How will data centers pay for power?

3 jun · Energy Capital Podcast

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.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe

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Texas competes on everything except transmission
8 jul· Energy Capital Podcast
Texas built a competitive retail electricity market: consumers choose among roughly a hundred providers, and generators build power plants at their own risk with no guaranteed return. Transmission, the high-voltage lines that move power from where it is made to where it is used, runs on a different model. One utility builds each line and recovers every cost from ratepayers, plus a return, on time and on budget or not, and faces no competition.
ERCOT’s latest reserve-margin forecast goes negative in 2029 and 2030. To close that gap, ERCOT and the PUC have directed utilities to build a high-voltage backbone from West Texas to the I-35 corridor, which Smitherman puts at $33 billion, rising toward $40 to $50 billion by completion. Under the monopoly model, that cost lands on ratepayers.
On this week’s Energy Capital Podcast, Joshua Rhodes talks with Barry Smitherman, the only person to have chaired both the Public Utility Commission and the Railroad Commission of Texas and now chairman of Texans for Affordable Transmission, about bidding transmission out to non-incumbents under cost and timeline caps. He sat on both commissions during the CREZ buildout, Texas’s early-2000s program that moved West Texas wind to market, and saw competitive transmission work firsthand.
00:00 - Introduction & Texas Energy Landscape
05:31 - Permian Basin Load Growth and the 765 KV Lines
12:11 - Data Center Demand: Real vs. Speculative
14:09 - Texas Energy Fund and the Energy-Only Market
21:28 - How Texas Transmission Gets Built Today
23:13 - The Case for Competitive Transmission
31:46 - The Eastern Backbone and Cost Accountability
33:54 - Private Lines and Large Load Options
43:04 - Repealing SB 1938: The Path Inside ERCOT
44:34 - Getting Transmission Right: Future Tech and Landowners

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
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What batch zero settles and what it leaves open
1 jul· Energy Capital Podcast
Batch zero stops being theoretical on July 11. That is the day ERCOT’s rule for connecting large new customers takes effect. The new policy replaces a process that involved studying each giant load independently, then ordering restudies when new giant loads joined the queue, leaving projects stuck in a serial loop. Two prior episodes of this show traced how the new rule was designed. This one asks the people who connect the load what to fix before the next round.
Already projects are sitting in the interconnection queue as new regulatory deadlines loom. ERCOT figures show more than 445 gigawatts of large loads in the process, and the rule sorts them into base load, studied load, and excluded load. Developers have until July 10 and July 24 to meet certain filing deadlines, and the full batch study is targeted for early April. The policy also shifts more of the analysis from individual utilities onto ERCOT.
CenterPoint has been connecting large loads in Houston for decades. That experience drives a question the design phase mostly deferred: does a 75-megawatt cutoff for loads to participate in the program fit the manufacturing and industrial loads that move at the speed of business?
On this episode of the Energy Capital Podcast, Joshua Rhodes talks with Caitlin Smith, chair of ERCOT’s Technical Advisory Committee and senior vice president at Jupiter Power, and Jason Ryan, executive vice president of regulatory services and government affairs at CenterPoint Energy. Smith walks through how stakeholders developed the rules on a compressed timeline. Ryan presses the forward question of whether the 75-megawatt threshold and an annual batch process fit the loads Houston routinely connects.
Ryan’s concern is timing. When the batch becomes “the long pole in the tent,” he says, developers with real projects start to walk. The conversation works through:
* WL-PUN and PCLR, the withdrawal-limited private-use-network and provisional controllable-load resource programs ERCOT is repurposing to fit more load onto the current grid.
* The 75-megawatt cutoff, why Ryan questions whether mid-sized manufacturing loads belong in the batch at all, and the risk of projects sizing themselves at 74.9 to stay out.
* Non-firm service and reliability, how a load that agrees to curtail differs from the century-old obligation to serve, and what testing CenterPoint needs before it trusts the switch.
* What is permanent versus triage, which parts of batch zero survive into batch one and beyond as the Texas Legislature returns next year.
New to the batch zero mini-series? Start with Eric Goff on how batch zero took shape and Tiffany Wu on the mechanics.
How ERCOT sets the threshold and batch cadence will determine which loads get power on their own timeline and which wait for the next cycle.
Timestamps:
* 00:00 - Introductions: Caitlin Smith and Jason Ryan
* 02:43 - What Batch Zero is and why ERCOT needs it now
* 05:14 - Houston's diverse large loads, not just data centers
* 08:13 - Timeline: the July 11 effective date and key deadlines
* 10:44 - Base load, studied load, excluded load: winners and losers
* 12:55 - Inside TAC: compromises, new stakeholders, and fairness
* 16:10 - Does the queue mean a transmission build-out?
* 19:01 - The real number: CenterPoint's 40 to 50 GW prediction
* 23:18 - New constructs: WL-PUN and PCLR explained
* 28:13 - Non-firm service, reliability, and trusting curtailment
* 32:01 - Tracking success: what is permanent versus triage
* 36:07 - The 75-megawatt threshold and how often to run a batch
* 43:38 - Data centers, the final timeline, and what comes next
Resources:
People & Organizations
* Joshua Rhodes (LinkedIn)
* Webber Energy Group (Website - LinkedIn)
* IdeaSmiths (Website - LinkedIn)
* Caitlin Smith (LinkedIn)
* Jupiter Power (Website - LinkedIn)
* Jason Ryan (LinkedIn)
* CenterPoint Energy (Website - LinkedIn)
* ERCOT (Large Load Integration)
Company & Industry News
* ERCOT Again Revising Large Load Interconnection Process
Books & Articles Discussed
* Texas Senate Bill 6, 89th Legislature
* PGRR145, Batch Zero Process for Large Load Interconnections
Related Podcasts by Energy Capital
* Batch Zero, Explained with Tiffany Wu
* How Texas plans to serve ‘infinite demand’
* Open Season vs. Batch Zero with Travis Kavulla
Transcript:
Joshua Rhodes: Hey everyone, and welcome to another episode of the Energy Capital Podcast. I’m really excited today to have not one but two guests to talk about kind of what’s going on in the ERCOT Batch Zero process and kind of how that may continue to play out. So today on the podcast, we’ve got Caitlin Smith. Caitlin has a BA in econ from University of Texas and a JD Law from Penn State. She’s a policy consultant for CLEAResult for going on counsel at Jewell & Associates. She’s a vice president of AB Power Advisors and is currently the Senior Vice President for Federal and Regulatory Affairs at Jupiter Power, one of the largest pure play energy storage companies in the US. But she also is the current chair of ERCOT’s Technical Advisory Committee, the highest committee comprised of stakeholders, which makes recommendations to the ERCOT board. And that’s going to really come in handy today as we talk about one of the biggest policy shifts that’s working its way through the system. We also have Jason Ryan. Jason Ryan has his Bachelor’s of Business Administration and JD from the University of Texas. He was a Global Projects Associate at Baker Botts, managing partner at Ryan Glover LLP. And he’s also the information dominance warfare officer for the US Navy, which I kind of just want to stop and talk about that. If you can, you may not be able to talk about that. But now he’s the executive vice president of regulatory services and government affairs at CenterPoint Energy. Caitlin and Jason, welcome to the Energy Capital Podcast.
Jason Ryan: Thank you for having us.
Caitlin Smith: Thanks, Josh.
Joshua Rhodes: I’m really excited. So I’ve got two lawyers and two government affairs folks here today. So we’ll see how bad I do at managing this. Great. It’s gonna go great. But I know we’re under a bit of a time crunch, so we’ll get started because Caitlin, you’ve got a date for Elmo’s Got Moves. Is that right? Elmo’s Got The Moves. Okay.
Caitlin Smith: Almost got the moves. Almost got the moves. I’m seeing it tonight. I don’t know when this will air, but it’s in Austin Friday in San Antonio Sunday.
Joshua Rhodes: That’s some free advertisement there for almost got moves. But anyway, so we’ll go ahead and get started. And so the arc of this podcast is really I want to kind of catch up with what’s going on with the batch zero process. We’ve done two episodes, which we’ll link in the show notes, one with Eric Goff and one with Tiffany Wu, where we kind of looked at the overall kind of structure of the batch zero process and then with Tiffany got into kind of some of the details. But one of the things that it really was brought out, at least for my knowledge, during those podcasts, was We really had a framework for how things were going, but we hadn’t filled in all the details. And so I was just curious, Caitlin, if you could kind of refresh us on what batch zero is, where it stands, and why do we need it right now?
Caitlin Smith: Sure. And the impetus for me coming on, or one of them was Eric Goff said that the demand for load is infinite. I don’t believe it’s infinite. So I wanted to come on and correct. But maybe Jason thinks it’s infinite. So we could debate that. So batch zero, previously in ERCOT, there was not a uniform process for load interconnect. You know, before, I don’t know, six, seven years ago, nobody was really thinking about. Connecting these large loads when I was consulting, you know, we would have a call about a gigawatt hydrogen load or something that wanted to come online. This was starting in 2020. ERCOT hadn’t really heard about it or contemplated it at that point. So in the last five or six years, we had a major change to the system, which was ERCOT was actually seeing these applications for very large loads to connect and a lot of them What happened then was for the utilities, it was just either too much to process or they didn’t really know how to process it. Jason can correct me. And I think the other thing was there was not a uniform way amongst utilities on how to process these studies. And so they would study a load, another load would come on in their area, or maybe not even in their area. And ERCOT would say, No, we have to restudy. So people were getting caught in this infinite loop. So we are changing from that serialized process to a cluster or a batch, as we’re calling it, process where you can study a whole group of loads to make sure the system can accommodate the whole amount or the whole allocated amount of it at once and you can have a clear study. The other thing that does is really shift more responsibility to ERCOT. Before this was really each TSP. Was performing these studies and now there is a much larger ERCO component. And so batch zero is our way from transitioning from the status quo to the batch
Joshua Rhodes: process. Got it. And Jason, I guess the old process, like large loads were coming to transmission service providers like CenterPoint. Can you give us a feel for like when did the problem start to feel intractable in terms of like you going from having maybe one load at a time to dozens or hundreds of loads at a time? Can you give us a feel for when that started to come along to push this new process or to push talking about getting a new process?
Jason Ryan: Yeah, and so maybe I can answer it from a general perspective and then I can answer it from my company’s perspective. Sure. Because I think those timelines are a little bit different or the experiences are a little bit different. Between two years, you know, eighteen months, two years ago, I would say it started to become clear in many parts of ERCOT that something had to change. Okay. And yeah, we started talking about the batch process towards the end of last year and obviously the process has played out, got built this year and we now have more certainty on exactly what that looks like. And so I think the batch process has come together relatively quickly. Yeah. Once that problem was identified. I’ll speak to my company’s perspective. Yeah, in Houston we’ve been connecting large loads to the grid since before it was cool before everybody was talking about it. So we didn’t have the same challenges that you saw in other parts of the state. And in fact the current ERCOT study process for us continues to be very efficient, even through this transition into a batch way of doing things. Okay. Because like I said, we’ve had large customers on the grid down here in Houston for a long time, both transmission and distribution system, even we have large loads on our distribution system down here. The pace has obviously picked up. The size has expanded and gotten bigger. But for us, it’s business as usual at a faster pace. Okay.
Caitlin Smith: I think there’s a big some policy questions come into play for CenterPoint’s territory. I think a lot of those are things that need to be in the territory, right? Close to the shift channel or things that are kind of integral manufacturing businesses. That’s right. And so you also have these data centers or Bitcoin mines that come on maybe in other areas of the state that Some people maybe think don’t need to be there. Or maybe they can locate in a bunch of different places, right? They don’t necessarily need to be in the one spot. So I think not all of these loads have the same characterizations. And I think we tend to right now be solving for the data centers, which is something that’s new for us.
Jason Ryan: Yeah, I think that’s right. I’m glad you raised that too, Caitlin, because you we’ve got the largest petrochemical complex in the world here at Houston, the largest medical center on the planet, a significant amount of advanced manufacturing. And so it’s important that I share that view of a utility in a area that has a very diverse set of drivers of growth with large loads. We also have data centers, but I think you’re right. We shouldn’t over rotate on data centers and have unintended consequences to manufacturing jobs and energy and simply growth of populations that we have here in Houston.
Joshua Rhodes: totally. And I and I want to get to this new concept of well, a borrowed concept of the WL-PUN in terms of like getting through the batch zero process. CenterPoints obviously has connects a lot of the private use networks already. So you already have a lot of experience with that. I want to get to that in a little bit later, but first I want to like setting the timeline. So we’re recording this in kind of like late June. And at this point, the batch zero process has made it its way through TAC. It’s been approved by the ERCOT board. The Public Utility Commission accelerated its approval. Of batch zero and I think I got an email from ERCOT yesterday saying that the process is gonna start on July eleventh, if I’m correct, or something to that effect. Did I get that timerine right, Caitlin?
Caitlin Smith: Yes, that’s correct. I believe the rule becomes effective the eleventh, but there’s a lot of deadlines between the eleventh and the twenty fourth. Or the tenth and the twenty fourth.
Joshua Rhodes: Okay. Got it. All right. So whenever the rule becomes effective, well now that the batch zero is approved, what’s no longer theoretical here? Like what’s the process going to start to look like on July eleventh or maybe the twelfth the next day?
Caitlin Smith: That may be a better question for Jason. You know, I think a really different thing about this as opposed to some of the other policies stakeholders pass is you’re kind of immediately left with winners, kind of winners and losers. Or maybe not losers, but maybe you have to wait a little while. And so we have people who will be firm load in batch zero, right? They’re getting their studies are valid. They don’t need to be redone. They’re getting The allocation of everything they wanted, things that need to be studied in batch zero. So they’re good to go into batch zero. And then they will find out what their allocation is. And then we have people who are out of the batch who will have to wait till batch one. And so we know the criteria for that. I think by August, we will know who’s in those. The requirements are due. I think it’s mostly. The loads have to get it to the TSP by the tenth and then the TSP has to kind of affirm that to ERCOT by the twenty fourth. So we’ll know who those people are or I don’t know if that will be disclosed, but we’ll know the amount and they’ll know who they are in August.
Joshua Rhodes: So is the process, Jason, is it like are the large loads still gonna come to you first? Are they still gonna come to the TSPs first and then there’ll be a handoff to ERCOT or something like that for the big study? Yeah.
Caitlin Smith: Yeah.
Jason Ryan: That’s right. So, you know, what we’ve got now is we’ve got certainty over timeline and we’ve got certainty over requirements. In a couple of weeks you’ll know which loads are fall into what bucket. You’re either base load or your studied load, or you’re not either one. Then from there it’s the new part is ERCOT spap study, which we the utility would have provided the studies to ERCOT. ERCOT will continue to ask questions back and forth, right? We’ll provide answers, they’ll ask questions. That’s very typical even today. So the different thing is the batch study that Caitlin has laid out for us and you know, that is likely to take the balance of the year into next year. Early April is the target for the batch to be complete. And so there’s a lot of certainty now that we’ve got these rules in place, as opposed to January, February, March of this year when it was we were making the airplane as we were flying it. So a lot of uncertainty. You now have that certainty.
Caitlin Smith: Agree with that. We didn’t really start using the word batch, as Jason said, until the end of last year. And even though we did this on, I would say it was a very aggressive and kind of phenomenal timeline, it caused a lot of confusion, right? If you’re sitting there in January and you have some load projects and you just heard this word batch two months ago, but you’ve had loads in process for a couple of years. That really freaks you out, right? Even from January to today is sort of a long time to wait and have that certainty.
Joshua Rhodes: When we talked to Pablo Vegas on the podcast, I you know, he mentioned that this process was ongoing and we probably weren’t gonna get it exactly right, but it was gonna be basically building the plane kind of as we were going. I guess like the first step of that process, Caitlin, I guess went through TAC, right? Went through the technical advisory committee that you’re chairing, or at least that was kind of the process before it got handed off to the ERCOT board. And you had to take a pretty big contentious, you know, large load problem with a bunch of different stakeholders with a bunch of different wants and needs. And turn it into like a streamlined or a process. In that process, what do you felt like was the biggest compromise like y’all had to make or that everyone had to make?
Caitlin Smith: Yeah, I’ve been thinking about this because I think I may have used the word contentious or contested before. I don’t know that I would characterize this as extremely contentious, but I would characterize it as extremely important. Yeah. There was a lot of money on the line and extremely large, right? We’re sort of changing the entire system of load integration onto the grid. And we had a lot of new players. So as you said at the beginning, I chair what’s called the technical advisory committee. I can’t speak on behalf of a group here, but I have a lot of experience chairing that committee. And that committee is comprised of stakeholders, you know, from every segment, generators and Jason segment and municipals and everything. So I sit on the Committee for Jupiter Power. I happen to chair it. So I facilitate the meetings. These low developers have not been part of the process to date. So there was a lot of learning for them, right? They’re not even really voting members yet. And so they were sort of coming in from the outside to a process like this. So there’s a lot of learning. As I said, this was a little bit unusual and they’re kind of immediate commercial winners and losers. And so that gets contentious, but I don’t know necessarily that the policy things we discussed were contentious, but it was hard to differentiate sort of a policy cut versus what is a fairness issue. Is it appropriate to pick a winner and a loser? Because I think there were some issues that came up that were sort of fairness issues that people were very sympathetic to. You know, we talked a little bit with Jason already about the differences between the loads that an IOU might have, right? They might have a lot of data centers in their territory or they might have a lot of critical industry and manufacturing in their territory. And so I think there are a lot of specific to them things that load developers brought to the table. And it was sort of hard to kind of pick what needs to be in batch zero, what’s fair or not, that kind of thing.
Joshua Rhodes: Yeah, I think another word that maybe got overused a bit was when we were talking about the large load queue, we I started talking about it like there was a process. Like, you know, there was no real queue. It’s kind of more like a list, the thing, you know, and with the individual TSPs where things would kind of work their way through. That makes sense. I mean, it’s like if you’re staring down kind of the barrel of like, I think the latest number is like four hundred and forty-five gigawatts of large loads in the process and like ninety percent of that being data centers, it’s like it’s either create a process or just get paralyzed by the fact that you know, you can’t move forward. So it’s like, yeah, hats off to y’all for coming up with something so quick. That was pretty impressive. And I think the rest of the country is watching, particularly other other grids like maybe PJM and stuff. So Jason, in this process, ERCOT’s gonna allocate transmission capacity. It’s like, so we’re gonna go through this process, projects are gonna get either their full allocation or they’re gonna get like a staggered allocation. But that means that utilities actually have to build the stuff and connect. Given how much is going through the queue, is that gonna mean a like a substantial acceleration of transmission expansion in the next five or six years?
Jason Ryan: Well, not to connect to these batch zero loads, most likely. Okay. But you then have to replenish the capacity on the grid. Right. And so if you assume that we will continue to do batches, you know, if we run out of capacity on the current grid in batch zero or batch one, then obviously you have to build more capacity, which gets to maybe Eric’s point of the infinite growth. Whether it’s infinite or not, it certainly is relentless right now. And you see it’s a fair amount of transmission projects being constructed today with early twenty thirties in service dates. Yeah. I think you will continue to need that infrastructure for the future batches. But if you’re in batch zero and you want energy in twenty eight, twenty nine, you’re gonna have the existing grid that you’re counting on. There obviously will be some upgrades that are needed, but you’re not talking the hundreds of miles of transmission line. That’s gonna serve growth end of this decade, early next decade. You know, it is interesting. I think I mentioned this to you, that things will slow down for us so that it’s an unintended consequence of the batch process is that we won’t be able to move as quickly as we otherwise would. I think that will work itself out of the batch process over time, I suspect.
Joshua Rhodes: But the new classification framework, it creates base load, study load, and excluded load. Do we know how much is going to s at least start out in each one of these buckets? And do we have a feel for like what might make it out the other end of the batch zero process?
Caitlin Smith: I don’t have one I’m willing to commit to. I think we’ve heard various numbers from ERPA along the way, but sort of big ranges. And I think a big part of this process is for baseload and for studied load, there are requirements, eligibility requirements. So I think we know based on by all accounts ERCOD and the TSPs have been doing a really good job on their end of what studies are done to say who’s firm load, who studied load. But there are these criteria now for the loads to meet, right? Certain development criteria, a significant financial security posting. So I think we don’t know how many of those loads are going to meet those criteria or choose to meet those criteria. And if they get allocated less than what their project is, do they then drop out? I think what’s been hard about load and the data center load in particular is just the lack of historical context. So certainly for batch zero, we don’t have any historical precedent to say, well, about 80% of the loads, you know, end up hosting their financial security. And with the load forecast, we don’t have kind of historical data to say, well, this is a huge number, but about 60% of these aren’t real or 30% are real. We just don’t have that yet.
Joshua Rhodes: Yeah, I guess we had that for the generator interconnection queue. I remember doing a kind of a study, kind of a longitudinal, we could figure out what percentage would make it between to each stage and f at the other end. But yeah, like I said, I don’t think we even really had a queue. We called it a queue, but we didn’t really have one for large loads. Jason, are you able to offer up any numbers for CenterPoint? Like what numbers are y’all looking at when it comes to kind of what’s trying to get in bash zero at these tranches?
Jason Ryan: Yeah, so I you know, the number if you unpack what ERCOT released earlier this year informs my view of what the ultimate number will be. Okay. So of the more than four hundred gigawatt number, we were a little more than four gigawatts of that. And we have since then had additional load that I believe is real come into the batch process. So, you know, that is not Currently my number that I’m predicting. Okay. But yeah, if you want my entire queue, I can see how you can get to hundreds of gigawatts. But yeah, we meet literally every day to go through our list of potential customers. Yeah. And have only submitted the projects that we believe are real. It’s one of the reasons why our review with ERCOT continues to be relatively straightforward and on historic timelines, and we’re not getting bogged down with a lot of unreal projects. As an aside, I do think that to some extent this is a creature of the utilities making. I’m not being critical of the utilities in saying that because we didn’t have any tools to help figure out who’s real or not beyond just our judgment. Yeah. But we do have to exercise our judgment in terms of what we bring forward. And so that’s why you’re not seeing eye popping numbers out of the Houston area because we’re not turning in, you know, our entire queue. That said, I think that we’re about twenty five percent of ERCOT’s load down in Houston today. Yeah. If you assume that I’m growing at roughly the same pace as the rest of the state and that I have about the same amount of available capacity on the system today as other parts of the state, maybe I have a little bit more. I think that drives me to I think realistic number coming out of that zero base load is forty, fifty, something like that. Again, it depends on what the timeline for those projects are. If those projects are needing power in the twenty thirties, then sure, perhaps that’s not an issue. But that’s my prediction. By the time this airs, I’ll probably be proven super wrong. Because we’ll know. But you may be right. But that’s my prediction just based on what we think is real among the customers that we interact with. You know, the utilities are the closest to these customers. Right. We have to do our job. Of vetting these before we just throw them into the machine of ERCOT. And so I do think that I’m not critical of how we got to the batch process. I think it’s needed across the state, but I think when you throw around numbers that are hundreds of gigawatts, we know that that’s not going to happen in this decade, right? But like I said, the utilities were kind of without a process to make the decision on well, who does get to go forward and who doesn’t. So that’s why I think batch is good. But we also have to be more realistic on the numbers that we put out there.
Joshua Rhodes: Well Kaylin, hopefully that helps tack there to figure out kinda maybe what’s going on.
Caitlin Smith: to the number. I’m not figuring out the numbers.
Jason Ryan: Yep. Forty or fifty gigawatts of baseload growth is mind boggling. But I think the grid could actually digest that in a relatively modest period of time. Then we should talk at some point about potential unintended consequences of the batch process because I think there are some that are worth talking about, especially down in Houston where all of our growth is not data center growth.
Caitlin Smith: Is a lot. Yeah.
Joshua Rhodes: totally. Yeah, and we’ll get to that here in a little bit. I did want to so you’ve talked thrown around a few numbers. I mean I think all of them are kind of wags at this point. Yeah, maybe but okay, between zero and in less than infinity, which mathematically is still inf whatever you
Caitlin Smith: They’re not infinity. Should do Twitter game like Russell Gold used to do. You should have people
Joshua Rhodes: we have to bet the price of oil. Yeah, next year. Okay.
Caitlin Smith: Yep, you should have people bet the gigawatts and batch zero.
Joshua Rhodes: Okay, I didn’t do it for batch zero, but I think I did this years ago. But when the numbers were like 100 gigawatts, not 400 gigawatts. And so it’s I’ll be honest. The last study I was hoping for 500, just you know, why not? Okay, but there’s a couple different to get a lot of these large loads in there, ERCOT has come up with a couple new constructs. Well, not new. They’re borrowing existing constructs to kind of help some of these. There’s the PCLR, the provisional controllable load resource, which, you know, essentially will have some firm service, but if the grid can support it, might be able to go above that during certain times, but they may be curtailed down to their firm. And then kind of this WL-PUN, which is a withdrawal limited kind of borrowing from the private use network that we kind of already have in a lot of like the high industrial loads in the CenterPoint region in the Gulf Coast region. So Jason, starting with WL-PUN, can you kind of explain just how a private use network works, like how it interacts with ERCOT and kind of how y’all see that when you’re doing your planning?
Jason Ryan: Sure. So, you know, as you mentioned, it’s not maybe the acronym is new. The concept isn’t super new of having generation sided with load, either literally right next to it or in close proximity to it. And you know, you look at a lot of our historic large load customers, many of them have their own generation. And sometimes they are using that generation for their processes and sometimes they’re selling that back onto the group. So we’re super familiar down here with how that works and how that’s engineered and those customers are super familiar with the economics of it as well. And you know, as it relates to you know, the move to more of that, it doesn’t cause us great concern because of that historic precedent. And as you talk about the controllable load resource, it’s again not super different. Then what we already see, again, the acronyms may be different and maybe everybody doesn’t have the same kind of experience that we have with these large loads that, you know, for various reasons might have to change what they’re doing, change their use of the grid in the moment, or even put extra power back on the grid for a moment. We understand how to build the infrastructure for that and how to take that into account when we’re interconnecting on
Joshua Rhodes: And Caitlin, I is my understanding that some of the acronyms are kind of new, but we’re borrowing from existing constructs that exist. Is my understanding, and please correct me if I’m wrong, that a lot of these new larger loads were actually wanting a new construct, like a point of interconnection netting, like with generation kind of behind the meter. If I got that right or it got it partially right, can you explain like what they were asking for and kind of maybe why we didn’t want to tackle it here with the batch zero process?
Caitlin Smith: I think that’s right. I think these are old concepts. You know, certainly the private use network. CLR, same thing as what I was talking about in the beginning with these loads, us not having seen this really until six years ago. I think the concept of CLR existed, but it wasn’t really being used until these data centers, maybe, I don’t know, four or five years ago. It’s basically a software solution to be able to respond to the grid as fast as a or faster than a generator would be, right? You’re a SCADA-dispatchable load. So it’s still a new concept. And I’ll want Jason to weigh in. I think what we’re talking about maybe since SB6 is more a concept of non firm service. And so these loads say, well actually I don’t need firm service all the time because I’m a CLR. Or because I’m a generator and I’d actually prefer not to have firm service if it increases my speed to market. And I think that that is a new thing, right?
Jason Ryan: Yeah, certainly newer in the electric space. We’ve been doing that forever on the gas utility side of our business though, right? That is how large users of natural gas get connected to a system that has limited capacity only in certain times. Right? So think about in the wintertime when all of us at home are turning the heater on using natural gas, we’re using more capacity. Especially here in Texas, that’s a limited period of time. Right? There are a couple of days in the year. Where we’re consuming a lot of natural gas, that capacity is there. And on a normal day, you know, the other three hundred and sixty days of the year, that gas is available to large users, but they know that they’re curtailable in the tails of the probability curve and they curtail their usage of the system. So it’s perhaps being applied in a different way, but the concept has been around to consume energy for a hundred years, right?
Caitlin Smith: Yeah.
Joshua Rhodes: Yeah, no, totally. I guess like but I guess maybe for like the electricity sector, it is like a bit of a different, you’ve always kind of had the obligation to serve, like four or five nines, you know, reliability. Whether it’s like a PCLR or just a different reliability class of something, I know that’s something I didn’t wasn’t fully aware of that we were having that particular conversation outside of the PCLR construct here in ERCOT. I know they’re doing that in PJM. They’re talking about different levels of reliability. For different customer classes. But like, I guess, Jason, say you got a project going through the batch zero process, they’re signing up as a PCLR, a provisional controllable load resource. Do you trust them enough? I guess right now? Do we have the solutions in place? Like Caitlin said, CLRs have only been around for a little while, and I think mostly have been used by Bitcoin mines, if I’m correct. But what do you need to see to be able to trust that, okay, you need to go down to your hundred megawatt firm limit? I mean, what do you need to see to make sure that your system stays stable?
Jason Ryan: Yeah, so I think it’s fair to say that we’ll have to do a fair amount of testing to make sure that we understand how this works, what impact it may have on our system when we need it to work. Yeah. And to ensure that we engineer a solution that works in all kinds of scenarios, not knowing exactly what the scenario is that would require them to trigger that feature of their site. And so I have no doubt that we will be able to work through that. There are things to work through though, right? We don’t have all the answers as we’re sitting here today. Right. I trust that we will be able to figure out together with those customers. And I suspect the answer is gonna be that you test various scenarios along the way. Not super different, more complicated, but not super different than what we do today with our load management customers. We test it periodically to ensure that they’re able to drop their load on the timeframe that they need to. This is a bigger scale. But it’s not super different than what we do already with some of our other programs. Okay.
Joshua Rhodes: Are you also concerned about one of the things when we saw this happen in PJM a little while ago? So we had a large data center, like a gigawatt worth of like data center load, like trip offline. And that created a lot of like local instabilities in the system. And when I teach electricity markets, I generally used to brush past the frequency going too high because we have like too much generation and not enough demand. And like it’s easy to turn things off. Like this is no big deal. But apparently, maybe is a big deal. And so like as you’re seeing more of these. Larger loads, what are you thinking about in terms of making sure that, you know, that side of a trip is covered? Caitlin Smith (00:30:51) I think batteries can help with that, Josh. Just I love the plug there. That works great. It’s a softball right for you.
Jason Ryan: In addition to batteries, I think again, we’ve had to consider this for a long time down here in Houston. Now again, the so take a large L and G terminal tripping off or, you know, any other kind of re large refinery type load or even some of the large manufacturers that have a significant amount of load, especially if you’re talking on the distribution system, we will need to work through that as the size of these facilities start to become multiple gigawatts, not just a gigawatt. Yeah. And so it is a consideration that we’re working closely with our engineering teams and our customers to ensure that we think through all of those scenarios and think through how we need to design a system to withstand that. By the way, it’s not super different in concept to designing a system to take that into account in terms of loss of large generation. Right? Yeah. All of these large contingencies that happen, you have to plan for and design the system to withstand them.
Joshua Rhodes: Got it. So Caitlin, TAC has handed off like the batch zero process. It’s been again been voted. ERCOT board, public utility commission, it’s getting started. What are y’all looking to track between now and I guess kind of the fall of twenty twenty seven is when this process is like supposed to end up with a plan for the regional planning group to say, Okay, here go build this stuff. What are you tracking between now and then to know whether or not the batch zero process is working? What’s success or what’s an issue?
Caitlin Smith: That’s a good question. I haven’t really thought about what kind of reporting we’ll want. I’ll defer to the other members of TAC. I should have said at the beginning, this really started with ERCOT staff and with commission staff. We did our part as stakeholders. We did, I think, more than our partners as much as we could. This was a highly collaborative process, which is an achievement on a short timeline. But the commission staff and ERCOT staff to their credit has been very hands-on and involved. I don’t think that there’s a world in which we say this is a failure, right? It’s what we’re doing. We’re moving to a new process. I think it was necessary. We’ve harped on a couple of the Things that were maybe problems before. Maybe studies were working in some areas, but there’s sort of a lack of transparency, right? Because there was no process. There wasn’t a standard interconnection agreement for load. So you couldn’t go online and see what other people were doing. Okay. You couldn’t go to a dashboard anywhere and see what your status was or if ERCOT was gonna need a restudy because some other load came online. There’s just a lack of transparency that I think needed to be. Remedied. So I think we have a lot more transparency and certainty. I think there are things that we will need to change, but there are probably things we’ll continue to want to change. You know, after batch one and batch two, we sort of always keep working on our rules for the market and for interconnection.
Joshua Rhodes: Yeah, that was gonna be my next question. Is you know, batch zero has often been characterized as kind of a triage of this big large load list or queue or whatever you wanna call it, you know, trying to inject some discipline into this process and like get things moving and get a process. But like as batch zero is kind of a triage process, presumably as we’ve mentioned, there’ll be a batch one, a batch two, a batch three, a batch in, who knows how many of these batches we’ll need. Do you have a feel for like what parts of batch zero should be treated as permanent versus what part of it is just the triage right now, kind of the emergency scaffolding here?
Caitlin Smith: You know, I think it’s a really good framework. I think people are going to have more asks, right? You brought up two of the big ones, the WL Han and the PCLR. Yeah. I think people are going to have more asks on those things. I think more people will start to weigh in, right? The legislature’s back in town next year. I think we’ll hear more voices, as I mentioned before. One of the challenges, but it was Don’t get me wrong, it was very good they were participating, but these load of developers were new to the ERCOT process. Yeah. They’re not new anymore, right? So we’ll continue to hear from them, which I think is good. But with more time, we also know more. I think they’ll just be continue to be more and more asks as we do batch one, batch two, batch three.
Joshua Rhodes: Got it. So kind of similar question to you, Jason. Kind of like we’ve got batch zeros, we’re gonna build the plane as we’re going, but you know, before we get to batch one, like is there anything in particular that’s CenterPoint?
Caitlin Smith: We built the plane. It’s great.
Joshua Rhodes: Well maybe we’re putting seats in the plane. We have engines, maybe. We’re taking off. We haven’t painted it yet, maybe? Something like that.
Caitlin Smith: I think putting seats on it is right.
Jason Ryan: We’re about to have passengers, right? So yeah.
Joshua Rhodes: There are about
Caitlin Smith: But not infinite passengers, a finite amount.
Jason Ryan: That’s fair, yeah, yeah.
Joshua Rhodes: Not infinite passengers. But Jason, so like before batch one gets going, like is there anything in particular like the CenterPoint is already looking to like get or caught the change or fix or to alter?
Jason Ryan: So I think I’ll talk maybe conceptually the things that we should be asking. Yeah. I feel like we should be asking ourselves is seventy-five megawatts the right cutoff to go into a batch? And that’s gonna depend on the answer to the other kind of high level question I think we should ask ourselves. But it’s not uncommon for us to add a hundred megawatt customer down here, especially on the manufacturing side of things, and the timeline to win a project like that whether it’s a new customer or an expanding customer, is not going to line up well with the batch process as we see it today. Okay. What I mean by that is we’ve got customers that have options. They could build a manufacturing facil they could expand their Houston facility or they can expand their Mexico facility. They’ve got contracts and obligations with customers to make stuff. And they are going to make that stuff wherever they can get the power quickest. And they’re not gonna be gigawatts of manufacturing facilities, right? So that’s why I say maybe that seventy five needs to be looked at and have some kind of stratification for what is still large load, but I’m not sure it’s the large load that’s causing the need for the batch. Okay. So I think that’s a question. And then the second question is how often are you going to run a batch? Yeah. And you could design a batch process that works even for manufacturing expansion where you can move at their speed of business, but maybe not if it’s only once a year. Okay. You probably could if it was twice a year. And so as you get past batch zero and you know, one through end, yeah, can we at some point get to the point where the batch process is not the long pole in the tent. If I have available capacity today There is no batch process that’s the long pole in the tent. It’s getting the studies through ERCOT, which is relatively efficient for us down here, and then connecting to the customer at their speed. Right. When you have the batch process be the long pole in the tent, not whether I have the capacity to serve them. Mm-hmm. That’s where I think you have unintended economic development losses. In Texas, we don’t accept those outcomes. I am confident we will figure this out. But I think those are the questions that we have to ask ourselves post batch zero. What do we want this to look like forever? And I think those are the top two considerations from my symbol.
Caitlin Smith: Is there a solve for that?
Jason Ryan: I think that if you don’t want to change the seventy five megawatt threshold and if you don’t want to increase the frequency of the batches or don’t want to or can’t, then you know, perhaps there’s a separate track where there’s clearly available capacity. Yeah. So again, if I’ve got a hundred megawatt facility that they just wanna employ a couple thousand Houstonians, I’ve got the capacity, everybody agrees there’s the capacity. Yep. Why should they wait? For a batch to be run. So you could maybe create that kind of exception. I don’t like having an exception to a brand new process. Exception. That’s why I think that we have to ask ourselves, are we concerned about the hundred megawatt loads? Because if we’re not and we’re concerned about you have a super large loads, then perhaps you create some kind of different process going forward.
Caitlin Smith: That’s interesting. You know, the seventy five megawatts, I’ve been wondering about that. Like, do we see a bunch of seventy four point nine? Like you see the nine point nine generation.
Jason Ryan: Hundred percent. We are seeing it today. Yeah. In terms of the distribution interconnection requests that we’re getting. So I think you are absolutely going to see that because when the process becomes the long pole in the tent, business is gonna wanna move at their speed still. And if the only option to move at their speed is to stay below that cap, I think you’re gonna see a lot of projects that stay below that cap in order to get speed to power. That’s why I raise the question if Is that the right threshold for a longer process? And the answer could be yes, right? I just think we need to ask that.
Joshua Rhodes: Yeah, no, that’s fair. I think that’s one of the questions I was wanting to ask is like, okay, how many 74.9 megawatt data centers are you seeing? Cause I think this’ll be get more clear as kind of like the needs of AI actually play out. So 90% of these large loads are data centers. Gonna presume, given the CapEx spin, that most of this is AI at this point. And we presume we need big data centers for the training of these models to create the new near next frontier models. But for the inference, the actual my students cheating on their homework or, you know, everyone asking kind of how things go, like you don’t necessarily need gigawatt scale data centers kind of for that. And there’s a lot of people talking about we may we’ll start to see a lot more inference data centers that are smaller that are popping up. I may have misunderstood you, Jason, there bit. It sounded like you were arguing for the cap to go up. I’ve heard most people argue it to go down. Like the original was 25 megawatts or something, but it sounds like you’re arguing for the cap. To go up for the batch process. Is that what I’m hearing?
Jason Ryan: I mean that’s the question that I would like to have a debate on. And again, maybe this is the exact right number. Maybe it should go down. No. I think the unintended consequence though of a batch process that is not more frequent than once a year is not going to be consistent with non-data center large loads business plans. Yeah. Especially if they just want to expand an existing site. I think the unintended consequence is that we could lose out on those projects. That’s what I think we need to have a debate about. You know, again, it is not uncommon for us to have a 75 or 100 megawatt facility dropped into our system. We’re quite used to that. It could be unusual in other parts of the state that aren’t used to that kind of large industrial manufacturing load. And I would dare to say that I don’t think those are the ones that are causing the need for the batch. If all we had was a lot of hundred megawatt load, not that that’s small. Right. But I don’t think that we would be in the So why are we scooping them up as well? Right. And again, we may decide that we need to. And I’m always happy for that to be the answer once we have the debate. Yeah.
Caitlin Smith: You know, the lower number, I think it’s confusing, but I don’t know that it’s a real problem. I think ERCOT, FERC, and NERC all have different numbers for what is the large load. So I think that will get confusing. But what Jason raised about raising the megawatt threshold, I think maybe makes sense. The exception point is something I’ve been thinking about a lot because we can get to a n great outcome. We can pass something through TAC that everybody loves policy wise. But what if something critical to Houston’s economy wants to interconnect? You know, what if yeah the governor has a press release about a hyperscaler load? You know, what about all these things that are really critical to our economy? How are we going to accommodate those? Or how are we going to say, well, now that’s on hold for eighteen months, even though we got everybody excited about it or we need it in our city. And it’s just really hard, I think, to provide for exceptions. So maybe the idea of raising the threshold is one that could help with that.
Joshua Rhodes: Yeah, I mean, I I wonder how politically salient something just putting us a particular customer class in the batch system, like the customer class maybe that’s kind of like maybe causing the need for the batch system to come around. I mean, I know that other regions are also looking at separate, either like we were talking about earlier, a little bit reliability standards or different rate classes or different transmission cost allocation mechanisms and things like that for particularly data centers right now that are kind of driving a lot. Of this. And so maybe that’s some of the debates and things like that that we’ll be having. But Jason, I have heard that concern from like non-data center loads about, you know, being kind of caught up in this kind of whole process. But we’re going after the same thing, electricity. Right. So it’s like a tough process. I guess like one final question is we kind of touched on this a little bit, but like the timeline is is we’re going to start the rule takes effect mid July. And, you know, there’s a roughly a five step process kind of coming out the other end. Are we still expecting that we’ll be able to have transmission plan handed to RPG at the late to the end of 2027 that would allow for the output of the batch zero process to then start to take effect, which then won’t get built out for the next like five or six years, kind of depending on how it kind of lands.
Jason Ryan: You raise a good point that I also think raises the question of unintended consequences because the timeline that you just laid out is quite long. Right. And if you think about it, this process is designed in part, maybe in large part, but at least in part, to kind of weed out speculative projects. Yeah. The question you’re raising that talks about all the steps, even once you get past the July tenth and July 24th dates of this year, you’re going well into the end of next year for even more process. I think that customers that are the most real are going to have a problem with that timeline. Okay. Right? So if I am a real customer with contracts with other real customers to deliver something to them, whether I’m a data center or I’m building something, and my contract with that customer has a timeline associated with it. That the more process and longer the timeline to get power, the more you are weeding out the most real projects. And I think that’s the reason why once we get past batch zero, batch zero kind of is what it is. Yeah. But once we get past batch zero, we have to start asking some of these questions of how do I make sure that we maintain the reliability of our system and affordability. Of the rates of that system, but also move at the speed of business. And I am confident we’re going to figure that out. But I think these are the critical questions we have to start asking. Because again, if you start then saying, well, what’s the timeline for batch one? Mm-hmm. You’re talking about timeline for batch zero that goes through the remainder of next year. If I get asked by a customer, what’s the timeline for batch one, when do you think I can get power? It’s very uncertain right now. Okay. And I think the more That the utilities who are kind of on the front line with those customers every day have to shrug their shoulders and say, I don’t know. You know, the more we have the possibility of losing out on development. And that’s why I’m encouraged that ERCOT’s going to turn their attention very quickly to batch one so that we’re not in a phase of having to shrug our shoulders because we don’t know. And again, I have great confidence that we’re going to figure this out and be able to meet this moment. ERCOT, do you see? All the stakeholders have worked super hard to get to this point. I know we’re going to work super hard to understand batch one. And the more we can have certainty over that future batch and what it’s going to look like, the more we as the folks that are talking to the customers on the front line can exude that confidence that Texas is open for business. We want their business. We want the benefits to existing customers of this growth that’s going to reduce costs. Not add to them. Right. But we have to get started on batch one and I’m excited that we’re gonna start those conversations soon.
Joshua Rhodes: Well it sounds like you’ll be there to ask a lot of questions of Caitlin in the intact and as soon as we get this photo. Someone will be there. So it sounds like we need more podcasts later on about this process as Infinite Podcast. That’s exactly right. Caitlin and Jason, thank you for coming on the Energy Capital Podcast.
Caitlin Smith: Infinite podcast.
Jason Ryan: Thanks for having me.
Caitlin Smith: Thank you.
Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make better sense of how the energy system actually works, share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy and Power at texasenergyandpower.com. That’s where you’ll find every episode, every article, and our latest updates. We’re also on LinkedIn, X, and YouTube. Where we share clips, insights, and ongoing commentary on energy policy, markets, and the grid. Before we go, a quick note. The views expressed on this podcast are my own and do not represent the official positions of the University of Texas, IdeaSmiths, Austin Energy, or Columbia University. A big thanks to Nate Peavey, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

