On the latest episode of the Energy Capital Podcast, I dive into our listeners' questions on a wide range of energy-related topics. Listeners reached out with questions about the Performance Credit Mechanism (PCM), energy-only market, battery storage duration, and peaker plants vs. baseload in the Texas Energy Fund. I was also asked what a reliable and affordable grid would look like. I attempted to answer all of these in one episode.

This is only our second mailbag episode so we would love to hear your feedback. Let us know if you would like to get more episodes like these and/or your thoughts on what was covered.

This podcast is for paid subscribers only and will not be listed publicly on podcast apps. For details on how to listen to this podcast in your favorite podcast app, please refer to this information from Substack.

If you like the episode, please don’t forget to recommend, like, and share on Substack, Apple Podcasts, Spotify, or wherever you listen.

I look forward to hearing your thoughts; don’t hesitate to share them with me and fellow listeners in the comments. Thank you for listening and for being a subscriber! Transcript, show notes, and timestamps are below.

Timestamps

1:15 - Difference between an energy only market and capacity market

4:10 - The novel capacity market construct called the Performance Credit Mechanism (PCM), explained

9:10 - Peaker plants, baseload generation, and the Texas Energy Fund

16:00 - Battery storage duration in the ERCOT market

22:08 - What would a reliable and affordable electricity system look like in Texas?

Show Notes

Energy Efficient Home Improvement Credit

"The Name of the Game is Flexibility," a Conversation with ERCOT's Pablo Vegas

Turning Waste Into Power: Crusoe's Cully Cavness on Revolutionizing Energy Use at Data Centers

The Energy Capital Podcast, Episode 1 with Former PUC Commissioner Will McAdams

Pathways to Commercial Liftoff: Long Duration Energy Storage report from the Department of Energy (scroll to bottom of the page to view the full report)

ERCOT Has More Questions to Answer

Podcast episodes and articles on distributed energy resources:

* Measuring and Valuing Energy Efficiency and DERs with Carmen Best

* The Future is Distributed

* Local Outages Are Still Outages

* Distributed Energy Resources and "all-of-the-above" energy solutions with CenterPoint's Jason Ryan

Transcript

Welcome to the Energy Capital podcast. I'm Doug Lewin. Today we're doing a mailbag episode. Got more questions than we can probably take today. We're gonna run through like five or six of them. Just quickly before I get started, this is a paid episode. We'll probably put the first answers onto the free platforms. If you're listening there, please do go to Doug Lewin, douglewin.com and subscribe. Lots of benefits there for paid subscribers, including some of the, subscriber only, podcast, but also all of the archives of all of the articles, as well as the grid roundups, which are for paid subscribers only, you'll find lots of benefits there. do hope that you'll go there and subscribe. We will also have a chat on July 11th and July 25th during the PUC meetings. Mark your calendar for that.

All right, the first question I got, which I want to take today, is a very fundamental question and large question, but I think it runs through so many of the other discussions. I wanted to start with this one. I had a questioner at Substack ask, what is an energy only market? So I think I was writing in one of the Grid Roundups or something like that about some of the latest related to the Performance Credit Mechanism (PCM). Which, that was the second question this questioner asked, is what is the PCM? So I want to take these two together. And again, it really is fundamental and runs through so many of the other things that we talk about. So I really appreciate this high level question. So, and obviously I'll oversimplify some of this, but I think it's important for understanding just to try to put it at the most basic level that I can.

And fundamentally there are two separate constructs. One is called energy only, and one is called a capacity market. Almost every other market in the world than ERCOT is a capacity market. And what that means is in those markets, the administrator is purchasing and you know, it'd be like ERCOT, right? Whether it's the regional transmission operator, the RTO or the independent system operator, the ISO, they are purchasing capacity to be available, but not necessarily to produce energy, to produce power. In an energy only market, as the name would describe, you're not procuring capacity just to sit there. You are reliant on energy to be produced when it is needed because of high prices. So in a capacity market, you have both the energy portion of the market and the capacity portion of the market. Depending on the design of that market, the capacity portion could be much larger than energy or energy much larger than capacity. And in fact, while we make it simplistic and black and white, like there's an energy only market, there's capacity market. Obviously, like I just said, within capacity markets, they are purchasing energy too. So there's a payment for the capacity. And then when the power is produced, there's a payment for that too. It tends to be a much lower price because so much is being paid on the capacity side.

