinds of things that go into that analysis. I think with the cryptocurrency, like I said, it’s a more purist application of this. And so you saw more dramatic response, more sort of predictable response, and at a larger scale. And I think there were companies in that space that were

touting their sophistication and efficiency for investors as businesses do, and talking about either the money they saved or the profits they made by liquidating power they bought forward into the market or selling ancillary services or some variety of that. And so I think that got regulators’ attention because they’re thinking, well, you’ve got residential and commercial customers at risk of...

power outage and then you’ve got these large companies that are making money off of it. But the piece of the logic that’s missing there is the behavior of those large customers is going to reduce the likelihood that there’s any reliability event for the residential and small commercial customers. And so you want that behavior. And I think you have to acknowledge sort of like the rational economic outcome there. If we’re sending a price trying to get people to portray all you can only

Katie Coleman (19:26.22)

have so negative a response if they respond to that signal, right? It’s ultimately what you want, but it certainly highlighted some things that the market was designed to elicit, but maybe weren’t as familiar to people. I think since Winter Storm URI and since some of the new trends and large loads starting with crypto and now getting into sort of larger AI data centers, there’s been a lot more...

public awareness and public knowledge around these issues, which I think is good. I think the narrative on this stuff has actually gotten a lot more rational and sophisticated over the last four five years just because of this sort of education that was forced through all of these major changes that we’re experiencing.

Matt Boms (20:12.066)

think also Texans are just like more fluent in energy than the rest of the country. Like we’ll just understand our energy bills, I think a little bit better because of the deregulation and retail providers and all that stuff. Well, we’re getting into like market design and I want to get into the weeds a little bit. And maybe you can help us understand how the energy only market is supposed to work in theory and whether the price signals that we’re seeing now are enough to bring in all the investment we need for reliability.

Katie Coleman (20:43.468)

Yeah. So go back to like a regulated model, because I like to compare what the energy market is supposed to look like to a regulated model. So in a regulated model, customers pay actual cost for energy and for power plants. So when you say, I’ve got your utility, you’ve got this load growth coming, you go and you say, I need to build this power plant. Here’s the most economic option to meet this need.

And then that goes into customer’s rates and they pay for it over the life of the power plant at actual cost plus a built-in return for the utility, a built-in profit for the utility. And they get the energy that that plant produces at actual cost. And that is an important difference that you’re getting energy at actual cost in a regulated model. In the deregulated model, the whole concept was we’re going to take that financial risk

of the capital investment for a power plant off regulated rate payers and we’re going to put it into the private sector. And we are going to let businesses compete for who can build the best mousetrap and who can meet the needs most efficiently. And in exchange, we’re not going to have customers pay the capital costs of power plants, but we’re not going to give them the energy at cost. We’re going to set a clearing price for the energy.

So that means whoever is the most expensive power plant that’s running, they set the price and everybody that’s cheaper than that power plant, they get a profit. And so the concept was all of those more efficient, cheaper power plants would get built and you’d have an incentive to continue building like more efficient power plants because they would continue to get this clearing price that’s gonna be set by older, less efficient technologies.

with a higher heat rate, et cetera. And you’re gonna get this financial risk off of Texas customers. Texas has historically been a very pro-markets state philosophically. And so there was a belief that as technology changed, as market needs changed, that a competitive construct would be more flexible, faster, and better suited to meet those needs, which I strongly believe

Katie Coleman (23:03.224)

continues to be the case. And it’s one of the reasons why one of the consultants that we work with a lot, Charles Griffey, he often says the energy only market works in practice, but not in theory. Because in theory, everybody’s like, the missing money and da da da da, which I’ll address what that is in a second. But we’ve for 25 years now had all these predictions that we’re going to have a reliability problem. We’re not going to have enough generation.

It never materializes. And part of that is because fundamentally, regulators can’t see more than a couple years down the road. They are not as good at rationalizing market incentives and dynamics as, again, the private sector. And so you can try your best to predict what’s going to happen, but in a market, you’re always wrong, right? And we’ve now got 25 years of experience showing that, that we’ve continued to replace plants, to get plants built.

get different types of technologies integrated in a way that has overall been reliable. Now, Winter Storm URI, I think probably people who are listening to this podcast right now are thinking, what about URI? Is it a reliable grid because of Winter Storm URI? And again, what I think people who are not in the industry don’t understand about URI is that was not really an issue of how much generation we have in Texas. It was an issue of the generation performing.