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Why PJM is looking at the Texas grid
24 jun· Energy Capital Podcast
ERCOT made a choice years ago that most of the country is now reconsidering. Texas runs an energy-only market with no capacity payments, connects generation through connect-and-manage, sorts out delivery in dispatch, and pushes interconnection risk onto developers. That design is a big part of why Texas has added generation faster than any other U.S. grid.
PJM, the operator for much of the eastern U.S., is now weighing whether to move in that direction. A white paper from the operator describes a shift from managing surplus to managing scarcity as data center demand outruns new supply. The paper lays out three pathways: long-term bilateral contracts, differential reliability standards for new loads, or an ERCOT-style tilt toward an energy and ancillary services market with a smaller role for capacity. The scale is large in both regions. ERCOT is now considering roughly 445 gigawatts of large-load interconnection requests against an 85-gigawatt system, while in PJM, one Dominion territory alone projects 70 gigawatts of new demand against a 24-gigawatt peak.
On this episode of the Energy Capital Podcast, Joshua Rhodes talks with Josephus Allmond, Virginia’s chief energy officer, about what separates the two grids and what PJM can take from the Texas model. Allmond points to ERCOT’s interconnection speed as the clearest lesson, given PJM’s projected 700 days from queue to agreement before construction even starts.
He also points to the state line, where borrowed fixes hit a wall. Virginia’s State Corporation Commission requires large customers to pay a generation charge for 14 years, even when a data center builds its own power. A load that sources its own generation, Allmond says, ends up “paying their own way and then turning around and paying Dominion.” The conversation works through:
* ERCOT versus PJM structure, energy-only and connect-and-manage against PJM’s capacity market and consensus-driven stakeholder process, and why one moves faster.
* PJM’s three pathways, and how the energy-market tilt is the one Allmond reads as closest to ERCOT.
* The large-load tools, controllable load resources, and behind-the-meter generation in Texas, and the Virginia charge that makes the same moves uneconomic.
* Interconnection speed, ERCOT’s developer-risk model against PJM’s roughly 700-day queue.
What PJM borrows from ERCOT, and what it refuses to give up, will shape how fast the East Coast grid can serve the load now lining up.
Timestamps
* 00:00 - Introduction and Guest Background
* 01:52 - Virginia’s Chief Energy Officer Role
* 04:15 - Data Center Alley and Virginia’s Hub Status
* 06:29 - ERCOT vs. PJM: Governance and Transmission
* 10:53 - PJM’s Shift from Surplus to Scarcity
* 19:29 - PJM’s Three Reform Paths
* 24:19 - Virginia’s Minimum Demand Charge Problem
* 29:36 - The Data Center Tax Exemption Fight
* 31:50 - Path C and the ERCOT Parallel
* 35:17 - What Has to Give: Allmond’s Closing Answer
Resources
People & Organizations
* Joshua Rhodes (LinkedIn)
* Webber Energy Group (Website - LinkedIn)
* IdeaSmiths (Website - LinkedIn)
* Micalah Spenrath (LinkedIn)
* Matt Boms (LinkedIn)
* Texas Advanced Energy Business Alliance (Website)
* Energy Capital (Website - LinkedIn - YouTube)
* Texas Energy & Power (Substack)
* Josephus Allmond (LinkedIn)
* Office of the Virginia Chief Energy Officer (Website)
* Southern Environmental Law Center (Website)
* PJM (Website)
* Monitoring Analytics — PJM Independent Market Monitor (Website)
* ERCOT (Website)
* FERC (Website)
* Dominion Energy (Website)
* Virginia State Corporation Commission (Website)
* Virginia Department of Energy (Website)
Books & Articles Discussed
* Powering Reliability Through Market Design — PJM White Paper (PDF)
* How Will Data Centers Pay for Power? — Travis Kavulla, American Affairs (Website)
Company & Industry News
* PJM floats options for capacity market overhaul (Utility Dive)
* Spanberger creates new cabinet position, appoints Allmond chief energy officer (Virginia Mercury)
Related Podcasts by Energy Capital
* How Texas Plans to Serve Infinite Demand, with Eric Goff (Texas Energy & Power)
* NRG’s Gigawatt VPP in Texas, with Travis Kavulla (Texas Energy & Power)
* Who Pays for Texas Grid Growth? — Roundtable Discussion (Texas Energy & Power)
* Who Pays for the New Grid, with Pablo Vegas (Texas Energy & Power)
Transcript
Joshua Rhodes: Hey everyone and welcome to another episode of the Energy Capital Podcast. I’m really excited to have Josephus Almonds on today to get us out of our comfort zone a little bit here in Texas and ERCOT and talk a little bit about PJM, kind of some of the things that are happening in other grids. PJM is one of the other grids that is experiencing large amounts of load growth, particularly from things like data centers. Texas is no stranger to that. And so it might be useful to figure out kind of how other regions are doing it, approaching it, and maybe we can
Cross-collaborate on some of those. So Josephus got his JD from Duke, where he did a couple of stints at BakerBots and Kirkland and Ellis. And then he was an attorney with the Southern Environmental Law Center, where I should say that we worked together on Dominion’s IRP a couple years ago, intervening in that. But recently was named CEO, should say Chief Energy Officer, although this may be one of the few podcasts where Chief Energy Officer might get you more kudos than Chief Executive Officer for sub.
But Josephus was recently named Chief Energy Officer from Governor Spanberger. Josephus Alman. Welcome to the Energy Capital Podcast.
Josephus Allmond: Yeah. Thank you so much for having me, Josh. It’s good to see you.
Joshua Rhodes: Yeah, it’s good to see you too. So first I gotta ask, how’s dad life treating ya?
Josephus Allmond: It’s great. We actually just had his first birthday party this past Saturday. So awesome. We went all out with a clues theme, had paw prints all over the house, a bunch of decorations. We had my in laws were in town from California and some of her aunts from Texas. So full house, lots of friends and family over and a blue smash cake that Josephus really loved.
Joshua Rhodes: Nice. That’s awesome. You know, Aiden’s only just about a month ahead there. I remember when I when we were working together when you were at SELC and I was like, hey, I’m not gonna be able to make this like super important meeting that I said I’d be at because it’s literally on the day of my son’s birth. I think you told me that y’all were also expecting. So that’s awesome. We’re right in there together. Neither of us are probably getting any sleep at all. So we’ll see where this goes.
Let’s start out with the job title. So Virginia now has a chief energy officer. So what was the problem that the Commonwealth was trying to solve with creating that role? And what does success look like for you there?
Josephus Allmond: Yeah. So historically we’ve got a Virginia Department of Energy, used to be known as the Department of Mines Minerals and Energy. And so they do all of the permitting for mines for oil and gas, mostly out in Southwest Virginia, and recently started to do more of the state energy office stuff as Virginia created the RPS and started its clean energy journey six years ago with the Clean Economy Act. So that’s sort of one agency within the Secretary of Commerce and Trade, but
We all know that energy sort of touches everything. And so the governor really wanted to create a more nimble cabinet level position that could work with the different secretariats on energy issues as they pop up and as they’re impacting the different secretariats. And so the Virginia Department of Energy is still under the Secretariat of Commerce and Trade and we’re working really closely together. They’re doing some modeling to inform an energy plan that we gotta put out later this year.
But I’ve really got sort of the ability to work not only with them, but with the Secretary of Labor when it comes to apprenticeship requirements or the Secretary of Education when it comes to apprenticeship programs in K twelve or energy savings performance contracting, as we’re looking at trying to get more efficient government buildings to even working with our Secretary of Public Safety and thinking about
Can we develop some distributed solar facilities at our jails and prisons and incorporate some training there? So really trying to bring energy to the forefront in sort of everything that we’re doing. And in today’s world where affordability is sort of dominating the conversation, having that position at a cabinet level, I think really just elevates the importance of it and puts more of a high profile on it, just given how much it sort of seeps into everything that we’re doing.
Joshua Rhodes: Yeah, totally. I mean, particularly on the affordability front with all the load growth and with electricity and data centers. I mean, Virginia’s no no stranger to data centers. You’re kind of the original area. Can you talk about data center alley? Where is that located and what’s the importance of that region and the energy that it consumes?
Josephus Allmond: Yeah, so we are sort of the data center capital of the world. Loudoun County is home to Data Center Alley up in Northern Virginia. And there are a number of reasons why I think that emerged as a hub. We’ve got a great fiber network already built out, the proximity to DC for the three letter agencies and their needs. And then our tax exemption is something that we’ve had on the books for a really long time and gives an exemption for
Basically all of the equipment that you purchase for your data center facility, that’s going back, you know, fifteen years at this point. And the way that that exemption has played out over time is that once a data center sort of obtains that exemption in a specific county, everything else that they do in that county is rolled up into that same memorandum of understanding. And so even if, you know, the subsequent facilities don’t hit the original investment and jobs numbers to get you that initial exemption.
you can still sort of roll new facilities into that. And so that’s why we’ve sort of seen that clustering effect in Northern Virginia, but even now in some other counties where they’ve started to develop.
Joshua Rhodes: Okay, I’d never heard that part. That makes a lot of sense. I mean, on Texas has some economic development tax codes and things like that for abatements and things. Well, we won’t get down into the weeds of those necessarily. I remember hearing something like seventy percent of the world’s energy traffic goes through Northern Virginia and data center alley. I think Texas is trying to give Virginia a run for its money when it comes to data center capital of the world. I think we’ve, you know, got hundreds of gigawatts of data centers that are trying to connect. I haven’t I haven’t believed these numbers in a long time.
Around here. I don’t know that anyone believes load forecasts right now. But I mean a lot of the focus of this podcast is really around electricity and we’re deeply steeped in ERCOT. Can you explain for an audience like what the biggest structural differences as you see in between like ERCOT and PJM are?
Josephus Allmond: Yeah. So I think the the biggest one that comes up to me is sort of the governance. And so PGA app has a stakeholder consensus process that can really slow things down. And so they’ve got to reach a certain threshold of votes to get to consensus on any given issue before that even goes to the board for consideration. And then more often than not, you also need FERC approval after that. Whereas less FERC oversight with ERCOT.
And then for transmission planning, Texas had the competitive renewable energy zones a long time ago that really laid the foundation for transmission. PJM does transmission, I say more of an incremental fashion through the RTEP process, regional transmission expansion process that sort of looks to build out infrastructure over the next several years, but not quite as comprehensive as sort of that competitive renewable energy zone process from Texas.
Joshua Rhodes: Yeah, we’ve built a lot of transmission down there. You mentioned the Kres lines. We’ve got another tranche of lines coming, the Permian Reliability Project or the STEP lines, as it were, building some really big 765 transmission lines, some really even higher even higher voltage ones. They’re working their way through the siding process right now, which, you know, is a whole another regulatory kind of firms. Whenever you’re, you know, moving that linear infrastructure. You mentioned like a pretty
detailed like consensus. I talked to a consultant named Eric Goff on a couple of podcasts ago and ERCOT used to have a stronger consensus. He said ERCOT used to have a stronger consensus mechanism and then post URI it became more of kind of an advisory body. It became less consensus or less binding. If the consensus is slowing things down, is there any look in how that might change in PJM or anything like that?
Josephus Allmond: Yeah, I think that’s one of the big issues is sort of how slow things are moving and also how fast they need to be moving going forward with the supply-demand gap that PJM is projecting, these sort of long, drawn out stakeholder processes might be good in an environment with no load growth where careful planning can sort of take its time. But when we need to be making really significant overhauls of the capacity market generally.
It’s good to see how that stakeholder process can sort of lead to that result in any amount of time that sort of solves the problem that we’re we’re needing to solve.
Joshua Rhodes: One of the biggest differences also between like ERCOD and other regions like PJM is, you know, this kind of multi-state governance situation you got going on. There’s a lot more people in the room when it comes to making decisions, a lot more people maybe represented in the room. There were some recent statements out of FERC saying that maybe BJM was a little bit ungovernable when it comes to that. Is that that’s all I’ve heard really of that? But I mean, is that making any waves around in your part of the world?
Josephus Allmond: It’s something that I’ve heard more and more. I was at an energy conference last week and heard someone talk about maybe it makes sense to have some of the regulated states, you know, Virginia, West Virginia, North Carolina sort of form a PJM South. Not say I’m endorsing that idea, but that’s something that’s coming to the forefront as I’ve grown into this role sort of appreciating the difference between regulated and unregulated states within PJM.
and sort of the different positions they take and how that affects, you know, how they view the actions that P J M’s taking, because certain things that P J M’s thinking about has a much larger impact on a state like Pennsylvania than it does on a regulated state like Virginia.
Joshua Rhodes: Can you pull that thread a little bit? Like when you’ve got all these folks in the room, are disagreements like falling along those lines, the regulated versus the unbundled or kind of deregulated states? What’s the tension there?
Josephus Allmond: Yeah. So I’ll I’ll just give an example and we’ve actually hopped into the PGM Governors Collaborative, which is my counterparts in other PGM states that have been thinking about this problem for over a year now. And this goes back to sort of Governor Shapiro driving for the cost cap a while back and their continued engagement. But I think this comes up a lot when we’re talking about how we’re doing resource adequacy versus how we’re doing bilateral contracts to sort of hedge long term.
And especially with some recent decisions that have come out of our State Corporation Commission that make that bilateral contracting a little bit more difficult for large load customers.
Joshua Rhodes: Got it. I want to get to some of the Virginia specific pieces in a a little bit later. But one of the things, like when we were going back and forth about this, trying to get you on the podcast, is you sent me a white paper that PJM had just put out, I think just a couple days before when we were having that conversation. The white paper basically, you know, says you’re moving from managing a surplus to managing scarcity. I remember back in the early days of Energy Twitter making charts showing how big PJM’s reserve margins were compared to everybody else’s.
And being like, isn’t that silly? So for moving from, you know, managing surplus to managing scarcity, do you think the core is of the issue is that PJM’s market design is broken or is it just demand is moving too fast? What caused them to want to write this white paper?
Josephus Allmond: Yeah, I think the problem sort of inherently is that new demand is just coming faster than new capacity can beat it in PJM. And the markets were designed to reach lowest cost units in an era of declining load, and they’re now unable to incentivize sort of high capital investment that we need, the growing demand. But I want to put a caveat on that and sort of going back to something you mentioned about the Texas load, it’s like I think before we even start.
This discussion, we’ve got to get a much more informed view on the load forecast and the confidence that we have in that load forecast. The numbers coming out of, you know, just Dominions, DOM LC alone is 70 gigawatts of new capacity from large loads coming online in the next couple of decades. Our system peak right now is 24 gigawatts. And so the idea that we’re gonna triple our capacity over the next couple of decades.
The independent market monitor was on a panel at a conference I was at last week and called the numbers fantasy. And I largely agree. I mean, if we sort of rewind to Virginia back in 2018 when Mark Christie was still on the State Corporation Commission here, he basically ordered Dominion to stop using their own loop forecasts and to start using PJMs because for years and years they had consistently over forecasted demand at about a five percent annual clip.
And so now they’ve shifted to using the PJM load forecast, but the wrinkle there is that the only thing that’s driving up the PJM forecast are the sort of supplemental forecasts that they get from individual utilities that then they do not vet. So the utilities who have a history over forecasting demand have been feeding these supplemental forecasts to PJM that indicate really serious growth without sort of
Any check on the back end by PJM to see if there’s duplication across those loads. Something that I know we talked about going back to that IRP proceedings, this I idea of phantom load where you’ve got developers putting in bits in a number of jurisdictions trying to see where they can get the best deal. And if you don’t really have a process to suss that out, then you’ve got really overstated loads.
Josephus Allmond: Coming at you from a number of utility jurisdictions. And I think that’s exactly what PJM is dealing with right now. And so if you’re thinking about hitting that aggregate demand number that really has never been investigated, then I think that’s partially driving the because we’re trying to solve a problem that is really unsolvable. There’s no way we’re going to build an additional 45 gigawatt of moon generation in the DOM zone here. So
I think that’s step one is like really investigating, interrogating the forecasts and trying to figure out what’s real there.
Joshua Rhodes: Yeah, sounds like Dom’s trying to add a basically a Texas word about eighty five gigawatts, but getting kind of close there. Yeah, I mean, I think this is a conversation that’s being had across the country. And I’ve had a couple discussions with folks around, you know, ERCOT is setting up this dispatch zero process where they’re gonna try to figure out of all this load, which is like four hundred and forty-five gigawatts of like large load right now, again on an eighty-five and a half gigawatt system, they’re trying to figure out
We’re gonna try to shove all this into a study, but we’re gonna have some inclusion criteria of who makes it into the study. And you gotta get in the big study if you’re gonna get, you know, any megawatts out of the other end. It’s one thing they’re trying to figure out, okay, do you have like land controlled? Do you already order equipment? They’re trying to figure out what’s real, kind of what’s not. And Texas is working from SB6, which also forces these developers to say if they’ve got the same project in multiple different areas.
I recently talked to Travis Cavula who had a piece in American affairs where he was talking about, well, we should just like set this up to the highest bidder. It’s basically as like whoever can all the transmission folks get out there and say, Okay, we’ll build this much and then you start bidding that out to the highest bidder, and then you’d really find like you’d only get as much as you can support and then you’d find what it was worth. Is there any movement over there in terms of any of those two approaches or kind of what’s the current thinking?
Josephus Allmond: Yeah, it’s sort of the open season contract that he was discussing at.
Joshua Rhodes: Yeah. Well there’s a couple and there’s like four open season, fronting capital, transmission service agreements and then like BYOG. There’s a few things, but his main one was that open season. Yeah.
Josephus Allmond: Yeah, I’ve talked to Travis quite a bit. He was someone I reached out to first to try and get a handle on some of these PJM issues and just talk to some really smart folks. In Virginia, and I would I haven’t looked at the orders from other states that have like gone down the line of establishing large load tariffs. There’s sort of a structural problem that really is preventing these large loads from going out and doing something like that and bidding, trying to build out their own generation. Because with sort of the take of
or pay requirements that the SEC established. Basically you’ve got to pay 60% of your minimum generation for 14 years. That applies even if you go out as a large load customer and acquire your own capacity to match what you’re bringing online. And so you’ve got a situation where if data centers wanted to go out and provide for their own needs, like we’re seeing from the White House Protection Pledge or calls across the country really for data centers paying their fair share.
they would sort of be paying their own way and then turning around and paying Dominion sixty percent of that minimum generation charge over those fourteen years. And so not quite a double payment, but about a hundred and sixty percent for the energy that you would need normally.
Joshua Rhodes: Yeah. And my understanding is that like if you were doing that and like the utility went out and bought generation to cover that, or, you know, built generation to cover that. And then something happened to the data center, the risk there would be on the remaining ratepayers, right? That’s the big issue, right? Is like these data centers, they’re going out and we’re getting our own stuff, but we’re having to make this other side payment to get more capacity. But that risk is on the rate payer, not the shareholder from like the first round. Is that right?
Josephus Allmond: Yeah. So they’re really insulated from the utility is really insulated from risk there because they’ve got these sacred pay arrangements. And so that’s sort of the worst case scenario, right? Data center show up and that’s sort of put back on the rest of the rate base. The commission did do some things about allowing for sort of transfer capacity and so if that were to happen, maybe they could line up another
you know, large load customer that was in line for them to sort of assume that as opposed to it being socialized. And so I think they’ve done some things to mitigate against that. But yeah, that’s sort of the overall structure here.
Joshua Rhodes: Got it. I mean, that was definitely one of the things Travis was suggesting in that kind of open season that it would be a transferable thing. It’s like, you know, if you get it and then you decide, I don’t want to build my data center or whatever, you can sell that right, which then makes it easier to go out and get the right from the get-go and maybe even drives the cost up because there’s, you know, not as much risk of, you know, if you don’t end up getting what you want and dropping out and losing everything, which is the current way it’s happening in ERCOT, really. It’s like
You know, if you make it into the process and you make it to the third out of five step and decide to drop out, it’s kind of use it or lose it. But anyways, we’ll see kind of where we go from there. So I mentioned the PJM white paper. It kind of laid out three different pathways for PJM, you know, path A, path B, path C. Would you be able to give like a high level overview? Like these potentially could be some pretty major changes for PJM. Like what are they suggesting are some pathways forward here?
Josephus Allmond: Yeah. So path A is really looking to lean more on long term bilateral contracts to secure most of the supply and then the capacity market would sort of be a residual, not as much of an emphasis on it. Path B is what they’re calling sort of differential reliability, and so differing standards of reliability for new loads that are coming to town. Path C is what I’ve thought of as more of the ERCOT.
approach, which is moving more to an energy and ancillary services market with a a really small role for the capacity market to play in the background. So at a high level, those are sort of the three routes that they’ve laid out. They don’t really pick one that they think is the preferred way forward. It’s just sort of a menu of options.
Joshua Rhodes: Got it. Yeah. So Path A is kind of like a cum hedged model. It’s like, if I understand it, it’s like load is procuring that capacity, right? It’s not going necessarily through or as much going through like the centralized, but you’re, you know, the bilateral part there. It’s funny, is like Texas actually considered something like this post winter storm Uri. We called it the man, there were so many acronyms at that point. It was like the load side energy reliability obligation. I I think I butchered that.
I always called it LASO, even though that’s not the acronym. L S E R O or something like that. This is when we were flirting with all kinds of capacity mechanisms, we decided to go with none of Do you think path A would be a practical fix, or is it just shifting risk around from investors to consumers?
Josephus Allmond: Yeah, I think it’s more of the latter and also an issue, especially in Virginia, because of that minimum generation demand charge. And so because you’re asking sort of the loads to come edge, you’d be putting the loads in a position where they would be going out and doing this bilateral contracting, but then still have that requirement back to the utility. And so I imagine the the large loads, especially in Virginia, where a lot of them are located.
aren’t fans of sort of path A, especially with that minimum demand charge hanging over them.
Joshua Rhodes: Yeah, got it. And so path B gets kind of this like this differential path B is this differential reliability. I mean, essentially utilities that kind of had this obligation to serve at the highest levels, say three nines or five nines, you know, nine nine point nine nine nine percent reliability. Is how would path B work out in terms of like when would the reliability suffer here if it needed to be?
Josephus Allmond: Yeah. I think it would be sort of to the extent that they didn’t bring the capacity that they needed. And so they would be curtailed in those sort of peak hours where capacity wasn’t sufficient to serve them. This also I think has a problem, especially in Virginia, because, you know, if you put large loads in Virginia in that position, not many of them are gonna go out and hedge. And so they’re gonna be exposed to this sort of differential.
reliability where they would be curtailed, I would think, more than large loads elsewhere in PJM where they would be more free to contract and secure their own capacity.
Joshua Rhodes: Are you saying path B would be applied differently in different states, just based on kind of what the state level regulatory structure is like?
Josephus Allmond: Yeah. And you see sort of PJM encouraging states to get their cost allocation in order. And I think this applies more to like the deregulated states who haven’t really done this, but sort of in anticipation of this trying to figure out how they’re going to allocate those costs.
Joshua Rhodes: There’s a couple ERCOP parallels in here. One of the things we’re doing in the batch zero process is like we’re potentially only giving large loads like a set amount of offtake. Like say a large load wants to be 300 megawatts, and we say, well, we’ll only give you a hundred megawatts. But if you sign up to be this controllable load resource, it’s a PCLR, during times when the grid’s got capacity, we’ll let you go above that. But like if we ever need to, we might shut you back down to that one hundred.
Or there’s a second pathway, which is kind of a BYOG like pathway where it’s like you can only withdraw or inject a certain amount, like say a hundred megawatts. But if you have a three hundred megawatt data center, then you can bring your own two hundred megawatts of generation and that’s going to be fully kind of behind the system. So I mean, I guess it kind of depends on where you define like that level of reliability. I guess in Texas we’re trying to define it at that point of interconnection where we’re saying we’ll only give you this, but you can do
what you want with your own generation. Is there discussions around that? Like how is behind the meter gener is there behind the meter generation allowed and kind of how is that working out for large loads in the region?
Josephus Allmond: Yeah. So I think it depends on which state you’re in. And so behind the meter gen is allowed. And I think Dominions had sort of a self generation tariff on the books for thirty, forty years that some old manufacturers have used to do their own coal or gas on site. So it is an option at just again, frustrated by that minimum demand charge because even with that on site generation.
Powering your own needs, you’re still on the hook to Dominion, basically for 60% of that generation cost. So at least in Virginia, a lot of these PJM proposals sort of run into roadblocks that weren’t designed as such by our state corporation commission, but just as the way they’re functioning, I don’t think is going to allow large loads in Virginia to participate in these PJM options in the way that they’re envisioning them, which which seems to be more
Tailored towards the deregulated states.
Joshua Rhodes: Okay. So that sounds like a policy issue. I mean o obviously the policy issue. Electricity’s physically the the physics are the same everywhere. Is that something that has any room to wiggle or would that be a pretty tough mountain to climb?
Josephus Allmond: You know, so the SCC established that in their most recent order in the rate case. I don’t think they’re gonna sort of be upsetting that decision. And so there is always the option to affect change through legislation, which would also be difficult just politically speaking, because utilities also have lobbyists at the General Assembly and also trying to protect their interests. And so they see that minimum demand charge as something that protects
the rest of their customers in the event that data centers don’t show up. And so I think there’s some room, but also some discussion I think needed to be had about, okay, if we are going to allow large loads to go and shop, what’s the standard that we’re subjecting them to in the event that they have to come back to the utility? Cause I think that’s a concern that has merit from the utilities. They don’t want to end up in a situation where half of the data center load in their territory goes and
you know, shops and then a big chunk of that all of a sudden decides that they want to come back to utility service, that puts the utility in a tough spot where they’ve got to come up with a bunch of generation or capacity, very short amount of time. We just shortened the notice return window. It used to be five years that you had to give the utility heads up that you were coming back from being a shopper. Now it’s just 18 months. And so
What happens if that large load decides to shop and then wants to come back? Are they sort of subjected to some sort of curtailable schedule like PJM’s considering here? I think that’s something fair to think about. But I think there’s gotta be some trade offs if we’re thinking about sort of unraveling that minimum demand charge, making it easier for large loads to shop. How are we protecting customers in the event that a lot of them come back to the system after a excursion in retail shopping?
Joshua Rhodes: Got it. And if you don’t want to opine on other states in the general vicinity, I think West Virginia is setting up something or like some micro gridding. It’s funny to call them micro grid. These things are massive hundreds of megawatts. But setting aside these kind of special tariffs and things like that for some of these large loads, I think to make it easier is just right across the border. Is that do you think that might pull some data centers over that away or some large loads, I should say?
Josephus Allmond: They’re certainly trying their hardest to pull data centers over there. Yeah, I think there’s a lot of reasons why Virginia has become the pub that it is. And so a lot of that’s the fiber that’s been built out. I question whether West Virginia has some of that infrastructure ready to serve these data centers in a sort of to the extent that they need it, right? That’s something a concern that I hear when we’re, you know, looking to diversify geographically where these data centers are located, even within Virginia.
Once you get out to sort of the southwest corner of the state, your broadband is more sparse, there’s less fiber, even though there’s excess capacity in the APCO system down there, those other factors sort of lead data centers to deciding, maybe this isn’t the right place for me.
Joshua Rhodes: Yeah, totally. I mean, I I think one of the biggest aha moments or whatever I had recently was looking at okay, where is fiber located? And everyone said, Okay, well fiber’s located along we built the fiber optic network in the nineteen seventies around kind of where we had existing rights of ways. And that was where the interstate highways were, which was determined from where we’d be originally built the railroads. You gotta go like, so why are there so many data centers, you know, in Northern Virginia or in Texas, it’s in Dallas.
There’s this huge convergence of all of these much older rights of ways that we had the ability to build this infrastructure and so we did. Which really fascinating. We touched a little bit on like, okay, some policy change, things like that. I mean, I guess you don’t have to opine on this one if you don’t want to either, but I mean, it seems like data centers don’t have that many political friends right now or don’t have that much popular support, I should say. Like there’s a lot of groundswell like kind of opposition. So
As I was asking that question, I’m like, Maybe no one wants to even try to spend any political capital there right now. We’re starting to see that in Texas, but I’m sure that’s happening around the rest of the country too.
Josephus Allmond: Yeah, it’s sort of central to the budget fight that we’ve got here in Virginia. Typically the General Assembly sends the governor a budget and that’s finalized by the end of the General Assembly session. We’re still waiting to get a budget deal done in part because of a difference on what to do about the data center tax exemption. And so Democrats in the Senate here have proposed just eliminating it entirely. I think that comes out to about one point six billion dollars, just eliminating that.
exemption entirely. The governor is not there. And so it’s not just a tax exemption that these data centers have. It’s a tax exemption and then a subsequent memorandum of understanding that they’ve entered into with the state of the Commonwealth of Virginia. And so there’s two sort of categories of this. The sort of lower investment in jobs level gets you an exemption out to twenty thirty five. And then there’s a much higher investment threshold this year.
If you’re bringing $70 billion of investment to Virginia and a higher jobs threshold, you get the exemption out to twenty fifty. To date, Amazon is the only one that has entered into an MOU pursuant to that higher investment threshold, but that was really recently. And so the Commonwealth entered into a contract with Amazon to get them to expend that capital here in Virginia. The governor is really worried about the signal that sends to business if the Commonwealth just decides
one legislative session that we’re going to get rid of tax exemptions that have been long fought and negotiated for. And so as opposed to that sort of more rash approach of just ripping the rug out from under the data center industry, we sort of see an opportunity here to really affect some change in the way that data centers are operating by potentially attaching some conditions to that tax exemption and saying that
Hey, on energy, on water, on backup generators. You’ve got to do some things differently to be able to be in a position to keep that exemption. So that’s actually a big wedge issue that’s sort of holding up the budget here in Virginia. And I’m hoping we can get to a good place with colleagues in the Senate and the House of Delegates here.
Joshua Rhodes: That makes sense. Quickly get to pass C, so there’s a third option or a third pathway in this white paper. It shifts more revenue recovery into energy and ancillary services, but I think it it still kind of keeps the capacity market kind of in there. Is that PJM inching towards like an ERCOP structure or would it be a fundamentally different kind of hybrid model there?
Josephus Allmond: I think it’s a little bit of both. So it’s kind of getting trying to get more like ERCOT is, but keeping a capacity market in a way that ERCOT, as you mentioned earlier, has sort of explicitly decided against. So maybe that’s just a little bit of the organizational inertia and wanting to cling to the capacity market. But, you know, I think energy is already sort of the largest component of the wholesale cost of electricity here. And so moving to this energy only framework probably provides greater
benefit to intermittent resources and limited duration resources, which wouldn’t be bad from our perspective. Getting more solar and storage online. That was a big focus of the governors in the most recent legislative session is really expanding the amount of storage that our law calls for. And so now Dominion is tasked with getting 16 gigawatts of short duration storage over the next 20 years, four gigawatts of long duration storage. And so I think these
more of an energy only approach actually benefits those resources in a way that the current system just doesn’t.
Joshua Rhodes: Yeah, I mean one of the things that like absent the capacity market, if you’re not necessarily chasing a capacity payment or have to show deliverability during time, you can get closer to the thing we do in Texas called connect and manage, where we’re like, we’ll connect a lot of generation and we’ll just like manage it through the dispatch. Generation is mostly a competitive, you know, aspect in ERCOT. And so that shifts that risk to the developer, but it’s one of the things that has allowed us to move much quicker. And so as we’re having these conversations around flexibility, ERCOT has some
institutional inertia on that. Like we’ve got some institutional inertia on be like, okay, we’ll flex you because we’ll have to. And we’re trying to figure out if we can do that with load. I do see that as one of the issues in terms of if you’ve got that capacity kind of payment or that capacity market issue that makes it quite a bit harder. I don’t know, it’s always been weird to me like how you can give like solar in the region like a six percent effective load carrying capacity, but then require full deliverability in the studies. To me that makes no sense. Like that’s something that could be easily done.
very quickly because they don’t even care about capacity, not getting paid for capacity. Am I getting that wrong?
Josephus Allmond: No, I mean like at six percent ELCC, I don’t know, put the question to developers. Like, do you want full deliverability at the six percent capacity value? Are you willing to take the risk of being curtailed at certain times? PJM has this energy resource interconnection service option that they say is sort of similar to connect and manage, but I think when you dig into it, they’re still treating that E risk more akin to how you
traditionally study generators. And so there’s a lot more contingencies in place. And it ends up being almost as much of a headache as sort of going through the full study process. And so streamlining that process and really simplifying it to something that resembles ERCOT’s process more closely, I think would really allow the developers to make that choice. Because right now they look at the E-Ris option in PJM and they say, that’s almost as much work as doing the full study.
Why don’t I just do the full study and I’ll get the six percent, right?
Joshua Rhodes: Yeah, no, totally. I know we’ve talked about that before in different roles. So kinda last question. So if Virginia wants affordable power, data center growth, reliability, clean energy at the same time, like is there anything here that’s gotta give, like speed of load connection, who pays for transmission, tolerance for curtailment, or you know, the old assumption that every customer gets the same, you know, reliability product? Is anything gonna have to give to move quickly as you said, like the Commonwealth needs to move?
Josephus Allmond: Yeah, I think the thing to me that could make the biggest dent is really simplifying that ERIS process and making it something more akin to what you see in ERCOT. Because even with the sort of updates to the interconnection process, PGM’s still projecting almost seven hundred days from getting in line to getting your interconnection agreement. You’ve got another several years for construction after that. And so if we’re really trying to solve this near term
capacity shortfall, we should be trying to get as many resources online as quickly as we can. And so borrowing some of the things that have led to record deployments in Texas, I think is a really smart idea. And so, you know, maybe that involves looking at past C and looking at that option more seriously going forward. But that to me sticks out as one of the sort of biggest things that we could do to really get at this problem in a concrete way.
Joshua Rhodes: Yeah, absolutely. I mean, we’re not perfect and you know, we’re not doing it perfect, but we’re down here trying to figure it out. So like ask us anything, we’ll we’ll try to help out as as as much as we can. Josephus Salman, thanks for coming on the Energy Capital Podcast.
Josephus Allmond: Yeah. Thanks so much for having me, Josh. Good to see you. Absolutely.
Joshua Rhodes: Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make better sense of how the energy system actually works, share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy Empower at Texas Energy Empower.com. That’s where you’ll find every episode, every article, and our latest updates. We’re also on LinkedIn, X, and YouTube.
where we share clips, insights, and ongoing commentary on energy policy, markets, and the grid. Before we go, a quick note. The views expressed on this podcast are my own and do not represent the official positions of the University of Texas, Idea Smith, Austin Energy, or Columbia University. A big thanks to Nate PV, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
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Inside the PUC's Cost-Allocation Overhaul with PUC Chairman Gleeson
10 jun· Energy Capital Podcast
Texas spent five years rebuilding its electrical grid based on the lessons of Winter Storm Uri. Now regulators face a harder question: who pays for the surge of large new customers trying to connect?
The projections for electricity demand run far above what will actually get built, and hyperscalers want to power their data centers within 18 months, a pace much faster than the three-to-five years large industrial loads once took. ERCOT has run out of spare capacity, and the cost of building more lands squarely on residential and small-business customers if the projected load never arrives. The state’s answer is to make new load prove its intention and viability to build and pay for the grid it requires.
On this episode of the Energy Capital Podcast, Matt Boms talks with Thomas Gleeson, chairman of the Public Utility Commission of Texas, the regulator who must write the rules to make that principle work. Gleeson’s North Star is SB6, the 2025 law that rewrote how large loads connect. He explains the trade-offs behind the decisions commissioners are weighing, from financial gates that screen speculative projects to a December deadline to overhaul who pays for transmission.
Gleeson returns over and over again to the demand side, arguing that “the megawatt we don’t use is just as important as the megawatt that we generate.” The conversation works through:
* Batch zero, ERCOT’s first round of committing firm capacity and the financial security and fee requirements, recently set at $50,000 per megawatt and meant to screen out projects that are purely speculative.
* 4CP to 12CP, the proposed overhaul of transmission cost allocation, with a minimum demand charge so that large customers cannot zero-out their shares by curtailing at a few predicted peaks.
* The reliability standard, a new three-part measure of how often, how long, and how large an outage Texas will tolerate.
* Demand-side resources, the aggregated distributed energy resource pilot, virtual power plants and a $1.8 billion backup-power program funded through the Texas Energy Fund.
How Gleeson and the commission write these rules will set how much cost current ratepayers must shoulder and which projects ever get built.
Timestamps
* 00:00 - Introduction and Chairman Gleeson’s PUC background
* 00:48 - A new chapter for the Texas grid: from Uri reform to implementation
* 04:19 - The core problem: interconnection capacity and speculative vs. real load
* 08:28 - SB6 and ERCOT’s Batch Zero process
* 15:10 - Large-load ride-through and performance standards
* 19:18 - The reliability standard and load modeling assumptions
* 23:39 - The ADER pilot: lessons and whether to scale it
* 25:01 - Virtual power plants and the NRG proof of concept
* 27:29 - Standardizing DER interconnection across the state
* 29:20 - The backup power package: resilience for critical facilities
* 32:33 - From 4CP to 12CP: reallocating transmission costs
* 39:30 - Closing: taking a breath, and what the era will be remembered for
Resources
People & Organizations
* Matt Boms (LinkedIn)
* Texas Advanced Energy Business Alliance (Website - LinkedIn)
* Thomas Gleeson (PUCT Biography)
* Public Utility Commission of Texas (Website)
* Other Orgs
* ERCOT (Website)
* ADER Pilot Project (Overview)
* Batch Study Process for Large Loads (Overview)
* Texas Energy Fund (PUCT Program Page)
Company & Industry News
* Texas PUC Approves TEF Backup Power Program (RTO Insider)
* ERCOT’s Batch Zero Proposal and What It Means for Large-Load Projects in Texas (Seyfarth)
* ERCOT’s Proposed Batch Zero Process: What Developers Need to Know (Foley & Lardner)
Related Podcasts by Energy Capital
* How Texas Decides Which Data Centers Connect (Tiffany Wu) (Listen)
* How Will Data Centers Pay for Power? (Travis Kavulla) (Listen)
Related Posts by Texas Energy & Power
* How Texas Decides Which Data Centers Connect (Read)
* Price the Grid or Keep Rationing (Read)
Transcript
Matt Boms: Today, we’re very pleased to welcome back Chairman Thomas Gleeson of the Public Utility Commission of Texas. Chairman Gleeson was appointed to the commission and named Chairman by Governor Abbott in January 2024, but his service to the state of Texas goes back much further than that. Over more than 15 years at the PUC, he has served in a number of important leadership roles, including Executive Director, Chief Operating Officer, Director of Finance Administration, and Fiscal Project Manager. That gives him an unusually deep understanding of the agency, the Texas electric market, and the work required to turn major policy decisions into real world implementation. Chairman Gleeson, thank you for your years of service to Texas and welcome back to the Energy Capital Podcast.
Chairman Gleeson: Absolutely. Thank you for that introduction. Looking forward to the discussion.
Matt Boms: Awesome. Well, thank you for your time. We know that you’re really busy. This interview happens in the middle of a million conversations that are happening right now around energy in Texas. We’re gonna try to hit on as many as we can. And you know, just to kind of set this up, Texas is growing fast. The commission is trying to separate real projects from speculative ones, protect existing customers, use flexibility and customer side resources more efficiently. And build a grid that can support economic development without sacrificing reliability or affordability. So I want to start with, you know, since you last came on the podcast and Doug had you on, it feels like the Texas grid conversation has shifted a little bit from post-Uri reforms and market design and broad policy ideas into a very serious implementation phase. So, from your perspective, do you see this as a new chapter for the Texas grid?
Chairman Gleeson: Yeah, I absolutely do. I think you’re right. I think the reforms coming out of Winter Storm Uri, for the most part, have all been implemented. And I think the legislature, the governor, citizens are all happy with the reforms that we’ve put in place. You know, the grid has been tested a few times since Winter Storm Uri and has performed really well. So I think, yeah, the conversation has definitely now shifted to large loads, data centers, hyperscalers, how we’re going to incorporate those reliably and safely onto the grid. And then really, who’s going to pay for it? And I think as we move forward from today onward, who’s gonna pay for all of this is gonna take f you know, primary focus for everybody.
Matt Boms: Yeah, absolutely. And I think Texas has always been a growth state if we look back to our our history. But does this load growth moment feel different to you?
Chairman Gleeson: It feels a lot different. And the main reason for that is the speed at which it’s changing. You know, historically when large loads have come onto the system, it’s taken three, four, five years for those facilities to need their power. When you’re talking about hyperscalers, these companies want power sometimes within eighteen months to be fully operational. So the speed at which we’re being asked to make decisions that impact the economy is going quicker and having a much, you know, more difficult effect on us coming up with the right decisions in a short amount of time.
Matt Boms: And, you know, given all those decisions that need to be made and looking down, you know, over the next few years, what are two or three things that you think Texas absolutely has to get right here moving forward?
Chairman Gleeson: Yeah. So the first part again is who’s going to pay for this? We want economic development in Texas. You know, as the governor says, Texas is open for business, but we want to make sure that residential rate payers and small businesses are not bearing the brunt of all the costs that are going to come along with hyperscalers moving to the state. So I think figuring out how to effectively and efficiently allocate costs to those that are actually putting those costs on the system is going to be the number one thing that we do. Number two, and this will always be an issue coming out of Winter Storm Uri, I think, for for the rest of time for Texas and the ERCOT market. How do we ensure that we’re getting the right resource mix on the grid for generation resources? You know, we continue to see a proliferation of batteries and renewables on the grid, particularly solar. And that’s great for the state. You know, those resources keep prices down. When it comes to batteries and solar, you know, they help us a lot in the winter during our two peaks and the summer during our afternoon peak. But I think there’s a growing concern that we need more what we would consider baseload twenty four by seven generation, mostly thinking about gas generation. And so continuing to have discussions about how we incent that type of generation to come onto the grid, I think will continue to be really important for the state.
Matt Boms: Absolutely. And for listeners who are not living inside of ERCOT stakeholder meetings, that we certainly have listeners that do live inside of those meetings, but plenty of listeners that are new to the energy space. What is the actual problem that Texas is trying to solve here with large loads and data centers? Just for a beginner who is, you know, hearing this for the first time.
Chairman Gleeson: Yeah. So historically the grid has always had a lot of excess capacity. So the transmission system has capacity. A new customer can come and interconnect and not have a problem getting the service that they need. But because of the size of these facilities and the speed at which they are looking to interconnect into the grid, we’ve run out of existing capacity on the system. And so what was happening over the last say six to eight months was large loads were looking to interconnect and not being able to, because as soon as they would have a study validating. Their ability to interconnect, another load would come in behind them at relatively the same point on the grid, thereby invalidating their approval. And so that has been the problem we’ve been trying to solve for, like I said, the last eight or so months, how we can ensure that once these companies have an interconnection agreement that they are ready to move forward, they know that capacity will be there to serve them so that they can make proper business decisions.
Matt Boms: Yeah, if that’s the death spiral of the different pieces moving around, it’s just hard from the grid operator’s perspective, right? It’s how do you plan for a grid where with all those moving pieces?
Chairman Gleeson: Yeah, it’s and how you ensure that all of these loads can be interconnected reliably. Cause I think that is always going to be the key from ERCOT’s point of view is we want the economic development here, but we have to ensure it is paramount that reliability is the focus. And so it’s making sure we can interconnect all of these loads and loads in a reliable fashion. Yep.
Matt Boms: Yeah, for sure. And on reliability, I think Texas has earned a lot of credit across the country for how far we’ve come since Winter Storm Uri. And that’s that’s another podcast. And I encourage folks to check out the previous podcast that you’ve done with us because there’s a lot of good conversation there. But so for considering the load growth that’s coming, how should Texans think about the difference between projected load growth and load that’s actually ready to interconnect?
Chairman Gleeson: Yeah, so the projections are extremely high. And what we know is all of that load will not actually come here. A lot of it is speculative. But what we’re trying to endeavor to do right now is figure out what of that load is actually real. And that’s important for two main reasons that touch on the first two points I made. One, knowing what load is real ensures that we build a system, a transmission grid that meets those needs without overbuilding. You don’t want to overbuild the system to its needs. And because the main reason you don’t want to overbuild is those costs have to be borne by someone. If those loads, those large loads, don’t actually show up, most likely those costs will be borne by residential and small commercial businesses. That’s not an outcome that we want. Secondly, if the load is real, you will see an increase in what we would call wholesale electric prices, the forward markets for those prices. That should provide the incentive for new gas generation and other sources of generation to locate within ERCOT. So as we are approaching the need for more baseload generation, hopefully those future signals will allow those companies to make the business decision to locate those generation resources in the state, ensuring we have enough power for all residents and all businesses in Texas. Yeah.
Matt Boms: You keep mentioning this idea of keeping the grid affordable and reliable for Texans. You’re in this really tricky spot where you want to keep Texas open for major economic development, but still make sure that existing customers aren’t paying for speculative projects or stranded infrastructure, right?
Chairman Gleeson: That’s correct. And so what we’ve tried to do is come up as we look at interconnecting large loads with gating issues and thresholds for those issues that ensure if a project moves forward that it is real because those companies are going to have to put up real money in order to stay in the process to get interconnected. We’re hopeful that those gating issues and thresholds will accomplish that. But as always, as we’ve shown since Winter Storm Uri, if for some reason it’s not accomplishing its goal, we will analyze and iterate to make sure we get the answer right.
Matt Boms: Yeah, fix it on the fly. Right. Yeah. Okay. Well, I’m going to move into batch zero in a second here. But if you’re a large load customer in ERCOT, what do you need to demonstrate before the system starts planning major infrastructure around it?
Chairman Gleeson: Yeah. So the first thing you have to show is that you have the financial wherewithal to actually bring your project to fruition and energize it. So we’ve put in gating issues around the amount of credit that you have to put up that you show you have access to in order to move forward. The second major key element of that is site control. We want to make sure that these companies have an idea of where they’re gonna locate, that they have control over that site. So when they do get the green light to energize, they can move quickly. Because that’s the whole thing here. Once we have a plan. That is actionable. We need to ensure that the plan is being implemented in a way that those companies have certainty they can come here, but we also have certainty that they plan to be here for a long time. Cause again, we don’t want to overbuild this grid putting those costs on others. And so those are the main two things that we’re looking to accomplish that.
Matt Boms: Yep. And I think that leads us into Senate Bill Six, which passed the legislature last year. In plain English, what does SB six try to solve?
Chairman Gleeson: Tries to solve for the proliferation of large loads in this state and how to make sure we bring them online in a managed way. You know, again, post-2023’s legislative session, this was not a topic of discussion. And then probably around October of 2023, this became a hot topic through last session. This was about all we talked about. And so Senate Bill Six is really an attempt to make sure that we have guardrails around the processes we implement to make sure that. No one is harmed by these large loads coming here, but Texas is open for business. We want to ensure that economic development continues to see a pathway to Texas, but that the residents can be assured that they’re not causing these costs, so they will not be on the hook for them.
Matt Boms: Absolutely. Yeah. And there’s a reason right with why the private sector loves coming to Texas to build their project. So we had the batch zero process past the board of directors meeting this week. How does ERCOT’s batch zero proposal fit into this whole SB six implementation phase?
Chairman Gleeson: Yeah, it fits really well because for the first time we’re going to start committing capacity to these large load projects. And so that accomplishes two things. One, it gives certainty to the businesses that if they plan to come here and they can meet all of our gating issues, that once they interconnect, they will get the electricity that they need in order to fully energize in the state. So that is a huge thing. But secondly, it provides a path to ensure that all the loads coming here are real and not speculative. Because the financial gates in order to get into this process are really high, $50,000 per megawatt. And you have to be real, you have to be willing to put that skin in the game in order to move forward. And so I think it really helps ensure that the projects coming here are real. They’re not speculative. And so residents can really have a sense of certainty that we’re not overbuilding, that we’re not doing anything for businesses who don’t actually plan to locate in Texas.
Matt Boms: Right. Yeah. And that and that’s a huge point because that’s not true in other parts of the country as far as, you know, guaranteeing to some of these companies that we will have the energy that they need. And in a quick fashion, because Texas the you know, that’s the hallmark of our state is speed, right? Speed to pass.
Chairman Gleeson: That’s right. And and the other thing that this process does is we will marry this up with our transmission planning process. And so even if a company maybe doesn’t get the power on the rate that it wishes, it there we will have a six-year build-out of transmission that allows that company to know within that six year period, there will be transmission bill to ensure they are fully energized. And so that is a big selling point of this process and for these businesses locating in the state.
Matt Boms: And can you hammer that out for us? So the old approach was more of a one off, right? Where a large customer worked with the transmission provider, the studies would happen project by project, and then things move from there. But why is that no longer enough?
Chairman Gleeson: Yeah, so that was changed maybe a little over a year ago to where now ERCOT has a really, you know, front and center focus on this and they’re involved in that process. And again, previously we had a lot of capacity on the system. So it really wasn’t that big of a deal now because there is no excess capacity on the system. We have to make sure that ERCOT knows where these loads are locating, that they can do an integrated transmission planning process to ensure that they can ultimately provide the services that they need. They work with the transmission companies to ensure that they have what they need to build out the plan within six years. And we think six years is an appropriate amount of time to have all of the transmission upgrades and new builds done in order to energize these types of facilities.
Matt Boms: Right. And six years in the national context is still very fast, right? Even though some of these data centers are looking to interconnect tomorrow.
Chairman Gleeson: That’s right. And it’s a maximum of six years for full deliverability. So the hope is it can be done even quicker.
Matt Boms: So what from the PUC perspective, what does the Commission need from batch zero in order for it to be useful?
Chairman Gleeson: Yeah. So the first thing we need is we need to make sure that the number that gets out of batch zero is something that is actionable. So the idea behind, you know, there are two parts of batch zero, one that we’re calling kind of base, which those companies that get into that bucket, they’re going to get the energy they need on the ramp rate, on the schedule that they that they have requested. Then you’re going to have batch zero studied. Those projects will be a part of the first process to have that six year plan associated with them. To get fully energized. And so the first goal of batch zero, the first really need of it is what comes out of this, the number of projects in megawatts is actionable first within batch zero base, something that can be actionable today. And then within that studied or allocated piece, something that can be actionable with additional transmission upgrades over the next six years.
Matt Boms: Great. So we’re gonna move on from batch zero in a second. Sorry to grill you on. This is just a hot topic and everyone wants to know the details. So last question this would be how do you avoid both mistakes over building for projects that never show up, but also underbuilding for growth that is real?
Chairman Gleeson: Yeah. So, you know, the first thing is getting a better sense of what’s real comes from asking questions to the companies to make sure that they really have an intention to be here. Again, those gating issues around what comes in. But then we do a load forecast and we continue to try to find ways to refine that process to ask the right questions to make sure the numbers in that load forecast are a true reflection of projects that look to locate here in the near and midterm. So I think as we continue to go through those rules and look at what needs to be done to refine that process will accomplish that goal. Cause you’re right, you know, there is always the one that gets talked about the most is overbuilding, but businesses won’t come here if we underbuild. And so we have to ensure that we’re not doing that either because we want these businesses to come here, to come here in a way that is managed and doesn’t hurt reliability. And and in all the conversations I’ve had with these hyperscalers looking to locate here, they are bought in on this idea.
Matt Boms: Okay, that’s great. There’s been a lot of discussion about large loads riding through temporary grid disturbances. I know that’s a major concern from ERCOT, rather than instantly tripping offline. So how should we think about that specific reliability issue in this broad context of
Chairman Gleeson: As you see a continued increase in large loads, I think this becomes a bigger problem. I’m glad ERCOT has looked at addressing this issue. You know, the board approved this action going forward at the last board meeting a few days ago. It’ll now come to the PUC. I will say that there have been some issues brought up around the jurisdiction for URCO to require this of folks. That’ll work its way through some type of litigation potentially. So I don’t want to speak to that. But I think as a as a broad policy goal, it’s a really good goal because we have to ensure that one of these facilities tripping offline does not lead to a cascading blackout on the system. You know, I think the feds that FERC is going to tackle this as well at a national level. But as we’ve seen coming out of Winter Storm Uri and our weatherization efforts, we have the ability in ERCOT to address these issues first before the feds even, you know, take a look at this. So that’s what we’re going to try to do. We’re going to try to solve this problem. And hopefully that’s a model that can then be used and socialized around the country.
Matt Boms: Right. And which again gives us a competitive advantage over other states because we’re able to move so quickly and you know, we’re really the first state to start figuring out these tough questions.
Chairman Gleeson: That’s right. And because we have a very robust stakeholder process, my hope is always that what comes out of that is something that everyone can live with that is actionable and achieves its intended goal. And I think that’s what we’ll find coming out of this discussion as well. Yeah, I agree.
Matt Boms: So the basic principle, if I’m hearing you correctly, is that very large customers need to behave differently than ordinary load because they can affect the bulk system.
Chairman Gleeson: That’s right, because their singular impact or failure causes a much larger problem than it previously has. So we have to ensure that whatever the behavior of that of that facility is, the system is not impaired and cannot recover from it.
Matt Boms: Yeah. So how do you from your position, how do you create performance standards that protect the grid without prescribing one narrow technical design for every data center, every large campus?
Chairman Gleeson: Yeah. So I think what you try to do is be adaptable, right? And we’ve talked about this a lot over the last five years since Winter Storm Uri. The idea that we set a policy goal here, ride through, you know, events, and then work with the stakeholders to come up with a plan that achieves that goal while understanding that most of these facilities are not going to be exactly situated the same way. So allowing for the nuanced differences between these facilities, coming up with a regulatory framework for compliance. That works for everybody. And that’s and that’s what we’ve done here. Again, to the jurisdictional issue, we’ll have to kind of work that out. But I think the policy goal is a good one. And I think the plan that was approved by the ERCOT board is one that is actionable and we can move forward with.
Matt Boms: Yep. And though so for some of these large loads that say that they’re flexible, right? According to whether it’s true or not, this that’s what some large loads are telling us. How important is it that the rules and telemetry and all those incentives actually make that flexibility real?
Chairman Gleeson: It’s extremely important. I think for us to solve this, you know, we talk a lot about building transmission. But I think the other two key components are going to be bringing generation for these facilities to bring their own generation and then allowing for them to be flexible. So they will have those attributes. Like you said, that’s what we’re hearing from a lot of these facilities that they can be flexible. I will say what flexibility means is maybe not always the exact same facility to facility, but allowing that type of behavior to benefit the grid. Is really something that has to be a part of this solution because, you know, most of the time we’re not worried about the reliability of the grid. 99% of the time, the grid has plenty of capacity online. We don’t have an issue with resource adequacy. We don’t have an issue with ride-through issues. But there are going to be those times that we do having loads that are flexible that can react to the real world kind of operational situations on the grid and do that in a way that benefits the state as a whole. Is really something we need to try to find a way to incent and this is just one of those ways. Yep.
Matt Boms: That’s huge. On the reliability issue, we have something here in Texas called the reliability standard. You know, how would you explain that to someone who follows Texas energy issues but may not live in the modeling detail?
Chairman Gleeson: Yeah. So, you know, a reliability standard very colloquially is really a way of saying how often are you okay with the power going out with having some type of system outage? And so previously we had, you know, a measure of that that wasn’t really written in stone, but we were always trying to have a certain level of reserves on the grid. Now we’re doing something completely different. We’ve adopted a three-prong approach to looking at when there is an outage, how long is that outage? How often does it happen in a given year? And then what is the magnitude? Magnitude meaning how many megawatts actually have to be taken offline. And so this three-pronged approach, I think, really gives us a chance to have a holistic view of the system and what we and the citizens of Texas are willing to live with. And then what comes out of that is really simple, hopefully, I’ll say hopefully, is, you know, if we are short of the standard that we’ve selected, then we have options to provide incentives to either bring more generation. Increase flexibility of existing and future loads on the system in order to achieve that reliability standard. But the key here is we will do this on a cost basis. We’ll look at the costs and the benefits of any changes that we make. We have to ensure that the benefits outweigh the costs. We’re never going to put additional costs on the system that don’t achieve the outcomes we’re looking for. So that will be a key as we look to what the outcomes of that reliability standard are and then ultimately what the commission looks to do to achieve our reliability needs. Mm-hmm.
Matt Boms: And the load assumptions there matter so much, right? And how and can you expand on that and how we model out the reliability?
Chairman Gleeson: Yeah. So, you know, if you take the load numbers that have, you know, been talked about, say 410, you know, gigawatts, obviously trying to solve for that type of system is different than say 150 gigs. To your point, it’s very important to understand what the real load number is going to be in 2029. And that determines what the outcomes are and what levers we may have to pull to achieve that level of reliability. And so as we look to the batching process that we were discussing, you know, right now. ERCOT has out for comment two ways to maybe adjust their load forecast. One is kind of looking at history and how much of this load has come on in a given year and using that historical look back. The other, which I would give preference to right now, as I’m sitting here, is to look at what gets into the batch, how many megawatts, because those should be actionable, right? Those are going to be real projects that have a transmission plan around them. So I think solving for that for reliability standard makes a lot of sense, is incongruent. Across all different aspects of the ERCOT planning process.
Matt Boms: Absolutely. And is there a risk that we treat reliability as a supply side problem without looking at the demand side?
Chairman Gleeson: I think there is. I think we tend to think of it as a supply side problem, but I think you’re dead on. You know, there are demand solutions that can help us achieve this because again, the megawatt we don’t use is just as important as the megawatt that we generate. And so I think you have to attack it from both sides.
Matt Boms: Okay. That’s great. The market itself, when you look at the market we have here in Texas, which is robust, how should it value resources that could help during those hours where the grid is most stressed? So whether that could be generation, but it could also be storage, demand response, flexible load, right? Like how how are those tools working in the market?
Chairman Gleeson: Yeah, in kind of the value hierarchy of what we’re doing, those should be valued extremely high. And again, the way that this market is set up is we should put out as the commission and at ERCOT what we’re solving for and then allow the private sector to find a way to meet that need. And that’s what we’re gonna do here as well. So you’re right. We can look at supply side issues. Do we need to change incentives in order for more, say, gas generation to come on? Do we need to look at kind of how batteries are functioning and do we need To look at incentives for more long duration batteries? Do we need to empower residential customers to participate in demand response programs? Do we need to look at our incentives for the in current industrial demand response programs and do those need to be changed? So you have to address it comprehensively, holistically, in order to achieve this outcome because one thing is not going to fix everything.
Matt Boms: We have the ADER pilot here in Texas. So I’m really curious to hear your perspective on what we have learned so far. I mean, obviously there’s a cap on it, so it’s you know, it’s limited in scope, but what are the key lessons learned from your perspective?
Chairman Gleeson: Yeah. So the first thing we’ve learned from our ADER pilot is there is a lot there that we can win on, I think, which is key. That was the goal of the pilot was to see how much participation could we get and really was the juice worth the squeeze? And I think it’s clear coming out of the pilot that the juice is worth the squeeze. The question now is how do you scale it appropriately? Right. And so again, I think the more you can look To these different types of answers to this problem. ADER, distributed energy resources is going to be a big key for this. We just have to figure out the right policies to incent the behavior we’re looking for. You know, we’ve been working for, you know, five years on all these different issues. ADER is one that, you know, I think really needs to be brought more to the forefront and have more oxygen in the room for that type of discussion because it can’t just be bringing on new dispatchable generationly, because we don’t know if we can get prices to a point. To incent that type of behavior. I think the ADER pilot project has shown there’s a lot of desire for this in Texas. We have a lot of private companies looking for how to aggregate distributed energy resources. We should provide them with the incentives to do that and then we all reap the benefits.
Matt Boms: No question. And and there are virtual power plants now that exist outside of the ADER program, right? So I’m hoping you can unpack that for us. The one that comes to mind is the NRG renew home VPP that they’re working on, which they say will reach a gigawatt, you know, in a relatively short amount of time, just working with smart thermostats. So, like what do you see as the future here in ERCOT?
Chairman Gleeson: The best thing about that program is it is it proof of concept, right? And so having NRG, having, you know, the companies that are out there that benefit from this as well, right? Providing those incentives, looking for ways to scale this so that their customers win and they win. Again, then the whole state wins. I think proof of concept is really important. As we look to scale this up, how do we do it in a way that makes sense for the state to achieve the right outcomes? That is a great example of a private company. Looking at that, seeing a risk, but also seeing an opportunity, helping to empower their customers and then their customers and they reap the benefits. So I think the proof of concept of an issue like that is amazing. And I hope that’s something we can build upon going forward.
Matt Boms: That’s great to hear. And this conversation customer side resources, whether it’s backup generators, residential batteries, rooftop solar, smart thermostats, what needs to happen for those resources to provide real grid value at scale? Because to me, it sounds like that conversation, like the ADER pilot, started in 2022, I believe, right? Before this whole data center conversation started. And now we’re in a situation where we could really use every megawatt available on the grid. That might help us alleviate some of the strain that we’re seeing, especially on specific substations where we know if we had some, you know, some distributed batteries around that substation, we would be able to alleviate some of some of the stress. So where do you see those resources playing a role here moving forward?
Chairman Gleeson: Yeah, I think that, you know, as we talk about affordability, they’ll continue to play a really big resource. And I think an ever growing, you know, part of the discussion because the other thing they do is when you get those types of localized generation or demand response programs, it alleviates the need for transmission to be built. And so you’re doing both, right? You’re bringing megawatts onto the grid. You’re also reducing costs by not needing as much transmission. And so with affordability kind of being front of mind and, you know, everything something that everyone is looking to solve for, I think these new types of ideas like distributed energy resources, looking to use batteries in different ways, are going to continue to have to proliferate because we have to have an all of the above mentality when it comes to addressing the issue.
Matt Boms: Yeah. The the question around interconnection, I want to make sure I get that in before we move off of the DER topic. So the most common complaint that I hear from our member companies and from the private sector in general is it’s a very inconsistent interconnection process across the state, right? Because depending on which utility you work with as a DER company, you might have a completely different process for interconnection. Even within one utility, you might get different answers with within that specific TDU. So Do you have any answer to how we solve the interconnection problem here and establish some uniform rule? Because you the companies that I hear from are saying like, We’re just tell us where the goalposts are and we can do it, but like don’t move them around. Just give us some clear structure.
Chairman Gleeson: Yeah, no, I think standardization of the interconnection process is key to this. And what I’ve committed to, and I’ve had a lot of the same discussions, I’m sure you have with the companies. What I’ve committed to is once we have, you know, some of these other issues kind of, you know, in motion or dealt with, we will look at this because again, I think it does have to be a part of the solution. I’ve heard the same frustrations around not knowing company to company, or to your point, even within a company, depending on who you’re talking to, what the rules of the road are. That is Prime for us to have rules around to ensure that there’s standardization that again meets the needs of the companies, but also of the utilities who are looking to ensure that they have full visibility onto what’s going on in their grid, that any type of interconnection is done in a way that doesn’t impair reliability. We can solve for both. And the right venue to do that is through PUC rulemaking. Yep.
Matt Boms: Yeah, completely agree with you. We’ll move off the DER topic, but on the ADER program specifically, is there anything that you would need to see before it moves from a pilot? Like can we just lift off the pilot label at this point or is are we waiting on some final details?
Chairman Gleeson: There’s nothing that I’m looking for. Like I said, I think it has proven really successful. And so my hope is that we can move beyond that and really look to maximize the benefit of a program like that.
Matt Boms: Okay, that’s great to hear. Let’s talk backup power package, which is another one of my favorite topics. So the rule has been approved by the commission, which was great to see. Can you just give us an intro for folks that maybe haven’t been following us closely? What problem is that program designed to solve?
Chairman Gleeson: Yeah, so that’s really coming out of Winter Storm Uri and looking at at critical facilities and allowing for those facilities to have a cost effective way to have backup power to serve their local needs. And so the state allocated $1.8 billion in the Texas Energy Fund to address this. You know, and I had testified to this many times. My thought was and hope that this was going to be the easiest of the programs to actually implement. It has proven not to be so. Because there’s a lot of different ways you can implement a program like this with a lot of different constituencies. We wanted to make sure that we heard from everyone. We heard from engineering firms around what the specifics around a program like this needed to be to ensure it’s achieving the goals the legislature had when they passed the bill. And so we’ve done that. Like you said, the rules have been passed. Looking forward to seeing what we get in so that we can start providing grants out in order to get this backup power on the grid. Cause I think when we do get tight, when there is, you know, another really strong winter storm. I think it is helpful, even though I am secure in my belief that the grid is resilient and can respond to any type of grid you know, any type of weather condition at this point. I think it provides peace of mind knowing that those critical facilities on the grid also can isle in and have backup power just in case something were to happen locally. That’s right. And it’s and it’s one again, the state is willing to partner with those companies because they see the critical need to ensure they have twenty four by seven reliable power.
Matt Boms: It’s a last line of defense for them. Yeah. And so for Texans that are listening to this conversation, how should they think about the difference between resilience for a critical facility, maybe out in rural Texas, versus reliability for the ERCOT system as a whole?
Chairman Gleeson: Yeah. So, you know, I think of reliability as we want to make sure that the grid is reliable at the highest level, that when you turn that power switch on, you can ensure that your lights are going to turn on. Resilience is when there is an event like a Winter Storm Uri, like a winter storm [fern?], like a Hurricane Beryl, honestly, that if something happens that does affect the grid locally, right? Not again at the ERCOT wide level, but a local issue, that those critical facilities that everyone counts on. So think. Wastewater plants, right? We want to make sure that those stay up and are providing the service they need to, that if that a facility like that continues to have power even if there are localized outages that have to be addressed by the transmission distribution utility.
Matt Boms: Great. And longer term on the backup power program, is there a conversation to be had about whether some of the these backup assets at critical facilities could provide some grid value or is that outside of the scope of the program?
Chairman Gleeson: So I think right now I would consider that outside the scope. And all honesty, I think we need to really focus primarily right now on ensuring that power is there in order to serve the local need. But I think long term, again, as you continue to analyze and iterate, I think it’ll be important to see, yes, are there times when those facilities can provide power back to the grid? I just don’t know if the first iteration is the right place for that. Okay.
Matt Boms: Yeah, that makes a lot of sense. And I want to make sure we hit on four CP because we made it this far without without mentioning four C P. It was really one of the major rulemakings that came out of SB6. And maybe you could just lay out, you know, what four CP has done historically on the grid, why it may not be the best solution at this point and where the commission wants to take it from here.
Chairman Gleeson: Yeah. So four CP. So the CP stands for coincident peak. So when you think about these large customers, the way that they get their transmission costs allocated to them is when the grid during the summer months, June, July, August, and September is at its highest usage, what are those facilities using on the grid? And so that’s how we allocate transmission to those facilities, which back, you know, in 2001 made a lot of sense because we were most concerned about reliability at those gross peak times. Now, because of the proliferation really in batteries and solar, during those really gross peaks, the reliability on the grid is really solid because you have people at home running their air conditioners. The reason they’re running them is because it’s hot outside, because the sun’s also, you know, out. And so the behavior there I think has has worked itself out. What we’re trying to do now is ensure that if a company can reduce its its load during those peak times, that they don’t avoid you know, a large portion of their transmission costs. Cause again, those transmission costs have to be paid by someone. Most likely, if those large industrial customers aren’t paying some portion of their costs, those those costs are then being borne either by other industrial facilities that cannot reduce their usage at those times or by residential and small business residential customers and small businesses. And that’s not an outcome we want. We want to try to adhere to cost causation principles as much as possible. So we need to find a way to ensure That those facilities are paying for the transmission that they need. So what Senate Bill Six said is we have to, by the end of this calendar year, pass rules to look at moving away from 4 CP. The commission recently published its proposal for that rule, which included the idea of moving from a 4 CP to a 12 CP model and other things, such as a minimum demand ratchet, so that you couldn’t avoid all or most of your transmission costs.
Matt Boms: Right. And that’s I won’t make you say this. I’ll put it in my own words, which is there is an industry out there around predicting when those peaks will happen and then right the avoiding the cost of transmission essentially. So that’s what we’re trying to solve for here is you know, make sure everyone pays their fair share.
Chairman Gleeson: That’s right. And and you’re trying to solve for two things, right? Because you still want that coincident peak response. You want that demand response because the grid benefits from ensuring at those times of highest peak that of highest usage that those companies can take their facilities offline, therefore, thereby reducing the stress on the grid. But again, if you allow that too often and too easily, then a lot of these costs get shifted to other classes of customers. And that’s something that we don’t want.
Matt Boms: So we’re talking about potentially moving from a four CP to a twelve CP, which would mean if I got this right, the twelve you know, taking the f the intervals out of each of the twelve months of the year and those would be the that’s how those are the coincident peaks that we’re basing the transmission costs on.
Chairman Gleeson: So that’s the current proposal. I think we’ll endeavor through the comments to look at other ways of doing that. You could have 12 peaks, say, you know, kind of floating on the months just in the summer and the winter, if you want. You could look to have them weighted differently. So if we’re looking for more of a response in certain months, you could look to weight them differently. They don’t have to all be say one twelfth of the total. So I think there’s there’s a lot of nuance in that discussion that we have to work through between now and December when these rules finally get adopted. But I think this will be one of the more heavily invested in rules that we pass at the commission this year. And because there’s gonna be a lot of interest in how we do this.
Matt Boms: Yeah, no rest this summer for for any of us, I think.
Chairman Gleeson: That’s right. There’s there’s a lot of money at stake here and so a lot of interest in the outcomes.
Matt Boms: Well, great. And to wrap up the twelve CP conversation, you mentioned the minimum demand charges. So one thing that I’ve been thinking about is you want to keep this tool effective for the grid, right? So if if you’re a data center and you contract 80 megawatts and there’s a minimum demand charge of a hundred percent, then essentially you have no incentive to go down to sixty when the grid really needs it. Right. So how do you balance that as far as the minimum demand charges? You want to make sure the data center’s on the hook for something, but Maybe not all of it.
Chairman Gleeson: That that’s right. And so I think again, we have to look at the comments that come in because, you know, the companies and all the interested parties in this will have the best kind of line of sight on what the different options are. But I think you’re a hundred percent right. We have to balance the need to see coincident peak response to bring down demand with the idea that we can’t have these costs borne by other customer classes. And so there’s a trade-off in that, right? There’s not going to be a solution to this. There’s going to a trade-off when you solve for one thing, you’re also solving for something else and it’s having impacts. You know, as I sit here now and I think about the best way to really think about this, you could have a graduating scale based on size. You could, you know, look at other potential options for how you allocate those costs over the year to help ensure, again, that we’re not providing disincentives to the behavior that we’re looking for. Another thing in all honesty, I think you’re going to start to hear a lot of people talk about is in some of these policies, do we need to start differentiating, say, between a hyperscale large load and electronic large load? And a traditional industrial facility because, you know, historically we’ve done everything based on the amount of load on the system and kind of put everyone in one bucket. But it’s clear to me that your traditional industrial facilities behave differently than these electronic large loads. And so I think it’s time to at least have that conversation in certain policy areas. Does it make sense to have different policies for the different types of large loads?
Matt Boms: Yeah, depending on the behavior of the load, right? That that’s what really
Chairman Gleeson: That’s right. The behavior of the load and what their ability to respond to these types of things is, right? I mean, a Bitcoin miner is different from a hyperscaler, is different from a steel mill or a chemical plant. I think again, having rules that have nuance in them around the different attributes of those facilities is something we really have to start thinking about. Yeah.
Matt Boms: Agree. And I think it’s one of those things where like, you know, two things can be true at the same time. For all the criticism of four C P it still is maybe the most effective tool that ERCOT has right now as far as, you know, how you limit that peak load on a really hot summer day, right? There’s really nothing better than four C P at this point.
Chairman Gleeson: That’s right. And you can actually see when you look at the graphs of usage during those days that the companies assume will be a four C P day, you can actually see usage go down because they’re they’re chasing that interval for for that four C P reduction. And it does. It provides the grid a lot of benefit is the risk again is on the private company, not on the citizens. They chase that four C P interval and we get the benefit multiple times a month of their desire to come offline during those coincident peaks. Yeah.
Matt Boms: Well, we made it through the marathon of rulemakings and all the different topics and thank you so much because I know you got a busy schedule. I’ll let you go. I just want to close with a couple of questions about the future. And with all of the work that’s on your plate right now, like is there one topic where if you had the time and the resources and you could just sit there for a few days and actually create something new or think about things outside the box? Is there like one thing that comes to mind that you would like to spend time on?
Chairman Gleeson: You know, I don’t know if there’s one thing. I think what I would like to spend time on is we have done so much change over the last five years. I would like to be able to take a breath and see how all of these policy changes really work together. I think, you know, as as I think about if you’ve ever heard Bill Flores, the Eurocop board chair, he ends almost every conversation he has with someone with what keeps you up at night. I think if anything keeps me up at night right now, I’m proud of all the work that we’ve done. I just don’t know what the interplay between all the changes is and how that’ll work together. We want to make sure that we’re not adopting policies in one area that counteract a positive impact from a decision in another area. So my my hope is that as we head into the twenty twenty seven legislative session, we get to take a breath, look at all these changes we’ve done, be proud of the work that’s been done, but really take some time to see how they all work together before we look to make any, you know, real significant changes again.
Matt Boms: Yeah. You know, we’ve had previous commissioners and chairmen of the commission the podcast before, folks like Pat Wood have come on, Barry Smithherman. When people look back on this specific period of Texas energy policy, what do you hope that they’ll say?
Chairman Gleeson: That the challenges were great, but we were up to the challenges. I think Texas has always shown a resilience to anything. And I think history will look back upon this period and say they went first on almost everything dealing with electricity in the nation and maybe even in the world. They were up to that challenge. They met it. And then the work that they did was then used to go around the world and make sure that everyone could rise to the challenge. Couldn’t.
Matt Boms: Agree with you more and just so proud to work in a state that can attract all that investment and really meet the moment because again, I think a lot of other states, probably forty nine other states are looking at Texas right now as far as how we meet this specific moment and accommodate all this new demand.
Chairman Gleeson: That’s right. You know, as I go around the state and really the country and talk about everything we’re doing, one thing that I it reminds me of is how far ahead of everyone else we are and having these discussions and coming up with solutions. So yeah, again, my hope is we get this in a place where everyone can look at it and take it elsewhere, implement it, and everyone can be successful.
Matt Boms: Awesome. So we’ll end it there. Thank you so much again, Chairman Gleeson, for coming on the podcast, for your years of service to the state of Texas. It’s a pleasure to have you with us today.
Chairman Gleeson: Absolutely appreciate the opportunity to have the discussion.
Matt Boms: Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make sense of the energy world, share the episode with a friend and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis each week, subscribe to the Texas Energy and Power newsletter at TexasEnergyandPower.com. That’s where you’ll find every episode, every article, and all of our latest updates. We’re also on LinkedIn. X and YouTube, where we post clips, insights, and ongoing commentary. Big thanks to Nate Peavey, our producer. I’m Matt Boms and I’ll see you next time. Stay curious, stay engaged, and let’s keep building a stronger, smarter, energy future.

