Scientists are learning how to temporarily reshape materials by nudging their internal quantum rhythms instead of blasting them with extreme lasers. By harnessing excitons, short-lived energy pairs that naturally form inside semiconductors, researchers can alter how electrons behave using far less energy than before. This approach achieves powerful quantum effects without damaging the material, overcoming a major barrier that has limited progress for years.
When quantum spins interact, they can produce collective behaviors that defy long-standing expectations. Researchers have now shown that the Kondo effect behaves very differently depending on spin size. In systems with small spins, it suppresses magnetism, but when spins are larger, it actually promotes magnetic order. This discovery uncovers a new quantum boundary with major implications for future materials.
A major global study suggests that a hidden mismatch between two common blood tests could quietly signal serious trouble ahead. When results from creatinine and cystatin C—two markers used to assess kidney health—don’t line up, the risk of kidney failure, heart disease, and even death appears to rise sharply. Researchers found that this gap is especially common among hospitalized and older patients, and that relying on just one test may miss early warning signs.
A long-standing law of thermodynamics turns out to have a loophole at the smallest scales. Researchers have shown that quantum engines made of correlated particles can exceed the traditional efficiency limit set by Carnot nearly 200 years ago. By tapping into quantum correlations, these engines can produce extra work beyond what heat alone allows. This could reshape how scientists design future nanoscale machines.
Fungal infections are becoming deadlier as drug resistance spreads and treatment options stall. Researchers at McMaster University discovered that a molecule called butyrolactol A can dramatically weaken dangerous fungi, allowing existing antifungal drugs to work again. Instead of killing the fungus directly, the molecule sabotages a vital internal system, leaving the pathogen exposed. The breakthrough could help revive an entire class of antifungal medicines once thought obsolete.
The microbes living in sourdough starters don’t just appear by chance—they’re shaped by what bakers feed them. New research shows that while the same hardy yeast tends to dominate sourdough starters regardless of flour type, the bacteria tell a more complex story. Different flours—like whole wheat or bread flour—encourage different bacterial communities, which can subtly influence flavor, texture, and fermentation.
New research suggests that consistent aerobic exercise can help keep your brain biologically younger. Adults who exercised regularly for a year showed brains that appeared nearly a year younger than those who didn’t change their habits. The study focused on midlife, a critical window when prevention may offer long-term benefits. Even small shifts in brain age could add up over decades.
Researchers from New England Biolabs (NEB®) and Yale University describe the first fully synthetic bacteriophage engineering system for Pseudomonas aeruginosa, an antibiotic-resistant bacterium of global concern, in a new PNAS study. The system is enabled by NEB’s High-Complexity Golden Gate Assembly (HC-GGA) platform. In this method, researchers engineer bacteriophages synthetically using sequence data rather than bacteriophage isolates.
New experiments reveal that protein precursors can form naturally in deep space under extreme cold and radiation. Scientists found that simple amino acids bond into peptides on interstellar dust, long before stars and planets exist. This challenges the idea that complex life chemistry only happens on planets. It also boosts the odds that life-friendly ingredients are widespread across the universe.
Epaulette sharks can reproduce without any measurable increase in energy use, stunning researchers who expected egg-laying to be costly. Scientists tracked metabolism, blood, and hormone levels through the entire reproductive cycle and found everything stayed remarkably stable. This efficiency suggests these sharks have evolved to optimize energy in ways not seen before.
Everyone is talking about virtual power plants, but as I discuss with EnergyHub CEO Seth Frader-Thompson, not all VPPs are created equal. We get nerdy on the various stages of VPP maturity and the specific technical requirements that VPPs must meet to truly compete with conventional power plants rather than just acting as “enhanced demand response.”
Okay. Hello everyone. This is Volts for January 21, 2026, “Let’s dig a little deeper into virtual power plants.” I’m your host, David Roberts.
Virtual power plants (VPPs) are all the rage these days.
For those who need a quick refresher, a VPP is a collection of small-scale, usually behind-the-meter distributed energy resources — rooftop solar panels, home batteries, electric vehicles, water heaters, HVAC systems — coordinated by software to act in unison, as a single entity. A VPP can, depending on its composition, produce or store power, reduce or shift demand; it can, to varying degrees, simulate the behavior of utility-scale power plants or batteries.
When I’ve discussed VPPs in the past, I have mostly done so at a fairly high level of abstraction, as though they are a single kind of thing. But of course, in reality, there are many different kinds of VPPs, at varying stages of development, with varying capabilities.
Today, we’re going to get nerdy on VPPs.
Seth Frader-Thompson
To do so, I have the perfect guest: Seth Frader-Thompson, the founder and CEO of EnergyHub, the biggest VPP wrangler in the US. It currently manages over 1.8 million devices, which add up to more than 2 gigawatts of capacity.