We had 50 % of our gas fleet was on outage and no system in the world is designed to continue to provide power when you have 50 % of your generators on outage. It’s just not economic. It’s not realistic to have that level of a reserve margin. I’d have to go back and look, but I want to say our reserve margins at that time were like 25 % or something. I mean, it was a healthy reserve margin by any standard, but we had...

weatherization issues, every variety of issues. There were plants that were getting water from nearby cities whose water lines froze or busted. I mean, it just couldn’t get workers to the plant to clear alarms after there was a unit trip. Every variety of issue that you would expect for a state that is not used to those types of temperatures for a sustained period of time. So all that to say, yes, URI was a terrible event.

Katie Coleman (25:22.262)

a lot of lessons learned, but it really wasn’t an indictment. It was not an indictment of the fundamental construct of the energy market. The other thing I would say is this missing money problem that people talk about. The missing money theory is, as I described earlier, one of the generators sets the price, whoever’s the most expensive generator sets the price, and then all the more efficient generators get a profit from the inframarginal rents between their actual cost and the

clearing price, right? But the question is, well, the unit that’s setting the marginal clearing price, when do they make money? Okay, and this is like a very oversimplified view of how the market actually works. But that is the missing money problem is, you know, that that entity that’s setting the clearing price, they don’t get money to reinvest in capital to keep their plant running or to build new plants or anything like that. And so in theory, that’s going to put retirement risk on those plants on the margin.

The reason that is not true is because we do have administrative scarcity pricing of various types. So we have features in the market where prices are not actually set by that last unit. So when we start getting toward emergency events, there’s actually administrative pricing that kicks in, that sets prices far above any unit’s actual cost. And so it’s the ability to show up and perform during those periods

that can really drive investment for the units that can reliably perform, the types of units that can reliably perform. And from the consumer standpoint, that’s a really efficient market design. You’re only paying people to be there when you need them, to provide energy to you when you want it, and to perform when the grid needs it most. And you’re not making sort of like fixed payments, irrespective of what’s happening on the grid for a generator to just exist.

And so that’s one of the reasons that I think Texas’s market has been more efficient, lower cost, and has performed really well compared to other markets around the country.

Matt Boms (27:28.652)

That was an awesome explanation. And it’s like, I said that all the time that ultimately the rate payer is not putting themselves on the line in Texas. It’s the private investor that goes out and wants to build project. And if it doesn’t work out, it’s on them. It’s not on the rate payer ultimately. But what is on the rate payer is the transmission system. So that was a great transition there. So I wanted to ask you about all this load growth that’s happening and dominating the conversations in Texas.

I don’t think anyone knows how much of it will materialize. If you do let us know what the number is, but I think no one really has that exact number. But what are the kind of challenges and opportunities around building out this transmission infrastructure, which takes time, right? And that is on the rate payer because that’s the piece of our system that is still very much regulated by the public utility commission. like, can you talk us through.

how you can build out that transmission system efficiently and allocate the costs in a fair way.

Katie Coleman (28:27.95)

Well, so just to tie this topic into the last one, there’s so much uncertainty about these load forecasts and the demand that we’re going to see and what level of infrastructure we need to build to serve that demand in the space that’s still regulated. Okay. In the generation side, we’re allowing private capital providers to make those assessments about what they believe is real and build plants at their own risk. And can you imagine if we were dealing with this problem?

both on the transmission side on building generation plants, which in the regulated areas of the country, they’re having to deal with both. And it’s again, an area where I think a market is well suited to rationalize this behavior. And so I think the competitive generation market is gonna be an advantage for Texas as we move forward more than it even has been to date. But on the transmission side, yes, the biggest difference in what we’re seeing now

And what we saw before in terms of load growth is because of the money involved in developing an AI data center and the value of actually getting an interconnection in again, the race to market for AI companies, you’re seeing a lot of third party developers in this space that are out developing sites and they’re not going to be the customer at the end of the day. They’re trying to get powered land.

or get a site constructed and then have one of the computing company, one hyperscalers or whatever type of computing it is, but typically it’s the AI hyperscalers right now. They would then come into the site and operate there, but they’re not often the ones that are interacting with the utility. Now, some of them do self-build, but even those are often also looking at sites that are being developed by a project developer.