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How will data centers pay for power?
3 jun· Energy Capital Podcast
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.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
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How Texas decides which data centers to connect
27 mei· Energy Capital Podcast
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.

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How Texas plans to serve ‘infinite demand’
20 mei· Energy Capital Podcast
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.

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Austin Energy Enters the Next Phase of Decarbonization
13 mei· Energy Capital Podcast
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.

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Process is Killing Texas Data Center Projects
6 mei· Energy Capital Podcast
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.

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Texas Bets on Speed, with Gin Kinney
29 apr· Energy Capital Podcast
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.

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Transmission Takes a Decade, Load Doesn't — with Raina Hornaday
22 apr· Energy Capital Podcast
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.

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What a Wind Lease Is Worth Now with Rod Wetsel
15 apr· Energy Capital Podcast
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.

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Who Pays for the New Grid with Pablo Vegas
8 apr· Energy Capital Podcast
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.

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Texas Growth Is Running Into Power Grid Limits with Katie Coleman
26 mrt· Energy Capital Podcast
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.

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SPECIAL REPORT: Texas Feels the Iran Oil Shock with Michael Webber
18 mrt· Energy Capital Podcast
For a century, the Strait of Hormuz has been one of the world’s key energy choke points. But during the past couple of decades, the U.S. relationship to the shipping lane has changed.
In this special episode of the Energy Capital Podcast, Josh Rhodes talks with Michael Webber about what the Iran conflict means now, especially for Texas. The U.S. is not as vulnerable to oil shortage as it once was, but greater energy self-sufficiency does not insulate the country from global prices.
The U.S. now produces more oil and gas than it did in the 1970s, when another energy crisis rooted in the Middle East rattled the U.S. economy. That leaves the nation less vulnerable from a security perspective.
But consumers in Texas are still tied to global markets through pricing, refining constraints, and fuel trade flows. As Webber explains, even if the country has enough energy overall, price spikes abroad can still show up here at the pump, and they can linger.
The conversation gets into a few issues that will develop over the coming weeks and months:
* Why gasoline and diesel prices may rise with a delay, then fall more slowly than consumers expect.
* Why U.S. oil abundance does not fully protect Americans from disruption overseas.
* Why Texas benefits, and what’s at risk, from the state’s current energy mix.
Rhodes and Webber also stress that resilience covers a range of issues: what resources can be refined, what generation and infrastructure can be built, and how quickly the system can adapt to challenges. That spotlights variables including refining capacity, permitting reform, and the roles of wind, solar, batteries, and electrification in reducing exposure to fuel volatility.
The episode explores how Texas fits into a deeply interconnected global energy system, even after the state’s shale revolution.The unresolved question: if the disruption in the Middle East continues, where will the state’s real vulnerabilities start to show?
Energy Capital Podcast is produced by ClarityForge Studios.
Timestamps
* 00:00 - Iran Conflict & U.S. Exposure
* 02:29 - Why Prices May Rise
* 03:57 - Self-Sufficient, Still Coupled
* 06:07 - Texas Refining Constraints
* 08:03 - SPR, Export Bans, and Policy Tools
* 10:48 - Renewables, Gas, and Energy Security
* 16:35 - Affordability Politics
* 19:14 - Permitting Reform & Outro
Resources
People & Organizations
* Texas Energy & Power (Website - LinkedIn - YouTube)
* Joshua Rhodes (LinkedIn)
* IdeaSmiths (Website - LinkedIn)
* Michael Webber (LinkedIn)
* Webber Energy Group (Website - LinkedIn)
* International Energy Agency (Website)
* U.S. Strategic Petroleum Reserve (Website)
Company & Industry News
* US gasoline prices soar past $3.75 a gallon as Middle East war rages on
* Oil settles up 9% as Iran vows to keep Strait of Hormuz closed
* Goldman Sachs raises Q4 Brent, WTI crude price forecast amid longer Hormuz disruption
* Here’s the energy policy we need for the war in Iran
Related Podcasts by Energy Capital Podcast
* Build Fast or Fall Behind with Michael Webber
* Interview with Energy Expert Dr. Michael Webber
Related Posts by Texas Energy & Power
* The Growing Importance of Energy Efficiency
* Why Are Energy Bills Rising So Fast?
Transcript
Joshua Rhodes: Welcome to the Energy Capital podcast. This is a bit of a special edition where we’re going to talk to Dr. Webber again. We’re talking on Friday, March 13th, and we’re really kind of doing a little bit of a current events type take on the energy impacts of the current conflict in Iran and the Strait of Hormuz. Dr. Webber just published an article or an op-ed in the Houston Chronicle where he just talked about the energy implications of what that would mean for the U.S. So Dr. Michael Webber, welcome back to the Energy Capital Podcast.
Michael Webber: Thanks so much. It was great to be here and have another conversation with you. I appreciate you inviting me. Absolutely.
Joshua Rhodes: Well, let’s dive in. You wrote in your op-ed that the energy risks we worried about 20 years ago, like disruptions to the Strait of Hormuz, that are actually happening right now, but you argue that the U.S. Might not care as much this time around. Why is that?
Michael Webber: That’s right. I’ll say that first of all, the risks of the Strait of Hormuz have been known since the seventies, but really amplified as a risk in the eighties with the Iran-Iraq Tanker War that happened in the eighties and is really the main justification for why the US Navy projects so much force there just to keep the shipping lanes open, all that kind of thing. So the risk of the Strait of Hormuz as a choke point for global commerce around oil and refined products and helium and aluminum and other things like fertilizer area, that’s been known. But what has changed is how much we might care. So 20 years ago, when I studied this for Think Tank doing national security work for the Pentagon, we identified the closure of the Strait of Hormuz as one of the biggest single point risk failures the world could go through in terms of destabilizing global energy markets. But that was before the shale revolution, all these other things that happened 20 years ago. So we were really worried about what this might mean in terms of United States even getting access to the resources in the first place, plus price spikes and everything else. In the 20 years since we did that study for the Pentagon, The Shale Revolution’s come through, so we have a lot more domestic oil and gas production. We’re now exporting instead of importing. We have a lot more wind and solar, so we need less domestic fuels like coal or natural gas in the power sector. The whole situation’s changed where we’ll be exposed to the risks of higher prices, but we have enough supplies. We don’t have worry about absolute supply cutoff. And that’s a good position to be in. I think we should celebrate when we can policy successes. And I would say the last 20 years have been a combination of policy successes. That put us in a better national security position when it comes to disruption to Middle Eastern flows of energy.
Joshua Rhodes: So Americans are already seeing higher gasoline prices and diesel prices after this escalation. You mentioned that these price spikes can often lag disruption by a week or two, but should consumers expect this to get worse?
Michael Webber: I expect it to get worse and I also expect the high prices to linger for a while. So there are a couple of things that happen. The disruption happens physically. The prices start to reflect it in the futures market pretty quickly, but at the gasoline pump say a little bit later. So there’s some lag time between physical disruption and higher prices. And then there’s also lag time from when the disruptions are settled and when prices come back down. But sadly, as one of the sort of bitter ironies of life, prices go up a lot faster than they come down for variety of reasons. Yep. So even if the disruptions sorted out in the next few days, I expect higher prices to hang around for a while because people have to refill their inventories and they have to price in the risk of volatility or the risk of additional tax. So high prices will be here for a little while. And I think that’s one of the things about the US situation is that we are now self-sufficient on energy. It’s not like we’re independent. We’re still coupled to the global markets and being independent is different than being self-sufficient. We’re self-sufficient. We have enough energy to run our economy, but we are connected to the global economy. So even if we have the energy, if the global price goes up, our price will grow up as well. And there’s all these sort of couplings that happen to the prices, but also these lag times. So I think we got prices that’ll be high for a while. Secretary of Energy Chris Wright says it’ll be settled in a couple of weeks, not months. I expect prices to be high for a few months, but who knows? We’ll see how it goes.
Joshua Rhodes: Okay. We produce a lot of oil in the US now after the shale revolution, but we can’t always refine that oil here. I mean, we import a lot of crude from other regions like the Middle East, but we also export a lot of our sweeter crude to Europe where they can actually refine it. So can you speak to how even though we produce a lot of oil now, we’re still coupled to the global markets?
Michael Webber: It’s really kind of a fascinating irony in many ways that we did not foresee the Shale Revolution. And so what we saw instead, looking forward from the 1980s onwards, was more imports of heavier oils from Venezuela or the Canadian oil sands, or even like the heavy sour crude from Saudi Arabia or other places. These heavier crudes, which are more difficult to refine, but we put the money into our refineries to make the refineries capable to handle those heavier crudes. Then we find all those light sweet crude, which is like the champagne of oil, and we’re buying the beer of oil. The less valuable coarser crude that we know how to refine, but selling our more valuable champagne crude. So we can sell our light sweet crude at a higher price than what we pay for the heavier sour crudes. But the challenge is even when you have an abundance of the light sweet crude in West Texas for East Texas refiners, those East Texas refiners are not fine tuned for it. So you’re exactly right. We’re exporting the West Texas light sweet stuff to other people, refineries in say Asia or Europe and importing the heavier crudes to turn into jet fuels and things like that. And that’s one of the couplings of the global market. Though we have enough energy in the nation to be self-sufficient, we’re not refining our own crude into the products we need for our cars and trucks and planes. We’re still depending on the global market to provide the crude to do that. And that’s okay. Like financially, that works out for us until there’s a major disruption and we can’t get the crude we need for our refineries. And that’s a risk we have to think about.
Joshua Rhodes: Well, High Life claims to be the champagne of beers, but I don’t know if there’s a... Oil.
Michael Webber: Yeah, so I haven’t seen that ad yet. I feel like someone should do that. Yeah, the West Texas Intermediate is the champagne of beers, something like that. It is kind of a funny sort of global trade situation because you could do that with foods as well like, hey, I’ll buy your champagne if you buy my beer, is a pretty typical global trade kind of conversation to have. Or I’ll buy your really high-end cheese if you buy my low-end refined food products or something like that. So we do that kind of thing for other markets as well.
Joshua Rhodes: they recently announced like a new refinery in Texas that might be able to handle this.
Michael Webber: That’s pretty exciting. So there is a big announcement for a new refinery for the first time in 50 years, for the most part for the last several decades, four or five decades, we’ve been shutting down refineries, primarily around environmental reasons. Some of the older refineries were less efficient and dirtier. So refineries in the United States have becoming fewer but bigger and more capable and cleaner. So we have fewer refineries, but more refining capacity. And that refining capacity has lower emissions and more efficient throughput and things like that, but designed for the heavier crudes like we mentioned. There’s an announcement of a new refinery in Brownsville that can take the light sweet crude, which is pretty exciting. And it’s a new refinery. It’s kind of exciting because it’s been 50 years. It’s also not a new announcement. It was first proposed a decade ago and they announced their construction permits in 2024, like two years ago. So the latest announcement, it’s not really clear it’s going to be built, but there is an announcement. President Trump announced it, for example, and the Secretary of Energy was celebrating it. It’s not even 100 % clear to me who the actual investors are or whether there are the firm off-take agreements. But if there are actual investors in off-take agreements and it gets built, it will take several years. That would be pretty interesting. It would be probably good for the Texas economy and good for us to have a local user of the light sweet crude. There’s a lot of reason to be skeptical that it’s not really going to happen, but high prices are interesting because it helps the producers, but high prices make it harder for the refiners. And so a high price environment might not be a great time to build a refinery in terms of high price crude, except that Jet fuel and diesel and gasoline prices are high, so the product prices are higher, so then it would be a good time. And if you can’t get the crudes, like if the Gulf Coast refiners can’t get the heavier crudes, and you have a refinery that can get the light sweet crudes, it might be competitive advantage. So it’s all pretty complex. It takes a lot of risk, and that’s why these things cost billions of dollars and require 20-year off-take agreements. But there’s a long way to say that if it gets built, it’ll be the first new refinery in decades, and we’ll see if it gets built.
Joshua Rhodes: Fair enough. So the administration has just ordered a release of oil from the strategic petroleum reserves after the Iranian attacks on shipping. Is this the right tool in a situation like this?
Michael Webber: The SPR, the Strategic Petroleum Reserve is one of the right tools. It’s actually a tool that was custom designed for this exact situation. After the supply cutoffs in the 70s, happened in the early 70s and late 70s for different reasons, but the same region, the United States and other importing consuming countries all came to realization that there’s a vulnerability depending on a handful of countries for oil if those countries decide not to sell you oil anymore. So that was what led to the creation of the International Energy Agency primarily to coordinate strategic petroleum reserves around the world and coordinate their release. So the SPR was developed first in the seventies and really expanded over a couple of decades for this purpose. And releasing oil from the SPR to settle price spikes or to fill a physical gap of deliveries is exactly what’s designed for. This is the right tool for the job. It’s also not a sufficient tool for the job. Meaning like you’re going to need other tools. Like it’s one of the tools, but we need to think about efficiency and fuel switching and alternative routes for delivery. And there’s all sorts of things we need to do. This is one of the important ones because we can do it quickly. But if there’s a sustained outage or sustained disruption at the Strait of Hormuz, there’s not enough oil in the SPRs around the world to really fill that gap if it’s a multi-month situation. If it’s a few weeks, we’re good. If it’s months or years, we’re going to have to find alternatives.
Joshua Rhodes: That’s a good point. It’s not only the US has an SPR, they’re SPR’s equivalents around the world,
Michael Webber: Yeah, China, Japan, lot of European nations. United States has a very big one, so ours is very relevant. And just the announcement that the United States and other countries would release some oil kept oil prices down. And that release hasn’t even happened yet, I don’t think. It takes a while to get the oil out. But just the announcement itself was enough to calm markets a little bit.
Joshua Rhodes: got it. You know, whenever gasoline prices spikes, sometimes there’s political calls for the US to restrict oil exports. And we’re hearing that again, like we’re talking about stopping oil exports. Given what we talked about just a minute ago, would banning exports actually do anything or lower prices?
Michael Webber: I don’t think banning exports would lower prices and it’s really kind of amazing to have President Trump say that oil and gas industry does not want that solution. Right. And he presents himself as like a friend of the oil and gas industry and they’re like, okay, that’s not the statement we want you to make. So I think economists don’t like that idea. Think national security people don’t like the idea. The oil and gas industry doesn’t like it. I think in the end it wouldn’t even work. Frankly, we tried that after the 70s. We put a ban on exports and that wasn’t the appropriate solution. That would have been better just to increase domestic production or implement more efficiency to reduce consumption. I don’t think that will actually become policy, his announcement to ban exports. I think there’s too much resistance, but you never know these days.
Joshua Rhodes: Yeah, fair enough. You know, you argue that in the op-ed that deploying more wind, solar, and batteries can actually strengthen national security in times like these. How does building more renewables help in a crisis like this?
Michael Webber: There are a couple of things about renewables that are really handy for something like this and primarily in the power sector, if we look at wind and solar, they displace our demand for natural gas, which means we have more natural gas we can export to global markets. Gas prices are going up because LNG is disrupted as well. LNG is a liquefied natural gas and Qatar in the Middle East is a major LNG exporter. If they can’t get their LNG to market, then global gas prices will go up. Our domestic gas prices are lower than the global price, but they’ll be affected by that a little bit. If global price has gone up and we consume less gas here, that frees up some volumes for us to export. So we can sell it to our friends in Europe or Asia and help out our ally while also making a handsome profit. So it’s a good moneymaker for us. The more wind and solar we have in the grid, the more gas we can sell. We also have coal in the grid. We’re mostly shutting down coal, but coal can ramp up for months or years at a time to help offset some of the gas needs as well. But it’s hard to build a new coal plant. Meanwhile, we’re building a lot of wind and solar. So wind and solar is immediately a benefit in terms of freeing up how much gas we use, but it also is something we can build on the order of 18 months to 24 months to get new construction in place. It doesn’t take 10 years to build the way it does for nuclear, for example. So we can ramp up on this production if we think this is going to be a sustained disruption.
Joshua Rhodes: Yeah, one of the things you and I were talking about the other day is like the possibility for high oil prices to actually incentivize more or potentially lower natural gas prices because a lot of natural gas production, particularly in Texas, is associated with oil. And so the higher the oil price, the more oil production, maybe the more gas it gets, but then maybe the more exports. Do we know which where that falls?
Michael Webber: All of it, everything you say is possible. So these price spikes might lead to a glut, which leads to low prices. That might be a uniquely American situation because we have so much domestic production. But if we take what you said and carry through, there’ll be high oil prices, which means we’ll drill more. So we’ll get more oil. We’ll produce more gas, which will lead to a supply glut, which leads to lower gas prices. But there are also high gas prices and those high gas prices will lead us to build more wind and solar to use less gas, which means there’s even more of a gas glut. So the high gas prices and the high oil prices might simultaneously lead to more gas production in the United States and less gas consumption, which will then lower the prices. And this is the problem with oil and gas. The world is, it’s kind of complicated because high prices will bring on the solutions to the high prices, which will lower prices and the solutions are less consumption, more production. But low prices will also lead to higher prices because if you have low prices, you’ll produce less but consume more. And eventually you get a scarcity situation, prices go back up. So it’s hard for me to really anticipate, but the geographic tension with the United States is the West Texas oil will be produced getting associated gas kind of for free, but the shale production say in Pennsylvania is really just gas. And so as we’ve been drilling less for oil in the last year, one of the consequences of the Trump administration is less oil drilling. We’ve been doing more gas drilling in Pennsylvania. And then the question is like, okay, in a high oil and gas price environment, do those drilling rigs come back to Texas to produce oil, giving you gas for free? Because it’s associated gas? Or do they stay in Pennsylvania and keep drilling gas because gas prices are high? Or do we just do more drilling of everything, right? All of these things are possible. But I think any way you slice it, probably our prices are lower than in Europe and Japan. But whether prices collapse again, that’s hard to predict unless there’s like some real global economic collapse and then prices will drop for sure. But yeah, I think you’re exactly right that higher prices for oil will lead to more oil production, which leads to more associated gas. If you can get that gas to market because of new pipelines, in which there are some, then gas prices should stay relatively mild and won’t spike as much.
Joshua Rhodes: fascinating. You know, one of the things that I’ve kind of always said about energy is like, no one really wants energy, they want the things that energy gives us, right? And so I was talking the other day or conversing with folks online about if you want to be insulated against high gasoline prices, then get an electric vehicle. And some of the things we’ve been talking about, like a lot of those fuels like natural gas and renewables that kind of flow into the electricity sector, is that the right argument to make? Would that make us more resilient against these types of events?
Michael Webber: Absolutely. So I think the technologies to consider are not just wind and solar or more domestic oil and gas production. It’s also in the consuming appliances and electric vehicles are a classic example of this. By using electric vehicle, I reduce my exposure to gasoline prices. Like I just don’t have exposure to gasoline prices. Right. But I do have exposure indirectly to natural gas prices in the power sector. So if the higher oil prices are accompanied by higher gas prices, which seems to be happening right now. By gas, I mean natural gas, not gasoline. If natural gas prices are higher, then power prices should be higher, which means my electric vehicle will have some exposure. But what we find is electricity price spikes are not anywhere close to the same thing as the wholesale commodity price spike. So crude oil and natural gas and gasoline prices can really spike. They can go up by factor of two or in some cases factor of 100, like in Winter Storm Uri. But retail electricity prices don’t spike. We have a rate making process that protects consumers, especially retail residential consumers, which is who most of us are when we’re charging up our electric vehicles. We don’t have price spikes. And so even though the wholesale price for electricity might be going up because the wholesale price for gas has gone up, the price you and I pay to charge up electric car probably has not spiked. So we’re protected through a rate making process. So it is a great hedge against this. And my costs for my car aren’t gonna go up with these price spikes. If they happen for years, maybe it’ll take a while to adjust the rates. But I think it’s a great individual level hedge we can make. You could say the same thing about electric heat pumps instead of natural gas furnaces and electric cooktops instead of gas burners and things like that. By going electric and having a rate making process that’s designed to reduce exposure to high price spikes, we’ll be fine.
Joshua Rhodes: Yeah, and I always think about there’s really only one one economical way to make gasoline and diesel is using oil, but there’s like dozens of ways to make electricity.
Michael Webber: Yeah, it’s got a built-in diversification, a built-in hedge, right? It breaks the monopoly of any one particular fuel or technology, which means that the consumers have power on this, not just the producers, which is really handy. And if you look at transportation, light duty vehicles in particular have been dominated by gasoline historically in the United States, heavy duty trucking dominated by diesel and planes dominated by jet fuel. They can’t electrify or find alternative fuels very easily. At our home with our electrons, we have so many choices, some of which are on a rooftop or our backyard, some of which are at the local utility, maybe dozens or hundreds of miles away, but we get a lot of options and that’s a nice built-in hedge for these kind of uncertain times.
Joshua Rhodes: is interesting about the timing of this and like how long things may go. There’s already political unrest around like rising cost of energy. And so as we’re kind of heading into like a political season, is this going to be a big player? Is it going to be a big impact?
Michael Webber: I think it will be. Think the electricity affordability crisis is already a political issue. I think it will remain a political issue for the elections in November because I expect prices to be high for months. Even if prices aren’t high for months, the lingering memory of it will show up at the ballot box is what I expect. That was one of the main reasons that Trump won. He ran on a platform of affordability. He used that to beat up on his opponent, Kamala Harris, and that was successful. So think a lot of people will take a page from that playbook and say, okay, well, running on affordability of eggs or milk or other food items, but also energy will be something that I expect candidates to run on. We’ve seen it already a little bit. There was an election a year ago, so in Georgia, where the statewide elected official for the public service commission, like the Public Utility Commission in Texas, was thrown out of office because of concerns around electricity rates. And usually the statewide commissioner positions are not one that people pay lot of attention to politically, but... That was when we were like, they flipped the party and threw out the incumbent, all this kind of stuff. So clearly there was some anger there and that might be a preview of what’s to come. And we don’t often get to vote on the commissioners themselves who regulate energy. Some states do, some states don’t. And so I think if people are grumpy, they’ll take it out on whatever people they can vote for or vote against. So I think it will be an issue. I think it is an issue. I think it’s already showing up at the ballot box. I don’t expect that to change by November.
Joshua Rhodes: Okay, last question. If you were advising policymakers right now, what’s the single most important energy policy decision that they can make?
Michael Webber: I think the best thing we can do right now is permitting reform to get more stuff built quickly. These supply disruptions and price spikes are a reminder that being able to have your own supply, which means your ability to build things, which could be power plants or oil and gas production or pipelines or transmission lines, all of that is important. So we got to get things built. And another thing, if I can take a second point, just say we’ve actually had some pretty good success the last 20 years, increasing domestic production of oil, gas, wind and solar, batteries, things like that, and reducing consumption. Our consumption per person and per dollar of unit of economic activity are down because of efficiency. So let’s keep the successes going. Let’s not give up on the things that have been working for us. And let’s get a lot more things built.
Joshua Rhodes: I’m Michael Webber. Thank you for coming on the Energy Capital Podcast.
Michael Webber: Thanks for the real-time current events discussion.
Joshua Rhodes: Absolutely, it was great. 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.