EnergyHub recently released a whitepaper introducing a “VPP maturity model,” a framework to assess the varying capabilities of VPPs and their usefulness to grid operators. It seemed like a perfect jumping-off point for a deeper discussion so … let’s do this!
Seth Frader-Thompson, welcome to Volts. Thank you so much for coming.
Seth Frader-Thompson
Thanks so much for having me. Very excited to be nerdy about VPPs.
David Roberts
Before we even dive in, I wanted to check the very first thing: there are some people out there, I think maybe the people at Sunrun still, who think that distributed power plant is a better term than virtual power plant. Do you care at all about that linguistic dispute? Are you invested either way?
Seth Frader-Thompson
The short answer is I do care. I think that today it doesn’t make a huge difference, but the real answer to that probably gets a lot to the meat of what we’re going to talk about and this white paper. Today it doesn’t matter. The distributed piece is not necessarily valued by the market. But as we get into talking about the Huels test and what comes after the Huels test, that distributed piece gets really important.
David Roberts
Okay, we’re just going to use VPP then, because that seems like what everybody else is doing. Seth, there are many VPPs out there in the US doing their thing today, but as I understand it, most of them are effectively acting as what’s called demand response, which means that when the grid operator runs into an unexpected event, say a surge in demand or something that they didn’t anticipate and they need to call on emergency resources, they’ll call on a VPP.
Where we want to get all of us involved in this is to a place where grid operators are calling on VPPs on a daily dispatch basis, where they are treating them as reliable power plants. Where they are treating them like power plants in their portfolio.
That is rare today. What we are going to be talking about is how to get VPPs from their current state to that state. Before we get to that, let us start with a little bit about EnergyHub or about what you are doing. Those 1.8 million devices out there in the world that EnergyHub is managing in one way or another, what are those devices? What are the big categories?
Seth Frader-Thompson
Yeah, first, the good news is that number jumped just in the last few weeks. We finished the year at about 1.9 million under what you would have called just the EnergyHub business. In December, we acquired a company called Resideo Grid Services. It was another DERMS provider, and they brought another 650,000 devices onto the platform. We now have two and a half million DERs, which is awesome.
But that doesn’t answer the question. The vast majority today from a device count perspective are thermostats, then followed by batteries and EVs on a megawatts basis. There’s lots of other stuff in there, typically C&I resources, which can be anything from the HVAC system at a hospital to an electric school bus or a fleet of electric school buses.
David Roberts
That’s commercial and industrial?
Seth Frader-Thompson
That’s right.
David Roberts
On a numbers basis it’s mostly thermostats, but when you look at who’s got megawatts at play, the big megawatt players tend to be commercial and industrial systems. Just because they’re bigger, I’m guessing.
Seth Frader-Thompson
That’s right. I think megawatts, maybe call it 20%. We’re at about 3,500 megawatts, three and a half gigawatts. Maybe 20% of that is commercial, industrial.
David Roberts
Interesting. Your basic product is software as I understand it, that is meant to track, monitor, coordinate these devices. One of the things I’m curious about is whether that software is truly agnostic. In other words, can you plug anything that uses electricity into it, or do you have to do a lot of bespoke programming if you want to add a new category? If you weren’t tracking any water heaters and a water heater VPP came along, would you have to do some reprogramming or is it truly agnostic as is?
Seth Frader-Thompson
The software is technically agnostic, but a lot of the value comes from when you go beyond purely agnostic. The strength of VPPs that are made up of millions of resources is that each one of them is behaving somewhat randomly. But when you put that together at scale and you use AI and machine learning to forecast and control that, you have very high degrees of predictability and your ability to forecast very precisely and then control very precisely. It doesn’t depend, but it is certainly enhanced by knowing what that thing is and what the physics of it are.
David Roberts
If you’re going to add a big water heater program, then you would do some “here are the specific qualities of water heaters,” just so the software is aware of it?
Seth Frader-Thompson
You think about if you’ve got a thermostat in a home, it probably makes sense to figure out what the behavior of that home is under different weather conditions. When it’s particularly hot or humid, does the home heat up or cool down particularly quickly? That would change what settings you might send to the HVAC system. If you’ve got a battery, you probably want to know what the state of charge is, what the typical operation mode that battery is in on its own.
You also need to know things like what’s the proximity of one device to another. That gets to be particularly important if you’re trying to get into that distributed angle and trying to understand what’s the impact that you might be having on the local grid and what’s fungible. If you’re controlling an electric vehicle that’s plugged in overnight, you have a huge amount of flexibility in whether you charge that thing at 9 pm or 2 am. Whereas if you’re controlling an HVAC system, the homeowner does care quite a bit whether you’re cooling their home at 9 pm or 2 am.