Similarly, in an energy only market, there is capacity that is procured. These are ancillary services, things like emergency response service. It's just they are a much smaller share of the market than the energy portion of the market. Whereas in a capacity market, the size of the energy capacity might be near each other or 70/30 or 60/40 or whatever. In an energy only market, you're procuring 10% or something like that of capacity, often less, sometimes more, kind of depends what's going on. The last couple of years, there's another question I get a lot is like, what does ERCOT mean by conservative operating posture? They're procuring a lot more ancillary services, they're actually procuring some capacity within an energy only market.

So that next question is, what is the Performance Credit Mechanism? The Performance Credit Mechanism is effectively a capacity market construct. The folks that came up with it, E3 Consulting, working with the PUC with the former chairman, Peter Lake, realized as they were going through that process that a straightforward capacity market, which is what E3, the consultant to the Public Utility Commission, recommended was not politically viable. So they tried to come up with a different name for capacity market. They dressed it up in kind of different clothing but underneath it is a capacity market. And basically what it's doing is trying to instead of having like you would in a forward capacity market like PJM or MISO or one of those where you're procuring the power out two or three years, this year you're purchasing capacity for 2026, 2027. This would actually be more of a look back based on availability, but it's still a payment for capacity and it still would, it leads to inefficiencies in the market in my view and a whole lot more expense for consumers.

So basically, and there was just a comment period that ended by the time we released this, I guess it would have been two or three weeks ago that comments were due on June 20th. The control number for those that know how to use the PUC interchange and all you have to do is Google PUC interchange. It'll come up and you pop into control number 55000. That's 55,000 and you will see the 20 or so comments that were submitted on the PCM. The commission asked commenters, I think it was something like 30, 35 different questions which they had answered 15 pages and that speaks to the complexity of the Performance Credit Mechanism. And they have to decide which hours the capacity is going to be paid for. Is that done seasonally? Is it 20 hours? Is it 30 hours? There's just so many variables. And I think that that is one of the biggest problems of it.

And one of the attributes of the energy only market, it is complex and people that work within the market will laugh if I say it's simple, it's not. But I think it is simpler than trying to come up with this convoluted Performance Credit Mechanism, the contortions that are required to make it look like an energy only market, what it would in fact be a capacity market.

So the Performance Credit Mechanism, how do you just boil it down to a definition? It's basically paying capacity to be available during some number of critical hours, but that is sort of masking the you know, complexity, which you can see if you look at the questions that were answered in that docket, I just referred to 55000.

The last thing I'll just say about this is that the politics of this do very much matter. The legislature, particularly the Senate, is very supportive of an energy-only market. The Senate must confirm all PUC Commissioners. At the last Business and Commerce hearing, which was, I believe, June the 12th, if memory serves, Chairman Schwertner asked Chairman Gleason and the CEO of ERCOT, Pablo Vegas, if they were trying to move on from the energy only market and move to a capacity market and they both said no, the energy only market could continue to work. And obviously Chairman Gleason will have to be confirmed by the Senate. So the politics of the PCM are pretty fraught and I think it's much more likely we will have some version of an energy only market though again, there will be capacity procured within that energy only market. The question is how much, how much does that cost consumers? What's the right amount? Whenever I'm asked this question about energy only capacity, I think it's important to think of it not as a binary, as like an on-off switch. It's really more of kind of a spectrum or a dial and you're deciding how far to turn it. By you, I mean, the policymakers, the legislators, the Public Utility Commission, ERCOT stakeholders are all weighing in with different views as to how much capacity needs to be procured. You're never gonna be in a pure energy only market where there's no capacity. That would be crazy. And of course, capacity markets are not pure either. There's energy markets within them. So the question is how far are you going?

All right, so let's move on from there. These next few questions are actually kind of related and is why I wanted to start with the question about the energy only market. I got a question from Former Land Commissioner Jerry Patterson. Thanks for being a subscriber and we should take a moment to acknowledge Commissioner Patterson's leadership when he was at the general land office and being a real catalyst for some of the first renewable energy projects in the state. So he asked, isn't electricity from a plant designed as a peaker plant more expensive?