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Build Fast or Fall Behind with Michael Webber
11 mrt· Energy Capital Podcast
For a long time, the basic story in U.S. energy was stability. Demand growth had flattened, efficiency was doing more work than most people realized, and expansion was steady.
Not anymore.
In this week’s conversation, Josh Rhodes talks with Michael Webber about what may be the most important shift now underway in energy: the dramatic growth in electricity demand, in Texas and beyond. Data centers are a big part of the story, but not all of it. Electrification, industrial growth, and population growth are also fueling the need for more energy.
In this episode, Webber notes that energy progress moves fastest when markets, policy, and engineering align. That is true for shale development, and it may be true again with the coming growth of the grid.
Texas is well-positioned to lead this next stage of energy development — we have a strong energy base, growing demand, and a mix of technologies competing to meet it. Josh and Michael talk through why geothermal power is gaining attention, why nuclear expansion plans feel different this time, and why wind, solar, storage, gas, and transmission remain essential.
They also address a problem that is becoming hard to ignore: new load can be built faster than new generation, and new generation can be built faster than transmission. That mismatch is showing up in transformer backlogs, turbine supply constraints, and growing pressure to move much faster than some energy executives are used to.
n many cases, the challenge Texas faces is not a lack of energy throughout the year — rather, it’s a shortage of power during a relatively small number of peak hours. That has real implications for cost, reliability, and what kinds of loads and technologies make sense for ERCOT.
Tune in to hear Michael and Josh talk through those challenges — and opportunities.
Energy Capital Podcast is produced by ClarityForge Studios.
Timestamps
* 00:03 – Introduction & Michael Webber Background
* 01:14 – The Energy Three-Body Problem
* 04:16 – Shale Revolution & Forecasting Misses
* 08:42 – Webber’s 2029 Energy Predictions
* 09:42 – Why Efficiency Still Matters
* 13:37 – Gasoline, Natural Gas & Texas Exports
* 18:13 – Electrifying the Texas Oil Patch
* 19:45 – Why Webber Is Bullish on Geothermal
* 23:32 – Nuclear’s New Momentum
* 26:27 – The Three-Part Energy Transition
* 33:30 – Scarcity, Flexibility & Data Centers
* 39:11 – Build Faster, Then Career Advice
* 45:15 – Closing & Outro
Resources
People & Organizations
* Joshua Rhodes (LinkedIn)
* IdeaSmiths (Website - LinkedIn)
* Michael Webber (Website - LinkedIn)
* Webber Energy Group (Website - LinkedIn)
Company & Industry News
* US power use to beat record highs in 2026 and 2027 as AI use surges, EIA says
* GE Vernova expects to end 2025 with an 80-GW gas turbine backlog that stretches into 2029
* A tour of global geothermal projects in progress
Books & Articles Discussed
* Annual Energy Outlook Products - Archive
* Energy Policy Act of 2005
Related Podcasts by Energy Capital
* Interview with Energy Expert Dr. Michael Webber
* Drilling for Geothermal Power and Storage with Cindy Taff
* More Power that’s Faster and Fairer
Related Posts by Texas Energy & Power
* Reading & Podcast Picks — March 4, 2025: Data Centers, Nukes, VPPs, and More
* The Growing Importance of Energy Efficiency, Reading and Podcast Picks
Transcript
Joshua Rhodes (00:03.726)
Hey everyone, and welcome to the Energy Capital podcast. I am really excited to have Dr. Michael Weber on to talk about, well, energy. He’s an energy guy, and I’m really excited to talk to him about energy and Texas energy and all kinds of things. Most of you probably know Michael, but just really quickly, he’s got a PhD from mechanical engineering from Stanford. He’s worked at Rand, various clean energy incubators, really been in kind of the energy space for a long time.
Joshua Rhodes (00:32.472)
But really the kind of the main areas right now that Michael’s he’s a double chaired professor at the University of Texas, which is pretty rare thing. The Sid Richardson chair at the LBJ School of Public Affairs and the Cockrell family chair number 16 in mechanical engineering. He’s a former CTO at Energy Impact Partners, which is a big climate clean tech venture fund and a former chief science and technology officer at Engie, one of the world’s largest energy companies, as well as a founding partner of Ideasmus upon which he and I work together.
Joshua Rhodes (01:01.688)
So he really sits at the intersection of engineering and policy and commercialization. Welcome to the Energy Capital Podcast.
Dr. Michael Webber (01:10.008)
Thanks for having me. Very excited to be part of the conversation today after being a long time listener.
Joshua Rhodes (01:14.574)
And so you really are kind of like a rare three world energy person. I mean you’ve kind of like gone across the spectrum from engineering to policy and you know commercialization. One of the things that this actually reminded me of and I’m gonna go off script almost immediately is kind of like the three body problem. You’re familiar with the three body problem in classical mechanics is that it’s basically impossible to predict the motions of three things that are gravitationally
Joshua Rhodes (01:42.786)
connected to each other at the same time. you feel this way in your three worlds? An engineering policy in the technical space? Like, is it similar?
Dr. Michael Webber (01:51.34)
That is a great orbital mechanics reference. did my undergraduate degree in aerospace engineering at UT. I took a class on orbital mechanics from one of the famous professors, Zabihay. Professor Zabihay taught that. And we could solve the two-body problem. You cannot solve the three-body problem. You can only approximate it. So you’re exactly right. And it does feel like this tension between engineering policy and markets or commercialization are in tension where you can’t completely solve the problem with all three. Although in orbital mechanics, you do get alignment if one’s swallowed.
Dr. Michael Webber (02:19.47)
where the planets align or the different celestial bodies align. And in my observation, at least in the United States, things work best when policies and markets and innovation are all aligned. If they’re all pointed the same direction, amazing things can happen very quickly. And so I like this sort of idea, like you can’t solve it perfectly, you can kind of get close, you can do some numerical approximation, but sometimes you have alignment. And if you have alignment, then great things happen. So let me give an example of that from like 2005 to seven timeframe, the Energy Policy Act of 2005.
Dr. Michael Webber (02:49.454)
in other things were happening where the policies were calling for more domestic production. We more natural gas in particular. The markets were calling for more natural gas production. Natural gas prices were quite high, say 2003 and other years. So the markets were calling for more natural gas. The policies were calling for more natural gas. And the innovation engineering was also unlocking a lot of new natural gas, which was a combination of technologies of hydraulic fracturing and horizontal drilling. So we had engineering policy and markets all aligned.
Dr. Michael Webber (03:16.044)
The world flipped, the whole shale revolution of producing so much oil and gas in such a sudden turnaround flipped geopolitics on its head. Where we went from LNG imports to exports, we went from feeling at the mercy of foreign countries for their oil and gas production to feeling a little more confident on the energy stage globally. That was a remarkable instance where things aligned. And we don’t have that very often in energy, frankly, for the decades before that.
Dr. Michael Webber (03:41.164)
We had groups calling for less production because of environmental concerns. have policies that inhibited production. The markets and innovation work there. So we often have misalignment, though when you have alignment, it goes quickly. And that’s another cool thing from Celestial Mechanics. So maybe we should write an article that says, what Celestial Mechanics teaches us about the energy three-body problem. That’d be a great op-ed. Let’s write that essay.
Joshua Rhodes (04:00.239)
Like we’re getting work done immediately even when we’re doing a podcast. This is great.
Dr. Michael Webber (04:04.204)
Yes, our to-do list just grew though, unfortunately.
Joshua Rhodes (04:07.106)
folks
Joshua Rhodes (04:07.307)
are interested in Three-Body Problem, there’s actually a Netflix series on it right now based on a series of books that have been written.
Dr. Michael Webber (04:13.026)
Yeah, and I feel like I should watch it. I hear it’s violent though. I don’t know. So we’ll have to check it out.
Joshua Rhodes (04:16.91)
I read the first book. I think there’s three of them, which of course there would be three, a trilogy on the three body problem. But it is on my list of things to watch. So that was interesting that we immediately got into a situation where we’re talking about fracking just a minute ago. If you had gone just a few years before that, no one saw that coming or very few people saw that coming. I did an exercise once where I went back and looked at all of like the annual energy outlooks from the EIA in like early 2000s. And you know,
Joshua Rhodes (04:44.47)
natural gas was on the decline. were going to be importing natural gas. Like LNG imports were like big chunks of charts. Coal consumption was going up. And then, boom, this thing happened. Hydraulic fracturing that no one was really thinking about or people didn’t see, weren’t predicting. And it completely flipped the script, as you say. We started turned around import terminals and, you know, turned them into export terminals and, you know, made us one of the energy powerhouses of today.
Dr. Michael Webber (05:09.166)
So the era of say like 2001 to 2007, it was a uniquely bad era when it comes to EIA forecasting. And I’m not trying to pick on them because what they do is very hard and they’re better at it than anybody yet they were wrong. They were wrong on top level energy consumption. Like they thought energy consumption was going to increase forever in the United States.
Dr. Michael Webber (05:30.51)
The EIA forecast were particularly bad. They thought top level energy consumption was going to grow forever. They failed to anticipate the effects of efficiency, for example, with the light bulbs and cars and other things. They missed on the fuels. They missed on whether it’s imports or exports or whether it’s domestically produced. A lot of mistakes were made. And that’s something we should all keep in mind and use as a source of humility. It’s easy to be wrong about the future of energy when making predictions. So let’s keep that in mind. The first I heard of shale in eventually hydraulic fracturing was in 2007 from a man named Robert Heffner.
Dr. Michael Webber (06:00.174)
who is a very famous sort of producer of gas, especially, but only gas in Oklahoma. He and I were at a conference together. He gave a presentation of the Shell resource in the United States and how much energy is there. And I was like, I’d never heard of this. So I heard about it in 2007. Then T. Boone Pickens, another Oklahoman, came to Texas, UT, and gave a lecture around 2008. And he talked about it. So Shell really hit my radar in 2007, 2008. It had been on policymakers’ radars in 2005, the Energy Policy Act of 2005.
Dr. Michael Webber (06:29.934)
had some clarity around how hydraulic reaction would be regulated. And they clarified that it would be the states would regulate it to the federal government. People called that the Halliburton loophole. Dick Cheney could put that into place. Dick Cheney from only guess since she knew it very well. So it was certainly on the radar of industry. It was on the radar of policymakers and a few wildcatters, but it wasn’t on my radar until I heard them talk about it. And then so to my eye, the shale revolution was really born from around 2007, 2008. It really took off around then.
Dr. Michael Webber (06:58.862)
from basically a zero dollar industry in 2008 to $150 billion a year in 2019. So it from zero to 150 billion in 11 years. And then if you dig into history, people like George Mitchell and Mitchell Energy or Devon Energy have been trying it since the seventies or the eighties. If you go back in time, there was dynamite fracturing in the 1860s and 1880s. wasn’t hydraulic fracturing. So we’ve been knocking on the door for quite some time, but it didn’t really hit the poppet of conscience even for energy analysts like me.
Dr. Michael Webber (07:25.856)
until 2007 or so. So there were a few people who saw it. There are a people who were evangelical about it, sort of preaching that it was going to change things. And they ended up being correct. But I feel like a lot of people missed it. I feel like Exxon Mobil missed it. Like some really big companies didn’t have a place. So they had to do an acquisition. They had to buy their way into it at the top of the market. So a lot of us missed it. But there were a few people who were singing it from the rooftops. And that’s something for us to keep in mind that the conventional wisdom could be wrong.
Dr. Michael Webber (07:54.178)
but there’s always someone who’s got some idea of the future, they might be right, there’s also a lot of people wrong who are seeing it from the rooftop, so we can’t believe all of them. But hydroelectric fraction really changed things quickly.
Joshua Rhodes (08:02.914)
Didn’t in the 70s we also try to do it with nuclear? Didn’t we try to do nuclear bombs?
Dr. Michael Webber (08:07.086)
Yeah. So there was projects to put nuclear down hole in the seventies to do fracturing. There were a lot of down hole nuclear tests for weapons purposes, but also for energy production. In the seventies, there were a couple of oil crises. like, let’s try everything. Let’s turn coal into liquid. Let’s try gasification. Let’s put nuclear down holes. See how that goes. We looked at nuclear aircraft that made people nervous. So there was like all sorts of things we tried in the seventies. Some were goofy. Some ended up leading to the development of hydraulic fracturing, which ended up
Dr. Michael Webber (08:34.689)
been very beneficial in solar and wind got their start in 70s. Didn’t really make sense for decades, but we fiddled around with it back then as well. Yeah.
Joshua Rhodes (08:42.83)
No, absolutely. So now that we’ve talked about how hard it is to get things right, I kind of want to put you on the spot a little bit because you’re a bit famous or infamous, I don’t know, depending on how you want to say it, for making predictions about the future. But I appreciate you willing to talk about the predictions after you’ve made them because I most people make them and then try to forget them, right?
Dr. Michael Webber (08:59.086)
Dr. Michael Webber (08:59.387)
That’s right, and I write them down and I publish them and so everyone can hold me accountable which is I think silly. I’ve made but anyway here we
Joshua Rhodes (09:06.656)
are.
Joshua Rhodes (09:06.946)
Yeah, here we are. about a year ago, roughly, you made some predictions about kind of where US energy would be in 2029 or so, kind of at the end of the Trump administration. Let’s just take like intermediate step on these and just kind of see how they’re going and if you would change them or if you’re still bullish in the direction that you’re going. One of the first ones you said is you said you think that national energy consumption will decrease, which is kind of counter in terms of
Joshua Rhodes (09:35.65)
We’re talking about data centers and electrification, like building out all this infrastructure. So what do you mean by that? And do you still stand by that?
Dr. Michael Webber (09:42.798)
So the context was it was April 19th, 2025. So we’re at the end of three months of the Trump administration. So by the end of three months, had a pretty clear view of what the Trump administration’s energy priorities would be. And not really many surprises. They were the things that he said he would do in the campaign trail. And so trying to flash forward, OK, at the end of the Trump administration, which is four years, so three years and nine months remaining when I wrote this on LinkedIn, what will the energy situation be in United States on January 20th, 2029?
Dr. Michael Webber (10:09.862)
And I think I stand by all my predictions. I haven’t really changed my mind, but we can go through them. the first one is your point out, and I’ve even tagged this or pinned it or bookmarked it whatever on LinkedIn so people can come back and make fun of me when I’m wrong, is that national energy consumption will decrease. And primarily, that is my hat tip towards energy efficiency. That efficiency will continue to be deployed and that despite population growth and economic growth, we will use less energy as a nation four years from now.
Dr. Michael Webber (10:37.922)
than today, well, I three years from now, but at this point, because of the new devices we are implementing and the ones that come to mind for you like electric cooktops, electric heat pumps, electric cars, more efficient industry. We already have better light bulbs. So we already done what we can there, but we have more ways to do things that accommodate even the low growth of data centers because we’ll have so many savings elsewhere. If we just take cars and the electrification of cars and despite Trump and despite policies that are not friendly to electric cars, electric cars are growing in their adoption.
Dr. Michael Webber (11:07.534)
might not be fully electric, it might be electrified drive trains like hybridized drive trains, things that will reduce the amount of gasoline and diesel we need to move about. Plus we have work from home and zoom and other things. So we have a variety of ways that our gasoline consumption will drop. It actually peaked in 2018, will continue to drop. the electricity we use in place either for working remotely or for electric cars is all more efficient. We use less energy. And so we can get a couple of percentage points of savings just on light duty vehicle transportation.
Dr. Michael Webber (11:35.374)
and then add this to the devices, we’ll get some savings. And in fact, I think efficiency is the unsung hero of the last 25 years. In the last 25 years, the United States, our energy consumption has been level or dropped, but our population has grown 20 % and the economy has doubled or tripled, depending on whether you look at nominal or real terms. So I think we’ll continue to have population economic growth, but energy consumption will drop, primarily because of this efficiency play. I stand by that. I think that’s gonna be the trend that continues.
Joshua Rhodes (12:00.418)
You think it’ll be resilient even in terms of the rollback of the endangerment finding?
Dr. Michael Webber (12:04.044)
Yes, so the endangerment is a very big news. So endangerment findings been rolled back. We’ll also have a lot of lawsuits that will go to the Supreme Court. Who knows what the Supreme Court says. Sure. But I think at this point, the endangerment finding really drives EPA decisions, for example. Yeah. But it doesn’t drive all the market decisions and the market decisions are going to go by what’s easiest or cheapest to build. And that’s not going to be a coal plant. Yeah. And coal plants, even if they don’t have endangerment finding for CO2, do have to deal with ash and NOx and SOx, the precursors to acid rain.
Dr. Michael Webber (12:31.65)
And they have to deal with mercury and the mercury rules are from the Bush administration. Those rules aren’t going away. And so no one’s going to build new coal. And then we have all this gas and wind and solar batteries that are cheaper than coal. So we’ll shut that down and even cheaper than gas in some cases. And then if we look beyond the Trump administration to the rise of geothermal nuclear. So I think endangerment finding is kind of sand in the gear. I’m going keep using that phrase probably in our coverage. Sand in the gears, it slows down the progress, but doesn’t stop the progress. We’re still going to move towards cleaner stuff.
Joshua Rhodes (13:00.492)
Yeah, I I think for a lot of our industry to be competitive in the global market, if we’re going to be at trade parity with other countries, they’re not going to want to buy stuff that they can’t use that’s less efficient, right?
Dr. Michael Webber (13:10.062)
I mean, maybe the Trump administration doesn’t care about CO2, but customers in Europe do. Right. And so people making products here for European market or Japanese market, you name the market that cares about CO2, there are several, they sell to clean up the supply chain to satisfy that market. So I think those fundamentals haven’t shifted. In fact, Europe’s now got the C-band, the carbon border adjustment mechanism. So there are even policies in place that will push for cleaning things up, even if those policies aren’t domestic out of DC. Yeah.
Joshua Rhodes (13:37.582)
You touched a bit on oil consumption, gasoline consumption. One of the predictions you made is gasoline exports will increase. So where are we going to send that gasoline?
Dr. Michael Webber (13:45.902)
Yeah, so there’s a phenomenon going on right now for the oil and gas world where half the products laid out of a barrel, the barrel goes of crude and the refinery comes out roughly half gasoline. The other half is diesel, jet fuel, waxes and tars and things like that. The demand for diesel and jet fuel is increasing, but the demand for gasoline domestically is dropping and has been dropping. We’re in year eight of the drop of gasoline. And so that means gasoline will be cheap. So gasoline is pretty cheap in the United States right now. And that will slow down the adoption of electric vehicles, but not stop the adoption of electric vehicles.
Dr. Michael Webber (14:14.902)
So I expect we’ll dump cheap gasoline on the world markets to other customers around the world who might want it for their light duty transportation and older cars or other purposes. So I’m thinking to sub-Saharan Africa or other markets around the world that would be happy to have the gasoline, they’ll export it. Now that might be a uniquely American problem because the refineries in Europe already produce more diesel and jet fuel than gasoline. So they’re less at risk for this problem. The American refineries have been tuned for a hundred years to produce more gasoline. So I think we’ll have to...
Dr. Michael Webber (14:44.61)
find other markets for it. We still need our diesel and jet fuel. So the refinery is going to keep running. And they’ll have this excess gasoline, which will lower prices. We’ll find someone for it potentially.
Joshua Rhodes (14:54.742)
Yeah, I guess similar for natural gas, like you predict natural gas production will increase and LNG exports will increase. I similar things are that like finding customers and
Dr. Michael Webber (15:03.886)
And there are lot of customers for natural gas globally. There might be more customers for natural gas than gasoline. The way I think about it, I feel like we’re entering a natural gas era. had a wood era, coal era. We’re in an oil era. Natural gas might have overtaken oil in terms of consumption in the United States last year. If not last year, probably this year. We just are producing so much gas. We consume so much gas, but we produce more than we consume. So we have gas that we can export to customers in Europe or Asia who are happy to have it.
Dr. Michael Webber (15:32.014)
For us, that’s good because they might use that gas to displace some coal, or they might use that gas to make electricity to displace some gasoline in those countries, and that would be good for the environment. So I think natural gas as a nation, we’re leaning in, in the Trump administration. People are very angry about the Biden administration, but frankly, natural gas production and consumption grew a lot under the Biden administration as well, and in the first Trump administration, and under the Obama administrations. So natural gas has been on the rise, has been ascended for a while, and I’ll see that stopping anytime soon.
Dr. Michael Webber (16:00.586)
maybe in a few decades, but it looks like the next five or 15 years natural gas. That’s a really good run ahead of it.
Joshua Rhodes (16:06.232)
absolutely. I think we’ve been talking about this in more of kind of a US context. Like, what do you think this means for the traditional energy production in Texas and how these like new exports and other things like that? Like, what does that mean for Texas here?
Dr. Michael Webber (16:19.352)
Texas has a good export capacity. We actually all have the ports. We have the LNG refrigeration trains. We have a lot of pipes that can move the oil and gas from West Texas or Haynesville or wherever to the ports. We can export to other states in the United States, not just other countries. So Texas is in a position. But if you look at the oil and gas policies under Trump administration, they’re actually not so good for oil and gas. In particular, they’re bad for domestic oil drillers. So oil drilling is down 20 % or something in Texas.
Dr. Michael Webber (16:47.638)
gas drilling is up 10 % nationally. so drilling overall is down say 10 % nationally. The rise has been in gas, the decline in oil, and that gas drilling is mostly in like Pennsylvania. The gas we produce in Texas is mostly, least in West Texas, mostly associated gas. It is the gas that is associated with oil production. So as long as we’re drilling for oil, we will have a lot of gas in Texas from the West. But if we...
Dr. Michael Webber (17:12.462)
drill less for oil or produce less oil, we will eventually have less natural gas in West Texas. The Haynesville areas in East Texas probably will still keep producing these gases in demand. And so there’s already been some warning signs that the CAPEX or the capital expenditures, the drilling investments, new sites for drilling in West Texas are down. So far, oil production has not dropped because they’re more efficient or more productive per well. But you can anticipate that in 2026 oil production in West Texas might drop.
Dr. Michael Webber (17:41.262)
which means gas production in West Texas might drop, which mean prices might go up. That might be good for natural gas sellers. It might be tough for consumers. If natural gas prices go up, it might make our exports less desirable on the global scene, depending on what price Australia or Russia are charging or Qatar, you name your country. We’re competing in a global marketplace and American gas is always undercut on price other providers. But that might be harder if our gas prices go up because our oil production goes out. It gets a very tangled mess, is the guess I’m saying.
Dr. Michael Webber (18:09.514)
And Texas benefits and loses simultaneously from all these maneuvers.
Joshua Rhodes (18:13.326)
We’ve been talking about energy writ large and focusing in on electricity. I one of the policy decisions we’ve made in Texas is to electrify those oil and gas operations out in West Texas, right? And so, if we run into these other kinds of pressures, they’ve been talking about at the same time, we’re getting them cheaper energy to get the energy out of the ground. Is this a wash? Do you think it’s net positive, net negative?
Dr. Michael Webber (18:32.014)
One of the hidden heroes of the oil and gas success in Texas, certainly a lot of innovation in the oil and gas sector, hydraulic fracturing, horizontal drilling, but electrification of the oil patch. I believe that the West Texas production, the Permian, is the most electrified oil field in the world at any significant scale. And having access to cheap electricity has improved productivity. It’s cleaned up production by reducing the venting or flaring of gases in some cases. It’s also improved
Dr. Michael Webber (18:57.454)
improved the boost with these downhole electric submersible pumps. electrification of oil and gas helps keep it competitive while also making it more environmentally friendly because of reduced emissions. And so, I think if we keep expanding the grid and keep installing transmission lines, which I know you’ve talked about and thought about, that will keep electricity cheaper for oil and gas. That is a competitive advantage that we get to have in Texas that not every oil and gas patch in America or around the world has. I think that’s kind of cool. And then if you look at Governor Abbott really pushing to expand the grid, he’s really leaning in hard on nuclear especially, but
Dr. Michael Webber (19:26.99)
he seems friendly to geothermal and other technologies. We’re going to have a pretty diverse mix of electricity. We’re going to build a lot of power plants. That means in my mind, despite data center load growth, we might still have low prices and that’ll be really good for oil and gas. oil and gas benefits from a big cheap reliable grid, just like we all do.
Joshua Rhodes (19:45.804)
Yeah, at the same time, you you’re bullish on wind, you’re bullish on solar, geothermal, nuclear will stay roughly about the same. I think some of this transmission we’ve been talking about are going to benefit particularly those first two. You’re bullish on geothermal. Talk about that.
Dr. Michael Webber (19:59.35)
Also in geothermal, I don’t think a whole lot of new geothermal will come online before January 2029, but there’ll be some. I think we’re entering in a few years, the geothermal decade. We’ve been in a solar and battery decade. Before that, we were in a wind decade. And wind growth has slowed down a lot. Solar growth doesn’t look like it’s slowing down again soon, but geothermal is about to take off for a couple of reasons. The technology has gotten better, especially for drilling. The technologies for finding the pockets of heat has gotten better with startups like Zanskar and others.
Dr. Michael Webber (20:28.878)
The demand for the power is there. We have a new customer class, these data center companies that have a lot of money and really want round the clock performance, but they want clean, they want renewable. So geothermal meets a lot of those. Geothermal doesn’t really compete with wind and solar. It competes with nuclear or competes with natural gas or carbon capture. So geothermal looks pretty good. It’s a good hedge against gas prices and it’s a good sort of speed to power choice because probably you can get geothermal online faster than nuclear. So geothermal looks good. It also seems to be
Dr. Michael Webber (20:58.566)
a favorite in a bipartisan way. Democrats and liberals and environmentalists like it because it’s clean and renewable and sustainable. think Republicans like it because it leverages drilling technologies, it’s domestic. So it’s got unique bipartisan, well maybe it’s not unique, along with nuclear has bipartisan support. And I think that means you’ll get good alignment on policies at the state, local and federal levels. And so there’s support for the Trump administration. I think Trump doesn’t love it as much as he loves nuclear.
Dr. Michael Webber (21:26.182)
But he seems to like it and he’s not beating up on it for sure. So geothermal looks like a winner. And one of the things that geothermal can leverage is all the advances in drilling technology that have happened in the last 20 years. It will also make advances, but it can leverage other people’s investments, namely the only gas industry’s investments in drilling technology. The geothermal industry can ride that cost curve down. And then they have this stable around the clock performance and customers who have the cash to pay for it. So geothermal looks really good.
Dr. Michael Webber (21:53.184)
It’s limited in location. tends to be Nevada, Utah, California, like Hawaii, places where have volcanoes or tectonic activity. There are a few pockets in Texas where you can do it. What I like from the Texas perspective as a Texas patriot is even if we’re not producing a lot of geothermal in Texas, the companies are talent or know-how might be here. So there’s a real good Texas angle for this, even if it’s for a site in Utah.
Joshua Rhodes (22:15.522)
That makes a lot of sense. I was thinking about this concept of talking about multiple different constituencies. They probably won’t want to use this as a tagline, but carbon-free drilling or something like that or low carbon drilling. It’s like got both buzzwords for both sides of this thing.
Dr. Michael Webber (22:27.456)
Yes, it’s one of the few options that satisfies most different people’s priorities, which is really great. think that’s one reason why it’ll be a winner.
Joshua Rhodes (22:35.512)
Yeah, it reminds me of the Green Tea Party, which is a coalition of Sierra Club and the Tea Party in Georgia back in like the early 2000s. They got together to force the utility to let them put solar on their roof. And was the libertarians were like, you won’t tell me what I won’t do on my own property. Thank you very much. And Sierra Club was like solar. In the Venn diagram of things, I was like the one thing that they kind of agreed on, but it was powerful enough to force Southern Company to let them do it, which is not an easy thing to do. It worked. It worked.
Dr. Michael Webber (22:59.522)
right? Yeah, they wanted to push back against the utility control. Environmentalists wanted the low emissions profile and the cleanliness. So yeah, and that’s a sign and I think solar still has that by the way, solar opportunity to grow because it satisfies some libertarian instinct as well as some environmental instinct. And so you look at those solutions that get there, they’ll do okay. Nuclear doesn’t satisfy a libertarian instinct so much nuclear is very clean. It is very reliable. It needs a very strong hand from government that is back to succeed. So you have a
Dr. Michael Webber (23:27.778)
kind of intervention in the markets to really give nuclear boost, but some of the other options do.
Joshua Rhodes (23:32.364)
Yeah, nuclear feels like it’s gone through a bit of a renaissance too in terms of like, it’s acceptance. There’s a lot of new environmentalist movements that are very pro-nuclear, just like, okay, we got to build something. We can’t just say no to building everything. Like the new environmental movement has to be about building something. And it doesn’t seem like it’s getting beat up on as much as it used to.
Dr. Michael Webber (23:52.11)
feel
Dr. Michael Webber (23:52.21)
like this is my third nuclear renaissance I’ve watched in the last 20 years. Everyone feels different. This one feels different. It feels stickier for that reasons you said, which is the environmental movement has been sort of looking at nuclear with a wary eye for one time because of the concerns around nuclear waste or meltdowns or public risk. Some security folks have looked at nuclear with a wary eye because of the connections with weapons proliferation. But I think the security establishment’s more concerned about other things in the energy system. And environmentalists had come around to the idea like, okay, nuclear still needs a lot of water.
Dr. Michael Webber (24:21.87)
There’s a nuclear waste issue, but there’s technologies for that. But it’s got a really clean profile. It doesn’t have the air emissions that are toxic. It doesn’t have the greenhouse gases. So the environmental movement’s kind of come around on nuclear after a hesitant relationship for many decades. But then there’s a cultural movement where you have students at universities like, why don’t we build nuclear? So you see nuclear engineering students from Texas A &M on ESPN College game day holding them a sign like, we love nuclear. And this moment went viral. And you have like,
Dr. Michael Webber (24:50.264)
beauty pageant winner who’s in nuclear engineering working for Constellation. She’s talking about nuclear, a Brazilian fashion model. So we have like fashion models and beauty pageant winners and engineering students on college game day all seeing the same thing, which is nuclear is a part of the future. And so there is a youthful cultural force that’s very different than the people who had been promoting nuclear for many decades. There’s going to be older engineers who worked at a utility or something. So it’s very different profile. So nuclear looks good. And then what that sort of manifests itself as is
Dr. Michael Webber (25:20.416)
local state and federal policies as far as certainly Trump administration supportive. But as I mentioned, Governor Abbott supportive, but even cities like city of Austin doesn’t seem opposed, right? Austin actually has a six of a nuclear reactor. I think you started to get this political and policy alignment, which is really interesting.
Joshua Rhodes (25:35.018)
totally. So thank you for letting us go through your historical predictions, predictions from last year about still into the future. And so I’m hoping you can come on and we can do this multiple times and you can either be proved right over and over again or wrong. So switching gears a little bit. So some folks may know that every year we have the annual Weber Energy Group Symposium, which is at the University of Texas. I’m in your research group and it’s kind of a celebration of all the research that we do.
Joshua Rhodes (26:01.964)
in the group. But one of the highlights of that event is you kind of give state of the energy or whatever talk, like a big wide ranging talk about where we’ve been, where we are, maybe where we’re going in terms of energy. And to keep with the theme of this podcast, one of the big themes of that talk you gave was energy is going through a three-part transition, right? So could you tell me what is that three-part transition that you think energy is going through?
Dr. Michael Webber (26:27.086)
Yeah, now we’re on our third trilemma, our third three-part transition, I would say. to my eye, it looks like three dimensions of the energy transition we’re going through right now. One is expanding the energy system or particular, expanding energy access. We have universal energy access in the United States, but we don’t around the world. There’s a billion or more people who don’t have access to electricity. A billion or more people don’t have access to other modern fuels, say gasoline or propane or something. They’re using solid fuels like wood or caldunga or straw or something like that.
Dr. Michael Webber (26:55.274)
And then we have a couple billion people who don’t have access to pipe to treated water or sanitation. So the sole access problem to clean resources or modern energy forms. And part of the transition is to expand energy access so that those people will have access to the energy that you and I already have access to. So that’s part number one, expanding energy access globally. Second is cleaning up the energy system. Those of us who have access, have a lot of emissions or land or water impacts must reduce our impacts.
Dr. Michael Webber (27:22.86)
And the energy system generally gets cleaner per unit of energy and cleaner per person, but we have more people, so it gets dirtier as a whole. It feels like we’re hitting a turning point where the energy system will get cleaner on absolute terms, even as we have population economic growth. So we have to expand energy access, that’s part one, but to clean up the energy system, that’s part two. Part three is operate in a warmer world. A lot of our energy system was built, for example, in the power sector 40 or 50 years ago in the United States, the pipelines often built
Dr. Michael Webber (27:50.828)
long before that, or the transmission lines built long before that. So we have a multi-decade or century old system in many parts of the United States that was designed for a different population, different strain on the system from the population, but also different weather. So as the climate warms on average, that means we’ll have milder winters, warmer summers, so more heat waves and droughts in the summers, but also perhaps more frequent and intense polar vortices or these cold snaps, which we just had a couple weeks ago in Texas and...
Dr. Michael Webber (28:18.904)
five years ago with winter storm Uri and we had all sorts of winter storms. So we have warmer weather, which will strain the system if you design it for different weather. And the heat waves are a typical problem in Texas, but the heat waves are hotter and lasting longer. Think of the heat dome in 2023 where it was summer for like four and a half months or something. heat waves in early May and heat waves in November, that’s six months, I can’t even do my math, but the heat waves in November and it was so hot for so long, that’s a real strain on the system.
Dr. Michael Webber (28:47.096)
but it is accompanied by droughts. You don’t have the cooling water you need for the power plants. We also have more people doing irrigation, which means more electric pumps for water, which means the demand goes up and blah, blah, blah. So we have all these things, that’s a real problem. So expanding energy access, decarbonizing, operating a warming world, that’s what we have to do with the entire system. And a lot of these assets are kind of old. The newer assets will be easier to design for, but we have to work with what we got and a lot of what we got isn’t new.
Joshua Rhodes (29:11.682)
Yeah, no, I think sometimes, you for some people now the term energy transition is kind of a triggering phrase. We have any other ideas for other things?
Dr. Michael Webber (29:21.006)
Yeah, I’ve got a list of phrases we no longer we used to call energy revolution unacceptable for a while we talked about energy evolution that’s no longer acceptable. For the last few years, we talked about energy transition that’s also unacceptable. So there were now like a short list of acceptable phrases, meaning like non triggering for different constituencies, things like energy innovation or energy expansion or energy addition or energy abundance or energy dominance. And you hear like with Trump administration’s energy
Dr. Michael Webber (29:48.524)
dominance. Secretary of Energy Chris Wright talks a lot about energy addition and energy abundance. And I like the innovation. I don’t really like the word dominant. That sounds like you’re beating someone up. But these are the kind of the phrases that work with the Trump administration that are less triggering. But within, say, the concept of energy innovation or energy expansion or energy addition, we have a lot of opportunity to add a lot of cool things to the grid or to the energy system that are cleaner and higher performing and more affordable and more reliable.
Joshua Rhodes (30:15.566)
Oh, totally. And so, maybe we’re beating up on the term energy transition. I mean, as it’s become, I guess, embody what it means, is it getting anything wrong right now? Like in 2026, what is the phrase energy transition get wrong?
Dr. Michael Webber (30:27.458)
I feel like a transition is still happening. I feel like for the most part, the fundamental trends are still occurring. We have to label it something different. Energy dominance, I think means exporting a lot of energy to the world and dominating the geopolitics of the markets, which actually we started around 21 or 22. Like a few years ago, we became the biggest exporter of qualified natural gas. For example, the biggest producer of hydrocarbons in the world. So we were kind of already been energy dominant for years, but we didn’t call it that. The Biden administration didn’t talk about energy dominance. They talked about energy transition.
Dr. Michael Webber (30:56.514)
The Trump administration talks about energy dominance, but not transition, but not a whole lot has changed for the most part. Some of the rhetoric has changed. Some of the policies has changed. The market preferences haven’t changed a whole lot to my eye. No one in the markets is really clamoring to build a new coal plant and the people who own coal plants are actually looking to shut them down. But they’re often forced to keep them online, even if they’re expensive because of policy fiat. So I think the word transition is too triggering. We had to drop it, but what the markets are doing hasn’t changed a whole lot.
Dr. Michael Webber (31:26.732)
The biggest change of the Trump administration has been sort of the all out war on offshore wind. That’s where the president has had the biggest impact. He’s revoked the permits or tried to cancel five projects that are either operating or closed operating. All have led to lawsuits. He’s lost every one of those lawsuits. All five of those wind farms will operate or are operational. But it’s going be hard to build a new offshore wind farm. So that’s one distinct change from the dominance. And I was like, well, if you really believe in energy expansion, we’ll expand everything. So that doesn’t make sense to me.
Dr. Michael Webber (31:56.046)
But he’s got his preferred fuels and the fuels he doesn’t like. Onshore wind and onshore solar will also suffer, but not as badly as offshore wind. And onshore solar is too competitive to keep out of the bar. The markets just are calling for it. Yeah. Yeah. Wind’s actually started to slow down in 2021 in the Biden administration. Yeah. Primarily because its supply profile doesn’t match our load profile and the lines were getting congested. So the new power plants with solar are a good compliment to that wind. I think we just had different phrases, but
Dr. Michael Webber (32:25.42)
the trends are basically the same.
Joshua Rhodes (32:27.982)
But even so, you said like the output may be not matching our load profile. But if we add a bunch of data centers that have not exactly flat, but flat-ish load profiles, I think that that script could flip back.
Dr. Michael Webber (32:40.024)
I mean, data centers want round the clock load. That’s not wind and that’s not solar, but wind plus solar plus a little bit of battery looks pretty flat in most places because the supply profiles of solar wind are so out of phase that you might get there. Data centers, a key thing there is they’re rich, they’re in a hurry, and they have high demands on reliability. And so that’s why they can pay for geothermal and nuclear, which is exciting. But because they’re in a hurry, they can’t wait till 2029 or 2035.
Dr. Michael Webber (33:08.75)
And if you’re in a hurry, it’s going to be wind, solar and batteries. So the thing is there’s room for everybody. would say we need fast simplicity of wind, solar and batteries and it’s cleanliness. We need around the clock performance. We’re doable source like geothermal. need the round the clock performance of large scale dense options. There’s room for all of them, but they arrive on different timelines. If you’re in a hurry, you’ll start to say, we’ll pay for everything. We just want everything we can get.
Joshua Rhodes (33:30.008)
Yeah. Do you think we’re given that we need everything? Like are we in an era, are we entering an era of energy scarcity or energy abundance?
Dr. Michael Webber (33:37.582)
That’s a great question. So if you look at the backlogs for like say natural gas turbines at Siemens and GE, there’s a rush on gas turbines, primarily for data centers behind the meter, say they might want natural gas combined cycle power plants, which are really good for around the clock performance. For grid reliability reasons, there’s a rush for the aerodirative fast ramping gas turbines, which you don’t use around the clock, but use on the hours or days you don’t have say winter, solar or other options.
Dr. Michael Webber (34:02.936)
So there’s a rush on the fast ramping gas turbines. There’s a rush on natural gas to mine cycle, but there are backlogs at all the different manufacturers. And so you could say, there’s a backlog, there’s gonna be scarcity. But fundamentally, we have plenty of energy available in the grid. We don’t have plenty of power. The scarcity is only a few hours of a few days of the year. And if we get to operate flexibly, dialing down the data centers or water treatment plants or steel smelters or whatever, we actually are fine.
Dr. Michael Webber (34:29.646)
We’re having all this argument, seems like over a few hours and a few days of the year. The rest of the year we have access capacity. And I think what people will find in our finding again and again is that the fastest way to get more power is through flexibility, or you can ramp your load up and down. You and I don’t worry about that so much at our houses with our light switches and each vac and heating and cooling. If you’re a crypto miner, especially, but if you’re some other big industrial load, you could totally dial down your load at peak times.
Dr. Michael Webber (34:56.706)
And that flexibility is going to look really cheap and fast to bring online. And we’re already seeing that. So I think that avoids scarcity. So I don’t think we’re heading towards a scarce situation very quickly. The scarcity will solve itself with flexibility.
Joshua Rhodes (35:07.406)
I think you noted in that presentation, know, peak load is a challenge, but you know, the grid is utilized on average less than 50 % of the time or something like that. yeah, with these new loads that are causing a lot of these backlogs at Siemens and GE and others, are these new loads, data centers in particular, are they a problem or an opportunity?
Dr. Michael Webber (35:23.086)
Dr. Michael Webber (35:23.406)
I think they’re an opportunity. I know they’re hated because there’s a fear they’ll drive up electric rates. There’s a concern about the land impacts and the water use. People are worried that it’ll make electricity more expensive. If we do it the right way and data centers and other loads are flexible, then all that new investment of the grid will actually lower the cost for everybody. It should improve the capital utilization. So we have a multi-trillion dollar power sector. We use it less than 50 % of the time. But if we had a lot of new electric users to the grid and they’re able to schedule their load, like charge
Dr. Michael Webber (35:51.63)
management for electric vehicles or flexibility at peak times with data centers and crypto miners, then we’ll get greater than 50 % capital utilization of entry 60 or 70 or 80%. That means we’re using the same asset base, the same trillions of dollars, but for more kilowatt hours. And so for dividing the same trillions over more kilowatt hours, that’s a lower cost per kilowatt hour. I think that’s where we’ll end up a few years from now. The intervening fears will be very painful because it takes a little while to get there. So we’re going to feel rates go up rates have already gone up rates are on the way up.
Dr. Michael Webber (36:21.016)
But I think as we get through this crush, we’ll get to higher performance, lower emissions, lower cost. That’s where I think we’ll end up. And I think we’ll get there within three to five years. I don’t think we’ll get there in one to three years. So it’s going to be pretty politically painful incumbents for the next few years. In fact, we already have politicians paying the price, losing office because rates have gone up. So I think that will continue for another couple of years.
Joshua Rhodes (36:47.348)
You talk about we’re moving into a transmission scarce environment. Is that part of that short term? These issues or is that more of a long term?
Dr. Michael Webber (36:54.56)
It’s all happening right now. these transitions, I talk about the trilemma now with energy access expansion, decarbonization and operating normal world, but we’ve always had change. Sometimes these changes happen in a condensed period of like 10 to 20 years. And we’ve had prior energy transitions that were very rapid. We call that the industrial revolution or the second industrial revolution or the jet age or the silicon age and now maybe the next energy transition. So there is a timing situation right now.
Dr. Michael Webber (37:21.438)
And one thing we’ve been at for a while is we’ve generally had an excess of transmission capacity and those days are over. Because you can build new load, a new data center, a new factory, a gigafactory, whatever it is, in like two years or less. You can build a new solar wind farm in say a couple years, a new gas plant maybe in five years, new geothermal nuclear for like four to 10 years. But transmission historically is six years in Texas, say, but 20 years elsewhere. So the time it takes to build new load is faster than the time it takes to
Dr. Michael Webber (37:50.254)
build new supply is faster than it to build new transmission. And we’ve gotten away with this tiny mismatch because of excess capacity in the grid. But we’re running out of excess capacity in the grid. We’re running out of excess capacity at the power plants. So we’re going to have to manage everything a little better. And I think we’re going to expand transmission. It’s just hard to expand it as quickly as the other things. But if you ramp up on flexibility, then we can solve all that, I think.
Joshua Rhodes (38:13.548)