David Roberts
In practice, currently are most extant VPP programs single device programs? In practice in the field, are these programs mostly “here’s a bunch of thermostats, here’s a bunch of water heaters,” or are there currently operating VPPs that are multi-device?
Seth Frader-Thompson
The answer to both questions is yes. The vast majority are single DER programs. The reason for that is that is how utilities tend to be funded by their regulators. A utility will figure out there is potential here to do a lot with smart thermostats. We are going to launch a smart thermostat program and then they hire a company like EnergyHub to provide the software to run that. But we do have quite a few programs where utilities are blending these things together.
We have talked publicly about three or four folks — National Grid, APS, Eversource, Duke Energy — but it is up to the utility at the end. If they have several programs running in their silos, there is not necessarily anything stopping them from putting those together in a more interesting, more advanced way.
David Roberts
What we’re going to talk about later — the advanced VPP requires device heterogeneity. It requires multiple devices.
Seth Frader-Thompson
Absolutely. You’re much stronger through diversity.
David Roberts
You can’t do a lot of the things that we want VPPs to do if you’re using single devices. Now, as we said, most VPP programs in practice, grid operators do not view them as equivalent to a power plant. I want to talk briefly about what grid operators and utilities want from VPPs. You have this list here: visibility, schedulability, and availability. These are the qualities that grid operators and utilities need from VPPs. “Here’s what we need if we’re going to treat you as a real power plant.”
Can you just go through that list real quick and talk about what those qualities mean from a utility perspective?
Seth Frader-Thompson
A lot of this came out of the world of demand response. In demand response, you’d build a resource that you hoped you didn’t have to use, but you were glad it was there when you push the button. If you are a utility making planning decisions, it was a backup, it wasn’t an operational resource. The transition to being operational is pretty straightforward. You want to know, is this thing there? Right now, what’s available to me?
David Roberts
That’s visibility.
Seth Frader-Thompson
That’s visibility. If you say, “I need to deploy this thing,” a classic thing would be a four-hour block on a hot afternoon or a cold morning. That’s the ability to schedule it, but ideally the schedulability goes a little beyond that. It’s not just, “I need this many megawatts over this period.” It probably has some ramp rate. You turn this thing on, ramp in, hold a particular level, and then come down. You might have it change its output hour by hour. That’s schedulability.
David Roberts
You’ll want to ramp in and ramp out, generally speaking. The grid doesn’t like big jumps.
Seth Frader-Thompson
Exactly. We should talk about that a little bit in the context of what happened in California last summer with DSGS. Maybe we’re getting a little ahead of ourselves. I’ll touch on it briefly here. The operator really wants to know how quickly this thing is going to react. A lot of the decisions that they are used to making have all these built-in assumptions around how quickly a big spinning piece of metal in a power plant would behave. A lot of people were very surprised when a few hundred megawatts worth of batteries reacted very quickly. That just gets back to this thing of you need the ability to schedule it, you need to be able to give it a shape.
The last piece of this is availability. Availability is not a binary thing. You can have something that is only available a certain number of hours or under certain conditions, and you can still provide a ton of value even if your availability is low. But generally, the more availability, the more valuable this thing is. That is what those three pillars are.
David Roberts
They want to be able to see what it is and its capabilities. They want to be able to tell it when to come on and come off, and they want it there when they need it.
Seth Frader-Thompson
That’s right.
David Roberts
Just hearkening back to what we said a minute ago, if you have a VPP program that is, say, all solar panels, solar panels generate when they generate, you can’t necessarily schedule.
Seth Frader-Thompson
They’re not dispatchable.
David Roberts
There are probably some time and level restrictions on thermostats too, that hedge into that a little bit. The more diversity you have, the more likely you are to be able to check these boxes.
Seth Frader-Thompson
Exactly.
David Roberts
If you check them all, if we design a VPP, which I think — tell me if I’m wrong, but I don’t think there is an extant VPP that completely gets there — but if you did get to that point where you are from a grid perspective, visible, schedulable, and available, then you passed what’s called the Huels test. Talk a little bit about the Huels test, which I find delightful.
Seth Frader-Thompson
What I love about the Huels test is that —
David Roberts
First tell us who it is named after, because it is not. I kept thinking it was some riff on fuels, but it is not.
Seth Frader-Thompson
No, it’s named after a person. His name is Matthias Huels, a former member of the data science team here, doing the AI algorithms. He started with this thought experiment, which was, “AI had the Turing Test, which is, essentially, can you have a computer that you’re having a conversation with over text, and it isn’t obvious whether you’re talking to a person or a computer?”
David Roberts
Can it convince a human that it is a human?