So I was writing about and he was asking a question related to an analysis I had done of the 150 or so applications put in for the Texas Energy Fund. This is the legislative program that was adopted during the last legislative session that put $5 billion taxpayer dollars towards subsidization of new natural gas plants. More of the applications appear to be for peaker plants. Now with the huge caveat that something like 70% of the, these aren't applications yet, their notices of intent to be more precise. 70% of them didn't say whether they're peaker or baseload. And if you're listening to this and not really sure about what peaker or baseload is, peaker is going to be a plant that is designed to run just a limited number of hours during the year, could be 5 or 10%, maybe up to 20 or 30%. But for a majority of the year, it's not gonna run. And that's by design. That's not a bad thing. That's not cause it's broken. That's because most of the hours of the year, we don't need more power. We have plenty of it. Prices are very low. We could frankly be using a lot more power like charging electric vehicles and things like that. There's plenty of capacity available, but there are these, this limited number of hours out of the year, usually a few hundred, maybe on a real extreme year, you know, 6, 7, 800 out of 8,760 hours a year. So it's usually less than 10%, where there is some scarcity. And obviously we're all kind of tuned into that in Texas. We hear, particularly post-Uri obviously we hear, okay, there might be scarcity coming and people pay attention. We get a lot more news stories, all that kind of thing. But that is a very, very few number of hours.

So peaker plants are designed to serve those few number of hours in an energy only market where energy prices can get all the way up to $5,000 per megawatt hour versus a capacity market where usually that price is capped much closer to $1,000 or even less, a peaker plant can actually do quite well turning on for only a very limited number of hours per year. It's actually the same logic as to why batteries are being built. Nobody's building a lithium ion battery to run it for thousands of hours per year. They're building it to run for many hundreds of hours per year and to make a lot of money during those hours when they're running. The same is true for peaker plants. So the question, are they more expensive? On a capital cost, they might be a little more expensive. It's roughly in the same neighborhood as a combined cycle, but you're going to have the idea is basically by running it less, your fuel costs are gonna be less. But by running it less during those scarce hours, you are capturing higher dollars and thus your profitability is much, much higher. A lot of the analyses out there, these sort of levelized cost of energy analyses just aren't accounting for, I don't think, in my view, if somebody thinks different, leave it in the comments and correct me and I'll make a correction in a future one. But in my view, those kinds of analyses are not taking into account the variable amounts of money that whether they be battery owners or gas peaker plant owners can make when those prices are very, very high for a short period of time. The levelized costs based on running for thousands of hours just doesn't apply in a market like ERCOT.

So the short answer to the question is electricity from a plant as a peaker more expensive. It might be on a capital cost basis. It might not be, but when you factor in the revenues they're gonna be able to earn, it probably makes a lot more sense to build a peaker than to build a base load plant, which by design is gonna need to run during hours when power prices are extremely low, sometimes zero. But for many hours, in fact, if you look at the dashboard most days, we're in a 10 to $20 a megawatt range, you're not gonna make money on a gas peaker, paying your gas charges and your maintenance and all that kind of stuff at that kind of level, whether you're a peaker or non-peaker, no gas plant's gonna make money in that kind of environment. So the peaker plants actually make a lot more sense in whether or not they're more expensive on the front end is a little moot. The question is, are they more profitable overall? That's really sort of the key question there.

Last thing on this, in the Texas Energy Fund, of the, I believe it was only 18 notices of intent that actually specified the dollar amount they were applying for. Of those 18, only eight said whether or not they were peaker or non-peakers. It's a very, very small sample size. I'll take it with a grain of salt. But of the five that were peakers, their average cost was about 25% less than the base load plants, than those three applicants for base load plants that gave us their numbers.

And those numbers were about $700,000 per megawatt installed for peaker. And that's only what they were asking for from the Texas Energy Fund. That's 60% of the capital. So it would be more like a 1.2, 1.3 million per megawatt. And then on the non-peakers, they were asking for 950,000. So that would be more like a million and a half or 1.6 per megawatt for the full cost.