Yeah, there’s other parts of that too. think you mentioned that we’ve got a gas turbine backlog that’s masking a gas pipeline backlog. Like it’s not just one part, it’s all parts of the system that are going to have to like grow quickly, right?
Dr. Michael Webber (38:25.134)
Everybody’s in a hurry for everything. We’re all waiting two to five years for transformers and three to five years for turbines. And then by the way, a gas pipeline hookup might take four to six years as well. So there’s just a lot that has happened. And I think a lot of that is consequence of we haven’t really grown to the power sector for 20 years. We’ve gone from a level mode where you don’t grow to also grow very quickly. So we’re taking a very large lumbering, continentally sized industry, causing it to grow five to 10 % a year.
Dr. Michael Webber (38:54.782)
Software and other parts of the world have done that. know how to do it. But energy, power sector, we’ve kind of forgotten how to do it. We’ve lost our muscle memory. So we got to break ground quickly, get steel on the ground quickly, regulatory approvals quickly, get your investment lined up quickly. Anyone’s really done that since the 80s. So it’s been a while since we’ve had to learn how to do that.
Joshua Rhodes (39:11.736)
So if there’s something you could get every policymaker out there to understand about how the energy sector is changing different, how fast it needs to go, like what’s one or two things you wish every policymaker would know about this current state of the energy sector?
Dr. Michael Webber (39:24.014)
I think there are two things on my mind. One is we’re going through a capex wave, a capital expenditures wave that is at really rare levels. Yeah. Exceeds what we did in the 50s with interstate highways. It exceeds what we did in 2000 with rural broadband. It exceeds what we did with the railroads and canals in the late 1800s. It exceeds wartime footing in some cases. Yeah. So it’s really a dramatic level of investment. So this isn’t some kind of ephemeral fly-by-night thing. There might be a bubble, but the numbers are real. Like there’s big investment.
Dr. Michael Webber (39:53.784)
just appreciate the scale of the situation and the opportunity. And secondly, I think we’ve been too fussy about our culture war of hating particular forms of energy or preferring certain forms of energy. I think if we just let people build stuff and make it easier to get our permitting, for the most part, we’ll build the right things. It won’t be perfect. We have to be willing to tolerate some imperfection. But I say the moment is calling for us to build quickly, let’s go quickly or else we won’t meet the moment. And if we...
Dr. Michael Webber (40:22.36)
build quickly and meet the moment, we’ll mostly meet it the right way. We’ll have a few things we build that we regret without a doubt. But I’d rather have a few things that we regret that we built than not build enough and then regret having missed out on one of the most important economic and national security opportunities in history. So I guess I’d rather err on the side of build too many things we regret than build too few capabilities that we’re really going to need in the future. Otherwise, you’re not going to meet the moment. Those are the two things I say is a real sort of interesting historical time. Let’s build. Let’s catch up.
Joshua Rhodes (40:51.052)
Yeah, I think it also exceeds the moon landing, but like we landed a few times. We haven’t been back. Maybe we’re going back. I don’t know. We’ll see what Elon’s talking about in this day and age.
Dr. Michael Webber (40:59.114)
He’s talking about Mars too, so who knows, right? So a lot of things going on and mostly private capital for that. that market has evolved as well.
Joshua Rhodes (41:05.902)
Okay, this is a part of the podcast where we’ve flipped the script. You’re now interviewing me. I’m on your podcast. What do you want to ask me?
Dr. Michael Webber (41:13.588)
What I want ask you, I love this. Okay, so if you were to talk to 18 year olds graduating from high school, and they’re confident in what they should do with their future for studies or career or whatever, would you recommend they go into energy?
Joshua Rhodes (41:27.374)
Totally. Of course, I’m going to be biased, but I definitely would recommend folks go into energy. I that doesn’t necessarily mean that you’re out on an oil rig or being in utility space. There’s lots of companies that are in this space. But in particularly, I think I would focus people on electricity. And again, I’m going to be double biased here that that’s what I study. That’s what I do. The thing is, I’ve heard people say the phrase peak oil. I’ve heard people say peak gas. I’ve never heard anyone say peak electricity like a real straight face.
Dr. Michael Webber (41:54.328)
peak electron. Yeah, that’s interesting. Yeah, that’s right. I’ve never heard that either. That’s right.
Joshua Rhodes (41:58.094)
Yeah. So I don’t think anyone said it because I don’t think anyone’s ever thinking that we’re going to use less electricity over time. mean, energy perhaps, but I think the electrification part of that continues to grow. think energy is going to be, or electricity in particular is going to be in a growth phase. Particularly right now, it’s in a massive growth phase with AI and data centers and all these other types of things. But yeah, I know I think it’s a great place to be in. I think some of this stuff AI is not going to be able to take over, at least in the next employment cycle wave or whatever. We’ll see where we eventually get to.
Joshua Rhodes (42:26.604)
I know we’re all kind of struggling with this, but yeah, think energy is a great place to be.
Dr. Michael Webber (42:29.966)
And electricity in particular, which says maybe it’s because you’re biased, but you also did your own thinking and arrived at that conclusion. Electricity is an exciting place to be and that’s why you’re excited. Okay. Can I ask you one more related following question? Yeah. Let’s say those 18 year olds are trying to decide to go to college or not. If they don’t go to college, should they just start working or get like a technical trade or some other thing? So what would you tell that 18 year old?
Joshua Rhodes (42:51.63)
Yeah, I I think if you’re not going to go to college, I mean, right now, sticking with the theme like electrician is a great career to be in. I’ve heard rumors of folks like working on data centers. Now you’re working multiple over times and other types of things, but making the equivalent of like three, $400,000 per year salaries right now. Hard work, a lot of work, but it’s probably hard to automate that at least at this point. I mean, if you’re going to college, I mean, I think one of the things that has changed that I would say, I mean,
Joshua Rhodes (43:18.914)
The advice I always give to people is study the hardest thing you like because it opens the most doors. If you like history and you like physics, equally, then study physics, minor in history or something like that. Just like study the hardest thing that you like. And that’s been the traditional advice that I’ve given to most that are going to college. Right now, I would focus on critical thinking. We’ve pushed hard into STEM. We’ve pushed hard into computer science and coding and a lot of this other kind of stuff. A lot of these things that are rules-based and...
Joshua Rhodes (43:45.888)
AI is pretty good at that kind of thing. AI is really good at things that have definite rules and even getting into law and like other types of things. But if you can still have the critical thinking to know how to guide these systems that we’re starting to use more, I think that’s still going to be valuable. I mean, it’s going to evolve over time. But yeah, so study the hardest thing that you like, but don’t skip liberal arts, the humanities, other types of things that make you actually have to think because some of the other types of technical thinking are getting co-opted by some of these.
Joshua Rhodes (44:14.678)
machines but kind of the bigger questions I mean I think we’re still going to need to know how to handle to guide the systems wherever they want to go.
Dr. Michael Webber (44:20.91)
I think I told you, I would say get a trade, pipe fitting, welding, electrician work, something, and study philosophy or humanities. So you could do both, by the way, you don’t have to do this, but I think humanities prepares us better to deal with the complexities of society that hasn’t presented itself yet with rise of AI and everything else. But the trades will call for a lot of work and lucrative careers and will be displaced by robotics later than coders who will be displaced by AI today or have been displaced.
Dr. Michael Webber (44:49.664)
I think I agree with you. There’s some combination there, perhaps.
Joshua Rhodes (44:51.918)
Yeah, and I still think things like engineering are extremely valuable in terms of just understanding systems and how they work and being able to like look at something and say, that’s a perpetual motion machine. That kind of intuition I think is super valuable. Intuition is I think is going to be lacking going into the future as we offload some of our cognitive processing.
Dr. Michael Webber (45:10.008)
That’s a point. And you only get that intuition from grappling with the problem and thinking that through. Yeah, totally.
Joshua Rhodes (45:15.726)
Michael
Joshua Rhodes (45:16.548)
Weber, thank you for being on the Energy Capital Podcast.
Dr. Michael Webber (45:19.096)
Thanks so much, I’m having a great conversation as always.
Joshua Rhodes (45:22.168)
Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make better sense of how the energy system actually works, share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy and Power at texasenergyempower.com. That’s where you’ll find every episode, every article, and our latest updates. We’re also on LinkedIn, X, and YouTube.
Joshua Rhodes (45:51.534)
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, Ideasmiss, Austin Energy, or Columbia University. A big thanks to Nate Peevee, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
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The Data Behind Texas Reliability with Max Kanter
4 mrt· Energy Capital Podcast
Behind the scenes, every few minutes, the ERCOT system generates tens of thousands of price signals, outage updates, and operational reports that demonstrate and drive the cost and availability of electricity.
Most of that data is public. But how can Texans access it?
This week, Joshua Rhodes talks with Max Kanter, chief executive officer of GridStatus, about the gap between public data and practical visibility and application, and why that matters in Texas.
In this episode, they discuss:
* Why public grid data is harder to use than it would seem.
* What real-time pricing signals reveal about system stress.
* How outage and congestion data shape ERCOT debates.
There are more than 70,000 pricing nodes across U.S. energy markets, updating every five minutes. ERCOT alone produces enormous volumes of operational data.Those signals often spotlight stresses on the system before they show up in prices and control rooms.
As Texas adds new industrial loads and faces continued risks from extreme weather, more policymakers, analysts, and large customers want to know what’s coming. They’re looking for distress signals.
On this week’s episode, Josh and Max tell you where to find them – and what to do with them.
Timestamps
* 00:06 – Welcome, Max Kanter intro
* 02:00 – Computer science, AI shifts
* 03:32 – What is GridStatus?
* 04:36 – What users see first
* 05:31 – Who uses GridStatus today
* 06:56 – Tiers, hobbyists, accessibility
* 07:52 – AI tools, new builders
* 09:47 – Why a business existed
* 12:49 – Early demand validated product
* 14:18 – From carbon to markets
* 16:44 – Data scale, nodal pricing map
* 32:20 – Flip script, Rhodes on public role
Resources
Guest & Company• Max Kanter - LinkedIn • Grid Status - LinkedIn
Company & Industry News• The power grid is hard to understand. This startup is trying to help. • Why We Invested in Grid Status
Related Podcasts by TEAP• The New Rules Behind ERCOT Prices with Andrew Reimers • Who Pays for Texas Grid Growth? - Roundtable Discussion• Texas’ Load Growth Challenges – And Opportunities, with Arushi Sharma Frank
Energy Capital Podcast is produced by ClarityForge Studios.
Transcript
Joshua Rhodes (00:05.778)
everyone, and welcome to the Energy Capital podcast. I am really excited to have Max Cantor, CEO of GridStatus on today to just talk about data, all the data that are coming off the grid and everything like that. If you’re steeped in grids, you’ve probably heard of GridStatus, you’ve probably seen at least a screenshot of dashboards and things like that floating around social media. But one of the things I wanted to bring to this podcast was to kind of dig a little bit deeper into some of the more technical side of things. And I promised all
Joshua Rhodes (00:35.278)
I’d be listeners that I wouldn’t completely bore you to tears with data, but we are going to talk about it a little bit because it is so important. So we have Max Cantor on. has a bachelor’s and a master’s of computer science from MIT. And I don’t usually name check theses, but this one actually caught my eye. So his master’s thesis was the data science machine emulating human intelligence in data science endeavors, which sounds like a harbinger of basically AI. We’ll get back to that here in a bit.
Joshua Rhodes (01:05.294)
He started off as CEO and co-founder of Feature Labs, which was acquired by Alteryx in 2019. At that point, was the VP of Engineering at Alteryx for the next couple of years before going back to MIT as a visiting scholar in the Data to AI lab, where at that time when he was at MIT, launched Grid Status in August of 2022. And the tagline, or at least the one that’s on his socials is, the future of the electric grid runs on data and AI. Grid Status provides
Joshua Rhodes (01:34.562)
data and insights for the understanding, investing and operating of the electrical grid. And our goal is to be the most trusted source for whatever is happening on the grid. Max Kanner, welcome to the Energy Capital Podcast.
Max Kanter (01:47.522)
Thank you, Joshua. Happy to be here.
Joshua Rhodes (01:49.452)
Yeah, I should probably say full disclosure, I’m actually a client as well. So I have a subscription to GridStatus. So thank you for making it so easy to get all of these data.
Max Kanter (01:58.456)
Yeah, that was the goal from the very beginning.
Joshua Rhodes (02:00.46)
Yeah, no, I think it’s worked out quite a bit. It’s much easier. I wanted to actually immediately kind of go off script. Your bachelor’s and master’s are in computer science. Do you have a feel for what computer science means today, kind of in this age of AI? How has it changed since you were there?
Max Kanter (02:16.312)
Computer science as an academic field is younger than many, right? So things like biology or physics, right? Computer science, I’d have to double check, but I think it’s probably a phrase that has only formally been studied for less than a hundred years. And so it’s come a long way in just that time from something minor to one of the hottest topics. One of the things I think is so interesting though about AI in particular though is
Max Kanter (02:42.87)
A lot of the earliest computer scientists, their goal from the very beginning was to create an artificial intelligence. That’s actually how they thought about computers, know, replicate the stuff that humans were doing. And so in some sense, the goals actually haven’t changed at all, right? I think over the decades, think the biggest thing that’s different is, really the size of the compute that’s being undertaken to actually accomplish it. And, know, one of the things, you know, thinking back to when I first started doing say academic computer science is so much.
Max Kanter (03:12.45)
of the forefront of the field was happening within universities. think nowadays when you think of, well, where’s the frontier AI research happening, know, oftentimes it’s thought of outside of universities. And I think that’s one of the biggest changes I’ve seen. And why is that? There might be many reasons, but think one of them is just the size of the compute and the cost of doing that.
Joshua Rhodes (03:31.916)
Yeah, that’s big implications of particularly like size of the compute. I mean for the electricity grid, right? Because you got to get a bunch of electricity to that. I apologize for throwing you a curveball right off. Yeah, totally. So, I’ve introduced grid status a bit. With someone who’s outside of energy, I think a lot of folks who listen to this podcast are kind of in energy. But if someone’s outside of energy, ask you what you do. Like how do you describe, you know, grid status?
Max Kanter (03:41.998)
that makes it more interesting.
Max Kanter (03:56.514)
Yeah. I would say grid status is the homepage for the electric grid. I think a lot of people, when they think about the grid, well, first they don’t actually think about it that much. You you plug something into an outlet, you get power, right? But behind the scenes, it’s actually the world’s most complex machine. And even though it’s this big machine, it’s not like you have one person operating it or one person putting power into it or one person regulating it. It’s actually very complex with a lot of different stakeholders.
Max Kanter (04:24.82)
And so, yeah, the role of grid status is to be, you if you have a question about the grid or you want to have an understanding about what’s going on, we want to be the first place people go. And so, yeah, we’re the homepage of the electric grid.
Joshua Rhodes (04:36.27)
That’s cool. Grid status started out as doing mostly data, Mostly hosting data and having data. Now there’s a lot more dashboards and other types of things. Can you just talk through a little bit, of like, if someone goes to the homepage of the electric grids, you say like, what are they going to find?
Max Kanter (04:52.748)
Yeah, I’d say that’s kind of the core product and technical question we’re trying to answer or solve, I should say. Right. And what are you going to find is, you know, the answer really is like, whatever is relevant for you. And we serve a lot of different types of users. Some people care a lot about, you know, what the fuel mix on the grid is. Some people care a lot about pricing. Some people care about forecasts and, know, grid operations for the coming days. And so our goal at GridSat is to show you what’s relevant.
Max Kanter (05:22.088)
And we’ve honed in on that over time.
Joshua Rhodes (05:24.76)
Nice. And talk about like you said for different types of users, what all types of users do you have?
Max Kanter (05:30.84)
I would say anybody who cares about the grid is part of our user base. And that’s one of the things that’s most exciting about grid status for me. think if you rewind five, 10 years and you were to say, your electric grid data and analytics company, who do you serve? The answer would be pretty narrow. Energy traders, utilities, power plant operators. What I see with grid status is really have expanded the pie of people who can make use of the data. So today I think some of our bread and butter
Max Kanter (06:00.318)
are people who are buying and selling large amounts of power. You know, it’s energy traders, it’s asset operators, but we’ve also expanded it. We have researchers, we have these like large loads who need to be responsive to the grid. Even the regulators, you we talk to people in the federal government who are trying to make laws about the grid and, the fastest place them to figure out what’s going on is grid status. Very large swath of people.
Joshua Rhodes (06:26.572)
Yeah, know used to, someone would ask me what was going on in ERCOT, which is a common thing. Well, when people start asking me what’s going on in ERCOT, I start to get worried. I used to go to the ERCOT website and, you know, grab a screenshot of something, but now more or less it’s to the grid status web page. You got better colors and fonts too, by the way. So that’s really nice. In the app, you’ve got multiple different tiers of access that folks can get. I noticed recently you put in like a hobby tier. Are you starting to see more hobbyists out there? Like using the data?
Max Kanter (06:55.928)
For sure. And one of the fun challenges with grid status is, you know, didn’t even actually start this thinking about me as company. It was very much around how do we make it easier to get access to this data? And that came from a personal problem I had. I wanted to build some actually machine learning algorithms for forecasting the price of electricity. And well, I needed to get access to the raw data to train those models. And so a lot of our journey over the last couple of years has been, you know, how do you solve the problem of making data accessible?
Max Kanter (07:25.262)
but also do it in a sustainable way. I mean, it’s not cheap or free to be collecting all this. And so, yeah, I think one of the fun things about Gridset as you talk about the tiers is yeah, we have evolved into, we have a free offering that is for everybody, hobbyist offering that you mentioned, and then also professional enterprise offerings and figuring out what goes into each bucket and how to, you know, sort of serve everybody is kind of like the fun side of developing the business.
Joshua Rhodes (07:52.398)
Kind of sticking to that hobby tier, you know, one of the things that AI has done is really democratize coding. You can write a thousand lines of code so much faster. It was so much less, how do I say, experience than it used to take. I mean, these models are pretty great. mean, like, have you seen anyone create anything from the hobby tier or other things like that? Really, since like, AI has made it lot easier to code?
Max Kanter (08:15.822)
I would say so. think from the kind of building blocks of it all, we’ve seen people actually take our tools and then wrap them in basically libraries to make it very easy for the AI tools to automatically consume them. so, you know, one of the things I think a lot of people end up using that for and on the hobby tier is there’s this whole group, I’d say of like policy advocacy, nonprofits, you know, people that have in the past had very limited budgets.
Max Kanter (08:45.784)
to get access to this data. Having to go to the ISOs themselves is either too time prohibitive, right? Or yeah, you know, as you kind of alluded to, like too expensive to actually write the code to grab all the data. And so using grid status, they’re able to kind of further whatever policy objective that they have. We don’t personally take any sort of stance, but it is definitely a goal of ours to supply the facts and the data for people to explore and make their case.
Max Kanter (09:13.024)
And so, yeah, like one of the things I’ve seen with the AI tools is I’m thinking of like a particular example of somebody in Illinois, you know, that’s where GridStats is actually based here in Chicago. So, you know, something that I personally like to pay attention to, you know, someone who’s a nuclear advocate, right? And, you know, being able to pull the data from GridStats about how nuclear power, the amount of generation in Illinois, where it’s getting imported and exported, how that affects costs. Yeah, it’s, you know, somebody who’s definitely very talented, but they certainly don’t have a computer science or programming background.
Max Kanter (09:42.51)
you’re not able to use our free and hobby products to accomplish that.
Joshua Rhodes (09:46.712)
So one of the things you said there was talking about like not being able to go to the ISO to get the data. I mean, I’ve done that before, right? Like I’ve played mostly in ERCOT. So I’ve gone to ERCOT’s website and downloaded a CSV that has like five minutes worth of data for like all the nodes and like all these other types of things. it just, well, one, they can only host like so much of it. You know, it was free, but it was very painful, right? We’ll give you the confidence that a business could be built around, you know, cleaning it up and getting it.
Joshua Rhodes (10:15.318)
organized in one spot.
Max Kanter (10:18.062)
Figuring out how to gain the confidence, I think, is a key part of the story of grid status. So early on, there was no goal to make it into a business. I had my own goal of actually trying to build out a vehicle to grid product. And I was like, in order to implement vehicle to grid, you need to have a sense or a forecast of where you think prices are going to be the next day. And so I started this grid status actually as an open source library, just going to be a little side quest.
Max Kanter (10:46.572)
to make it easy to collect this data. You know, if I had this problem, I’m sure somebody else is going to want to run this code. But yeah, I’d spend a few weeks on this and then get back to building Veil Code to Grid software. So actually, yeah, first I didn’t think there was a business here. However, I put that code out publicly. So I put it out on a product called GitHub, right? Where software developers hang out and, you know, very quickly met a handful of people who were saying things like, Hey, I wish this existed when I started my current job, because I would have just used that directly.
Max Kanter (11:16.098)
Right. And then people started asking for more features. They started contributing some code themselves. And, you know, that’s when I realized that, I’m not the only person who has this problem. And at that stage, it wasn’t even, let’s turn this into a company. was like, well, let me just listen to what people are asking for and build out some of those things. Because honestly, what gets me most excited and motivated is to build a product people use. And so you have someone basically telling you they’re going to use this software. you build that X, Y, and Z, you know, I did it. And.
Max Kanter (11:45.474)
Basically what happened is, you one thing led to another. We started adding in data sets and then people were like, you know, I don’t want to run your open source scrapers myself. I wish I could just hit an API and it would return me the data from your servers. And so then we built out the API and then people were asking, well, how do I even know what data is on the API? So then we built out the homepage that would just let people go to a URL and see what data is available. Right. And then they were like, couldn’t you show the data like this? And we started showing the data like we started showing, let’s say all the LMPs in one place.
Max Kanter (12:15.182)
And like, could you put that on a map? And we built that out. And you know, one thing led to another. And you know, now we have tens of thousands of people that are coming to this site every month because we just listened to our users. And somewhere in the middle there, I realized if a couple of people find this very useful, you we could probably find a lot more and find one people who are willing to pay.
Joshua Rhodes (12:34.222)
I think I was probably one of the people emailing you in 2022 when you started this about like... You were. How to use your Python, like how to use the API or how to use... I mean, I literally have it up on my computer right now. was pulling data the other day.
Max Kanter (12:48.002)
You probably don’t realize how impactful those early emails were because, I didn’t come from the energy industry. You guys had to know there was business here and it’s like, you know, I came from the general purpose data science world. I kind of just stumbled into energy really as a hobby project, right? Related to the vehicle to grid stuff I was mentioning. And so, yeah, you know, you are someone who obviously knows the energy industry very well. And so being able to see people like yourself feel like there was an unmet need. That’s when I said like, Hey, there are some underserved people.
Max Kanter (13:16.95)
And that’s ultimately, you know, I think if you were to say like, what is the actual inflection point to starting a business is, well, find a big industry, pretty hard to find a bigger industry than energy. And then, you know, find a group of people that have an unmet need or are underserved by the incumbents and build the product that they want. I think that’s a pretty good formula for starting a company.
Joshua Rhodes (13:39.662)
Okay, maybe this makes sense in terms of like the timeline of kind of when grid status started, like you were still at MIT. And you mentioned it just a minute ago. When was that inflection point when you’re like, okay, this is no longer the side hustle, this is going to be the full hustle? Like when did that flip?
Max Kanter (13:55.19)
Yeah, I would say I waited as long as possible. We signed a contract with one of our first customers who actually happened to be a very large entity in the grid who I never thought would decide to be the first customer of a startup. But I was like, yeah, mean, if they’re willing to pay us, we should make this formal and really go after it.
Joshua Rhodes (14:17.646)
That’s really cool. So you’ve kind of alluded to it a little bit like before you were working on machine learning algorithms to do like be able to grid. I think there was something in there about looking even for the carbon intensity. How did that play into when you went on your side quest looking for all this data?
Max Kanter (14:34.638)
So
Max Kanter (14:34.998)
I’d say early when I thought about energy, I think what was very much in the zeitgeist was climate, carbon emissions. I think, you you try to buy like an airplane ticket. say, you know, paying $10 more and we’ll, you know, reduce your emissions or, you know, buy some offsets. And so I think when I first thought about energy, like that was very top of mind at the time I saw, you know, there’s probably a dozen different startups doing carbon accounting. It’s a very like, I’d say intuitive.
Max Kanter (15:04.824)
thing when you say you want to get into energy, where should I start? And so definitely that was on my mind. I still find it very interesting, but what I kind of found in building the company is like, what I really had taken for granted was the part that wasn’t intuitive. And that was how the electric grid actually works. The markets themselves, you know, there’s not an inherently best way to run an electricity market, right? And that’s why we have a bunch of different ISOs and they all do things slightly differently.
Joshua Rhodes (15:32.728)
Besides Texas though, right? Sorry.
Max Kanter (15:35.182)
besides
Max Kanter (15:35.642)
that’s the best way. Yeah. And maybe they are the best way. And I think part of the reason why they can make a claim for that is because they have chosen to make decisions in a certain way. And maybe other people will all copy them, right? But that’s kind of like the beauty of the markets. Even though that’s where I started, like what was really cool about this whole space is just how many layers to the onion there are. And, you know, can just continually appeal them back at a greater understanding.
Max Kanter (16:02.286)
And, know, from someone outside of the industry, was like drinking from the fire hose. And that’s why I got really lucky to, ultimately meet my co-founder, Connor, who kind of unlike me had spent his entire career in energy because now I had someone to help me learn this stuff. And then the feedback loop of working with the data, working with someone who, you know, is clearly an expert in these energy markets, that kind of just caught the bug. And I’ve been focused on that ever since.
Max Kanter (16:29.474)
What still amazes me is actually how little public awareness there is. And I know I’m preaching to the choir here with you, but you how little public awareness there is of just how both interestingly complex these markets are and how consequential there are.
Joshua Rhodes (16:43.694)
Yeah, I mean, you can kind of see it like in the data, right? know, prices are formed every five minutes. Dispatch decisions are made, you know, in RCOT every five minutes are getting bids every 15 minutes. I know RCOT the best and so I know there’s other regions that may do things differently. But like, what’s the velocity or volume of data that you pull in every day? How much are you adding to your suitcases full of data like every day?
Max Kanter (17:11.374)
So
Max Kanter (17:12.174)
there’s a lot of different dimensions to think about it. So I think the first dimension is how many different data sets do we collect? Right. So we collect, you know, over 500 data sets at this point from all the different regions or all the different grids in North America. And then each of those data sets, you know, might have updates ranging from every 10 seconds to once a day or once a week. And then within each one of those updates, and this is where I think
Max Kanter (17:39.402)
It is an example of something that didn’t come intuitively to me is the granularity of some of those updates. So the pricing information is perhaps the most interesting where there’s not just one global price of electricity on the grid, as you know, it gets down to like the node level and there are 70,000 plus nodes in the United States that are getting priced on a real time basis. And so that’s a huge dimensionality to this data that we’re updating.
Max Kanter (18:06.728)
And all that kind of led to like one of my favorite product releases we’ve ever done at Grid Status was making our nodal price map. So without an account to Grid Status, you can come to the homepage and you can see we’ve manually kind of mapped the geographic locations for over 20,000 of these nodes. And you can see for free without an account, how those are getting updated across the United States in one place every five minutes. you
Max Kanter (18:33.698)
As far as I know to this day, there’s no one else that offers that product. Going back to the point about being, do we become the homepage of the grid? To me, that’s the best encapsulation of it. Where can you go to see the most granular data possible? The data, you know, being updated every five minutes at 20,000 locations in one spot, kind of summarize in a very intuitive way. That’s been my favorite product release probably. We’re trying to one up it, but that’s a tough one to beat.
Joshua Rhodes (18:58.61)
awesome. I look forward to seeing how you’re going to best a map. People love maps. mean, one of the things that I learned, one of my most popular tools that I created, it’s an online map that shows the levelized cost of electricity in every county in the US and you can change the cost of fuel and it’ll update and all that kind of thing. And people love maps. And I think it’s intuitive because people know how to get around maps, right? They may not know how to get around the box plot or a scatter plot or something like that, but people generally, you’re from somewhere on that map.
Joshua Rhodes (19:26.85)
your kid lives somewhere on that map, right? Like it’s just intuitive. I think you’ve done a great job of getting all that data onto one map. Cause I know what we used to do back when X was called Twitter, whenever like people would want to look at price of electricity across different regions is you’d have Vercot’s map and it would have its color scheme. You’d have MISO’s map and you’d have SPP’s map and like all these others. And then you would like put them together, but the colors would be different. Yeah, it is nice just having them all in one place.
Max Kanter (19:55.584)
Yeah. I in one place I’d say is one of the most repeated value propositions I hear for users of grid status. You know, they say I used to have six different tabs open at a time when I wanted to figure out what was going on in the grid. Yeah. And now I just have one, you know, and they say grid status is my new tab in my browser. And so, you know, that’s not the only thing that we do, but what differentiates us, you can get this data from a bunch of different places. It is public. You go to the ISO directly.
Max Kanter (20:23.992)
but to have one place that is super fast, convenient, intuitive, know, what I think we do best.
Joshua Rhodes (20:30.39)
I mean, I’m probably sound like a fanboy here, but like, I mean, it’s true. The all in one place thing is so useful. I used to know my way around the aircott website pretty well, probably less so now because I haven’t had to go get it anymore. But if I remember one time trying to go look for KISO data and just like, it’s so completely different. Like I had no idea of where to go and like what I was doing.
Max Kanter (20:51.586)
Yeah. And you know, it’s one of the interesting aspects of the fact that it’s public data because, know, I think a lot of people say, Hey, this data is public. And I say, yeah, it’s public, but if you don’t know where to find it, does it matter? And so part of the value proposition is just making public data discoverable. And you know, one other point I want to make too is, we don’t necessarily see ourselves replacing any of the ISO sites. Like we wouldn’t exist if each of the ISOs didn’t put in tremendous effort.
Max Kanter (21:20.972)
right, to make this data accessible in public. So, you one of things that we do is, you we try to be very transparent to our users of where did we get it on the ISO site. We know we have a data catalog and on every page we have a link back, you know, as much as we can to like literally, you know, click this URL and you will see the exact same data on grid status and in the ISO. No, there’s no goal to like this and intermediate. It really is just to be, we’re not the source of truth, but how can we be kind of like the public record?
Max Kanter (21:50.784)
of where people find the data.
Joshua Rhodes (21:52.428)
Yeah, citations and getting that as an academic, that’s super helpful all the time. You mentioned how you started as kind of data, now you’re doing kind of these insights. How do you choose when you want to publish an insight and maybe explain, we’ve talked mostly about grid status, posting a whole bunch of data, making it easy to get, but what is this insights piece?
Max Kanter (22:13.142)
Yeah. So the way I think about grid status, what we build is it all starts with, you know, we live in the energy markets ourselves, right? Like we spend all of our days thinking about what’s going on. And so to actually do that, right, we build the tools that we want to use to understand what’s going on. And so that’s why we started collecting the data. That’s how we build the different applications for monitoring it. And then the third step is to share out what we see.
Max Kanter (22:41.134)
And so, know, insights and this new insights product you’re referring to is essentially us just sharing out what we’re finding and how we’re using our tools to find it. Because then the fourth step is to then enable our customers and our users to do the same thing. Then the process repeats itself with them living in the markets alongside of us, building out the tools, right? For all of us to use it better, sharing what we see. And so, you know, the insights release is really meant to kind of flush out our platform. We have the data.
Max Kanter (23:10.222)
You have the tools to understand it. And then of course, the final, you know, actionable analysis of what’s going on.
Joshua Rhodes (23:16.226)
Are there any data sources or are there other things that you found really interesting that you wish people knew more about? is there some undiscovered piece there?
Max Kanter (23:25.998)
Yes. I mean, the true answer is yes. I mean, I think almost every customer I talk to, they’re not using our entire catalog. In probably 99 % of cases, right? Like they haven’t spent as much time clicking through parts of these sites that we have, or we just talk to so many people every day. Like if a customer requests a data set and we add to our catalog, it’s now available to everybody as well. This discoverability question, I think it’s actually very pertinent to how we develop a product.
Max Kanter (23:54.862)
Cause one of the biggest challenges we’ve had, you know, I’ll say over the last few years is, know, when the site started, it was very simple. We had a dozen data sets and we visualize a dozen data sets. Now we have 500 data sets. can’t put 500 data sets on the homepage. And so what happens is as you start building out your breath of data and functionality, you make it kind of harder to find things. And so I think about that a lot for, you know, a particular customer and their use case, how do you make it possible for them to find?
Max Kanter (24:24.438)
And so like an example of something that comes up a lot is like people want to know outage information, you know, which power plants are going offline, which transmission lines are going out, which of these things are happening, you know, on a scheduled basis or which ones are, you know, unexpected, right. And both of those, you know, have very different implications for operations pricing. And so I want all of our customers to find many different data sets, but that’s one in particular that I was trying to point users to because
Max Kanter (24:53.4)
They don’t always realize how much publicly available information there is in that regard.
Joshua Rhodes (24:57.452)
Yeah. Do people ever come back to you and say like, this is what I built with your data? Has anyone ever done that? Said, Hey, I built this cool thing. Like I just wanted to share it with you.
Max Kanter (25:06.99)
all the time, I’d say, you know, some of the really cool things are, you know, I’d say like the people who are actually physically participating on the grid. Okay. Right. So, you know, I think when you think about say like some energy traders, you know, a lot of them are virtually trading power, right? They’re kind of taking a position in one market and then later closing out that position in another market. And they’re not ever physically producing or consuming power.
Max Kanter (25:37.038)
Other users of ours, so like one of our users is Rayburn Electric Cooperative, a municipal generation transmission co-op, you know, in Texas. They actually service, I believe, know, 600, 700,000, you know, people and their member utilities. Right. And what’s really cool about their usage of grid status is the stuff that they build is, you know, actually translating to the physical world. Take a little bit of a tangent.
Max Kanter (26:04.728)
One of the things that really attracted me to the grid and energy from my previous world, or my previous life of really working in AI and data science was, so much of software never crosses that boundary into actually making a physical impact. so energy really felt that way. So we can influence decisions about how power plants are generating power, or people are building things on the grid, or where and when they’re deciding to buy power. That has just this early clear
Max Kanter (26:34.062)
physical real world implications. And so yeah, I could talk about Rayburn Electric, they’re a big user of ours. They actually became an investor in grid status as well. The stuff that they’ve built and just how they’re kind of rising to the challenge of the demand growth that they’re seeing is really cool. And we’re just along for the ride trying to build out some software to help them do that. But it’s always cool to see the stuff that they’re building.
Joshua Rhodes (26:56.396)
That’s really cool. If you’re talking about electricity, particularly like electricity grid, there’s a lot of carbon implications like that. There’s climate stories that are happening. How has grid status been used to talk about the climate and the impacts from the electricity?
Max Kanter (27:10.648)
I’d say one of the biggest ways I think we play a role in that story. First thing you need to decide is where is your power coming from? And when I say where is it coming from, like what generation, what fuel sources is it coming from? So one of the most prominent things we show on grid status is the basically generation stack. How much power is going from nuclear, solar, wind, natural gas, oil, and you know, the list actually goes on like some parts of the country.
Max Kanter (27:38.584)
For example, in New England, like they actually burn wood to generate power at times. And so, you when you think of the climate conversation or carbon or anything like that, it’s aware, how are we actually generating the power? And I believe a lot of people, they have very strong views and biases towards what they want the generation sources to be. And, some of those might be well-founded, very well-founded, but you need the data to actually back it up. And so, know, how is Goodsad contributing to that is like,
Max Kanter (28:08.194)
How do we make sure people who have very different opinions on where we should generate our power, how do we make sure they’re at least talking with the same facts, right? Having a conversation, you know, looking at the same data, understanding what’s going on together. And so one of my favorite things that happens with grid status and our visuals is like, we’ll have two people share the exact same picture of California’s fuel mix with solar in the middle of the day, taking up a huge share and decreasing prices.
Max Kanter (28:37.674)
Some people, people who are proponents of solar will share that and say one thing, people who are proponents of natural gas will point to a different part of the graph and share that. People who like batteries will point to the same graph. And so that to me is like one of the most powerful things. And I would say a very divisive kind of topic of how we should be providing power to the grid and what do we optimize for the effect that people can use grid status to be looking at the same data, I think is a huge win. And that’s kind of the role we hope to play.
Joshua Rhodes (29:08.14)
Yeah, that source is like ground source of truth. People who can have arguments but from the same set of principles or same set of facts or like same set of like data. It’s actually kind of rare these days, right? I remember the same thing like when I built the online map that I built, I mean that was one of the things that we saw was, you know, people would take the map. It has the same math underlies it. It’s very simple like calculating the levelized cost of electricity. People could put their own cost and their own fuel costs in there and it would update and then people could
Joshua Rhodes (29:37.87)
basically use it to discourse with each other, but they were starting from like a ground truth, right? They weren’t able to like manipulate things. that says, guess it feels like that translates here. You’re starting from the data and like people can do whatever they want, but if they’re using your product, they’re not going to be able to manipulate it, which seems like it’s a really good place to be.
Max Kanter (29:58.162)
Yeah, that all goes back to our mission, right? We want to be a centralized place that people can go to to understand what’s happening. two different counterparties in a transaction or, two different policy positions, right? They can take their stance, but making sure they have common ground on the facts is I think pretty enabling.
Joshua Rhodes (30:19.714)
Yeah. So do you have the data you need now to do your carbon accounting for charging your electric vehicle?
Max Kanter (30:25.39)
Short answer is yes. The longer answer is I thought when I started GridSats to get this data, was going to be a four week side quest and that would get back to building what I wanted. Turns out it’s a lot more complex than I expected. for example, we started 2025 with 200 datasets in our catalog. We ended 2025 with over double that. And the pace has kept up in 2026. So I thought that this was a very concrete
Max Kanter (30:54.894)
discrete challenge of collecting data about the grid. It really isn’t. And so I think at this point, the goal is not to get back to building vehicle to grid software, but it is to enable users and our customers to build that. know, since embarking on grid sets, you know, I’ve learned of so many different use cases and honestly, just like companies and organizations I didn’t even know existed a few years ago, but are very important for the operations and reliability of the grid.
Max Kanter (31:23.106)
Data has become table stakes for these companies to operate, right? And just making sure that they have what they need. We will always keep on trying to get the best data available to make even better vehicle to grid or other kind of innovative use cases like that possible.
Joshua Rhodes (31:37.934)
Yeah, absolutely. You 500 datasets. We talked a little bit about like how much you’re pulling every day and the granularity. If you had to count all your data points, LMP at this time is one point. Do you have any feel for how many data points you have in your database? Multiple databases. How many trillions? I’m assuming it’s trillions.
Max Kanter (31:58.808)
Fair to say hundreds of billions. Fair to say that. It depends how you count a data point. But yeah, hundreds of billions for sure. But like we’re collecting like tens of millions of rows of data a day. And each of those rows of data have multiple columns. You can multiply it out. It’s a lot of data, put it that way.
Joshua Rhodes (32:19.638)
Yeah, I’m sure it is. Okay, so one thing that I am asking folks is like, if we could flip the script right now, you’re interviewing me. Is there a question you would like to ask me?
Max Kanter (32:30.232)
I do have a question for you. So before Grid Status, I had completely taken the grid for granted. One of the things, you know, following you over the years is you are one of the more visible voices talking about the grid, you know, both in, you know, I’d say close industry circles, right? But also more broadly in the mainstream media and, national publications. I guess, how do you approach, I guess, that role? Because I find there’s a lot of needles to thread.
Max Kanter (32:59.936)
And so, yeah, I’m curious how you approach that role of being a very public face of the grid.
Joshua Rhodes (33:05.73)
When I started, my dissertation work was on Smart Grid 1.0. So this was like money coming out of the American Recovery and Reinvestment Act after the Great Recession area. Like I actually wanted to look at green roofs and other types of things, but they’re like, hey, we’ve got this project looking at Smart Grid. And I’m like, what is Smart Grid? And they’re like, yeah, we’re going to figure that out. As I dove deeper kind of into the data, I just got really comfortable there. I just got really comfortable looking at how homes are using energy and looking at how
Joshua Rhodes (33:35.596)
that would translate to, you know, what home makeups were and that type of thing. And I had a mentor, Dr. Michael Weber, who like he was also in the media quite a bit and he couldn’t do all of his media stuff. And he would just suggest me for things that he kind of couldn’t get to. And so I just I’ve never really been afraid of trying new things. And so I just kind of like tried it and turned out I’m pretty good at talking in analogies in a way that normal people could understand kind of these complex things. And so just being able to take the complexity of the grid or in the data to underlie it.
Joshua Rhodes (34:05.398)
and put it into terms that normal people can understand. Like I was just pretty good at that. So I just kind of kept going with it. And then once you get in someone’s, know, Rolodex, they tend to keep calling you. So.
Max Kanter (34:16.206)
Awesome. Does it feel like a lot of responsibility?
Joshua Rhodes (34:19.244)
You know, it does actually because I don’t ever want to be wrong. Like if I’m going to be interviewed or asked about something, I’m going to go do research. And in these days, it’s generally pulling a lot of data and looking at things. And part of that research is going to grid status and looking and seeing kind of what’s going on in MISO or wherever. I think that one of the tricks is never getting over your skis, being able to appropriately caveat things.
Joshua Rhodes (34:47.277)
I do have like a little bit of a good setup such that like if folks are wanting to interview me, it’s generally they’re looking for an expert so they’ll actually make me sound smarter than I am, which helps me out quite a bit. And so maybe that’s actually what it is. Is there actually looking for someone smarter so they make me smarter? I don’t know. We’ll see. But anyways, Max Cantor, thanks for being on the Energy Capital Podcast.
Max Kanter (35:08.328)
My pleasure, anytime.
Joshua Rhodes (35:12.024)
Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make better sense of how the energy system actually works, share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy and Power at texasenergyempower.com. That’s where you’ll find every episode, every article, and our latest updates. We’re also on LinkedIn, X, and YouTube.
Joshua Rhodes (35:41.39)
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, Ideasmiss, Austin Energy, or Columbia University. A big thanks to Nate Peevee, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