Seth Frader-Thompson
Exactly. He said, “What if we had this for power plants? Could you replace a conventional power plant with a VPP and a grid operator can not tell the difference?”
As soon as I heard that, I just said, “This just boils it down to something that is so clear to people.”
That resonated. We started talking about that with customers. I think everybody loved it. What we wanted to do next was say, “That’s binary. We know we don’t entirely pass it today, so let’s come up with some milestones.” Where we looked for inspiration in milestones was the autonomous driving framework that the Society of Automotive Engineers have.
David Roberts
All the levels of autonomy.
Seth Frader-Thompson
Exactly. Mobileye, the company, has done a really successful job of communicating: feed off, hands off, eyes off. Cruise control is feed off, hands off is you’re monitoring this thing and just letting it drive itself, but you have to pay attention. Eyes off means you can be watching Netflix while you’re on a road trip. We said, “This makes sense. Let’s do this for VPPs.”
David Roberts
This is super nerdy, but I want to walk through those levels. We should, because they are very illuminating. The Huels test, as you say, is binary. Turing test is, can a computer convince a human that it is human? Huels test is, can a virtual power plant convince a grid operator that it is a power plant?
Seth Frader-Thompson
That’s right. There is a difference between passing the Huels test from a technical perspective and functionally eliminating the need, say, for a gas peaker plant. You can genuinely stabilize the grid and prevent the utility or a wholesale market from dispatching a wholesale power plant without being fully at the level of passing the Huels test.
David Roberts
There’s plenty of value in the preceding levels before you get there.
Seth Frader-Thompson
Exactly.
David Roberts
You don’t have to get there to produce value. Let’s go through these levels. There are five levels. Let’s start with Level 0, which is just basic demand response.
Seth Frader-Thompson
Level 0, you used to call “press and pray.” What’s fascinating about Level 0 is that for decades Level 0 was providing value. Utilities built these systems where they would go to people’s homes and hook up a switch that would interrupt the signal from your thermostat to your HVAC system or temporarily shut off your water heater. Those would get activated by a one-way paging signal. There was no data coming back to the utility. They’d have to do random sampling, using data loggers to figure out what the impact was. But the utility could see and aggregate at the system level that when they broadcast that message, something happened and it lessened the demand on the grid.
In a way, everything we’re doing is standing on the shoulders of the people who built successful business models and operating models.
David Roberts
That’s been around for a while — the basic demand response.
Seth Frader-Thompson
20, 30 years.
David Roberts
A lot of that is also commercial industrial involving grid operators calling people.
Seth Frader-Thompson
Exactly.
David Roberts
Calling people on the phone saying, “Ramp down your whatever at whatever hour.”
Seth Frader-Thompson
Classically, Macy’s in Herald Square in New York City, they’d call whoever was in charge of the air conditioning and ask them to shut down the air conditioning or turn it up. Or you’d call a cold storage facility and have them do something similar.
David Roberts
That’s basic demand response, which means you’re just sending a signal out. You’re pinging a signal out to all these devices either through the phone or through some switch and then hoping for the best.
Seth Frader-Thompson
That’s right.
David Roberts
That’s Level 0. Then you get to Level 1, which is this basic demand response plus a little data coming back. What does that look like?
Seth Frader-Thompson
That looks like if you’re the utility operator, you push the button and now you’re able to look at a graph showing what’s happening with this thing. It’s showing a load curve, it’s showing acknowledgments of the devices. If you’re broadcasting a signal to 100,000 or a million devices, the first thing you know is that this was successfully delivered. Then you know that signal not only was delivered, but the devices are acting on it. It gives you a sense of whether customers are overriding it, are they uncomfortable? Finally you get some load data coming back to show what the impact is.
But you’re still, to be nerdy about it, open loop on the load shape. What you get is what you get based on you probably sent the same signal to everyone all at the same time, and you’re not necessarily closing the loop to control what that load shape is.
David Roberts
You’re not fine-tuning here. It’s still a pretty crude signal.
Seth Frader-Thompson
The criticism of Level 1 would be that if it’s a bunch of thermostats, you’re going to get a big load shed at the beginning of the event that says, “These homes all raised the temperature on their air conditioner by a couple of degrees.” They’re now all coasting to the new temperature and then they’re going to start air conditioning themselves again at a higher temperature. If you’re the utility, what you see is a big load shed in the first hour that gradually decays in hours two, three, and four.
If you’re doing this with batteries and you’re not thinking about what the state of charge of each battery is, you’re seeing the batteries essentially run out of juice as they discharge themselves into the grid. The reason to bring Level 2 in is where you have the ability to provide flat load shapes. You train a model on what the behavior of each individual device is going to be in response to a signal, and then the system will figure out how to tune those signals. Either you go a little bit less deep with the initial activation, or you stagger the timing of each of these devices.