So yeah, peakers actually can be less expensive on a capital cost basis, but again, their profitability I suspect would be a lot higher. And I think what we're gonna see built in Texas under the Texas Energy Fund is gonna be a lot of peakers. That is unless the regulators and policymakers put their thumb on the scale and really push towards the non-peakers. But I think if that happens, we're gonna end up with more defaults than we would otherwise and taxpayer dollars will be wasted rather than repaid. So they've got to be real careful, obviously, in how they do that and put the money towards the plants that they think have the best chance of recouping their costs and being profitable so the taxpayers can be reimbursed. This is a loan fund. There's grants associated with it, but I think the preponderance of the money is going to go into these loans and the assumption is they're going to be paid back. I would be very skeptical about baseload gas plants being able to earn their money back, particularly if the cost from that small sample size of 25% more than peaker plants holds, I think they're gonna be upside down underwater.

All right, the next question I got, this was also from Commissioner Patterson, does battery storage energy only last four to five hours absent recharge? So this depends on the configuration and how the developer sets it up. And that also comes back to market design. So in Texas, effectively all of the battery storage that is being built is two hours or less. And the vast majority of it is configured for one hour. We're starting to see more two hour come in. So maybe I shouldn't say vast majority. Maybe it's just more of a lean majority at this point that is one hour with some moving towards two hours because batteries can participate in the ERCOT contingency reserve service because they've got the last two hours in there. We're seeing more two hour configurations to try to get after that ancillary service.

In California where they have a different market structure that incentivizes four hour storage, they're getting a lot longer duration lithium ion storage, but usually not beyond four hours. Yeah, and of course, it's very rare again, to this discussion about the energy only market, on most days, it's an hour or two of scarcity and not more than that. That's don't mishear me. That doesn't mean all days. There are some days where it's longer than that, but something like 80 to 90% of days where we're at very high prices in the market, that doesn't last more than an hour or two.

So the batteries and again, gas peakers are really trying to capture those higher dollar amounts. It is very difficult for these, whether it be a gas peaker, regardless of the technology, but inclusive of batteries, it is difficult obviously to figure out when to bid into the market. Cause if you're waiting for a $5,000 peak, you could miss the thousand or $2,000 a megawatt hour,

kind of moments, there's been some discussion at ERCOT board meetings about the IMM looking at battery storage, bidding behavior and stuff like that. I think though you're seeing a whole lot of days where if you're bidding in the thousands and prices are in the high hundreds, you're missing out on it. It is a competitive market. Everybody's got to decide on what their bidding strategy is gonna be. And if they're in a competitive market, if you don't get chosen in that auction, if you don't bid low enough and you're left out, you don't get paid. It's not a capacity market. There's no capacity payments for that stuff. So you are then left with no payment at all. So it does behoove all of the developers and operators of these assets, again, whether they be peaker plants or battery storage to bid in at a level where they think they're going to get chosen.

One other thing on this battery energy storage piece in about four to five hours, it appears that ERCOT is making a decision. They have said publicly now to the legislature and to the PUC that they intend to exclude battery energy storage from a new ancillary service, which is being designed and it's not being implemented yet. Probably won't be implemented for another two years, but when it is implemented, it'll likely be a large one. It's called the dispatchable reliability reserve service. It is required to have a four hour duration and they plan to exclude storage from it, which I just think is a massive mistake. There are reasons why they're doing that. They're kind of technical. I'm not going to get into it in this particular podcast but we can in the future. But if they do that, if they exclude storage from it, we're likely not going to get a lot of four hour storage. And again, I think that's a mistake. I think we should, the market should be sending a signal to developers that we want four hour storage and including storage in the dispatchable reliability reserve service (DRRS). DRRS would be a great way to do that.

Last thing on this question about, does battery storage last four to five hours? So usually when we're talking about battery storage, we're talking about lithium ion. That is far and away the dominant technology. In fact, I think it's might be the only technology used. There is like a four megawatt, what is it? Sodium sulfur, I think that AEP uses way out in West Texas. That's actually a utility asset, not the competitive market. Often referred to as Bob, big old battery. It's a huge thing and it's four megawatts. So there may be a few here and there, right? There may be a few other examples, but 99% of the storage in Texas or more is lithium ion. There are other technologies on the horizon and I'm not going to do a full tech review here. There's a great report, the Department of Energy did on long duration energy storage. I can put a link to that in the show notes. One that I'll highlight is iron air, a hundred hour battery being developed by a company called Forum Energy. But you know, so you can get durations everywhere from eight hours to a hundred hours in these different long duration technologies. You know, pumped hydro, which we can't really do in Texas because we don't quite have the geography for it, is a form of energy storage, but some companies are looking at cavern energy storage, pumping hydro underground from higher to lower areas and using that as energy storage. The technology exists, it's really just a matter of can those kinds of technologies get enough revenue from the market, including storage and DRRS would be one way to do that.