So the question of what is real becomes really esoteric because there’s all these steps that have to happen after a developer gets an interconnection. They’ve got to develop the site in other ways aside from electricity. Different applications need access to fiber or robust communications networks. You need gas supply. There’s all other types of things that have to happen at a site. And so you don’t have, like we used to have, a customer like

Katie Coleman (30:53.622)

a refinery or a semiconductor fab, I’m a chemical company, you don’t have that entity interacting with the utility in this sector. It’s these third party developers. And it’s this race to get powered land that I think is causing these huge numbers that nobody knows what to do with, because it’s just a new type of project development that we’re seeing at a much different scale than we ever have before.

I think ultimately we’re going to get experience with what are the indicators that really should tell you that a site is going to make. But we just don’t have that yet. It’s a new industry. new data centers are not new, but this AI application and the size and the type of development is new. And again, the presence of third parties who are developing these sites, it’s not been at this scale before. So I think that is causing these huge numbers.

Senate Bill 6 was an important step in Texas toward trying to rationalize some of these load numbers. Before, when you were dealing with the direct consumer, there was not a lot of financial commitment required in order to get a utility to study you and to sign an interconnect. Really, when you sign an interconnection agreement, there was a decent amount of security, but to get studied and to get reflected in our cuts planning models was not a big.

financial commitment until you got to the point where the utility was offering you an interconnection and you posted security for that interconnection. So that’s changing. That was probably the main thing. Senate Bill 6 changed is to require proof of financial wherewithal earlier in the process. So we’re not just getting a ton of speculation. But I think what nobody realized when we were doing SB 6 is that solves part of the problem.

That’s all sort of unsophisticated speculators who just have a piece of property with a transmission line across it they don’t really know anything else about interconnections or developing a data center. But for the companies that do actually know that they’re very cost insensitive. And we’ve seen an appetite to put up big application fees, big security. And so it has not kind of culled these numbers in the way that people expect it. And in fact,

Katie Coleman (33:14.478)

what my industrial manufacturing clients would tell you is that it’s gotten to a point where the pay to play proposals are threatening to kind of push them out of the market. So right now there’s a rule pending at the Public Utility Commission where in order to get studied and get an allocation of capacity to interconnect, you would have to post $100,000 per megawatt non-refundable security fee.

If you’re talking about one huge hyperscaler company developing a data center or a couple data centers, maybe that makes sense. I don’t really know. But when you’re talking about oil and gas and midstream companies that are developing multiple sites a year that are over 75 megawatts, and they might get a lead time on interconnection that’s three or four years. And so you’re having them post tens of millions of dollars of credit each year.

that the utility has been holding until they energize, it just gets to be kind of silly. And it’s not something that other jurisdictions do. And so I think you’re going to see possibly two types of behavior from the traditional manufacturing sector. They’re going to try to get under that 75 megawatt threshold if they can. And they’re going to look elsewhere. And again, this rule hasn’t been adopted. It’s still under consideration. But I think we’re at a point right now where we’re having to

grapple with, do we need to treat this new type of development differently from kind of the traditional industrial manufacturing development? It’s something that my clients have struggled with because we fundamentally don’t want to discriminate based on what people are doing with the power. So we really have not wanted a different set of rules because these people are doing AI and we’re doing traditional manufacturing processes. That’s been something that we’ve not.

pushed for. But I think what you’re starting to see is other potential sources of demarcations like size, like a traditional manufacturing site. There are exceptions, but a lot of them are 200, 250 megawatts or less. They’re not a gig. They’re not two gigs. And it’s really that type of behavior that’s causing, you know, a lot of the major transmission needs and things like that, as opposed to what we’ve seen again for 30 years, 50 years in Texas with the industrial sector. So

Katie Coleman (35:41.986)

I think it’s going to be a tricky needle to thread how you put appropriate financial incentives for this new type of development without really harming the traditional business sector that’s been a key part of the economic story in Texas. I think everybody’s struggling with the right answer to that.