David Roberts
Cut in the thermostats here, and then an hour later, start the batteries.
Seth Frader-Thompson
Exactly.
David Roberts
You’re working at the timing of these multiple devices so that they average out to flatten the load.
Seth Frader-Thompson
Or they average out to something that isn’t flat but is something you drew, as in “I created a multi-stage ramp.” That’s where we are today — with a multi-DER aggregation we can do a pretty good job at Level 2.
David Roberts
To be clear, you don’t get to Level 2 unless you have multiple kinds of devices?
Seth Frader-Thompson
No, you can be a single DER at Level 2. It’s more valuable if you’re doing more than one together. You get to do, instead of a four-hour event, a six- or eight-hour event. If you want to do extra flat load shape, it’s better that way. But you can do Level 2 with just a single one.
David Roberts
What’s required for Level 2 that you don’t have at Level 1? Is it just the multidirectional communication? What is the piece that you’re adding?
Seth Frader-Thompson
It tends to be things like data. How high quality, what is the latency of the data? There typically is some degree — at Level 2, you are doing some limited locational stuff. A utility might say, “We care about providing relief to a neighborhood that is served by a substation that is getting close to its operating limit.” The utility can target the event at that.
What you’re not doing at Level 2 that you start to do at Level 3 is really mapping in a semi-real-time way how the VPP is overlaid into Level 3. Or you’re better integrated into the other systems that the utility uses operationally to run the grid.
We should just pause for one more second on Level 2. Level 2 is one of these things where — there are no technology problems that need to be solved at Level 2 at all. There aren’t even system integration problems to be solved at Level 2. Level 2 is getting everybody in the value chain to provide the same table stakes, making sure that they’re providing high-quality data with low latency and feeding that into the necessary systems through EnergyHub systems and then on over to the utility essentially at parity among each other.
There are some companies in the DER chain who allow us to operate fully at Level 2, and then there are some who still have work to do. That is a matter of people finishing up some work.
David Roberts
To be clear, Level 2 is currently the most sophisticated VPP. Are there Level 3 VPPs yet or is that a gleam in your eye?
Seth Frader-Thompson
I think Level 3 is the topic of slight disagreement in the industry right now.
David Roberts
What counts as getting there?
Seth Frader-Thompson
To me that’s success. That was the whole point of this framework — to have a common language for these things. There are companies out there who are making a reasonable point that says that they have highly available, highly forecastable, highly predictable systems that, from a control perspective, from an output and outcomes perspective, are at Level 3. I would generally agree with them.
Where I think they aren’t quite there yet is how well integrated into other systems they are. If you’re a utility and you’re using some level of unit commitment software or some other software that mixes all the different supply sources together into your overall supply plan, generally speaking, I don’t think there are VPPs that fully integrate into the utility’s workflow today.
David Roberts
Even the advanced VPPs are treated as kind of an extra thing.
Seth Frader-Thompson
Exactly. If you don’t make this tool look like the existing tools, it is relegated to being an extra thing or it is relegated to being viewed as a demand-side tool as opposed to a supply resource.
David Roberts
But you say Level 3 does pass the Huels test — that it does behave like a power plant.
Seth Frader-Thompson
Exactly. At the end of the day, if you’re running a power plant, there’s a stream of telemetry coming off that power plant telling you exactly what it’s doing.
David Roberts
Briefly, just tell us what telemetry is.
Seth Frader-Thompson
Telemetry is just a bunch of data showing what that is. If you’re thinking about a power plant, you probably are looking at flow rates of fuel, how many RPMs a turbine is spinning, things like that. There are probably other things just like what is the frequency of the supply coming out of that, what is the megawatt level, etc. In general, I’m not aware of a VPP that produces telemetry on par with a power plant today. I think the output is there, but the data that would give an operator total confidence that it is working is not quite there.
David Roberts
This gets us up to Level 3. Level 2, interestingly, in your chart you’re still calling DR rather than a VPP, you’re calling it enhanced — enhanced fancy demand response.
Seth Frader-Thompson
That’s right.
David Roberts
It is when you get to Level 3 and you are automated in some sense, automated and integrated in the utility workflow, you use the term VPP. Automated VPP.
Seth Frader-Thompson
Exactly. VPP in this chart that we have in the white paper is a brief moment that you’re at the full VPP and then once you get to Level 4, you’re into grid-adapted VPP or what Sunrun would call a DPP. At that point you’ve gone beyond what a conventional power plant can do and now you can both support the regional grid at the transmission generation level and you can support the distribution grid.