All right, I think the last question I'm gonna do for today, gonna try to keep these mailbag episodes to about 30 minutes. That is a huge question and one that would take a long time to answer fully. And I will not attempt to give a full comprehensive answer, but we'll go into a few of the elements of it. I was asked, what would you propose a reliable electricity system to look like in Texas to minimize cost to users, residential, commercial, et cetera? What does a reliable electricity system look like in Texas?

So as you can probably tell from the way I was talking earlier in this, I do think the energy only market can deliver a reliable system and I think it can deliver it at a lower cost. Winter Storm Uri was not a failure of the energy only market in my view. If you want more on this, listen to the podcast I did with Commissioner Will McAdams just a couple of weeks after he left the Commission. He and I got into this, and we agree on it, in that podcast. And you can hear more about why I think that to be true.

But the bottom line is the failure of Uri was a failure of regulation, particularly of winterization or weatherization of the natural gas supply system, of power plants and of homes and buildings. So the first thing we need to do to have a reliable electricity system is make sure that those three elements, the natural gas system regulated by the Railroad Commission, and I know that that's difficult. I know this is not an agency that is known for its excellent regulation of industry to put it lightly, but I just think while gas is the dominant source on our system and it still is, you have to have a reliable source of gas during the winter time when it is needed more. And that was the biggest failure during Winter Storm Uri. It's in the FERC and NERC report. It's in the UT Energy Institute report. Some people dispute these things. But there is not a more definitive account than either of those two sources. And they did cite natural gas supply as being among the biggest problems, among the only two or three biggest problems during Winter Storm Uri.

Another one was power plant winterization. I think the PUC and ERCOT have done a pretty good job. It's not perfect. It's certainly nothing that everybody should be sort of patting themselves in the back and saying, job well done, it's all over. It needs to get better. But we have data from Winter Storm Heather, which was early in 2024 compared to Winter Storm Elliot, which was December 2022 and Uri of course, in February 2021. And we saw a large drop in power plants that were not able to run. In other words, we saw an increase of availability of power plants from Heather, in Heather from as compared to Elliot and those two storms were different than Uri for sure, but they were similar to each other. Elliot and Heather were pretty close. Not exactly the same, obviously, but pretty close. And we saw something like a drop of like 30 to 40% of the power plants that were out because of freezing issues. So it does look like the winterization is working on the power plant side and PUC and ERCOT are doing a pretty good job of that. Unfortunately, we do not see improvement in the natural gas supply system. We're still seeing 30 plus percent drop in natural gas supply output from Heather compared to Elliot. And of course, he was even higher during Winter Storm Uri in more extreme conditions.

The other piece of that weatherization is homes and buildings. So we really need to winterize homes and buildings. This is a resilience measure because if the power goes off, you have a better chance of surviving inside a home that is well-insulated, but it also is a release valve for the grid itself because demand was one of the things that really caused the problem during Winter Storm Uri. It was two things. It was lack of supply because of that lack of winterization on the, on the gas supply and of power plants, but it was also insanely high demand, demand that we are going to see rise even more as we're adding more loads onto the grid.

We've got to do something about the demand side. Energy efficiency is a big part of this, Texas does have utility efficiency programs. They have existed for 25 years. They have not been increased by even a little bit in 14 years. 12, 13 years. It'll be 14 by the next legislative session. Because it looks, unfortunately, like the PUC has wasted another interim without increasing energy efficiency. This is very disappointing. And it's more than disappointing. It's actually dangerous. It makes Texans more vulnerable to outages during winter storms than if we were doing something systematically to really decrease demand.

I've written about this many times. The things we really need to go after are HVAC systems, particularly ones that have backup resistance heat. There are about 4 million homes in Texas that have backup resistance heat. Much of that will operate as the main source of heat. Once you get below, well, it's a backup. It's not the main source. I should be careful. But once you get below 32 degrees, kicks on in a major way. Spikes demand. Homes can go from using five or six or seven KW all the way up to 15 or 20. So you're seeing a doubling of what each house is using, times that by four million. And you start to see that you just get into these situations where you can't possibly keep up. So energy efficiency through utility programs is a big deal.