Matt Boms (35:59.862)

Yeah, I think that’s reasonable. And you don’t want to pit certain industries against each other. And you definitely don’t want to become a state that relies just on data centers and not on any other industry. Right. So there are huge questions, I think, happening at the highest levels of our state right now. And it’ll be interesting to see how this shakes out over the next few years, because like you said, this is kind of unprecedented, right? At least in our lifetimes, like we haven’t seen this kind of load growth before. So I think it just raises new questions that we haven’t needed to ask for a very long time about.

Who gets interconnected? How much do they need to pay? Because I think probably the thing that most people don’t want to admit at this point is like, we just don’t have enough generation to meet all of this load. It’s going to take time to build it. I mean, we could definitely build enough generation, but it’s going to take some time for the transmission system to catch up to that. The infrastructure is just not there yet.

Katie Coleman (36:46.968)

Well, let me mention one thing on that, which is, you know, a lot of the data center developers and the hyperscalers themselves are interested in supporting generation development. And they are not as cost sensitive in many instances, like I said, the traditional manufacturing community. So they’re interested in bringing generation, especially if it means that they can get interconnected faster.

But there’s not right now a formal way in the planning process to give a customer credit for that generation when they’re interconnecting. The way it’s studied is, well, what if the generation’s not there? We have to plan to serve the full load or what if the load’s not there? We have to plan for all the generation to export and show up on the grid. That’s something that I think the commission has recently given really strong direction to try to come up with a way that you get credit if you’re bringing generation and ERCOT’s working on that.

But I think that’s going to be a key part of the solution going forward is if I’m building a gigawatt load and I don’t get it to interconnect any faster, if I bring my own generation, it really diminishes the incentive to do that. So I think fixing that is going to be a key part of the solution. Cause I do think people want to build stuff, not just the companies themselves for self use, but the traditional dispatchable generators in Texas. think they want to build things too.

But figuring out exactly what the load looks like and, you know, if you can get credit for having this relationship with a large customer, I think those two things would go a long way toward making that happen.

Matt Boms (38:22.85)

Yeah, the system has changed so much, right, that it’s not simple anymore as the utility brings you the poles and wires and delivers the electrons, right? Like now you’ve got these large customers bringing their own generation. That’s a huge game changer. Okay, well, as we wrap this up, moving forward, what is your vision for the Texas grid? If we could snap our fingers and just travel 10 years into the future, like what is the best case scenario here of how this all shakes out?

Katie Coleman (38:49.368)

I really am hopeful that we’ve been through a period of really rapid change and dramatic change since Winter Storm URI. And I feel like we were just kind of coming out of all of that, reassessing market design, making a lot of changes. And there was hope that this last legislative session, it was going to be a quieter session on the electricity front. And then, of course, we got these data center numbers.

And so we had a very active session on electricity again last session and now there’s ongoing rulemaking. So there’s just been a ton of turn. What I’m really hoping for, and I hear this echoed from people at the legislature and at the commission, is a period of more stability where we get these impending problems addressed and then we let things ride, let the market digest it, let people react to it.

Because I think you’re seeing right now, I mean, I every day get questions from clients trying to understand the batching process that’s going on. Just understanding what it looks like to try to get an interconnection here. There’ve been major structural changes to rates recently, and they’re considering additional structural changes to transmission rates that people are still trying to understand. Wholesale pricing, has there been significant changes in that regard?

It’s really hard to get investment of any kind in an environment that’s changing that rapidly. And so I really think the key to the long-term success of the Texas market is again, to rely on market forces as much as you possibly can and to create stability and predictability. I think that’s gonna be the key to long-term success of the market.

Matt Boms (40:32.908)

Yeah, totally. Like the companies that I talk to also are, they’re all saying the same thing. It’s just show us where the goal posts are and just keep them there for a while and that’ll help. Well, Katie, thank you so much. know you’re extremely busy and I just really appreciate the time that you took out of your day to talk with me and just share your expertise. You’re such a brilliant person and so well respected in our industry. So it means a lot that you came on to spend some time with us today. So thank you so much.

Katie Coleman (40:57.848)

Glad to do it. Thanks for the invitation.

Matt Boms (41:02.008)

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 Empowered newsletter at texasenergyempowered.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 Bombs and I’ll see you next time. Stay curious, stay engaged and let’s keep building a stronger, smarter energy future.