David Roberts
How do we do that? How do we get from Level 3 to Level 4? Is there a clear threshold or is it just added complexity? More data? What does the transition from Level 3 to Level 4 look like?
Seth Frader-Thompson
It’s all of the above. You need better data, you need tighter control loops, but more importantly than all of those, you need better integrations into systems. You either need the ability to see what congestion exists, or other conditions would exist on the distribution grid, or you need the distribution grid to be able to articulate to the VPP, “Hey, I need some help on this substation here, or further down into this feeder, or all the way down to the individual service transformer.”
No one can be at Level 4 on their own. Level 4 is a group activity, a highly integrated system of systems.
David Roberts
You need the grid that’s ready for it as well as a VPP that’s ready for it.
Seth Frader-Thompson
Exactly. Level 4 is something that we are pretty far along in terms of the technology pieces and we are doing limited demonstrations today. Today with batteries and EVs we can, in real time, balance the loads on the grid to make sure we are, for example, charging a fleet of cars overnight, making sure that we are not overloading any piece of the grid for longer than it is able to do that, shifting power around to better sponge up the available wind power or based on the price of electricity — there is a co-optimization, multiple variable optimization going on and do all of that at multiple different levels up a big hierarchical chain from the very local to the very system wide.
The limitation, the reason why we wouldn’t say, “Great, we’re done, we’re at Level 4,” is that it is not being done in a fully automated, fully integrated way at scale.
David Roberts
Is that true across the board? Is there anywhere where the grid is sophisticated enough to support one of these Level 4 VPPs?
Seth Frader-Thompson
No. Nobody has the whole system in the world. No.
David Roberts
Getting to Level 4 VPPs is about evolving VPPs but it’s also about evolving grids — the grids are communicating with the resources better. Once you have Level 4, you have this collection of resources that is optimizing for distribution grid performance. Then it’s also optimizing for what the customers need and it’s also optimizing for what the bulk transmission grid needs. It’s got all these different parameters and it’s supporting all these objectives at the same time, which you point out — and I think this is crucial.
I’ll read a quote here from the report: “When a VPP can meet each of these requirements — full stack optimization, which means optimizing for all these different criteria; locational awareness, which means it knows where it is and where help is needed; wholesale and retail market integration; and ultra-fast telemetry — it becomes a preferable substitute for conventional generation.”
This is the grail. A Level 4 VPP is a super power plant. It’s better than a power plant.
Seth Frader-Thompson
Why would you not want a thing that is cheaper, greener, more customer-centric, and faster to deploy than all the alternatives?
David Roberts
And has more capabilities! You can’t store surplus electricity in a power plant. This literally can do things that power plants can’t do.
Seth Frader-Thompson
The thing to remember in terms of why we’re not at Level 4 today is that the system for years has run on design margins. Distribution grids — you didn’t need real-time control of the system because when you were building the grid, you applied margin. That meant that you always had a little bit of a cushion. What we’ve been doing is eroding those cushions for the last 30 years. We’ve been electrifying homes. My house has electric heat pumps for heating and cooling. I’ve got an EV charger, I’ve got an induction stove.
A bunch of people get those along my section of the grid and suddenly there is a bunch of load that nobody assumed would be there. We have been installing random power plants — in the form of solar panels. We have been installing batteries that can discharge in a way that nobody planned for. At the same time you have all this load growth on the grid. All of those design margins that we used to be able to count on, we cannot necessarily count on anymore.
David Roberts
I should just insert, because one thing that has come up a bunch in recent pods is why power prices are going up in the US, and the big piece of that puzzle is the distribution grid is rising in cost all the time. I think probably because of what you are talking about.
Seth Frader-Thompson
The poles and wires, the fixed costs of running the grid, are not getting cheaper.
David Roberts
This brings us to the value delivered by VPPs. You’d think a kilowatt is a kilowatt. This is not true. Once you get more sophisticated VPPs, they’re producing more and more kinds of value. Level 0 and Level 1, more or less the bulk of the value you’re getting out of those is you’re avoiding having to generate energy. Otherwise, you’re removing some demand, so you’re avoiding those generation charges. That’s the bulk of the value.
That value remains large as you go up the levels. But as you go up the levels, you get more and more. This is what I find interesting: you’re avoiding — and there’s a little sliver, even from Level 0, you get a little sliver of avoided transmission capacity.
This is something that VPP folks like yourself talk about all the time. Rooftop solar people are constantly talking about, “The more local gen and storage you do, the less transmission infrastructure you need.” That’s a piece. Once you get to Level 2, you get this new piece which is avoided distribution capacity. That gets to be a pretty big piece by the time you’re at Level 4. I think it’s intuitive, but just talk a little bit about how a sophisticated VPP would help avoid building distribution capacity.