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Who Pays for Texas Grid Growth? - Roundtable Discussion
25 feb· Energy Capital Podcast
Texas’s new era of electricity demand is forcing policymakers to walk an unprecedented tightrope.
The state has to keep the lights on – and it has to make sure that Texans can afford to do so..
Massive load growth from data centers, population, and electrification is teeing up existential questions for the ERCOT grid. How do we build what we need without overbuilding? And how do we avoid burdening households with costs that businesses and large users should be paying?
Those questions framed our latest Energy Capital roundtable with Matt Boms and Dr. Joshua Rhodes.
Why bills are rising faster than people expect
Utilities across the country are planning massive infrastructure investments over the next several years, and Texas is leading the way. Between new generation, transmission, and distribution upgrades, the price tag for this growth is substantial.
Texas has covered recent load growth primarily with a mix of solar, wind and batteries. Some state leaders have prioritized new gas plants as well, though capital costs for these facilities has more than doubled in some cases, even as wait lists for turbines have grown.
At the same time, transmission and distribution companies are filing rate cases tied to resiliency, reliability, and growth. Those investments often show up in rates years before customers see any economic benefit from load growth.
What’s driving costs matters more than ever
As large new loads, especially data centers, request connection to the grid, the question of who pays becomes unavoidable.
The basic principle is simple: if infrastructure is built for a specific customer, that customer should bear the cost. If infrastructure provides broad system value, then costs should be shared. Problems arise when all customers pay for expensive upgrades to cover loads that may be temporary or never fully materialize – especially with transformers, substations, and core hardware now costing multiples more than they did just a few years ago.
Without guardrails, Texas risks building expensive infrastructure that everyone pays for, even if demand disappears for the energy that infrastructure is meant to support.
Underused tools
There are ways to blunt this load-growth pressure.
Distributed energy resources (i.e. community power or local power), demand response, and energy waste reduction can reduce peak demand and delay or avoid costly grid upgrades. In many cases, these solutions are faster and cheaper than traditional investments in poles and wires.
Analyses show that even modest levels of community power can save ratepayers meaningful amounts of money by deferring transmission and distribution spending while also delivering wholesale market value.
One way or another, decisions made in upcoming utility rate cases will lock in costs for decades.
Grid growth is real. Infrastructure costs are rising. Ignoring either won’t protect customers. The state must align costs with the parties driving them, wringing out value from lower-cost flexibility strategies before committing to the most expensive build-outs.
If Texas effectively walks the line between affordability and reliability, this period of load growth can strengthen the grid without punishing Texans who rely on it.
Timestamps
* 00:06 – Rising Costs, Rising Stakes
* 01:17 – Load Growth and System Pressure
* 03:16 – Gas Dependence and Fuel Risk
* 06:21 – New Generation Costs and Competition
* 07:05 – Oncor Rate Case, $830M Request
* 08:27 – Who Pays, ERCOT vs Other States
* 12:08 – Driveway vs Highway Cost Test
* 15:33 – Capital Bias and Regulatory Incentives
* 18:49 – Avoiding Rate Shock, Role of DERs
* 24:07 – Higher Prices, Solar Payback Effect
* 34:12 – Missing Price Signals in Distribution
* 37:05 – Final Takeaways and Wrap
Resources
Hosts Platforms
* Texas Energy & Power - LinkedIn, Twitter (X), and Bluesky
* Micalah Spenrath - LinkedIn
* Matt Boms - LinkedIn
* Texas Advanced Energy Business Alliance (TAEBA) - LinkedIn
* Joshua Rhodes - LinkedIn
* IdeaSmiths
* Webber Energy Group, UT Austin
Company & Industry News
* Electricity rate hikes slash commercial solar payback periods by 33%, says Wood Mackenzie (pv magazine USA)
* Rising retail rates are accelerating commercial solar payback periods (Wood Mackenzie)
* The Value of Integrating Distributed Energy Resources in Texas (Advanced Energy United)
* TAEBA news page, DER study links (Texas Advanced Energy Business Alliance)
* CenterPoint raises 10-year spending plan to $65.5B (Reuters)
Related Podcasts by TEAP
* More Power that’s Faster and Fairer, Roundtable Discussion (TEAP)
* Why Are Utility Bills Rising So Fast? (Powerlines) (TEAP)
* Distributed Energy Resources and all-of-the-above energy solutions (TEAP)
* Texas’ Load Growth Challenges, And Opportunities (TEAP)
* Texas Needs a Vision for Customer-Side Solutions (TEAP)
* Where the Grid Goes from Here, Reading and Podcast Picks (TEAP)
Energy Capital Podcast is produced by ClarityForge Studios.
Transcript
Micalah Spenrath (00:05.55)
Hi everybody and welcome back to the Energy Capital podcast. I’m your host, Makayla, and I’m joined by Josh Rhodes and Matt Bonds. We are at an interesting place in the energy transition. Energy costs are rising. Utilities are planning to spend trillions of dollars across the country to keep up with rising energy demand. And at the heart of these macro trends is us, the consumers, the payers of electricity bills. So that raises a question. How do we build the grid that we need today?
Micalah Spenrath (00:34.868)
and tomorrow without overbuilding it or pricing people out. I’d like to dig into what’s driving energy costs, where utilities are planning to spend those billions and trillions of dollars, and how we can modernize the grid in a way that’s reliable, efficient, and still affordable. So setting the stage, demand for energy is rising, outpacing traditional energy system planning frameworks and timelines, and utilities are in the middle. Challenge with meeting that demand and keeping costs.
Micalah Spenrath (01:03.778)
to consumers reasonable. So starting with the primary question, what is the primary driver of these increased energy costs in Texas or nationally?
Joshua Rhodes (01:17.038)
You know, there’s just this massive growth in electricity. There’s like a lot of things kind of coming together, kind of been kind of a perfect storm here, right? It’s like one across, you know, the US electricity growth has been flat. It’s been growing in Texas. Texas has been an exception to other places. I mean, really demand growth has been kind of flat, right? And managing a system that is just kind of going from day to day, not really changing is much different than managing a system that’s growing. The amount of inputs you need to that are just different.
Joshua Rhodes (01:46.734)
A lot of the utility spending and buying has been responding to storms or just replacing things kind of at the end of their life, but not really building for growth. And that’s just a different mindset. The big topic right now is like data centers and like all this other kind of stuff driving up demand. But I mean, even before this, 2022, 2023, before we taught the internet how to talk to us, we were already expecting.
Joshua Rhodes (02:11.532)
electricity used to go up, right? We were already looking at electrification of buildings and electrification of transportation and kind of reshoring of like, you know, manufacturing and all this other kind of stuff. I mean, we’re already looking at a lot of that, but then AI is here, you know, among us and demand is going up. There’s still hangovers from like, you know, COVID supply chain. Surprisingly, it’s really like at the same time that we’re looking to grow everything that we need to buy to facilitate that now costs like way more than it did five years ago. It’s kind of a perfect storm.
Joshua Rhodes (02:41.518)
Onomat, you got any extra thoughts?
Matt Boms (02:43.66)
I think Josh said it perfectly. The pie is getting bigger for everyone, right? Everything’s getting more expensive. We’ve got supply chain issues. And at the same time, I feel like we’re in the best possible place to meet all of this load growth. Michaela, you know I’m a glass heffal kind of guy. And I tend to think that where else would you rather be living and working when it comes to which market is best positioned to meet all of this load? And I think we’re seeing the answer play out in front of our eyes with all the action that’s happening in ERCOT, right? That’s true.
Matt Boms (03:11.362)
So yeah, I’m feeling more optimistic by the day. think it’s a huge challenge, but I think we’ll be able to meet it.
Joshua Rhodes (03:16.216)
some other interesting things in there. As I was thinking about what types of fuels and things like that that we’re going to use to meet this electricity sector growth. I think if you look at the interconnection queue, we’re going to build a lot of solar and storage, or what is like chock full there. we have gigawatts of natural gas in that queue as well. And long term, ERCOT’s gotten about 45 % of electricity from natural gas. I mean, there is pressure on natural gas prices, right? mean, they fluctuate.
Joshua Rhodes (03:45.55)
We’re going to export more from LNG and like how associated gas production is dependent on the price of oil and like all these other kinds of things. know, natural gas can be volatile in terms of its fuel price, which we saw in 2022 in Russia invaded Ukraine, natural gas prices tripled over two years. They tripled. And then two years, they came back down. It doesn’t mean that some other shock couldn’t do that as well. And 25 years ago, there was first generation tech bubble. thought we were going to be building a bunch of data centers for, you know, pets.com and
Joshua Rhodes (04:15.586)
what the original tech bubble that was out there and through efficiencies and switching to cloud and like a whole bunch of other things that demand growth really didn’t materialize. And there were utilities and builders of natural gas turbines and things like that, that kind of over invested, overbuilt and kind of got burned in that space. And I think there’s a bit more discipline right now in terms of, okay, we see the growth, maybe we’ll output of this factory by 20%, but we’re not going to increase it by 120 % or something like that, right? I think there’s some kind of
Joshua Rhodes (04:45.016)
things going there. And just, it made me also think of back in the seventies, even going further back, we actually used a lot of oil to generate electricity. And then we had the energy crises of the 1970s that kind of got us off of using oil for electricity because oil got super volatile. I don’t know. It just makes me think, could that be something that happens in gas too? I mean, probably not in the near term, but long-term it could be interesting to watch.
Micalah Spenrath (05:10.742)
Yeah, I think the word that stuck out to me there was discipline. So I think disciplined utility spending is music to my ears. So hopefully, hopefully we will implement some of the lessons learned from the 70s and prior. So for me, from what I’ve been seeing, a primary driver to increased energy costs nationally, but also Texas, is that
Micalah Spenrath (05:34.58)
utilities are leaning into natural gas in order to meet some of that demand. And as you noted, there’s fuel costs associated with that. There’s higher operating costs associated with that as compared to some of the other technologies at our disposal. So I think it’s really interesting to see that natural gas is still playing a very large role in utility strategies, even though the cost of natural gas is increasing. So that’s based on EIA data. So I think that’s part of it, right? And then I think another
Micalah Spenrath (06:04.12)
contributor to increased prices is barriers to low-cost energy deployment, whether that be market-driven or policy-driven. So if we don’t have as many low-cost electrons on the grid, you’re going to be spending more on things like natural gas. So that’s definitely going to drive up prices as well.
Joshua Rhodes (06:21.23)
Even like the costs for the gas power plants are up, right? When we do grid modeling, we used to do like a thousand bucks a kilowatt, right? That was like our thing for like a natural gas combined cycle. then somewhere now between, you know, 2,500 and 4,500, depending on which study you’re looking at. And does that include new pipeline infrastructure and all this other kind of stuff? Which is interesting because we did a study last year or two years ago that looked at how cheap does nuclear have to get versus when it becomes competitive in like a unbundled or deregulated kind of market.
Joshua Rhodes (06:51.84)
If we’re at 4,500 bucks per kilowatt for like combined cycle, that’s about where it started to look really competitive, which is just interesting to note. We’ll see, like, you know, do people think those are long-term prices or whatever? It is an interesting point.
Micalah Spenrath (07:05.122)
Yeah,
Micalah Spenrath (07:05.482)
okay. Continuing on, so looking a little bit deeper into utility spending. So as I mentioned, utilities are planning to spend trillions of dollars across the nation through 2030. And much of this investment is to expand capacity, modernize the grid and infrastructure, and then also respond to demand growth. So bringing it closer to home, looking at Encore in Texas, Encore recommended their revenues be increased by approximately, I think it was like eight
Micalah Spenrath (07:33.998)
$130 million or something like that, looking at about a 13 % increase over their current annualized revenues, which is a lot. That proposal can translate into meaningful bill increases for customers if regulators ultimately approve them. We haven’t found out the results of that just yet, but what they’re looking at primarily is resiliency and reliability projects and really infrastructure build out, which is not a surprise given the cost of service regulatory model we have in Texas.
Micalah Spenrath (08:04.226)
So when we talk about utilities needing to invest all of these billions of dollars, millions and billions of dollars, what types of projects are truly necessary for reliability and what might be deferred or approached differently? Simply put, are utilities investing in the right places in order to meet demand but also meet responsible costs for consumers?
Matt Boms (08:27.162)
I’ll take a stab at that Josh. My feeling on that Michaela is most people just want to know who’s left holding the bag. Who’s going to end up paying for all of this? Like if we were in a house state affairs hearing and chairman Todd Hunter were asking us questions, the first thing he would ask us is who’s ultimately paying for this? And that’s again, like bringing it back to Texas. That’s where we’re lucky that our utilities are just transmission and distribution and they’re not generators. So going back to the gas projects that are being built.
Matt Boms (08:56.556)
That’s happening all across the country with vertically integrated utilities who ultimately they’ll build the plant, they’ll own the plant, they’ll put them to the right base and they’ll get the guaranteed return on the gas plant, right? Regardless of what happens next, we know what the steps are, it’s predetermined, right? Versus in ERCOT, the company that builds the plant puts themselves at risk because they’re bidding into the market, right? So we’ve got a great market-based system where...
Matt Boms (09:21.824)
In my view, we can have that conversation on transmission and distribution infrastructure and what we need to meet all the load. at least when it comes to what I’m seeing, what I’m hearing from folks in other states is a whole lot of construction that may or may not be worth it for ratepayers. So that’s at least one thing that I’m grateful for working in Texas, in Urquhart specifically.
Joshua Rhodes (09:41.888)
Yeah, I think the national numbers are just some of the reading we’re doing before. It’s something like almost 71 billion in rate increases between now and 2028, like across the country. Like it’s not a little bit of money, right? I’m curious what the number would have been five years ago before all of this. this triple that or double that or is it similar magnitude? I don’t know. We’re just paying more attention to it lately. Some of these companies are starting to come out with like plans for this, which I think a lot of the big tech companies, now that they’re moving into hard infrastructure.
Joshua Rhodes (10:11.64)
They just didn’t really know how to deal with that. Like when you’re doing software and you’re dealing with a different kind of use case than you are for like grid infrastructure, sunk costs, fixed costs, things that other people are kind of paying for and kind of the whole Silicon Valley ethos of move fast and break things, you know, doesn’t work super great in the utility space, right? Whether that’s electricity or water or other types of things. And so, mean, there’s been some interesting stuff like, I think Microsoft recently came out with community first plan for like data centers that they’re going to
Joshua Rhodes (10:40.866)
shoulder a whole lot more of the cost and not ask for some of these tax abatement programs that maybe exist in certain regions, which is really interesting. I’ve been saying things like if these companies have buckets of money, let them spend it. And so maybe they sounds like starting to do some of that, but it’s been interesting, probably like, you know, working through that regulatory structure, right? It’s like, this is probably the first time that companies have come in, been willing to do that, or at least got to the point where they’ve been willing to do that, right? Just because of how fast they want to move and all this kind of stuff. So, I mean, I think it’s a really interesting.
Joshua Rhodes (11:10.638)
model that may start working, particularly in some of the regulated parts of the state. Now I talking about we are unbundled and we have deregulation in most of the state, but there’s some parts of the state that don’t. I think there’s a story just yesterday or that I read just yesterday talking about that Metta is going to pay for a brand new gas plant in the El Paso electric region, which is a regulated area. I swear it up and down that they’re going to pay for the whole cost because it’s all going to go to support a data center. I think it’s a 366 megawatt gas plant.
Joshua Rhodes (11:40.044)
and about there. So that’s an interesting thing because there’s a lot of competitive in Texas, but there’s still the non-optin entities, the non-ERCOT parts of the state, whether that’s in the far west, the panhandle, or the eastern or the far eastern part of the state. And then we’ve got these transmission and generate co-ops and other types of things like that. So there’s a big portion of the state that some of that thinking might be able to work its way into. mean, the majority of the power is in the deregulated competitive area, but there’s a good chunk of it that’s not.
Micalah Spenrath (12:08.354)
Yeah,
Micalah Spenrath (12:08.744)
I think what you said was Microsoft and their proposal to pay for the infrastructure that they are incurring. It just reminds me of conversations that we had at the Public Utility Commission of Texas, right? So driveway costs versus highway costs. Yeah. So I think many people understand the concept of if this is your driveway and it’s dedicated to you for your use, you should pay for it. Yeah. If it’s going to be something that all of us are using, then feel free to socialize those costs.
Micalah Spenrath (12:37.944)
but you don’t wanna have rate payers paying for something that they’re not gonna be benefiting from. So if that natural gas plant in El Paso is dedicated to this data center, then I think it makes common sense that Microsoft should pay for it. Although many people might interpret that as an act of goodwill, I interpret that as just aligning with cost causation principles. So it’ll be interesting to see if the community side of things evolves beyond that.
Micalah Spenrath (13:07.342)
or if it doesn’t. So I suppose we’ll see.
Joshua Rhodes (13:10.838)
Yeah, it’s an interesting, I think it’s Meta, the one on Microsoft and El Paso one, but it will be interesting to see like if some of those principles can also work their way into the competitive part of the state, right? I think there are some mechanisms. I may have talked about this in our last round table and I know I’ve talked to a bunch of folks around it, but like there’s this principle of how infrastructure is paid for in the Alberta system operators. Alberta is like the Texas of Canada, right? It really is. It is kind of uncanny in a lot of different ways, but they do this for generators and we can do this for load.
Joshua Rhodes (13:40.014)
New generators have to pay for like the cost upgrades that go into the system to be able to deliver that power. But then they’re paid back over time. So the generators pay for the driveway and the highway, but then they’re paid back for the highway over time if they exist over a long period of time and provide the market benefit that existing in that system does. And so, right, think some of the concerns, if some of this AI, you know, stuff turns out to be bubble-ish or
Joshua Rhodes (14:06.542)
partial bubble or whatever that like we build out all this infrastructure and then there’s no one there, you know, using that infrastructure or consuming that power that would pay for that infrastructure. And then right payers get left, you know, everyone else gets left holding the bag for that, right? If Matt was, was talking about, I mean, I think we could do something similar. It’s like right now in ERCOT, we just make you pay for the driveway, but we could make you pay for the driveway and highway and then pay you back for the highway over time. Put that up to load if you exist for 10, 15 years, whatever it takes.
Joshua Rhodes (14:36.236)
to pay that infrastructure cost back. And then if you are a bubble, if you’re gone in two years, then you defer the other 13 years worth of payment or something like that. And we’re not left holding the bag, right? So I think there are some mechanisms. I think they’re clear in like the regulated space, even in the deregulated space. I think we could do some learnings from other regions.
Matt Boms (14:54.518)
Yeah, it would be a good, interesting solution because under that scenario, Josh, you would take away some of the risk from the investors. ERCOT is completely dependent on those investors. And like you said, if it is a bubble, then you lose them, right? Right. Versus a middle ground. You don’t want to go to vertically integrated because then, the rate payer is paying for that drive. That drive is going to get turned into a highway or will pretend that it’s a highway, even though it’s really just a driveway.
Joshua Rhodes (15:21.73)
Five lane driveway, yeah.
Matt Boms (15:23.042)
Yeah, so you’d want some middle ground where the investment doesn’t dry up, but at the same time, you give it the value it deserves instead of prepaying and assuming that there’s some value there.
Joshua Rhodes (15:32.471)
for
Joshua Rhodes (15:32.646)
sure.
Micalah Spenrath (15:33.282)
This might be a hot potato of a question. if it is just. Many utilities are referencing historic load growth as justification for their historic spending, primarily pointing the finger at large loads and data centers. My question is, is this truly a new constraint that utilities are facing or does it largely and perhaps conveniently fit within the traditional utility model that prioritizes capital investment?
Micalah Spenrath (16:02.616)
So basically like, are utilities just doing what they’ve always done in that they’re spending on capital because that’s what they get a rate of return on and they’re just using data centers as a convenient justification for that? Or is this genuinely something that is catapulting them into a whole new order of magnitude of spending? I hope that’s not too controversial.
Matt Boms (16:25.706)
No, I don’t think so. I think that the answer is always somewhere in the middle because they’ve already been spending about $9 billion a year on poles and wires in Texas, right? And that’s roughly $5 billion on distribution, $4 billion on transmission. So you add that up, that’s $80 billion over the past 10 years. And that was all without the load growth that we’re seeing now. So the nature of utilities is to build because that’s what we’ve asked them to do in ERCOT. The shareholders want more capital expenditure, so you can’t blame them for
Matt Boms (16:55.224)
doing their job well. And I’ll let Josh answer the more difficult question, which is like how much of that is reasonable?
Joshua Rhodes (17:01.87)
Yeah, I mean the engineering answer it depends right but like I think there’s two camps on this right is one was like well the load growth will come and they’ll take care of all of that and a lot of people point to like that LBNL study that looked at like historically how you know electricity costs have maybe not risen as fast in places that have had low growth versus those that haven’t. There’s always a danger of saying this time is different but there are some flags that kind of this time is a little bit different in terms of the low growth is just much faster than we’ve done in the past. I mean I think it does come back to like
Joshua Rhodes (17:31.434)
Everything that we need to buy from the poles, the wires, the transformers, the conductors, everything, the power plants, everything that we need to buy cost way more than it did five years ago. mean, if you got mad about inflation on the cost of eggs, you should look at pad mount transformers in terms of how much more expensive they are. CPI on eggs is like 10 % and people were like in the streets, right? The inflation on like transformers is 200%.
Joshua Rhodes (17:56.44)
You know, those green boxes that are like out in your neighborhood or the cans that are mounted on poles and then all the way up into like the big pieces of equipment that, know, step voltage and things like up and down on the transmission system and, and other parts. mean, all that costs more money. And so it’s like, if all that didn’t cost double, triple, like what it did a few years ago, then I could be more convinced that, okay, this low growth is going to like help with that. Those costs will be spread out over a whole lot more megawatt hours and kilowatt hours.
Joshua Rhodes (18:23.798)
everything’s just more expensive. And so, I mean, I’m afraid because we’re asking the system to like grow much faster than it has and everything that we need to build is more expensive, there’s going to be more money quicker moving into that rate base and there could be a rate shock, right? I mean, that’s what I’m worried about is it’s the mechanisms are probably long-term we’ll even out, but like the short-term, know, people got to pay mortgage this month, not the average over the next 10 or 15 years.
Micalah Spenrath (18:48.62)
Yeah, and I think the idea of rate shock is something that is certainly the big bad wolf that everybody’s looking at. So in terms of what practical solutions are to moderate cost and to avoid rate shock, right? I’m thinking about a few options, distributed energy resources. Matt, looking at you, we’ll come back to that, right? So rooftop solar storage, demand response, energy efficiency generally, and flexibility.
Micalah Spenrath (19:17.772)
So virtual power plants and things like that, those can really temper peak demand and defer costly investments if we actually incorporate those into our strategy. So the question is, are utilities doing that sufficiently or aggressively? So Matt, know that Teba has a report on that very question, like how can distributed energy resources defer some of this to indie investment? So can you share any high level findings with the listeners?
Matt Boms (19:47.278)
Yeah, thanks for teaming up there, McKinna. That was awesome. Well, I think the total savings that we came up with was $1,850 per rate payer over 10 years. And that number was calculated on the one hand, the TND deferral, right? So like how much of the distribution upgrades are not being made immediately because you’ve got more DERs on the system, whether they’re distributed batteries or any one of the technologies you just mentioned.
Matt Boms (20:13.038)
And then the other half of it is wholesale market value. like, think the assumption we had in there was pretty small, but it was like 2.5 gigawatts of DERs over the next 10 years. And just that alone yielded over $1,800 per rate there. So there’s a lot of value on the table, right? And I think we’ll see moving forward how utilities incorporate that into their strategy. think your question is dead on because you asked if they’re doing enough, I would say no, because they’re leaving distributed.
Matt Boms (20:42.786)
technologies on the table and they’re not taking advantage of them. But again, poles and wires only ERCOT. So if you’re a TDU in ERCOT, you’re just building out grid infrastructure. You’re not allowed to deal with storage unless you’re a CPS or an Austin Energy or one of the vertically integrated ones. So that would be the reason why.
Micalah Spenrath (21:02.058)
Yeah. So where my mind goes with this is it’s going to be very difficult to reorient utilities to prioritize some of these cost effective technologies, which can be cost moderators is something that we’ve discussed. Without a regulation reform, I think cost of service regulatory models had their purpose and I think they’ve served people well in the grid of yesterday. But I think that performance based regulation is
Micalah Spenrath (21:32.066)
Hard pressed, I’m hard pressed to understand how we’re going to get to a more flexible, dynamic energy system, distributed energy system, without taking a hard look at how utilities are financially incentivized to get there. And in Texas, I just don’t think that many of them are, unless of course you’re an integrated utility or don’t know what you’re something like that. But that leaves a lot of other folks on the table that don’t have those incentives. So.
Micalah Spenrath (22:00.952)
That’s a question. And is there the political appetite to tackle that, right? Because we’ve had cost of service regulation in Texas for so long. So that’s certainly a question I have.
Joshua Rhodes (22:12.674)
I think your spot on, Michaela and Matt was mentioning it earlier. I mean, just follow the incentives, right? It’s like, if you change the incentives, the companies will change their behavior, right? It’s just cartoon, like a trail of money, right? It’s just make it go a different direction or whatever and they’ll go a different direction, right? It’s just pretty much that simple in concept, probably not so much in terms of changing like, you know, the regulations and things like that. I think you sent this out. There was something about, okay, if like costs are going to go up, it actually starts to make distributed energy resources look
Joshua Rhodes (22:41.506)
better, right? Because I mean, a lot of times you’re making comparisons like, do I get solar? Do I get storage? What does that cost relative to like my electricity bill or whatever arrangement I have for energy? And like, as the electricity, you know, as one side of that equation goes up, then like, you know, systems that were more marginal or maybe didn’t pencil out, you know, start to pencil out, right? I mean, I think we’re seeing this in ERCOT, like wholesale prices as those have gone up, particularly in like the western part of the state. I mean, those have gone up. I was just looking at the western load zone.
Joshua Rhodes (23:11.384)
prices yesterday and they’ve gone up last year quite a bit further than like the years before in other parts. And so as those costs go up, whether that’s distributed energy resources or more utility scale, know, wind and solar projects, they start to pencil out even with the loss of the tax credits. There’s kind of like, we’ll see which one wins there, right? There’s like dueling things. One, the loss of the tax credits makes it more expensive, but if the cost of the grid is going to go up and electricity prices are going to go up, then maybe they start to pencil out again, right? It’s a weird
Joshua Rhodes (23:40.034)
What’s the new equilibrium going to be? When have we ever had an equilibrium? But when will we get there? But even getting back down to the distributed side, for distributed energy resources, I I don’t love that this is the mechanism, but it’s the silver solar lining of this, right? As more of those DERs become like more competitive in this region where prices are going up. Again, don’t love that that’s the reason why, but it might be the case, right? Yeah.
Micalah Spenrath (24:07.402)
Yeah, I think for me, it’s a very interesting and perhaps unintended consequence of some of the federal policy changes that we’ve seen related to clean energy. So rising energy prices might actually make it more financially viable or feasible for people to make these investments. So to quote what the resource I had shared, it was a Wood Mackenzie report, and it found that increasing retail rate escalation
Micalah Spenrath (24:34.648)
can reduce payback periods by about a third for commercial systems. So my interpretation of that is that could spur more renewable energy deployment even as we contend with the materially different federal tax credit landscape. So I think that that’s really interesting because it’s a bit counterintuitive. You wouldn’t expect that to be the result, but it absolutely makes sense. If energy is more expensive, it makes it more feasible for me to just
Micalah Spenrath (25:02.624)
invest in my own energy and produce it at home rather than buying it for my utility. So I think it’ll be interesting while those changes may have been intended to decrease renewable energy deployment, it might actually have the opposite effect now that markets have kind of taken hold and we’re seeing these different trends.
Joshua Rhodes (25:20.362)
Yeah, like I’ve not looked at this at all, but it’d be really interesting if, okay, with loss of the federal tax credits means less utility scale gets built. the price of electricity wholesale goes up. So that means that retail goes up. that means people build more distributed energy resources because the cost of has gone up. If we just completed the circle on that and that’s actually where it came to, like, and I have no data for that whatsoever, just a hot take on it. But I don’t know, that would be really interesting to see, but maybe we’re starting to see that. Yeah.
Micalah Spenrath (25:48.12)
If you
Micalah Spenrath (25:48.352)
do any research on it, please report back.
Joshua Rhodes (25:50.894)
Okay,
Joshua Rhodes (25:51.814)
I will do.
Micalah Spenrath (25:52.974)
Ha
Matt Boms (25:53.998)
The problem is also like to unlock the real value of those distributed resources. There’s so many layers of the value stack that are currently not accessible, that are not available in ERCAD to customers, right? Like I mentioned the TND deferral, that’s not on the table. The way that price is settled is only instead of notally, right? If we want to get real nerdy and talk about if there’s a customer in a really overloaded substation in Houston on a really hot day in August.
Matt Boms (26:20.46)
Why aren’t they getting rewarded? Like we have all the technology in place to make that happen, but it’s ultimately a policy choice. And that’s what I love about what you said, Michaela, because we’re not asking anyone to reinvent the wheel. if, when you say performance based regulation, what we’re saying is essentially, shouldn’t we reward utilities based on how reliable they are and how much money they save for their rate payers, right? And like there are other states across the country that do that. Like Arizona, Georgia, Illinois.
Matt Boms (26:49.73)
We can look to other places and like Josh mentioned, Alberta, there’s plenty of successful case studies where folks are doing that in a better way because ultimately the way that we set up our system here in ERCOT is cost recovery for all capital expenditure. It’s not based on how many consecutive days you keep the lights on for your customers and how much money you save them.
Micalah Spenrath (27:10.422)
And I think you hit the nail on the head with it mostly being a policy choice, right? We can choose to better compensate residential customers for grid services. We just have to commit to it. And I think we’ve started a lot of progress there, but to your point, there are additional pathways or components of the value stack that we could really be utilizing to deliver even more benefits to consumers. It’ll be interesting to see how that evolves over time and if there is the momentum to get there.
Micalah Spenrath (27:40.184)
But to your point, yes, I think that we do want to reward utilities for performance, not necessarily just for capital investment.
Matt Boms (27:49.806)
And also to take it one step further, Michaela, I don’t know if you agree with this, but it sometimes takes emergency or a disaster to shake people because I remember Hurricane Barrel when folks started questioning Centerpoint and folks in Houston were really outraged at what happened. I hope it doesn’t take that. Like I hope that we’ll be more sensible and plan for this and really be able to meet the moment. Like actually reward utilities for performance instead of just writing blank checks.
Micalah Spenrath (28:15.518)
Yeah, so I think my interpretation of a lot of the utility spending that I’ve seen, and I haven’t read every proposed rate case or strategic plan that a utility puts out, but a lot of them are reactive, right? So it’s we experienced a hurricane, we experienced a wildfire, so now we’re going to be investing in these strategies versus an adaptation perspective. So if we know and
Micalah Spenrath (28:42.4)
If we look at the data, we are going to be experiencing more challenges in the future, but perhaps not less, right? So it would be interesting to see how utilities plan to innovate and adapt over a long time horizon versus having plans that are a bit reactive in nature. And that can really change the perspective, I think. It can also change how a consumer is actually going to be serviced. So I want to be able to rely on my utility.
Micalah Spenrath (29:12.242)
And being aware of them looking into the future versus the past, I think would really increase confidence that they’re actually going to be doing that. I’ll pay for that. Like as a consumer, I will pay for adaptation because I think that’s going to benefit us in the long run. For me, it’s a bit harder to pencil out if you’re only going to be reacting to things that we’ve experienced thus far, because we know that the future is going to look a little different.
Joshua Rhodes (29:40.046)
Yeah, I will say it is. Maybe I’ll provide a little bit of pushback. Predicting the future is hard. Yogi Berra taught us this. Or making predictions is hard, especially about the future, I think is a quote that’s probably misapplied to him. But anyways, building out stuff for like an adaptation against an uncertain future, like utilities kind of get caught with their pants down if they like make the wrong investments. They can get dragged before committees and other kinds of stuff. And like, why did you spend this money on this thing?
Micalah Spenrath (29:41.084)
That might be a hot take.
Joshua Rhodes (30:07.042)
you haven’t used or it’s not going to be useful or like other types of things. If we’re going to do that route, like we have to be willing to let them make some mistakes because no one can predict the future. But that’s hard is like how much, how much of making a mistakes is, you know, just imprudent or whatever the terms are in terms of how that works. And so like, I understand why they’re like always being kind of more reactive than proactive. And maybe it’s just whenever they want to be proactive, there’s not enough buy-in from the
Joshua Rhodes (30:34.584)
communities and folks and everyone and everyone just getting to an understanding of like, hey, we’re building this for the future. There’s a potential that we don’t do this exactly right. It’s one thing to like look back and say, okay, you this storm took out like all transformers that were below a certain sea level in Houston or whatever, like, okay, all those need to be either all stilts or whatever, right? Versus we think that the next hurricane is going to get them at 20 feet higher or whatever the metric would be. I think, you know, utilities are pretty sensitive on like
Joshua Rhodes (31:02.83)
spending money that they may get called out on so far in the future. I think we need more consensus on that and consensus is hard, right? That’s really hard to get. On the other hand, you can look at the Texas has experienced like 27 plus billion dollar CPI adjusted storms over the past 20 years, right? And if you look at the chart, it’s just going up and up and up. And so like basically maybe the base level of every resilience needs to get better on spending on that kind of stuff. I can kind of have a little sympathy there for like being against a rock and hard place.
Micalah Spenrath (31:33.27)
Absolutely. So the two words that come to my mind are prudently incurred.
Joshua Rhodes (31:38.646)
Okay, I’m the engineer.
Micalah Spenrath (31:41.08)
So yeah, so that’s one of the standards when it comes to costs and utility spending. So prudently incurred, I think what is it, and reasonable. And I’m sure someone listening who’s a lawyer is probably gonna add something to this.
Joshua Rhodes (31:55.54)
I was trying to just put them together, yeah.
Micalah Spenrath (31:57.694)
No, no, no. So that’s one of the standards that I think they have to meet, right? These costs have to be prudently incurred. So I think to your point, we do want to make sure that they have this space in order to innovate and experiment and even make a mistake every now and then because they are adjusting to an uncertain future. at the same time, that has to be based on some sort of prudent strategy that they have. And if they’re not looking into the future and seeing that
Micalah Spenrath (32:25.192)
our extreme weather costs are going up, then it’s hard to understand how the billions that they plan to spend are going to be prudent. So I actually think that does give them some cover, right? So like we are looking, we’re staring down the barrel of an uncertain future and this is what we think we need to do. And hopefully we will have the policy spaces to encourage experimentation. Josh, I have a quick question for you. To your point,
Micalah Spenrath (32:53.322)
What do you think is missing that would basically encourage a utility to be more innovative and take, I don’t want to say risks, but essentially take the leap that they feel they need to take in order to meet the challenges of the future based on currently available models and data. Cause it sounds like you might think that the current incentive structure that they have might not allow them to feel that way. And I could be misinterpreting.
Joshua Rhodes (33:21.582)
Well, I mean, I utilities can do things like pilot projects that are like, you know, it’s kind of in the name, right? Okay, there’s a pilot. We’re going to try something out. Who knows maybe in the face of like how fast things are like set to grow and how much more we’re sort of set to spend on like electricity and how much more electricity is going to be going. Maybe we just need bigger pilots. The ability to take some bigger steps kind of in that direction. And maybe that’s the vehicle that it can be shielded through. actually don’t know if there’s okay. Pilots can’t be more than 2 % of.
Joshua Rhodes (33:49.45)
operating or whatever. have no idea like if there are even like current constraints on that, but maybe in the face of, you know, higher levels of growth, being able to have some like higher value pilots and things like that to try out some of these new technologies, whether that’s bigger virtual power plants or advanced conductoring or whatever it is to let them try some of these things.
Matt Boms (34:11.928)
think, Michaela, this is also the problem with central planning because what Doug used to talk about this on the podcast, right? I won’t get into Hayek and I won’t be as intellectual as Doug, but I do think these are the dangers of a centrally planned system because you don’t have the price signals. the ones that we have in the wholesale market are pretty damn good. And that’s why folks love doing business in Texas. And conversely, we don’t have those price signals for the TDUs, right?
Matt Boms (34:41.1)
And like, we’re both relatively familiar with resiliency plans that were proposed by the utilities and approved by the commission and roughly a billion dollars a year for Encore and Centerpoint each. none of us are arguing on this podcast that they shouldn’t do hardening and they shouldn’t do vegetation management. Like we all agree on that stuff. It makes sense to be preventative.
Matt Boms (35:03.17)
But at the same time, like there were no DERs in those resiliency plans, right? There wasn’t a demand response program or energy efficiency or you name it. None of that is part of the resiliency strategy of the TDUs in Texas. And that’s a big problem because we all know that moving forward, that’s exactly what we need in Texas is more demand side solutions because most of the time we’re fine, but there’s always the chance of a winter storm and there’s always a chance of a really hot day in August. Then we’re kind of reaching the limits of what our grid can handle.
Joshua Rhodes (35:33.134)
So this is an interesting thing. I’ll agree like on half of that, that we don’t have the price signals. I think maybe not on the distribution side, because we don’t have prices down at the distribution edge or whatever. But on the transmission side, we do have congestion, right? Because of the way we do invest and connect and like we have our location of marginal pricing, LMPs, we do congestion revenue rights and all other kinds of complex things. I think we do have pretty good economic signals of like where new transmission is beneficial. But right now the way that we handle that,
Joshua Rhodes (36:02.434)
the economic test for transmission is so hard to overcome, the test doesn’t make sense. It essentially is like to pass the economic test and someone in chat or whatever is gonna tell me how I’m not exactly right on this, but essentially like you have to be able to make up all of the costs in one year or something. Whereas like transmission infrastructure upgrades and stuff, or that infrastructure is decade long infrastructure, right? It lasts for decades. And so like if we can take the congestion
Joshua Rhodes (36:32.602)
LMP signals, like I think it sends a very clear signal of where economic upgrades in transmission would be useful if we had a more sane economic test for that. So I think for the transmission side, we could, we have the data to be able to do this, but we’re just not doing it. But on the distribution side, yeah, it’s like if you want to do the same thing, you would need prices down there. And that does get pretty complex pretty fast. Maybe there’s always a divorce there somewhere, but like, I think at least on the transmission side, I think we do have the ability to do this now. just
Joshua Rhodes (37:01.696)
not doing it as good as I think we could.
Micalah Spenrath (37:04.59)
All right, so thank you so much for this amazing conversation. We are just about at time. So we’ve touched on a lot of different things, utility innovation, utility regulation, the pressures facing the energy system, whether that be cost or just speed of growth. So just quickly, what are your final takeaways from this conversation?
Joshua Rhodes (37:24.942)
I mean, think it just comes down to the pace at which this is happening is just so different than in the past, right? So I think we need to relook at how we’ve handled growth in the past and some of the mechanisms probably need to change to be able to handle how fast it’s coming to us now.
Matt Boms (37:38.958)
completely agree, Josh. And I think this is the moment where we need more innovation. I think we need to change the way we think about planning for the future. And if that means that our utilities have to become a little more innovative to meet the moment, then that probably makes sense as far as rewarding performance instead of just writing those checks for capital expenditure.
Micalah Spenrath (38:00.034)
Well, thank you so much for this amazing conversation, guys. And thanks so much to our listeners. Signing off, I’m Mikayla.
Matt Boms (38:06.731)
A man?
Joshua Rhodes (38:07.798)
I’m Josh.
Micalah Spenrath (38:08.93)
and we’ll see you next time.
Matt Boms (38:12.376)
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,
Matt Boms (38:41.618)
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.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
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The New Rules Behind ERCOT Prices with Andrew Reimers
18 feb· Energy Capital Podcast
Texas keeps adding load, adding generation, and adding complexity. But attracting the next wave of investment often comes down to a crucial question:
How does ERCOT use market forces – especially signals that determine where energy prices are set – to boost reliability on the grid?
In this episode, Josh Rhodes sits down with Andrew Reimers to pull back the curtain on the machinery most people never see, including operating reserves, scarcity pricing, and what changed when ERCOT launched real-time co-optimization in December.
The quiet lever: reserves, scarcity, and incentives
Andrew breaks down the pricing story to a simple idea: when electricity on the grid gets tight, the value of the next increment of reliability rises fast, which should signal to investors that they can make money by building more generation in Texas. ERCOT tries to reflect that through scarcity pricing and its operating reserve demand curve.
The hard part is running the grid in a way that ensures affordable, reliable electricity, and that doesn’t smother the very price signal that’s supposed to attract new capacity to the market.
“Carrying this large volume of operating reserves… you can suppress the prices… disincentivizing investments in new generation.”
That tension – lowering the risk of outages today vs. maintaining investable signals for tomorrow – drives the entire market design debate in Texas.
Reliability policy is also investment policy.
What changed on Dec. 5, and why it matters
In this episode, Josh and Andrew discuss ERCOT’s move to real-time co-optimization late last year and what it means for the ways reserves are procured and obligations show up in real time. That can change outcomes, even if the physical grid looks the same.
The conversation covers:
* Why pricing can look wrong even when the grid is fine.
* How rule changes can create unexpected incentives.
* Why these mechanics matter more as demand rises and the resource mix shifts.
Batteries, forecasting, and the value of looking ahead
Josh and Andrew also show how this all connects to batteries.
Andrew frames batteries as a question of timing and trade-offs, not just megawatts.
“Batteries… it’s opportunity cost. If I discharge now, I can’t necessarily discharge in the future.”