The Inflation Reduction Act is gonna also be a game changer there. There are right now tax credits available. If you're interested in pursuing a heat pump to lower your energy bills to help the grid to increase your own resiliency and reliability at your home, I highly encourage you to do that. These technologies are really gonna take off. They're available now. They're mature technologies. You wanna look for, and what I like to call an all climate heat pump, but you could call a cold weather rated heat pump, one that'll keep you warm inside your home all the way down to five degrees. So the Inflation Reduction Act has tax credits for that. There's also money available for individuals and families that don't qualify for the tax credits that will be available next year. It is not available yet, but that'll come through the State Energy Conservation Office. More on that in future months and even next year as those dollars start to come out.

So, winterization, gas supply, power plants, homes and buildings, that is like fundamental just cornerstone of a reliable electric system that is also affordable. Energy efficiency, by the way, does put downward pressure on prices on a system-wide basis and particularly for those that are able to avail themselves of those incentives.

Let's talk through a couple of the other elements. I write about these a lot. We can put links to some of the articles if you want to read more but distributed energy resources. So I include energy efficiency as a resource because resources are not just supply side, they're also demand side, but the supply side distributed resources are great too. So solar and storage systems, as a matter of fact, ERCOT just said in a meeting ERCOT staff just in the last few days when I'm recording this, that they expect the system peak to move from 5 PM to 10 PM, the hour ending 10 PM, within four years. And there's a few reasons for that. But one of the biggest reasons they cited was the preponderance of solar panels on roof. So that doesn't look to ERCOT like a utility scale solar plant that's way out in West Texas, that is injected as supply. Solar on your roof looks to ERCOT like a reduction in demand. And so the reduction in demand is large enough that they expect that peak to move beyond the time that the sun is out, which is really just a, that is a sea change. We haven't had a system that peaks at 10pm maybe ever. I don't know if in the very, very early days of the electric grid when it was all light bulbs, maybe there was a peaking system then, you know, what goes around comes around. We're coming back to a 10pm peaking system, but it certainly hasn't happened in anything like you would define as the modern era, certainly not anything in the post-World War II era. It's a major, major change. But these solar and storage systems, that's really good for the distribution grid. That eases the strain if you're taking a lot of that load at the customer's home or business and reducing that load. That's big to relieve distribution system stress, and it's also relieving the bulk power system.

Another huge one included in that bucket of DERs, we've already talked about energy efficiency, solar and storage. Let's talk about electric vehicles and particularly managed charging, making sure that we are charging electric vehicles overnight is gonna become increasingly important. Bloomberg New Energy Finance just updated their numbers and said that within, I think it's been three or four years, they now expect one out of every three vehicles sold to be electric, this, you know, despite some of the headlines about slowdowns of EVs, it's not slowing down. If anything, it's more rapidly progressing than could have really been imagined in recent years. And I think that those trends are going to accelerate. So the managed charging is going to become more. We can talk about vehicle-to-grid. I think that that ends up being very important eventually too, but in the early days, the big thing it's like crawl, walk, run. The crawl is let's make sure that when people come home from work at six or seven in the evening and they plug in those electric charges, their electric vehicles, they're not charging immediately unless they needed to. If they needed to, we should build a system to accommodate that. But for most people, they're not going out again that night. They're gonna get up the next morning and wanna drive it. So charge that car at one or two in the morning, not at six or seven in the evening as the sun is going down and demand is still high. So that's gonna be a big deal for reliable grid.

Got to talk about demand response. I hope that that starts to come through retail electric providers as a competitive market function. There is a proposal in front of ERCOT for a smart thermostat pilot. Don't believe they've approved it yet. Oncor, the utility for DFW, was trying to work with reps to get that in place this summer. It may be too late for that to happen, but it definitely is something that should happen in future summers.

The aggregated distributed energy resource program, allowing customers that have solar and storage to be paid for the value that those bring to the grid, that will increase reliability and lower costs for those customers and then make it more possible for more customers to get those kinds of assets at their home. That increases their personal and community reliability, also strengthens reliability of the grid. This is the way we've got to think is where are those win-win-win kind of situations. And that is certainly one of them.