Seth Frader-Thompson
In many ways it is the same problem as you have at the transmission level. Somebody does an analysis and figures out what is the maximum coincident demand for power going to be on this piece of wire that stretches through this neighborhood, or how big does this service transformer need to be to serve the four homes that are behind it. If you put something in 10 years ago and you still have plenty of extra capacity, then great, until that thing wears out, it will just keep doing its job. But if load grows behind that thing, at some point you get to the point where you have got to replace it.
The question is, what if you don’t? What if you can just say, “We’re going to avoid setting a new peak demand or we’re going to avoid having the demand on this component last longer than a certain amount of time.” If you have a system that’s looking across DERs and saying, “I’ve got this many cars behind this thing, I’ve got this many air conditioners behind this piece of equipment. I’m looking at a forecast for how they’re all going to come together. I’m going to figure out which pieces of this demand puzzle I can shift to the right or to the left.”
You can bring that peak moment down and you can avoid an upgrade. It’s possible that you could avoid that upgrade for at the very least, table stakes would be a few years. Ideally, you’re talking about avoiding that upgrade essentially forever for the length of that component.
David Roberts
It’s, as you say, the same thing as on the transmission level. You’re just trying to reduce peaks. It’s peaks that trigger the need for new infrastructure. It is possible to add more to the grid, more demand without driving that peak up.
Seth Frader-Thompson
It’s really good if you can add load without driving that peak up. Now you’re spreading the cost, a fixed cost, over a much higher amount of usage. The one other thing that people don’t talk about a lot here, but is becoming more and more important as a result of climate change, is that most of the limits we talk about in the physical grid are thermal limits. There’s some piece of equipment that you put enough power through it, it gets too hot, and there’s some component in that that’s going to wear out.
A lot of the time you have a decent amount of cushion, that thing can get pretty hot for a few hours, as long as it has a chance to cool down overnight. What if it doesn’t cool down overnight? For example, in Arizona, not only are they setting records for number of days where the high temperature is over 100 or over 110 degrees, they’re now setting records for the number of days where the low temperature is higher. I think they had “a hundred days where they didn’t go below 90 overnight.”
David Roberts
Nightmare. Nightmare fuel.
Seth Frader-Thompson
Exactly.
David Roberts
Absolute nightmare. Gross.
Seth Frader-Thompson
Some, again, back to those design margins. If you had a margin of safety based on the idea it’s going to cool off and then this component’s going to cool off, what if it doesn’t? Again, this allows you to spread that thermal load out and squeeze more out of the system.
David Roberts
This is just reducing peaks, which is the whole thing you want to do. If you keep your peak where it is or lower, and you can keep adding capacity. Also by doing that, as you say, you are better utilizing the infrastructure that you already built. We paid for all this infrastructure.
Because these peaks are so high, most of the infrastructure is only getting used a tiny fraction of the time. Just utilizing existing poles and wires more fully is a huge thing. This is something I’m going to return to in future pods. I think we are going to be thinking about regulatory and legal ways to force utilities to better utilize the infrastructure they’ve already built. The only way to do that is through VPPs.
Seth Frader-Thompson
The thing that gets lost here is when you have an entire industry that is used to valuing things a particular way that is based on a set of engineering assumptions, it is hard to update those engineering assumptions if you do not have the data.
What we hear from a lot of utilities is that they’re fully on board with doing as much of this as possible. The difference between a Level 0 through a Level 2 VPP and one that’s at Level 4 is we’ve known what the business model was for the lower levels for years. Somebody at some point took the capital cost and the O&M of running a gas peaker and translated that through some derating into this many dollars per kilowatt annually for system-wide capacity that’s available 60 to 80 hours a year.
But when you’re moving into Levels 3 and 4 and you’re saying this thing is highly available or it’s highly distributed, there isn’t a number that everybody agrees on what it’s worth, or if you’re talking about extending the life of this component, there’s a question of by how long. It’s pretty hard to take that uncertainty and turn that into something where the utility can go to the regulator and say, “We think this is worth paying X for.” The regulator can with confidence say that’s a prudent investment. This becomes a chicken-and-egg problem for the industry.
David Roberts
This is what all the pilot programs are supposed to do. This is why we’re in pilot hell forever — we’re supposed to be demonstrating, that’s the point of all these pilots and test programs that utilities are constantly running, to show that they work. How far along is that process?
Seth Frader-Thompson
I think we’re well along in that process. What we see most utilities doing is they’re running programs at scale way beyond the pilot stage — Levels 0 through 2 or 3. They’re taking small slivers of those programs and doing locational pilots. I think in the next year or two we will start to see enough data emerge that it can then start feeding back into the regulatory process and into planning processes. This is why we felt there needed to be a common language in the industry to talk about how we’re doing and how far along we’re going.