If ERCOT’s market structure encourages operators to look ahead even an hour or two, the state will end up valuing flexibility more intelligently – and customers will avoid the excess cost of simply buying more reserves to cover forecasting errors.
Final Thoughts
This episode shows that the Texas grid is not just about steel in the ground. It’s also a unique, and largely successful, experiment in how free-market policy – with smart guardrails – can translate individual investment into reliability for all.
If you want to understand why ERCOT decisions spark so much argument, and why market design tweaks can have outsized consequences, this conversation is a great map.
If this prompted questions for you, drop one in the comments. And if you know someone who cares about ERCOT prices but hates reading market docs, send them this episode.
Energy Capital Podcast is produced by ClarityForge Studios.
Timestamps:
* 00:05 – Episode Setup, Why This Matters
* 01:09 – Andrew Reimers, Role of the IMM
* 05:03 – Operating Reserves and Market Design
* 09:55 – Real-Time Co-Optimization Explained
* 14:30 – ERCOT vs Other Markets
* 16:42 – Post-Uri Conservatism and Price Signals
* 19:12 – Scarcity Pricing and Investment Incentives
* 23:50 – DRRS, RUC, and Reliability Tradeoffs
* 28:26 – NPRR 1309 vs 1310 Debate
* 31:02 – Load Forecasting and “Officer Letter Load”
* 36:55 – Solar, Wind, and Shifting Peak Dynamics
* 40:45 – Batteries and Multi-Interval Markets
* 49:15 – Out-of-Market Actions and Hidden Impacts
* 53:59 – Final Takeaways and Wrap-Up
Resources:
Guest & Company
* Andrew Reimers (LinkedIn)
* Potomac Economics (Website - LinkedIn)
* Potomac Economics - ERCOT IMM overview
* Joshua Rhodes (LinkedIn)
* Webber Energy Group (LinkedIn)
* IdeaSmiths (Website - LinkedIn)
Company & Industry News
* ERCOT NPRR 1310, IMM comments (Feb 3, 2026)
* S&P Global, ERCOT ancillary services rule changes and IMM perspective (Aug 6, 2025)
* RTO Insider, ERCOT and IMM ancillary services study (Jul 1, 2024)
* Potomac Economics, 2024 State of the Market Report for ERCOT (PDF)
Books & Articles Discussed
* Ancillary Service Study, Initial IMM Results (Aug 28, 2024)
Transcript
Josh Rhodes (00:05.174)
Right now, Texas is planning for rapid load growth while still catching up on transmission and interconnection constraints. The challenge is not whether demand is coming, but how fast the system can realistically respond. Welcome to the Energy Capital Podcast, where we cover the decisions, data, and debates shaping the Texas grid and the energy future. I’m your host, Joshua Rhodes. Today’s guest is Andrew Reimers. He’s deputy director of ERCOT at Potomac Economics, the independent market monitor. Andrew is an expert on grid planning,
Josh Rhodes (00:35.234)
load growth, and how infrastructure decisions actually get made in Texas. In this episode, we walk through what planners know, what they are assuming, and where uncertainty is doing real work in the system. We discuss load forecast, transmission bottlenecks, and the trade-offs between moving quickly and maintaining reliability. You’ll walk away with a decision-useful lens for understanding how Texas is navigating growth right now, and where the biggest pressure points are likely to emerge next. Let’s get into it.
Josh Rhodes (01:09.25)
Andrew Imers, welcome to the Energy Capital Podcast.
Andrew Reimers (01:11.566)
Happy to be here. Thanks for the introduction. You and I have, I think, known each other for like 13 years now.
Josh Rhodes (01:17.154)
Yeah, I it has been a while. I was wondering at a high level if you could just describe what Potomac Economics does relative to Earth.
Andrew Reimers (01:24.098)
Yeah. So, you you have ERCOT who is the independent system operator. So they are sort of a quasi government institution. They’re really a nonprofit institution with a charter through the state of Texas to manage the flow of electricity on the transmission network, and then also run various wholesale electricity markets. And, you know, there are several different flavors of that. The most important one for the conversation we’re going to have today is the real time market.
Andrew Reimers (01:53.752)
So that’s really where the physical scheduling of generation happens and everything ultimately is transacted according to the prices that come out of the real time market. That’s ERCOT where Potomac Economics comes in. This whole concept of an independent market monitor, if you kind of take it back historically, all of these power grids and deregulated electricity markets used to be like vertically integrated.
Andrew Reimers (02:18.58)
utility markets where you’d have retail customers that were in a monopoly all the way up to the firms that own the generation and stuff. and that model still exists in certain parts of America. Yeah, the Southeast parts of the Midwest are still kind of like this. The Rockies are like this, although that’s kind of an evolving situation. Yeah. Most of the rest of the US is what we call deregulated. That means that you have
Josh Rhodes (02:30.328)
like the Southeast.
Andrew Reimers (02:44.204)
divested the transmission system from the generation system. And there is no longer necessarily as strict of a monopoly on the retail side. And be that as it may, you still had a lot of legacy firms that had a lot of concentration in the market. So like in Texas, the big firms might be Luminant slash Vistra that historically could be traced back to Dallas Power and Light. And maybe you have NRG Reliant.
Andrew Reimers (03:13.24)
who can be traced back to Houston Power and Light, these two firms, even though they’re now in a deregulated market, are still very big players. And so there’s a concern about the ability of these players to exercise market power and whether or not the market is sufficiently competitive to kind of incentivize those players to bid competitively. That’s really where the role of an independent market monitor comes in. We kind of have...
Andrew Reimers (03:41.56)
two different fundamental roles. The first of which is to monitor the market for uncompetitive behavior. We have various screens and things going on that are meant to catch peculiar looking behavior, maybe uneconomic offer behavior, uneconomic outage behavior. And then related to that to identify problematic market design.
Andrew Reimers (04:07.126)
situations, maybe make recommendations for improving market design to kind of improve the competitiveness of the market. My firm in particular is called Potomac Economics. And so we have a contract with the state of Texas to serve as the independent market monitor for ERCOT. We also are the independent market monitor for several other of the big deregulated systems in America. So MISO, which is kind of the big Midwestern ISO, ISO New England.
Andrew Reimers (04:36.726)
New York ISO. And then we also are the market monitor for Reggie, RGGI, which is the regional greenhouse gas initiative in the Northeast. those are all different aspects of what our firm does. And my team in particular focuses on ERCOP. And my role within that team, I kind of manage the personnel. And then I’m particularly
Andrew Reimers (05:03.222)
oriented around the market design aspect of the job. So most of my work kind of individually has been more on market design stuff than necessarily the market monitoring stuff. And in particular, what I’m hoping we can talk a lot about today, I’ve worked a lot on operating reserve policy. And so that is a big part of market design where things are changing very quickly and it’s very important that we kind of get the details right.
Josh Rhodes (05:33.26)
Yeah, no, I know that that’s a really big aspect of what’s going on in Texas and ERCOT. I do want to get there. But before we get there, I kind of wanted to ask like, so in that role, you know, there’s the market monitoring and then there’s the market design. You know, what do you see in that role that other folks in ERCOT don’t see?
Andrew Reimers (05:49.944)
Well, the biggest thing if you’re taking what we see versus everyone who isn’t ERCOT, the biggest difference would just be we have direct access to all of ERCOT’s data. And so, you know, that is a major distinction between what, say, market participants would be able to see versus what we can see. As far as what we’re doing and why it’s distinct from what ERCOT does, several of the ISOs have an internal market model.
Andrew Reimers (06:16.758)
So, KAISO and SPP, for example, have their own internal market monitoring division. Some of the ISOs, to my understanding, have both internal and external market monitors. I know it’s the case with New England and it might be the case with NISO as well. The reason to have an independent market monitor is really that there are going to be cases where you’re making recommendations that go against what the ISO has proposed and you need an independent third party to effectively
Andrew Reimers (06:45.322)
make an alternative case than what the ISO has proposed for why they want to do things. You know, this sort of situation is going to vary depending on the kind of nature of the ISO. So for example, a single state ISO has a different kind of set of political incentives than a multi-state ISO. Right. The other thing is that Texas is unique in furcot being entirely isolated in Texas. So in Kaizo or
Andrew Reimers (07:14.412)
New York ISO, even though they’re single state ISOs, they’re synchronized on a bigger grid. And so there still is some extent to which the politics of those states can’t entirely dictate what the ISO is going to do. In Texas, that’s a lot less the case. And, you know, that has implications for the role of the ISO.
Josh Rhodes (07:35.47)
Josh Rhodes (07:35.95)
Yeah, that’s really interesting. You talked a little bit about that, you know, pushing back against Irkut and that as the role is the independent, like why it’s important to be independent. mean, Potomac has pushed back on Irkut against several rulemakings. You know, what usually drives those disagreements?
Andrew Reimers (07:50.062)
Well, at least since I’ve been here, it’s mainly been operating reserve policy. And so I mentioned that earlier. It might be worth going ahead and explaining what that is. But there have been plenty of other issues in the past and they aren’t always directed at ERCOT per se. So we also have proposals against rule makings at the legislative or PUC level. So for example, we’ve been critical of 4CP a lot. We can talk about that later. I know that’s topic that you’re interested in.
Andrew Reimers (08:19.554)
But as far as things at ERCOT, it’s probably helpful to explain what an operating reserve is. So your audience, know, you know, I listened to this show, I suspect your audience is fairly savvy about how some of this works. Worth going into the background a little bit. So the real time market for electricity technically clears every five minutes. So every five minutes, the market is kind of producing new instructions for who’s supposed to be generating how much.
Josh Rhodes (08:24.684)
Yeah, go for it.
Andrew Reimers (08:49.014)
Importantly, one of the kind of nuances here is that this market isn’t necessarily instructing resources to turn on or off. So that aspect of things we call that commitment is a more complicated scheduling process. And ideally the way this market functions when everything’s going smoothly is generators decide for themselves when they’re going to turn their resources on. Usually it takes
Andrew Reimers (09:16.224)
More than an hour to turn those resources on. And so it’s something they kind of have to have a view for what prices are going to be during the day. And then once they’re online, the real time market moves them up and down according to changes in supply and demand. You can think of, you know, on a summer day, the sun is coming up in the morning. We might turn down some of the thermal power plants because the solar is starting to enter the system.
Andrew Reimers (09:45.26)
We might also start having higher temperatures. so the demand for electricity overall is going up as the air conditioning load is going up. And then maybe at some point in the day, thermal power plant trips and you need to schedule some generation to fill the gap from that power plant tripping offline. So those are all examples of kind of what the real time market is doing to schedule generation.
Josh Rhodes (10:09.666)
And before December, those reserves are being scheduled in the day ahead market, but now they’re being co-optimized in the real time market. Is that right?
Andrew Reimers (10:16.376)
That’s right. Yep. And so what you’re referring to is called real time co-optimization, which also happens to be a former Potomac economics recommendation for ERCOT to implement. Yes. We finally made it. took almost two decades. So, but we got there. So you referred to December. on December 5th, real time co-optimization went live and so far we haven’t seen any major system issues. There are some pricing outcomes that we think are
Josh Rhodes (10:28.088)
Congratulations on getting it through.
Andrew Reimers (10:46.254)
problematic that we might get into later, but that’s all very in the weeds. Yeah. So just to clarify the point you were saying before, until December 5th, the way the market worked is operating reserves were only procured in the day ahead market. And then that award was effectively a physical obligation to carry operating reserves in real time. There were nuances to this. You could trade in and out of these positions, what have you, but
Andrew Reimers (11:14.542)
In real time, if you were carrying an operating reserve, then you were expected to be able to provide it. Whereas the way it works now, you don’t even have to sell operating reserves in the day ad market. If you do, they are entirely just financial positions and your awards in real time kind of determine what you’re physically obligated to do in real time. And you’re kind of just arbitraging between day ad and real time.
Andrew Reimers (11:38.85)
That introduces all sorts of things that we haven’t really covered yet. We haven’t really covered what the day ahead market is or what operating reserves even are. So maybe it’s helpful to go back into that. So if the market only clears every five minutes and we’re not actually scheduling who turns online, that is really where the need for operating reserves kind of comes from. So you can imagine the demand and supply of electricity are actually changing on a much faster time scale than every five minutes.
Andrew Reimers (12:08.738)
So you need some capacity in the system that can respond to those short-term fluctuations. So for example, a common type of operating reserve is something called regulation or regulating reserve. If you’re providing regulating reserves, you’re getting signals every four seconds to adjust your output to address every time someone flips a light switch, someone turns on their dryer or something like that. There needs to be capacity in the system that can respond to those short-term fluctuations in supply and demand.
Andrew Reimers (12:38.062)
But then you also have issues related to how these commitment decisions work and if there were forecast uncertainty in the day. So for example, there’s really volatile weather conditions and at 12 p.m. we think demand at 4 p.m. is going to be relatively low. And then as 4 p.m. approaches, we realize demand is actually a lot higher than we thought. The clouds are clearing. It’s hotter than we expected.
Andrew Reimers (13:05.996)
Maybe the clouds are coming in and it’s just cloudier than we expected and we don’t have as much solar generation online. These dynamics can leave you where you don’t have enough generation online to serve load effectively. And so you procure some amount of reserves in advance to handle these kinds of forecast errors. And for some added context to that, that problem has gotten a lot more complicated.
Andrew Reimers (13:34.092)
with the combination of intermittent renewables, duration limited resources, i.e. batteries, and then the kind of aging of the thermal fleet. And so those are all different things that are leading to a situation where operating reserves are a much more impactful policy and where there’s a lot of new thinking about how to handle them correctly. So, you know, the forecast there for the weather.
Andrew Reimers (14:00.724)
is more impactful on the supply side than it used to be. It always was impactful on the demand side, but now it also has big implications for how much you’re generating with wind and solar.
Josh Rhodes (14:11.374)
is
Josh Rhodes (14:11.494)
affecting both sides of that supply must equal demand equation. That’s right. Yeah. OK. And this is in contrast to how other regions do it, right? Like ERCOT has SCAD, Securities Constrained Economic Dispatch, but PJM, believe, also in the day ahead, or other regions have SCUD.
Andrew Reimers (14:27.202)
I’ve heard it called STUCK is what KAISO calls it, short term unit commitment.
Josh Rhodes (14:30.826)
Okay, so there’s a whole alphabet soup of things, but basically it’s like they pre-commit generators in the day ahead, right?
Andrew Reimers (14:37.132)
So as far as the biggest difference between ERCOT and other ISOs in terms of operating reserve policy, the biggest difference is that we are in electrical islands. And so if things really hit the fan in Texas, the downsides are a lot greater. You have a lot of generation trip offline, something like that. In the big Eastern interconnect, PJM can kind of rely on the fact that they’re in a big synchronized network and
Andrew Reimers (15:03.692)
They don’t need necessarily as much of their own operating reserves to keep things stable. The NERC kind of requirements for grid reliability and things like that are sort of the minimum requirements. And then what you see in Texas is a lot more, you know, extreme than that. And some of that is valid and some of it is questionable. The other big thing is just the percentage of generation from intermittent renewables and storage is way higher in Texas than just about anywhere.
Andrew Reimers (15:32.78)
The only place that might be comparable and I think Texas is rapidly exceeding this would be maybe like California, which has a ton of solar demand isn’t as high. So the percentage is, you know, maybe about the same, but like I said, California is in the Western interconnect. So they are less anxious about having to deal with all of this on their own. You know, random States like Iowa have a lot of their generation from renewables. Iowa is actually the
Josh Rhodes (15:53.89)
Yeah, they can import power.
Andrew Reimers (16:00.406)
second or third biggest wind generating state in America, despite only having, you know, three or 4 million people or something like that. And so there are exceptions, but for the most part, the island nature of the ERCOT grid and the much larger penetration of renewables make it sort of a unique situation from operating reserves.
Josh Rhodes (16:22.646)
Yeah. And want to touch on some of those implications, the fifth anniversary of winter storm Uri. And I want to get there and chat about that. But before we kind of leave some of the disagreements and things that Potomac has had with either ERCOT or the PC or the legislature, can you point to an example of like, maybe there’s a current one, but like a well-intentioned change that created issues or long-term risk or pricing issues like we might be seeing right now? I know you’ve been working on some stuff like that.
Andrew Reimers (16:48.194)
Yeah. So this ultimately does kind of get into the winter storm URI talk. So yes, does. So the elephant in the room is still the kind of aftermath of winter storm URI and without relitigating that whole situation, even though it really didn’t have much or anything to do with operating reserves. One of the kind of political effects of it was that a decision was made that the grid would operate more conservatively.
Josh Rhodes (16:52.824)
It all does these days, right? It all-
Andrew Reimers (17:17.326)
And what was meant by that is that more operating reserves would be kept online to deal with potential supply shortfalls or something like that to avoid, you know, not just to avoid outages, but even to avoid the concern about outages. So you might recall a few summers ago when it seemed like every other day we were getting a conservation warning. This kind of stuff was seen as politically problematic, especially after how traumatizing.
Josh Rhodes (17:37.87)
2023, I believe,
Andrew Reimers (17:45.366)
Winter Storm Yuri was. And so a decision was made that we’d operate the system with a lot more reserves. That can have negative impacts on pricing in either direction. So it’s important to kind of spell out the nuances here. You mentioned PJM and the fact that they schedule a lot of their generation the day ahead. That is really a downstream consequence of the fact that they have a capacity market. And so
Andrew Reimers (18:14.934)
ERCOT, famously energy only market, the signals for investment decisions only come through the energy and ancillary service prices in the real time market. We’ll get more into how that actually works. In pretty much every other ISO, there is some kind of forward capacity construct, which is how you go about looking ahead to see how much demand you think you’re going to have and then acquiring capacity through an auction.
Andrew Reimers (18:43.48)
to cover that kind of future demand. One downstream aspect of that is if you are picked up in that capacity auction, there are certain must offer obligations in the day ahead market in PJM. so that day ahead scheduling, a lot of that is a function of how many of those resources participated in the capacity market. And so you have something like 95 % of all of the available generation has to participate in the day ahead market. And so you come into real time with.
Andrew Reimers (19:12.938)
a schedule that’s already pretty close to what you’re expecting in real time. Workout isn’t like that. Instead of having this capacity construct, we have all of our kind of revenue for incentivizing new generation comes from the real time market ultimately. And the important aspect to how those prices are formed is something called scarcity or shortage pricing. Basically in situations where
Andrew Reimers (19:41.622)
reserves get really tight. Conceptually, what’s happening is the probability of some kind of loss of load event is getting higher. And you try to impose something called a operating reserve demand curve on top of that, which is going to produce elevated pricing to reflect the fact that the marginal value of the reserves is going up as they’re becoming more scarce. So
Andrew Reimers (20:07.82)
You can imagine what that looks like. Basically, the tighter the system is, the smaller the difference between the available supply and demand. You’re going to clear at bigger prices. part of the problem with conservative operations, as it’s called, i.e. carrying this large volume of operating reserves. One of the problems is you can suppress the prices. now your MO is that outages are to be avoided.
Josh Rhodes (20:17.87)
Hmm.
Andrew Reimers (20:36.566)
And the way you’re avoiding it is causing prices to be suppressed, which is disincentivizing investments in new generation, which you can see coming back to bite you in the long run, if you are concerned about demand increasing. So that’s one aspect of it. You kind of alluded to something earlier with how the market design has changed before co-optimization. It’s also possible for this.
Andrew Reimers (21:04.974)
kind of conservative operations posture to result in prices being higher than they should be. So what happened a few years ago, ERCOT introduced a new ancillary service called ECRS. The way this was implemented before real-time co-optimization meant all of that capacity was kept out of the energy market. And so in the summer of 2023, we now had
Andrew Reimers (21:28.29)
thousands of megawatts of capacity that used to be in the energy market and was effectively removed from the energy market and kept in reserve. And now what happened a lot that year, even though we had a lot of capacity in reserve, the energy market perceived itself as being in scarcity because it couldn’t access those reserves because we didn’t have real-time co-optimization yet. And so rather than suppressing prices, this caused prices to blow out.
Andrew Reimers (21:57.256)
And we estimated billions of dollars of excess costs caused by how the situation was managed. And so you can have price distortions in either way. And on one hand, they’re reducing the incentive to build new generation, which creates kind of resource adequacy concerns. On the other hand, you’re creating excess and unreasonable costs for consumers. And in either case, you’re creating a lot of uncertainty and risk for anyone who’s trying to figure out.
Andrew Reimers (22:26.616)
How should we go about investing in this market, whether it’s on the load side or the generation side?
Josh Rhodes (22:33.58)
Yeah, it’s been interesting, you know, since winter storm, Yuri, we’ve had a bunch of discussions of, well, frankly, capacity like products, right? know, capacity is a four letter word in RECOT, but I remember there was the LSE obligation. There was the PCM performance credit mechanism. We’re now looking at another ancillary service. mentioned ECRS, we’re talking about DRRS. Do you want to touch on DRRS? Like what that might look like, what it actually stands for, et cetera.
Andrew Reimers (23:01.57)
Yeah. So DRRS stands for Dispatchable Reliability Reserve Service. And believe it or not, the origins of DRRS also come from a Potomac economics recommendation. know, part of the story with conservative operations that I haven’t really touched on is a concept called reliability unit commitment. So I mentioned in general, the market does not
Andrew Reimers (23:30.134)
decide when to commit resources. So ideally resource operators decide for themselves when they’re going to turn their power plants on based on some view of what prices are going to be that day. But in the case of forecast error or what have you, ERCOT does have the ability to force generators to turn on. And this process is called reliability unit commitment or Ruck. Everybody hates Ruck.
Josh Rhodes (23:58.412)
Why does everyone hate Ruff?
Andrew Reimers (23:59.562)
Everyone hates Ruck because the impact it has on clearing prices and because it isn’t hedgeable. And what that might mean is if you’re a load serving entity, whatever your cost exposure to Ruck is, you may have hedged your other kind of cost exposure. So regardless of what happens in real time, you have a price locked in. But if you’re then on the hook to help cover the cost of committing these resources.
Andrew Reimers (24:28.088)
then you weren’t able to hedge that in advance. So that is one reason people hate it. Another reason is a lot of times what’s getting committed are older resources and it’s just kind of a pain to start these up and there’s an implied opportunity cost of starting them up. So if you imagine like CPS in San Antonio has big issues with their emissions constraints. So since they’re right near a city, there’s air quality constraints they’re trying to manage. If you turn on my resource in March,
Andrew Reimers (24:58.304)
And it say it’s an annual emission limit that I’m trying to stay under. Now I’m running in March. I would really like to save my emissions kind of threshold for in the summer when the prices are higher, for example, or I might not want to have to keep as many staff around in March, or I might not want to have to do my maintenance during this window when the kind of maintenance market is more expensive. So, you know, I know you’ve reported on this before.
Andrew Reimers (25:24.802)
the maintenance window in ERCOT keeps getting tighter and tighter because everyone wants to be available in the summer when prices are elevated, that we increasingly have big winter events where people need to be around. And so in the fall and spring, everyone’s competing for the same relatively small market of maintenance vendors. And so you might want to be able to kind of stagger when you’re getting some of your facilities worked on. And if you keep getting instructions from ERCOT,
Andrew Reimers (25:53.656)
to turn on these old plants, it’s harder for you to do that. So those are just some examples of why people hate rock. And DRRS in some respects was really imagined as a way to bring that process into the market in a more economical, transparent, hedgeable way. And we initially referred to it as an uncertainty product. So kind of like what I was talking about earlier, you look a few hours ahead,
Andrew Reimers (26:23.03)
And it looks like you had been under forecasting load and over forecasting renewables. And you realize you have a supply shortfall on your hands and we can send out an instruction to commit a resource now or several resources because we see that there’s this looming shortfall. That’s the idea of the RRS originally. Now people tell me that if you went to those hearings where they were referring to DCRS, where they were talking about it.
Andrew Reimers (26:51.552)
It was also well understood that part of the motivation of DRRS was to, to some extent, incentivize new investment in dispatchable generation. That might’ve been part of the spirit of DRRS, but it’s hard to say. There was all this other stuff in the mix. There was the PCM, like you mentioned before. Eventually there was the Texas Energy Funds. There are all these different things in the mix that are trying to incentivize new thermal generation.
Josh Rhodes (27:19.328)
at Texas Energy Insurance product. Remember that 10 gigawatt thing too? Yeah.
Andrew Reimers (27:23.298)
Yep.
Andrew Reimers (27:23.718)
So the PCM didn’t really get off the ground. There were various proposals to try to design something that would satisfy the legislation. TEF seems to be having a hard time maintaining interest and the original series of proposals for it has winnowed down to a relatively small stack and it’s unclear how much of that’s actually going to get built. And now we’re left with the RRS and ERCOT feels like they
Andrew Reimers (27:52.994)
have to at least try to inject a kind of resource adequacy objective into the DRRS product. And so one of our big fights with ERCOT right now is to push back against this concept and insist that DRRS be developed as strictly an operating reserve product because there are some kind of fundamental flaws with the resource adequacy concept they’ve come up with.
Andrew Reimers (28:21.332)
And I’m happy to get into all that. This is something we’ve been talking a lot about lately.
Josh Rhodes (28:26.038)
Yeah, if you could, mean, you know, part of what Potomac does is comment in dockets and other types of things like that. Can you talk a little bit about those disagreements there that y’all have had in the public sphere? Yeah.
Andrew Reimers (28:37.228)
Yeah. So they’ve had various workshops on DRRS. I’ve been at all or most of them. They have two distinct rule makings out. These are called NPRRs. Nodal protocol revision request. so anytime there are changes to the ERCOP market, they are usually instantiated through this NPRR process. And the two NPRRs related to DRRS currently are 1309.
Josh Rhodes (28:47.63)
And what does that stand for again?
Andrew Reimers (29:06.798)
which defines DRRS as an operating reserve product. And 1310, which incorporates the kind of resource adequacy components for DRRS. We are mostly okay with 1309. I think it might be too in the weeds to explain where we have issues with that, but sure. 75 % on board with it, know, qualified support for it. 1310, we recommend that it be.
Andrew Reimers (29:34.252)
dismissed with prejudice. we have severe issues with 1310. So what are we talking about? ERCOT is talking about implementing an hourly capacity product, which they want to refer to as an ancillary service. And so you can imagine that every hour you are procuring a certain amount of capacity. The idea of this capacity product is simply to inject revenue into the market to support
Andrew Reimers (30:03.18)
resource adequacy. Fundamentally, the problem with this concept is you can’t effectively set procurement targets today to satisfy demand in the future. So we’re procuring this capacity in the day ahead in real time markets, according to a demand curve. And that’s supposed to produce enough revenue that we’re going to get the investment that we need to have the capacity built for the future.
Andrew Reimers (30:33.048)
So that’s kind of the fundamental issue here.
Josh Rhodes (30:35.97)
Yeah. Anymore thoughts you’ve got on that, that would be great. I mean, you also brought up a good point about it’s trying to plan today for what the future looks like. And that’s also somewhere where I wanted to go because I mean, you know, the future of five years from now, at least from all the charts and all the reports and like, you know, everything in terms of demand growth look way different than they did five years ago. Right? Sure. And so what’s different there? And if you want to tie in like,
Josh Rhodes (31:02.508)
what your feelings are on this product relative to where demand looks like it’s going. That’d be great to know.
Andrew Reimers (31:08.472)
Yeah, so we covered the kind of demand forecast prospectus in our last edition of the State of the Market Report. So I don’t know if I mentioned that at the top. So one of the main deliverables that my office produces is something called the State of the Market Report. Right. Every IMM produces these for whichever ISOs they monitor. And it’s a series of metrics and trends and things like that that have been observed in the market over the last several years.
Andrew Reimers (31:37.376)
And then usually there are deep dives into a handful of contemporary issues where we’ve either identified something strange or problematic, or we are using it as a case study to propose some kind of recommendation.
Josh Rhodes (31:51.864)
Okay. It’s a very useful report. I’ve used every single one of them, think, for the past decade or so. On some level.
Andrew Reimers (31:57.614)
Happy
Andrew Reimers (31:57.774)
to hear it. The 2024 edition of the report features a kind of long deep dive into the whole demand forecast situation. And these numbers are really crazy to put it simply. as far as the actual, yes, as far as the actual forecasts on demand, our position on that has been that the analysis that’s been done to produce those forecasts
Josh Rhodes (32:13.933)
I that’s the scientific term.
Andrew Reimers (32:26.808)
probably is over forecasting how much load we’re going to have. I could get into specifics. There’s this officer letter load business, which is effectively transmission utilities get a request to interconnect something. And the developer of that project signs something saying that they intend to develop this project. That gets sent to ERCOT. Now this is in ERCOT’s demand forecast.
Josh Rhodes (32:53.59)
And part of that was driven by like a bill in 2023, like HB 5066, right? It’s not just ERCOT, it’s the legislature saying thou shall consider this, right?
Andrew Reimers (33:01.794)
Right.
Andrew Reimers (33:01.994)
Well, a lot of the problem that we are seeing for better or worse is the way that legislation actually manifests itself on the ground. And, you know, I’ve seen it firsthand. I totally sympathize with how difficult it is to satisfy the language of a lot of this legislation, because once you actually start trying to implement these things, it’s hard to do it in a way that
Andrew Reimers (33:27.872)
is going to satisfy the statutory language while also being sound market design and everything.
Josh Rhodes (33:34.102)
I remember like post-URI, it seemed like the legislation was getting more and more specific, whereas before it was the legislature sets like general goals, the public utility commission puts them into like policies and then ERCOT creates metrics or protocols, right?
Andrew Reimers (33:50.328)
Well, and actually designs the, you know, technical things that are needed to satisfy the PUC rulemaking or what have you. And that is conceptually how I think it’s supposed to work. And the more detailed the legislation is, the harder it is to actually implement it properly or in a way that isn’t going to have other negative consequences. And so I’m not an expert on how you would necessarily go about doing this. If you were trying to do it effectively, it’s a perfectly reasonable.
Andrew Reimers (34:19.274)
idea that future demand growth should be factored into whether it’s, I mean, a big part of it would be transmission upgrades, for example. And maybe if you want to factor into your shortage pricing mechanism in a market like ERCOT, having some future view on both supply and demand. Cause I keep mentioning how forecast error factors into the operating reserve situation. If you’re imagining the rate at which we’ve built more solar,
Andrew Reimers (34:48.386)
then you might want to formulate your shortage pricing over the next year based on the fact that you’re expecting even more solar in the system. The magnitude of your forecast area is gonna grow a certain amount and you want to account for that in the way your shortage pricing works. And so it’s a reasonable enough thing that you’d wanna factor these forecasted changes into market design, transmission planning, things like that. But when we looked into it as far as last year,
Andrew Reimers (35:17.964)
The forecasted load growth didn’t seem to be very reasonable to us based on what we were able to get our hands on. And so if you’re going to use that kind of forecasted load to justify some kind of market design change, that’s going to be a problem. But the real problem with the DRS thing isn’t so much that they’re trying to incorporate future demand growth into some kind of resource adequacy product. It’s they want to clear that product in real time.
Andrew Reimers (35:46.37)
based on real-time operating conditions to produce the revenue to satisfy capacity needs in the future. And that’s really where the disconnect comes from. It’s a completely different thing if you’re talking about, we have scarcity pricing in the market today. You’re getting paid based on the value you’re providing the system today, but that elevated pricing is also telling investors, okay, there’s room in the market for more capacity. If we’re producing high prices like this today,
Andrew Reimers (36:15.33)
then that means that already based on the current kind of supply and demand dynamics in the system, we can expect prices to stay high until more generation gets built. And so in that sense, producing prices today based on real-time operating conditions is an effective incentive to build more capacity for the future. Putting in a capacity product where you’re trying to produce revenue, even if the supply and demand conditions today are not stressed,
Andrew Reimers (36:45.002)
And the whole objective is to hope that that’s going to be like some efficient allocation of capital to invest in the future. The signals just don’t work very well that way.
Josh Rhodes (36:56.59)
Okay. So we’ve talked about pricing and we’ve talked about products. We’ve talked about, you know, summer demand and all this kind of thing. And we talked about 2023. One of the things that I have seen the past couple summers though, is prices seem to be a bit divorced from peak demand, right? I mean, the past couple summers, 2024 and 2025 didn’t hit the peaks that 2023 did. But I mean, I think one of the big drivers there was like a lot more solar, right? So even when the systems...
Josh Rhodes (37:24.162)
Delivering the maximum amount of electricity to end users like prices have been low and the spicy part of the grid has been pushed to like, you know, the net peak demand the 7 to 9 p.m. like How are y’all thinking about that in terms of price signals and things like that? seems like that price window is getting a bit narrower and I whether been any conservation alerts in the past couple years
Andrew Reimers (37:47.546)
Right, right. So you’re definitely correct that the massive increase in solar has kind of disconnected the correlation between prices and demand. So you still have some elevated pricing like in the evening when the sun is going down. Batteries are quickly kind of cannibalizing all of that. They’re really effective at managing that situation because usually it’s pretty predictable. Like every night the sun goes down and you need
Andrew Reimers (38:16.652)
batteries to fill the gap of tens of gigawatts of solar coming offline. And we have something like 15 gigawatts of batteries in the network now. And so they’re pretty effective at doing that. Even though they’re duration constrained, usually they can generate power for one or two hours at full output. And so that’s more than enough usually to handle this kind of situation. But like I’ve been saying all along, it’s not as simple as just what’s the peak demand or even the peak net demand. It’s really the
Andrew Reimers (38:46.552)
Forecast error. So something that happens not infrequently is, know, wind is a lot trickier to forecast than solar. you know, the sun comes up, the sun goes down, know, in regularity. Yes. Shocking regularity. Clouds do complicate solar and the magnitude of the forecast error is still, you know, something that has to be designed around. But the general shape of the generation profile is pretty consistent. Wind is
Josh Rhodes (38:58.83)
shocking.
Andrew Reimers (39:15.722)
more mercurial and just a quick aside on a Andrew Reimer’s take that is not a Potomac economics take. think wind is a trickier resource to design your system around for all those reasons. mean, it generates a lot, which means it kind of cannibalizes the market for other resources. So maybe a lot of thermal resources that used to stay on overnight now turn off overnight because the wind is blowing a lot and.
Andrew Reimers (39:43.182)
they’re not going to make any money because prices are depressed. And then you can’t necessarily count on the wind to be there when you really need it. And an example of that is say the solar downramp happens almost every day. The way that happens is the sun is going down and then the wind kind of picks up as it cools off and gets darker. Well, say that wind picking up is just delayed by 30 minutes to an hour. Now you have a
Andrew Reimers (40:09.706)
reliability situation on your hands where you’re probably going to see elevated pricing. And depending on how big that delay is and the magnitude of that delay, are you concerned that you’re going to use your storage resources effectively to manage it? This is all kind of a long way of getting to my point. We think the way to kind of manage that situation is something called a multi interval real time market. So they already have these and Kaizo has this. You really need something like this. If you’re going to.
Andrew Reimers (40:38.7)
strategically and economically schedule batteries. So batteries, the important thing to think of is opportunity cost. If I discharge the battery now, I can’t necessarily discharge it in the future and I might really prefer to have it in the future. It might even make more money in the future. And so if you can run a real time market that looks ahead over the next hour or two hours and sees that you want to reserve some of that battery capacity,
Andrew Reimers (41:08.226)
because demand is going up and because the wind forecast has changed or something like that. That’s really how you would go about doing that rather than what we see ERCA doing, which is trying to account for more and more forecast error in their operating reserve policy.
Josh Rhodes (41:25.216)
Is this kind of the pushback that y’all have been having on the post real-time co-optimization in terms of like the battery duration requirements?
Andrew Reimers (41:32.896)
It 100 % is. for example, non-spinning reserve. Non-spinning reserve is, you know, until taking DRS out of the question or whatever, kind of the lowest, lowest grade quality of reserves that ERCOT has in the system really meant for over an hour or so dealing with forecast error. ERCOT has committed to maintaining a four hour duration requirement for non-spin, meaning whatever.
Andrew Reimers (41:58.39)
volume of non-spin they want to procure is related to the forecast error over four hours. You know, where does that four hour number come from? A lot of it comes from looking at the existing gen mix where we, seem to be rucking these four and six hour start time units a lot. It is based on concerns over duration constraints or duration limited resources rather. Our position on that has basically been.
Andrew Reimers (42:28.268)
Say you have an issue that manifests itself over an hour and you’re worried about the duration that the batteries have. If this is a real, you know, scarcity situation, you’re going to expect elevated prices. And as that hour goes along, that’s plenty of time for, we usually have a gigawatt or more of quick start gas turbines that can turn on in an hour. And so the idea would be the batteries have more than enough juice to
Andrew Reimers (42:58.688)
handle things for an hour and then by the end of that hour you’ve sent the signal to this gas generation to commit. And so the idea that you need all of that baked into your operating reserve policy as opposed to letting real-time market prices incentivize more generation to come online, that has been sort of a big part of our complaint here. Another aspect of this complaint, and this is a little more technical, but let’s see if I can explain it.
Andrew Reimers (43:25.858)
By imposing a four hour duration requirement on batteries to provide non-spend, you’re actually incentivizing them to sell energy rather than to carry operating reserves. So I always use the example of as a hundred megawatt, hundred megawatt hour battery. So I can only output at full power for one hour. I can either sell a hundred megawatts of energy or I can sell 25 megawatts of non-spend.
Andrew Reimers (43:52.128)
And so unless the price of non-spend is four times higher than the price of energy, I would just rather sell energy and say all the other operating reserves are fully subscribed. So this, I’m just making a trade-off between non-spend and energy. So now I’m going to sell energy and I’m going to run out of state of charge and then say the problem persists. I mean, if I had just been selling reserves instead of selling energy, I’d have more gas in the tank to be around for this problem. You can see how this is the kind of thing that a multi-interval market
Andrew Reimers (44:20.76)
could potentially help mitigate.
Josh Rhodes (44:23.542)
Is that something Potomac’s making recommendations on and push for?
Andrew Reimers (44:26.622)
Yeah, yeah, it’s been a recommendation of ours for a while. It’s something that would take forever to actually make its way through the ERCOT stakeholder process. It’s not a trivial thing at all.
Josh Rhodes (44:35.916)
Yeah, who would be for and who would be against that? Would there be camps on that one?
Andrew Reimers (44:40.066)
I’m sure there would be, but I would need to think more about it because a lot of entities, even if you can imagine them benefiting from the situation, they might have their business model oriented around the status quo. Sure. You could imagine like if you’re a thermal resource where I’m like a 30 minute turbine or something like that, having the ability to be economically committed by the system could be beneficial to me. It could reduce risk that I’m going to commit.
Andrew Reimers (45:09.258)
and prices aren’t going to be like sufficient to cover my costs, for example. I think it could also be beneficial to batteries, but you create all this uplift problem as well, which is if I, you know, am looking ahead and see a need for generation in the future, but then it turns out I had the forecast wrong and I saved you now. I didn’t discharge you now and I discharged you 30 minutes from now and you lost money because I didn’t discharge you when prices were actually high.
Andrew Reimers (45:39.01)
that creates kind an opportunity cost problem that you have to figure out how to deal with. So it introduces new complexities. It’s really an effective kind of reliability scheduling tool more than anything else.
Josh Rhodes (45:51.054)
Josh Rhodes (45:51.655)
Okay. Just a couple more questions. What’s one thing you wish policymakers better understood about the electricity system in Texas?
Andrew Reimers (45:59.662)
Yeah, so here’s the story I have been spinning recently. Let’s follow the logic of conservative operations a little bit and let’s take it for granted and try to fix it instead of arguing against it. So say you want to operate the grid more conservatively because you have a very low tolerance for outages. Well, one thing you’re saying is you have a very
Josh Rhodes (46:15.084)
Okay.
Andrew Reimers (46:28.034)
high value of lost load. We haven’t really gotten into value of lost load. It’s a, it’s a very controversial topic. I actually have a paper here from our friend, Will Gorman at Lawrence Berkeley. Also former Weber group, the quest to quantify the value of lost load. So it is as academic as it gets, but conceptually it relates to how you formulate shortage pricing. So if you’re worried about some probability of load shed,
Josh Rhodes (46:41.036)
Also a Weber Group student.
Andrew Reimers (46:57.538)
You have to also put a price on how costly load shed is before you can really do anything about scarcity pricing. So we need to adjust this shortage pricing to reflect the fact that we have a very high value of lost load. So now we’re going to take all those demand curves I was talking about earlier, and we’re going to calibrate them to the fact that we have a low tolerance for outages. So far, so good. That’s at least a consistent way to go about doing things. But now what are you going to do?
Andrew Reimers (47:26.786)
You’re going to tend to raise the price of electricity. You’ve effectively bumped up the floor on the clearing price for electricity. Maybe that’s okay. Maybe people are really, would prefer to pay more for electricity if it meant that they were really buying themselves, you know, security against outages.
Josh Rhodes (47:45.272)
Like you pay for firm gas versus like market gas or something like that.
Andrew Reimers (47:49.304)
Perhaps it’s not entirely unlike thinking about insurance or something like that. I would posit that as a native Texan, the whole kind of reason that this, you know, sun bleached hellscape has become a massive economy and a very dynamic place is really because it’s been a good place for doing business. It’s been cost effective, the energy markets and things like that, whatever their flaws have been, have been efficient and
Josh Rhodes (47:53.368)
Yeah, okay.
Andrew Reimers (48:17.248)
relatively lower cost than a lot of the competition. mean, if you compare Texas and California, there’s a big difference in the access to and cost of energy. And so I would just suggest that if you follow the logic where to get the reliability that conservative operations supposedly is trying to get you, the only way to do it is ultimately to pay more for electricity. And then you’re left with a real conversation about how much more are we willing to pay for?
Andrew Reimers (48:45.654)
this level of reliability and is this kind of a reasonable end goal?
Josh Rhodes (48:50.936)