Let me touch on just a couple more and then I'll stop. Transmission, we're gonna need more transmission. We're gonna need to build more. We've got to change the cost benefit calculations. They're still requiring transmission to prove that it's paid for all of the costs based on the benefits only accrued within the first six years. That's insane. Nobody builds big infrastructure based on a six year time horizon. So that needs to be changed.

We also have to use the system we have better. I wrote a lot over the last year, but particularly a piece I wrote September 7th, 2023, which is still one of the most widely read pieces I've written on the newsletter. It was the day after ERCOT declared an emergency. It was the only emergency we've had on the system post-Uri. And unlike Uri, they actually, it happened so quickly, they skipped the emergency alert level one and went straight to two. As bad as Uri was, that didn't happen then. It did happen on September 6th. This was a really serious incident that I don't think has gotten nearly enough attention. And part of it was because ERCOT decided that they could only use a double circuit, a two circuit line as only one circuit. They manually curtailed renewables that were coming over that line. Was that necessary? I don't think we know that. And I think that's where using the system better, using things like dynamic line rating, using grid enhancing technologies, getting better sensors on these lines to know how much power we can actually move through it instead of guessing is going to be extremely important. So we need more transmission, we need to utilize the system we have better.

Large flexible loads are gonna be a big part of a reliable grid. All of the attention it seems in that particular discussion seems to go to Bitcoin and these days a little bit towards AI data centers. But don't forget hydrogen electrolyzers are going to be large flexible loads. ERCOT for whatever reason in their forecast where they keep talking about going to 152 gigawatts by 2030, they are assuming a lot of hydrogen from electrolyzers and they're assuming those are a hundred percent loads. They just run 8,760 hours per year with no flexibility, no ramp down when prices are high. That is crazy. That makes no sense. Hydrogen will not be developed that way. It won't pencil out if it does. So that is something that ERCOT's really got to get a handle on, not only for planning, but for operations to make sure that these large loads when they come in are getting very favorable treatment if they are flexible. So hydrogen, carbon capture machines, water desalination, these are all large loads that have flexibility in them. Electric vehicle fleets are another one. There's a long list and there's gonna be others coming in as well. And yes, AI data centers. There are applications that the AI data centers are running. Inference is one of those, we talked about that in the podcast with Cully Cavness of Crusoe. There are some things data centers do that really aren't flexible, but there's a lot that are. There's a whole lot when you're training a large language model as one example that can be flexible. So that is going to be just an absolute necessity going forward. If we're going to have anything like a reliable and affordable system is continuing to figure out how these large flexible loads work.

Coming back to the DERs, don't forget the small flexible loads, right? I was talking about heat pumps earlier. Those have inverter compressors in them. They can work like a continuously variable transmission in a vehicle. They have infinite different speeds they can run at, whereas most HVAC units today are two speeds on/off, that's it. And when it's really hot out, they just run at a hundred percent, basically all through those hot periods. You can start to get into with better insulation, things like pre-cooling of a home, and then running that compressor at 70%, 80%, 90% of its rated capacity instead of the 100% they run at now. So small flexible loads, things like pool pumps, things like electric hot water heaters, air conditioners, those can all be small flexible loads. Those are gonna be a big deal as well. The podcast episode I recorded with Pablo Vegas, right, I took a quote from that and made it the title. Vegas said, the name of the game is flexibility. And I think that is a thousand percent true.

Last but definitely not least, because I think it underpins all of this, is if you're gonna get that flexibility in, we are gonna need all sorts of technology innovation. We also need regulatory innovation. Technological innovation will go a long way. It's already going a long way. We're seeing that right now with this proliferation of electric vehicles and solar and storage, heat pumps, I could go on, but we're gonna need regulatory innovation too.