Hmm, sure. I’ll make a plug for my part of Texas, East Texas, which is less sun bleached. Lots of pine trees, really tall pine trees. Yeah, yeah, yeah. I guess my last question is, Andrew, is there anything I didn’t ask you that you wish I had?
Andrew Reimers (49:07.008)
Okay, so something that you didn’t ask me about that is another topic that, you know, relates to this whole issue is the concept of out of market actions. And so basically there are all these different programs that get glued into the electricity market design kind of landscape. And you’re familiar, I’m sure with a lot of these, we have emergency reserve service, we have firm fuel supply service. There’s a proposal for an out of market.
Andrew Reimers (49:36.278)
residential demand response service. Something I want to highlight for listeners of this podcast who are interested in these topics is that all of these programs are ways of kind of injecting revenue into the energy market that is not directly coming out of the clearing prices themselves. And what they actually do is they incentivize behaviors that tend to suppress the energy price. So for example, if you’re paying
Andrew Reimers (50:04.878)
through some sort of backdoor mechanism to turn down residential load, for example, that’s going to have an impact on the clearing price of electricity. And so what we’re trying to get at here, and this is kind of a big push from my office is all of these programs ultimately are pulling revenue out of what is set by the energy price and sort of inefficiently allocating it through all of these other programs. We’d really recommend
Andrew Reimers (50:32.032)
Really nailing down the shortage pricing mechanism as the primary way that investment signals are made in ERCOT is kind of the overriding mission of this office presently.
Josh Rhodes (50:44.504)
So to keep it pure, what you’re saying?
Andrew Reimers (50:46.83)
Keep it
Andrew Reimers (50:47.05)
pure. mean, you know, we don’t want to be overly ideological about it. It’s just that there are counteracting forces here if you go the other direction. So you might think you’re improving the situation by implementing some of these programs, but it’s hard to actually say how any of that’s going to net out. And what we’re confident of is that it’s going to have an impact on efficient price formation. And if you believe that the wholesale market is a really efficient way of allocating
Andrew Reimers (51:14.978)
you know, scheduling who’s going to run and forming a price, then you would be apprehensive to do anything that’s going to interfere with that.
Josh Rhodes (51:25.294)
So would that look like all of these programs figuring out how to actively bid into the market?
Andrew Reimers (51:32.844)
Yeah, sure. So a good kind of juxtaposition here. The AIDR program we’ve generally been pretty favorable for. you know, the guys from base may have been on the podcast already. I’m not sure. They’re basically like a residential battery developer. They have a pretty interesting business model where they’re now a pretty big player in our cuts. AIDR program where that is one way of kind of getting retail customers exposed to wholesale prices.
Andrew Reimers (52:01.826)
That’s a much more efficient solution than this resDR program that our cot has proposed.
Josh Rhodes (52:08.256)
And ADER stands for Advanced Distributed Energy Resources.
Andrew Reimers (52:11.906)
I think it’s aggregated distributed energy resources. Cause they basically for each kind of load zone, you aggregate all of the customers who are participating in that program. And now they’re treated as one resource in kind of the ERCOT market model per load zone.
Josh Rhodes (52:29.368)
So if you’re in that program and you’re actively participating in, you know, ERCOT’s market dispatch through SCED, I mean, that’s kind of like, you’re participating in the energy side of the market, right? Versus like some of the other things you’re saying, if they’re more capacity type products, because we don’t have a capacity market, like they’re being shoehorned in there. Is that the fair summary?
Andrew Reimers (52:46.808)
Well, so for example, ERS, ERCOT recently presented that a huge percentage of the emergency reserve service market has been taken over by crypto operators. I’m not here to throw crypto operators under the bus. I used to work for one. Fair enough. But part of the whole point of the way the economics of that kind of business is it’s very price responsive. And so when wholesale prices are higher,
Andrew Reimers (53:16.882)
they have a strong incentive to reduce their load. And so they’re already going to be responsive to price conditions on the grid that are supposed to be reflective of the reliability situation on the grid. And now you’re just funneling all of this extra money to them for something they were going to do anyway. And so that would be another example where, you know, rate payer money is being distributed really inefficiently. You’re not really getting anything extra for what you’re buying in that case.
Josh Rhodes (53:45.442)
Yeah, okay. That sounds like something that the market monitor would want to be on top of.
Andrew Reimers (53:50.156)
Yeah, this is definitely something we’re kind of working on our response to now that we’ve seen this report from ERCOT at a recent market meeting presentation.
Josh Rhodes (53:58.776)
With that, Andrew Remmers, thanks for being on the Energy Capital Podcast.
Andrew Reimers (54:01.806)
Thanks a lot Josh, it was fun.
Josh Rhodes (54:04.984)
Thanks for listening to the Energy Capital Podcast. If today’s conversation helped you make better sense of how the energy system actually works, share the episode with a colleague and hit follow on your podcast app. You can find us on Apple Podcasts, Spotify, and all the usual platforms. For deeper analysis and context each week, subscribe to the Texas Energy and Power at texasenergyempower.com. That’s where you’ll find every episode, every article, and our latest updates. We’re also on LinkedIn, X, and YouTube.
Josh Rhodes (54:34.35)
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, Ideasmiss, Austin Energy, or Columbia University. A big thanks to Nate Peevee, our producer. I’m Joshua Rhodes. Thanks for listening, and we’ll see you next time.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.texasenergyandpower.com/subscribe
- Luisteren Nogmaals beluisteren Doorgaan Wordt afgespeeld...
- Later beluisteren Later beluisteren
Stop Heating Texas Like It’s 1985 (with Kurt Heim)
11 feb· Energy Capital Podcast
Every time a winter storm hits, Texans run through a mental checklist: gather more blankets, drip the pipes, and hope the grid holds up. Kurt Heim, Vice President of Environmental Advancement at Daikin Comfort Technologies North America Inc., understands why that anxiety stuck after 2021’s devastating Winter Storm Uri.
But this reliability and affordability problem has a surprisingly accessible solution.
In this episode, Kurt and host Matt Boms zero in on a big part of winter peak demand that doesn’t get enough attention: electric resistance heating, especially in older houses and apartments. These systems use excessive amounts of electricity to heat homes in one of the least efficient ways possible.
It’s an easy issue to miss … until you run the math for millions of housing units.
As Matt notes, if Texas has to serve roughly 12 gigawatts of resistance heating load during extreme cold temperatures, that represents real low-hanging fruit. Addressing it would fortify the grid in a way that helps Texans who struggle to afford their power bills:
“What it would do is pay some really good dividends around affordability.”
Kurt also talks about “flattening the peaks” so Texas gets more value out of infrastructure that Texans already paid for, instead of constantly adding fixed costs that show up in rates.
That framing lands even harder in light of ERCOT’s booming load forecasts: if Texas is serious about serving this growth, we should be just as serious about reducing waste, especially during the most extreme weather.
Policy levers that are already moving
Diving into the weeds, Kurt discusses updates to the technical reference manual that sets industry calculations for energy efficiency. The updates will make it easier for new construction and multifamily development to have more efficient systems.
New construction is only part of the story—improving existing structures will take more work. But as this episode makes clear, such investments will pay off in greater reliability and affordability.
Final Thoughts
Texas can chase growth and reliability at the same time. But we can’t afford to do so with outdated systems that exacerbate grid weaknesses and punish the people least able to absorb their bills.
The grid has a waste problem. Texas needs to deal with it. The best place to start is with a readily accessible solution that addresses a clear problem, lowers bills, frees up capacity when Texas needs it the most, and allows the grid to keep growing.
If this sparked a question for you, drop it in the comments. And if you know someone who still thinks winter reliability is only about power plants, send them this episode.
Energy Capital is produced by ClarityForge Studios.
Timeline:
* 00:00 – Winter peaks, why it matters
* 01:20 – Kurt Heim, background
* 02:59 – Winter anxiety, resilience mindset
* 05:08 – The resistance heating problem
* 07:08 – How big these loads get
* 09:21 – Heat pumps, how they work
* 13:11 – Climate tech, variable speed
* 15:10 – Efficiency math, 1x vs 2–4x
* 16:50 – Economics, bills and adoption
* 18:57 – ACEEE study, scale of savings
* 26:58 – What blocks heat pump adoption
* 29:05 – Codes, standards, and design basis
* 35:30 – Incentives and contractor training
* 37:53 – Political will, signs of progress
Resources:
Guest & Company
* Kurt Heim - LinkedIn
* Daikin Comfort - LinkedIn
* Matt Boms - LinkedIn
* Texas Advanced Energy Business Alliance - LinkedIn
Books & Articles Discussed
* Transforming Texas: How Heat Pumps Can Replace Electric Resistance Heat, Reducing Costs and Winter Power Peaks
* Quantifying the impact of residential space heating electrification on the Texas electric grid
* Our Homes Aren’t Ready for Extreme Cold and Power Outages
Related Posts by Texas Energy and Power
* Texas Got Tested, Grid Stayed Upright
* 2022 Cold Snap Shows Resistance is Futile
* ERCOT calculates a 1:7 chance of outages in December; could be worse in January and February
* ERCOT Still Doesn’t Understand Winter Demand
* NRG’s Gigawatt VPP in Texas with Travis Kavulla
External References and Tools
* Energy Efficiency at the PUCT
* Texas Climate Zones by County
* State Energy Conservation Office Programs
Transcript
Matt Boms (00:05.004)
Why does Texas continue to see winter peak demand spike so sharply during cold weather, even years after winter storm Uri put winter reliability front and center? Welcome back to the Energy Capital podcast. I’m Matt Bombs. And today we have a really special guest and someone I’ve been excited to talk with for a very long time. Joining me is Kurt Heim. Kurt is vice president of environmental advancement.
Matt Boms (00:32.662)
and Texas Government Affairs at Deichen Comfort Technologies, one of the world’s largest manufacturers of high efficiency heating and cooling systems. Kurt has spent more than two decades in the HVAC industry, including leading the development of Deichen’s massive manufacturing facility in Waller, Texas, one of the largest HVAC plants in the world. He works at the intersection of technology, manufacturing, policy, and grid reliability.
Matt Boms (01:02.102)
And he is exactly the right person to help us talk about how heat pumps can lower bills, strengthen the Texas grid and help us stop panicking every time winter shows up. So Kurt, you’re the star today. Welcome to the show and thanks so much for your time.
Kurt Heim (01:20.108)
Matt, thank you very much for having me. I’m a long time listener of the podcast and I’m really excited about the direction that you’re going in. I’m just really pleased to be here and get a chance to talk about ePumps.
Matt Boms (01:32.91)
Thanks so much, I appreciate that. So I want to kick us off. We’re coming off of this winter storm Fern and it feels like this anxiety cycle that we go through in Texas. You can trace this all the way back to Yuri and understandably Texans get nervous when they hear a winter storm is coming. We had a few since then, we had winter storm Heather that hit, now we have Fern. And I think just to tee this up, why do we still feel like the grid is on knife’s edge?
Matt Boms (02:02.41)
every time it gets cold in Texas.
Kurt Heim (02:05.036)
Yeah, that’s a good place to start. I am probably going to say that really Yuri was a shared experience in a searing event that touched a lot of people. I don’t know anybody that didn’t have some level of disruption in their life. Mild forms of it would have been that you lost your power for a few days, but you know, a lot of people had severe issues. My neighbor was one of them that lost power, but then had pipes burst in his
Kurt Heim (02:34.026)
ceiling in his attic. And so he had a major, you know, rehabilitation of his, of his house. So those things really make an impression in your mind when we watched it happen in front of us. And there were a lot of scary things that were talked about at the time. Like would we lose the grid? Would it lose functionality? And that was something that I think sticks in our mind going forward. So I think that’s why we still have some anxiety around it.
Kurt Heim (02:59.434)
I think for me, I try to use the anxiety to my benefit. Like, Hey, let’s prepare for it. Let’s get things in line to do it so that you can personally be more resilient. But I think that’s where it comes from, Matt. We just all had that very, very visceral experience with Yuri.
Matt Boms (03:14.87)
Yeah, it’s definitely a shared experience. And I know that the media pays a lot of attention now when a winter storm comes. And the question that I get asked the most is, you know, will the grid survive this winter storm? And luckily we did make it through the last one, right? But I want to really pick your brain on what the root of the problem is here, right? Does Texas have a winter grid problem and what can we do to solve it?
Kurt Heim (03:43.148)
Yeah, I think you’re putting a fine point on it. You know, we’ll talk a little bit about technology and heating technology specifically as one of the, I guess you could call it vulnerabilities that we have. But you know, what these events really teach us is that we can put a button on some of the things that we need to change and do. And so, you know, out of URI, there was a lot of attention paid to weatherization. And I think that the
Kurt Heim (04:11.106)
The legislature has done a lot of good work and then the PUC and ERCOT have done a lot with that too. We may have that largely behind us, but then we’re also exposing these other rocks. And one of them is around heating technology. We’ll talk a lot today about electric resistance heating. And that is a form of heating that is extremely wasteful. It’s an old technology that we still have on our grid, but we have it its scale.
Kurt Heim (04:38.986)
And so that’s the concern really that we’re driving forward and one that we really need to keep in front of us. And one that we can solve as, you know, if we’re talking about the energy discussions, one of the nice things about where we are today is that it’s more of an all of the above discussion. And I truly sense that when I’m talking to people about it. so finding places to understand where we have opportunities, where we have levers, where we have things that we can change.
Kurt Heim (05:08.546)
that are not terribly expensive, but they need to be addressed is really where we are. so I think winter grid problem, I think we have an electric resistance heating issue that we need to solve. And that’s one that we’ll probably talk about some of the stats in this discussion, but it’s not insignificant. And I think that it fits a lot with where Texas wants to go. We probably want to use that power that we could save by changing heating technology.
Kurt Heim (05:34.882)
to do other more value added things that will help the state prosper. that’s really what I think we have is a heating problem, heating technology problem.
Matt Boms (05:43.862)
Yeah, well said and help us understand what that means, Kurt. So when you say resistance heating for someone listening to this podcast and maybe they’re in a house or an apartment and they have resistance heating, what does that look like? And how could that person look at alternatives, right? Like walk us through why so much construction in Texas is already built with resistance heating versus more advanced technologies.
Kurt Heim (06:14.076)
yeah, this is a good place to start. So an electric resistance heater is basically what you see in your toaster. What you do is you run electric current through resistive wires and those wires heat up and they glow. And so then if you push air across that, now you’re heating with electric resistance heating. And they’re called a lot of different things like electric furnaces, for example.
Kurt Heim (06:38.7)
But what it is is it’s one unit of electricity produces one unit of heat, heating energy. And so it requires a lot of electricity to generate a lot of heat so that you can heat a dwelling. A couple examples of where that is. If you’re in a single family home and that home was about, let’s say, 2,000 square feet, you might have 10,000 watts of electric resistance heating if that’s how you’re heating it.
Kurt Heim (07:08.334)
10kW. If you’re in an apartment, like a one bedroom apartment in Houston, Texas, you might have five. So that’s a lot of energy that you’re using. Now you’re not heating. We don’t have the most severe winters, but really that starts to kick in around, you know, where your set point is. So if you keep your thermostat at about 68 degrees, you’re going to start seeing that electric resistance heater come on.
Kurt Heim (07:36.052)
at that point. Now it operates a little bit different than other technologies, but that is the most basic heating technology I think that’s out there other than, you know, like a gas furnace. And I think one of the reasons why we see it quite a bit is if you look at multifamily, a lot of multifamily is all electric. So in all electric areas, you really don’t have a lot of options for other fuels. So that’s why you see there, but at its core, it’s a hot wire that you blow air across.
Matt Boms (08:04.448)
Yeah, that’s really well said and I want to hear more about heat pumps from you because you’re such an expert on this. And I think there’s a myth out there that heat pumps don’t work in the cold. So can you take us through this and just explain in simple terms what a heat pump does and why it’s so much more efficient than resistance heating?
Kurt Heim (08:26.21)
Yeah, completely. think you’re right. I think there’s some misperceptions out there and it may stem from really what a modern heat pump is to maybe what a heat pump might’ve been and how it works. And really and truly most of the time you’re not going to know the difference between an air conditioner and a heat pump because the technology is held in the outdoor unit. And so what it is at its core is an air conditioner that can run backwards and it doesn’t create heat, it moves heat. So even
Kurt Heim (08:56.136)
zero degrees Fahrenheit or freezing, there’s a lot of heat in the atmosphere. And when the refrigerant cycle runs backwards, it collects that heat from outside and it moves it inside. So the parts of your air conditioner in the summer that get cold that you blow air across get warm and you blow that warm air around your dwelling and you get heat from it. So
Kurt Heim (09:21.292)
Because it doesn’t have to create the heat, it moves the heat and it uses the refrigerant cycle to do that. It can do it up to four times more efficient than the electric resistance heat. So think about it that way. It’s an air conditioner with a few different technology differences that allow it to run backwards and then collect that heat, which we know the sun’s renewing that heat all the time, but even at those low temperatures, there is...
Kurt Heim (09:47.65)
heat there to gather and move into your house to provide that more efficient heating.
Matt Boms (09:53.922)
Yeah, that’s really helpful, Kurt. And you mentioned the history and I think it actually is worth diving in a little bit and unpacking that because that’s the great thing about a podcast is we have time to talk and the long form conversation I think lends into getting into the weeds a little bit on this. So help me unpack how far heat pumps have come over the past few decades here. And maybe that’s where some of the misperceptions are.
Matt Boms (10:21.782)
as far as how efficient or how effective heat pumps can be in cold weather.
Kurt Heim (10:26.594)
Yeah, I think using kind of Houston or most of our state is in two different climate zones, climate zone two and three. So you think of it this way, Houston’s in two, Dallas is in three. So you get that kind of differential and that’s where most of the population is kind of, you know, above I-20, around I-20, between I-20 and I-10 and then south of I-10. But in those particular climates.
Kurt Heim (10:53.63)
We don’t have severe winters, right? We’ll have an occasional winter storm. But one of the areas that heat pumps have improved over the years is in their capacity, their ability to deliver and gather more heat and move more heat at lower ambient temperatures. And so one of the things that I think contributed to some hesitation about using heat pumps in the past is that that capacity would, start to run out of capacity at higher ambient temperatures.
Kurt Heim (11:21.868)
So if your heat pump wasn’t working well around 30 degrees and you need to design for 30 degrees, then you’ve got to look at some other technologies. But as things have evolved, compression technology, refrigerants, and things of that nature have improved, it’s improved the efficiency and capacity of that. And so now you see them operate very well in our climate zone. I think part of what we, I think, want to...
Kurt Heim (11:49.134)
talk about as well is the future. So one of the things that Dyken has as a core technology is variable speed. So a lot of what we’ll talk about in basic heat pumps is a single speed technology, which is really like your air conditioner turns on, it turns off. But variable speed will actually modulate or adjust with the need of heating and cooling that is required.
Kurt Heim (12:14.754)
what’s exciting about where the technology is going, it’s starting to move more into variable speed. And variable speed actually offers even more heat delivery at lower temperatures. So even, you know, as low as negative five, you’re going to have some variable speed heat pumps that are going to perform very well. For reference, you know, that negative five is probably mostly out of the design standards for, you know, Texas. Maybe you might get into some of that.
Kurt Heim (12:42.198)
in the pan handle, some of those variable speed will require no heating backup at all. So a lot of heat pumps will have a backup electric heater. Kind of the one that we talked about before will work the same way that if you are starting to get into a temperature where the capacity is going down, you’re not left without heat. It’s going to work in conjunction with that heater to deliver. But the promise that we really see a variable speed is being able to go to a lot lower ambient temperature.
Kurt Heim (13:11.978)
with very little, if any requirement for electric resistance heating. And another exciting thing just to kind of put out there for variable speed. I know you guys have done a lot of work on, you know, what needs to be on the grid. How can we actually create value with our consumption, so to speak? Variable speed offers a lot of promise for being responsive to grid conditions and
Kurt Heim (13:38.702)
because of the efficiency that it delivers. But the fact that, you know, if you needed to do a demand response in today’s world, you got to turn your system off, basically, you know, either move your set point to where it’s off or physically turn the system off. Variable speed could just go down to like, well, we’re operating at 80 % speed, we’ll go to 75 % or we’ll go to 65 % speed and really still have a lot of comfort.
Kurt Heim (14:03.97)
I say comfort. If some people really need, it’s a health issue. They need to have a pretty moderate climate in their home. They need a certain amount of heat, a certain amount of cool, but you may be able to achieve that with variable speed and not really have to turn anything off. So that’s really kind of going from, you know, the past where the capacities weren’t as good as they are now, improvements in refrigerant compression technology and heat exchange, bringing it to the future. Now variable speed is factoring into it and
Kurt Heim (14:32.554)
even getting to a place where backup heating isn’t really required in a lot of climates with those variable speed systems.
Matt Boms (14:41.184)
Yeah, that’s a game changer. And it sounds like what I take away from that is Texas is uniquely suited for heat pumps, right? Like I think some people think of heat pumps as, you know, a great solution in a place like New England or the Midwest. But what I’m hearing from you is actually we’re uniquely positioned in Texas to benefit from heat pumps because of the climate that we have down here. And I think what I wanted to know, Kurt, also is when you were talking about resistance heating, said, you talked about that one to one.
Matt Boms (15:10.956)
Right, one unit of electricity yields one unit of heat. What does that look like on the heat pump side?
Kurt Heim (15:17.654)
It’s more like two to four times. So that’s where the efficiency is gained really, and not having to create, not having to use the energy to create the heat, but actually just use it to move around. So it can have what’s called the coefficient of performance. electric resistance heat has a one on your scale and heat pumps are going to be anywhere up to four. So that’s where you’re really driving a lot of efficiency. Let’s put that in perspective.
Kurt Heim (15:46.976)
And I’ll use for a point of reference, a project that we did in Houston’s fifth ward in an apartment complex where we took about 25 % of the HVAC systems that were electric resistance heat, and we converted them to heat pumps and nothing else was done to the dwelling. No added insulation, no windows and door ceilings. Nothing of that, just technology A and replace it with technology B.
Kurt Heim (16:13.07)
In those particular instances, we’ve seen about a 50 % reduction in the demand for energy in order to heat those dwellings. So those went in, in December of 2024. So we caught a really cold February in 2025. And now we’ll catch the data from this past winter storm as we’re kind of sitting here recording it. We’re on the last day, I guess, of the winter storm that we had in January of 2026. So we’ll catch.
Kurt Heim (16:41.794)
some of that data and it’ll be interesting to see, but yeah, those are delivering about 50 % reduction in demand.
Matt Boms (16:50.146)
That’s so wild because your baseline is cutting energy costs in half basically for folks who have heat pumps installed. And I want to jump into that and talk about the economics because Texans are very savvy when it comes to energy use, right? And we’ll jump into that in just a second. But I didn’t want to skip over the grid level conversation and how much of a difference this could make during a winter storm event, right? Because we have a winter problem in Texas.
Matt Boms (17:18.68)
There was a Texas A study that came out last year that talked about resistance heating over 2.7 million homes in Texas and still use electric resistance heat. They can each pull about nine kilowatts of, you know, during a cold snap like we saw last weekend. And if you add that all up, that’s 12 gigawatts of winter demand equivalent to 40 large power plants, right? So are we essentially looking at
Matt Boms (17:47.99)
millions of homes turning into giant space heaters at the same time. Is that really what we’re doing in Texas, the way that we built our homes and apartment buildings?
Kurt Heim (17:58.274)
Sometimes I look at it that way. Sometimes I’ll drive around and I’ll see a new apartment complex going up. And I think about each one of those with the five KW heater or maybe a bigger apartment with an eight KW heater in it. And we know that that’s happening. We’ve done our own research in the market. And we know that about 85 % of the apartments that you see, if we just talk about multifamily as a big cohort.
Kurt Heim (18:28.064)
About 85 % of those are going in with electric resistance heaters. So, and they’re going in at scale. And when you think about that, the life of that equipment could be 15 years. So you’re 15 years away from an end of life technology change where you have the opportunity to make a different decision, not necessarily that you are going to, but you’re about 15 years away from that. And so the Texas A study.
Kurt Heim (18:57.094)
And the ACEEE study really put a bright light on the potential that we have in changing out that technology and what that could go towards. You you hit it on, on the head about almost 3 million homes. think a big percentage of those are apartments. And I think a big percentage of those are all electric apartments, but that’s a big number, 9 KW per using that to heat. You know, that starts to.
Kurt Heim (19:26.786)
help you reason around why we had a winter peak that was over 80 gigawatts. You know, that’s like an August number, right? And so you start to see that at scale and it is something that really needs to be addressed and thought through. You know, we’ll probably talk about it. There are some levers to get there, but really that you framed up the problem right there. There’s a lot of waste there, but I think in our state, one of the good things about it is that
Kurt Heim (19:56.556)
You know, you could reframe where that energy could go and that energy could go to adding industry and jobs and prosperity, but we’ve got to draw big distinctions in how we go after it and really divvy up the problem and find these little pockets and areas of opportunity and go after them.
Matt Boms (20:14.758)
Absolutely. And now that Texas is ushering in this new age of data centers and AI and we’ve seen some load forecasting over at ERCOT that sees us doubling our peak demand in the next five or six years, right? So considering those numbers, you’ve got 12 gigawatts on the table right now in the form of resistance heating, right? So you would think that
Matt Boms (20:42.988)
The easiest and quickest solution would be picking that low-hanging fruit and saying, that’s something we could take care of tomorrow. That’s just an easy solution that’s sitting on the table. And it could at least, at a very minimum, avoid the anxiety that we all go through every winter time when there’s a storm and we’re sitting around wondering if the grid will survive.
Kurt Heim (21:05.6)
I think going after it makes a lot of sense. What it would do is pay some really good dividends around affordability. So if we, if we need to add that capacity, like you’re talking about, what we’re really talking about is increasing the fixed cost of our energy bill, right? There’s a lot that needs to go into that. Now there will be users of all that load, but if we can find ways to more fully use the capacity that we have.
Kurt Heim (21:33.878)
We can hold down the costs and the costs are going to be very important. There’s a lot of good research by TEPRI that really gets into how energy vulnerable people are and the things that they go through with their own curtailment and discomfort. You know, in the summer, they’re too hot. In the winter, they’re too cold and they’re trying to save. And really we can find these areas and eliminate this waste and help hold those costs down. We are going to grow and that’s going to happen, but I think.
Kurt Heim (22:02.772)
One of the things that sticks in my mind is at the Texas Energy Summit, Doug Lewin gave kind of a really nice Ted talk kind of thought discussion. And he talked about utilization of the existing infrastructure that we have and higher percentages of utilization are really what we need to strive for. We need to flatten the peaks so that we can get more utilization. Cause there we’re using the assets that we already have.
Kurt Heim (22:28.908)
And so that actually can start to make an argument that it could lower costs over time. So really that’s got to be part of the focus is getting to that.
Matt Boms (22:37.294)
Absolutely. Yeah. And let’s get into the economics here, Kurt, and you mentioned the AACEE study and we’ll share the study in the notes. Can you walk us through the economics here at, you know, just the household level? And there’s, think, common misperception that heat pumps are so expensive that they don’t make economic sense, right? So help us understand the real economics here.
Matt Boms (23:04.012)
What’s the return on investment, right? How long will it take me to recover those upfront costs?
Kurt Heim (23:09.762)
Yeah, really when we think about this, let’s go back to the kind of the original discussion that we had where, you know, what is a basic single speed heat pump look like? It looks like your air conditioner outside. So that’s kind of the starting point. And what does it have that’s different than that air conditioner outside? It’s got, you know, a few modifications to it. It’s got something called a reversing valve, and then it’s got a little bit of a different control board.
Kurt Heim (23:34.988)
When you’re talking about the added costs of that, you’re talking about a few hundred dollars between, you know, the sunk cost of buying a basic air conditioner and then the amount of additional spend and costs that you have to buy a basic heat pump. So a few hundred dollars in that. In that ACEE study, it looked at couple different ways that you would get into a heat pump. There’s a little bit more expense for retrofitting. So let’s say.
Kurt Heim (24:04.878)
$700, $800 or less on average is what they found. I think those are probably pretty good figures, but the savings could be substantial and it could be as high as, you know, close to $400 a year. So you’re looking at one to two year paybacks for the rate payer on that. They also looked at new construction. New construction is the cheapest way to put in a heat pump. You’ve got a lot of things at your advantage in that, in the procurement.
Kurt Heim (24:32.142)
because you’re buying at scale probably, you know, if you’re, if you’re a builder and you’re putting in a neighborhood, you’re not buying one system, you’re buying, you know, dozens, if not hundreds of systems. So there’s some benefit there and then lower cost if it’s designed in as a basis of design. And so, you know, we took that seven, $800 retrofit example, ACEE thought that that would come down by about half. So what would that give you?
Kurt Heim (24:59.126)
That would give you like a one year payback, right? On that for the people that go in that direction and the people that use a heat pump. So those are the economics. I think if you start to roll that into annual, if we started today and we started working through getting more and more systems retrofitted and then in construction, if we started, you know, having a higher percentage of them go in with heat pumps, that would have been electric resistance furnaces.
Kurt Heim (25:26.668)
then you could start to see in the billion dollar range per year after a few years in bill savings. And so there’s, you know, some calculations on that. What are the costs going to be per kilowatt hour? But right now we’re expecting those to probably go up 30 % over the next, you know, period of time before 2030. And I don’t think that’s a crazy thing to think about. So those improvements and paybacks are even going to go up.
Kurt Heim (25:52.578)
So in the example that we’re giving, it’s really, you you’re the homeowner. This is something that you should really take a hard look at. You’re the rate payer as well. So you’re making the decision in that. But also we talk about the multifamily piece of it. That’s where there’s some need for some economic alignment around incentives because the landlord or the builder or the developer has one set of incentives that are different from the rate payer. The rate payer doesn’t get to participate in the choice.
Kurt Heim (26:22.106)
of the heating technology so they can be the recipient of a higher bill due to that technology.
Matt Boms (26:29.292)
Yeah, you teed up my next question perfectly because in listening to you, it’s such a no brainer, right? Like, why wouldn’t you do this? If you’re saying that for new construction, essentially you’re getting a hundred percent ROI, right? On that initial investment of the heat pump. And then for retrofits, you’re making your money back in the initial one or two years. So the fundamental question in my mind is, well, why haven’t we fixed this already? Like.
Matt Boms (26:58.434)
What are the main obstacles here? Because it just sounds like a no brainer, Kurt. It sounds like we should all have heat pumps up and running in our homes and businesses. Yeah.
Kurt Heim (27:08.406)
Yeah, know, this is a question that vexes me quite a bit. Why can’t we get there? I think we’ve got a lot of tools to help us get there. Sometimes it’s a little frustrating because those tools are, you know, like incentives and rebates, et cetera, will pay for the switch back, you know, switch from electric to heat pump. But what is making you make the right decision out of the gate, right? How do we get there?
Kurt Heim (27:38.516)
And so really, I think it comes down to education because if somebody’s designing, we’ll use the apartment as an example. They’re designing an apartment. There’s a basis of design. If that basis of design is the code minimum, which is really what probably it is or heavily influences it, then you’re going to get the cheapest alternative, the least expensive capital outlay to get there. And that’s going to be an electric resistance heat, you know, an electric furnace.
Kurt Heim (28:08.52)
And why is that okay? Because you’re not the rate payer, right? You’re putting capital into the system, but you’re not actually paying the operating costs of it. So I think basis of design is something that we have to really look at, which goes back to the energy codes. And so really happy that the state is, you know, through a process in the midst of a process of updating those to a 2024 standard. But when you peel back the onion on that 2024 standard, it doesn’t deal with electric resistance heating.
Kurt Heim (28:37.976)
the way it needs to. It has a lot of restrictions on electric resistance heating for climate zones for and above. But remember earlier in the podcast, we talked about most of our state’s population is in climate zone two and three, and it doesn’t address climate zone two and three. That’s something that we’re hoping that the State Energy Conservation Office and Texas A who’s doing the evaluation will take a very hard look at. Because if they can
Kurt Heim (29:05.366)
understand how to make that code work better for the population in the state, then we’re going to get a basis of design that is going to be more restrictive of heat pumps. And then we’ll start to see the market change on that. But you asked a very good question. And I think for me today, as I sit here, we studied this problem quite a bit. It’s really comes down to a lot of a basis of design.
Matt Boms (29:29.27)
Yeah, it sounds like a combination of inertia, maybe lack of awareness and just business as usual, right? We’ve always built this way and this is how we’ll continue to build instead of looking at more advanced technology that really could save hundreds if not thousands of dollars for folks that are actually living in these homes, right? It’s a huge opportunity. mean, this is every time we have these winter storms in Texas,
Matt Boms (29:56.054)
It’s heartbreaking when you see the bills that folks have to pay because they just have old resistance heating and their homes can’t keep up with these temperatures that dip into the teens. if God forbid we end up in single-pitch temperatures, that could be a grid crisis, right? Just because of resistance heating.
Kurt Heim (30:12.844)
Yeah, you really put a good visual on it. I would say one other thing contributes to it in business as usual, I think is good, but we’re almost a victim of our own success. the rates, the kilowatt hour rate in the state is low relative to a lot of other parts of the country. That’s why we’re seeing a lot of load growth come to the state and the potential is even more.
Kurt Heim (30:38.038)
So there’s a lot that this state has exactly right, which attracts it to it. We just have a few of these tweaks that we need to go after in order to really shore things up. But, you know, I would add to that just kind of a victim of our own success.
Matt Boms (30:54.338)
Yeah, absolutely. And for someone who’s living in a multifamily apartment building, that person might not feel like energy is affordable because of how much energy they’re forced to consume, right? Because they’ve got resistance heating and the kilowatt hour might not be expensive, but if you add up all the kilowatt hours, it certainly is a lot of money that they’re paying at the end of the month.
Kurt Heim (31:18.946)
Yeah, you could, you you kind of set this up in a nice way to think about it from a cost perspective. The human part of it is really hard. People are dealing with a lot, but you could see somebody with a winter storm bill. Like if we had an extended cold snap, you know, they’re using 5kWs to heat that one bedroom apartment to cool it in August. You know, they’re probably using half of that for the compressor to run. Right. And so that compressor.
Kurt Heim (31:47.552)
in a heat pump is going to deliver the same heating that you’re going to get out of the summer, but it’s going to do it at a lower kilowatt per hour. And so they’re not experiencing that. And so for them, they’re not getting a break and they have to adjust their behavior. think in our fifth ward project, we’ve seen on average right at a hundred dollars in savings in the first winter that we had the units in. And I’m expecting that we’ll see that again.
Kurt Heim (32:14.894)
this winter, maybe even a little bit more, because we didn’t get them in until December of 2024. So we missed a little bit. It was a warmer winter, but 2025 was pretty cold for that. And then 2026 is starting off pretty cold too. So you think about the impact that somebody on a fixed income, know, hundred dollars, or we even saw one that was closer to $140. You spread that all across two or three months. That can really be a big impact to their budget.
Matt Boms (32:44.512)
Absolutely. Yeah. Well, I do want to focus here in the last bit of our conversation on what can be done to solve this problem, right? Like it’s a hard nut to crack. We’ve already talked about the reasons why heat pumps aren’t widely installed in Texas and why they should be installed in Texas is pretty much common sense for anyone who’s made it this far into the podcast. So what can we practically do about this problem, Kurt? You know,
Matt Boms (33:12.728)
Texas is a pro-business state, we’re not mandating anything anytime soon, but we do want a free competitive market that supports common sense technologies like heat pumps, right? So business as usual can’t be acceptable anymore. And for decision makers in this state, they are certainly looking at this as the next logical solution for saving money for their constituents.
Kurt Heim (33:38.208)
I think we’ve got to really engage more with policymakers and do a good job of educating on the issue. had Chairman Anchi of Dallas introduced a bill and Senator Boris Miles of Houston introduced it in the Senate in the last legislature and we had a hearing on it and the hearing started to really educate the lawmakers on, you know, electric resistance heating and why the bill was actually asking them to.
Kurt Heim (34:05.698)
prohibit it from being used as a primary heat source. So electric resistance heating under that bill could be a backup or supplemental heat, but you had to have a heat pump as the primary, which is kind of similar to the building code that we talked about that won’t really impact our state. So now you’re starting to see why, you know, the legislative route made sense. We’ve got to educate more on the topic. We’ve got to really draw good examples.
Kurt Heim (34:32.386)
You know, talk about the economics of it, talk about what you can do in terms of greater grid utilization. We have good programs out there for utilities. We’ve got to publicize those. I think of Dyken as an OEM, a manufacturer. We want to make sure that our customers are aware that there are options out there offered by the utilities to supplement or, you know, provide rebates and incentives to change the technology, right? To transform that. So we have to educate more on all that and bring it forward.
Kurt Heim (35:02.552)
We also have to take a hard look at some of our building standards. And then I think we have to look at the priorities that we need to make. think that if you take the ACEE at 12 gigawatts or Texas A at almost 14 gigawatts that they think this is, there’s a lot more higher value add that the state can bring to bear by spending those gigawatts on new business or expanding industry, et cetera. And we have to start to look at that.
Kurt Heim (35:30.744)
paradigm, so educate on the value, educate on the ways that exist today to transform the market by way of incentives and rebates. We’ve got to continue to focus on contractor training. One of the things that we see is, you know, who the expert is on HVAC when you’re sitting in August in a hundred degree home. The contractor is really the expert that you rely on to help you make a technology selection. We’ve got to help them understand what they can offer in terms of different technologies.
Kurt Heim (36:00.854)
And then just public education. think we have to raise the issue as much as we can. And I think all those things will contribute. We see really positive results when the legislature and the different policy agencies in the state are well informed on an issue. And it just looks like this is almost a no brainer, but it’s one that you have to get out there and really advocate for and educate.
Matt Boms (36:26.242)
Yeah, absolutely. And there was a great article that came out recently in the Houston Chronicle from Claire Howe talking about how this is the next logical step for Texas in meeting all of this load growth that’s coming, right? And if you can bring in more market incentives for this technology, as an example, the utilities are responsible for upgrading our distribution grid in Texas, right? So
Matt Boms (36:54.146)
They ultimately spend millions of dollars and recover those costs and the rate payers end up paying for the infrastructure. But there are cases where technology like heat pumps could step in and play a really important role in reducing the local load, right? Like we’re talking about 12 gigawatts or even 14 gigawatts here. That’s a significant chunk of our winter peak load, right? So if a utility can come in and say, look,
Matt Boms (37:23.266)
we know we can solve part of this problem with heat pumps, then the state should take a serious look at that and actually allow utilities and different market players to come in and provide that solution for the customer. Because ultimately we’re all trying to help the customer here, right? Like we’re all trying to make sure that we’re lowering bills for customers and making energy more affordable. I’m cautiously optimistic here listening to you, Kirk, because I feel like we do have the next steps that we need to take here as a state.
Matt Boms (37:53.014)
I just hope there’s enough political willpower to get it done.
Kurt Heim (37:56.578)
Yeah, I agree with you. I would like to highlight something that really encourages me quite a bit. know, utilities need tools or they need the PUC to kind of align with where they want to go. And one area that I can talk about is a success area is that we had a heat pump working group that was helping provide feedback on potential updates to the TRM, the technical reference manual, which is kind of like the rule book in the score book.
Kurt Heim (38:24.504)
for how utilities work with incentives. And one of the things that we found was that the baseline, so anything you get benefit from, you have to exceed the baseline, but the baseline for new construction and multifamily actually assumed that the heat pump was being put in. So you had to go to an Energy Star heat pump or a high efficiency heat pump in order to really qualify. The working group kind of provided some data and information to the PUC that say, actually,
Kurt Heim (38:52.032)
We don’t think that that’s accurate. And they made a change and they lowered the baseline. So what that is going to allow is that, you know, greater amount of incentive could be paid for somebody installing like a mid-efficiency heat pump than before where the baseline just assumed you had a heat pump in there anyway. This is one of the great things about this state that we’re really practical in how we operate. But when facts and figures and people align on it, you can see change, but that change is really.
Kurt Heim (39:21.494)
going to be for utilities can offer that, but they have to offer a program. Somebody has to take you up on the program and then they have to, you know, put in the system and that’s really for new construction. So it helps us stop digging the hole, but really the nearly 3 million homes that we talked about earlier are already out there. They’re already built, the built environment is there. We need more to address that, but it’s very encouraging that when you can bring all that together, you can actually see some change happen.
Matt Boms (39:51.822)
Absolutely. you know, Texas is obviously leading the country in a lot of different categories. It’s a pro-business state. I think that technology moves a lot quicker than the policy does sometimes, right? But no better company or business or case study than Dyken, one of the largest HVAC manufacturers based right here in Waller, Texas. So keep up the great work, Kurt, and I’m sure we’ll have you back and we’ll be hearing from you soon.
Matt Boms (40:19.276)
I think this is just the easiest step that the state could take to meet all of its energy demand and lower bills for customers. So thank you so much for joining us today and thanks for unpacking all of these complicated topics for us.
Kurt Heim (40:31.66)
You bet, Matt. Really appreciate getting the opportunity to come in here and talk about heat pumps today and how we really think that they offer something that is a tremendous benefit to the state. So good luck to you and the rest of your podcast this year. And really, really glad to be a part of this one.
Matt Boms (40:47.736)
Thanks, Kurt.
Matt Boms (40:50.786)
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.
Matt Boms (41:20.038)
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.

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