And a couple of things related to that. One, as we are building out a system to handle all of these electric vehicles and heat pumps, these increasing loads, we are seeing distribution system costs rise at a very high rate, faster than anything else. In fact, costs in the power sector have gone down. TND has gone up. A lot of people blame transmission for that, but the cost of distribution is actually even rising more rapidly than transmission. And so I think we've got to have innovation around the distribution system to make sure that we aren't building a system. So if a home right now has a five or six KW peak, now you put an electric vehicle out in the garage with a level two charger, maybe you put two of them. Each of those can charge seven KW at a time. Now, instead of one house, you have two houses. But as far as the grid is concerned, it looks like two or if there's two vehicles, three homes, because two of those homes are in the garage needing seven KW. This is again, where that smart charging comes in, where you need a distribution system operator, whether that be the distribution utility or some other entity to really make sure that there are price signals at the distribution level to incent customers to use energy in smarter ways. This doesn't require manual actions from customers. These are automated systems that pay customers to participate. And that can be as simple as charging their car later. It could be as complicated as injecting power from the battery in the car back to the grid. But all of that has to be coordinated. And I think some kind of distribution system operator is going to be necessary.

We also want to look at what are called non-wires alternatives. I actually think it's kind of an unfortunate name. We probably need a better name for that because we're going to need a lot more transmission. We're gonna need more distribution infrastructure as well. But we wanna look at is where having a combination of distributed energy resources, energy efficiency, demand response, solar storage, EV managed charging, can lower those costs. In other words, if you say, here's, in this neighborhood, five people just bought Ford F-150s, the Lightnings, the electric vehicles. Now I've got those five houses that need another 50kW of capacity, I'm gonna go as I've on the utility and build a new transformer, a new substation, you know, upsize that transformer, increase the capacity in the substation, that's gonna cost $10 million. Could I come up with a demand response program that would make sure that that charging is spread out over time so that I'm better utilizing the system I have, the capacity factor of the whole system I have is going up but the peak charging, the peak use is not going up? Thus I can keep my costs much less. Can I develop a demand response program and instead of 10 million, it's a million or two? And by the way, that million or two is going into the customer's pockets instead of that 10 million that I'm charging them for it, right?

So that kind of thinking, it's gotta be systems level thinking. It's gotta be, how does the distribution grid interact with the transmission grid? That's actually one grid, but there are different parts of it. How do they interact with each other? And I think all of that kind of sits under this framework of performance-based regulation. The transmission distribution utilities, their incentives need to be aligned with the incentives of their customers. In other words, how do we get them to bend the curve on spending and actually start to decrease spending in some areas? Overall, we're gonna need more spending. I don't think there's any doubt about it that the grid is going to need upgrades, we're gonna need to spend more. But these costs are gonna get out of control if the old utility business model, which is basically everything you spend, you get 10% rate of return on. If that remains, the incentive remains there for more spending in all cases. And I think we've got to replace that with some form of performance-based regulation to give an incentive to the utilities to look at these non-wires alternatives to implement frameworks that whether we call it distribution system operator or something else acts like that to orchestrate all of these small resources for greatest system efficiency and lowest cost. And that might mean paying them some bonus instead of paying them a 10% rate of return or return on equity adder. So to the question, what should we do to have a reliable system that minimizes costs?

You start with the weatherization. It's like blocking and taxing right before we're gonna run some really complicated play, let's get the basics right. Weatherize the gas system, weatherize the power plants, weatherize homes and buildings using energy efficiency. From energy efficiency, you go to DERs, solar storage, EV managed charging, demand response, more transmission, but also using the transmission system we have better, integrating large flexible loads, making sure that they're not drawing power in those couple of hundred hours out of the year when the system is scarce but have really great prices for the rest of the time. So they still wanna come to Texas and our economy remains strong, create jobs, all those kinds of things. And last, but definitely not least that regulatory innovation. I've given a couple examples. I'm open to those could be the wrong examples, but I think the major point is the regulators need to innovate too. It's not just technology innovation. You have to have the policy structures in place to capture the benefits of that technology innovation.

All right. I said, I want to keep these at 30 minutes. I'm at like 45. There were some more questions, but I'll leave those to a future mailbag episode. If you have things you want me to address in a future mailbag episode, put those in the comments. We'll try to do these, you know, either every month or every other month, depending on how many questions come in. Thank you. Thank you. Thank you for being a paid subscriber to the Energy Capital Podcast, the Texas Energy and Power Newsletter. This is impossible without you, please tell your friends, neighbors, colleagues, and encourage them to subscribe as well. And with that, thank you for listening. Have a great day.

Thank you for subscribing. Leave a comment or share this episode.

Mailbag! — July 3, 2024

Energy Capital Podcast (private feed for maxwang1990@126.com)