David Roberts
You think we’re close to a point where some utilities are going to have the confidence you are talking about.
Seth Frader-Thompson
I think we’re very close.
David Roberts
The one other thing I want to say about the value delivered by VPPs. As you say, once you get to Level 4, you’re getting avoided generation, avoided transmission, avoided distribution, and some ancillary services — grid balancing services — once you get up to Level 3 and 4.
One value that’s not on this chart is the value of resilience, which is very difficult to measure precisely. This is not a convenient metric, but strengthening distribution grids is resilience — that is what resilience is. Is this something as a selling point for you or the resilience benefits? Does that come up a lot when you talk to policymakers or anything?
Seth Frader-Thompson
It does. This gets a bit into a piece of this that isn’t really captured by the framework itself, which is these VPPs are built up of devices that are in people’s homes and businesses. The question is, how did they get there? If you look at a place like Arizona, lots of people have smart thermostats because everyone has air conditioning. We’ve spent the last 10 years; people have just been buying smart thermostats. If you look at places like California, where power prices are really high, you have lots of solar and lots of batteries that are there to help people save money. If you look at a place like Puerto Rico where their grid was destroyed by Hurricane Maria, you’ve got huge numbers of people who invested in solar and batteries just to keep the lights on.
They started with their own personal resilience of “How do I make sure that I have power when the grid goes out?” but once it is there, it becomes this latent resource that the grid can tap into. Puerto Rico is a great example where they are literally keeping the lights on because of these battery-backed VPPs. It is in the background, as it were.
What’s fascinating is that there is a positive feedback loop to be built here, which is that as utilities or other grid operators recognize the value, they can turn that value into incentives for customers. The incentive for customers then drives adoption. In places where there is a really strong incentive to participate in a VPP, you see people buying more batteries, buying more smart thermostats, and renting them out to the grid.
David Roberts
I talked with Pier LaFarge on a pod last year about utilities running these things, running VPPs, doing it on purpose and procuring them deliberately. What I’m wondering is, once utilities are really confident that these things work, that they’ve seen how they work, they’ve seen how to make them work, it seems like you could go beyond incentives.
How do you get beyond the consumer model here? When I think about scale, I think, how are we going to get to scale when we’re trying to persuade one consumer at a time to do these things? There’s got to be some bigger way to do this, some bigger, bulkier way to do this.
If a utility really believes that a VPP can reduce peaks in a particular part of the grid, in a particular congested part of the grid, could you envision a utility on purpose building a VPP in that part of the grid? For example, putting out an RFP and paying for and owning the solar panels or the batteries in the backyards or whatever and running it as a utility asset. In other words, being proactive rather than just accepting VPPs that come along. Being proactive and building them where needed.
Seth Frader-Thompson
This is interesting because there’s an element of that that is the old way of doing things. The original residential demand response programs — because people didn’t have smart thermostats or smart water heaters — the utility would give you a free pager-based thermostat and install it for you. The downside of that model is now the utility is on the hook for the cost of the hardware. They’ve got to roll a truck to your house, they’ve got to install it for you, they have to pay for all of that. Anything that ever goes wrong with that is their fault.
Those were successful. There were some utilities that installed a couple million of these things. If you contrast that with what happened with IoT devices, we now have tens of millions of homes with batteries, thermostats, and EVs installed. That’s where the BYOD model came from.
This is where EnergyHub’s business succeeded. Twelve, thirteen years ago we saw, “Hey, these categories of products are taking off. We can adopt the business model that worked for first-gen DER and apply it to this new delivery model which is bring your own thermostat, bring your own battery.” In that case you’re building a partnership between the customer, the DER manufacturer, typically the local installer base, the trades, and the utility or the grid operator. All the data shows that is vastly more scalable than a centrally planned version.
David Roberts
Right now most VPPs are hovering around Level 2. Some of them are nudging up into Level 3. As you say, there’s not really any place ready for a Level 4 yet. Let’s talk about how to get from here to there. You lay out a roadmap in the paper. Talk about some of the things that you need to do, that the VPP industry needs to do, and then some of the things that you would like to see utilities do to bring more Level 2 VPPs into the bright future of Level 3.
Seth Frader-Thompson
Some of the things that are in, if I look at the chart and at Level 4, where does EnergyHub most glaringly not make the cut? It would be in the realm of telemetry. We can’t provide 2- to 6-second telemetry to provide a true real-time view of what is going on with every level of the resource.
David Roberts
Why is that? Is that a lack of fiber? Is it a lack of communications technology? Is that a practical or technological limitation? Why is that?
Seth Frader-Thompson
Today it is a technological limitation in the sense that we need to take a bunch of very noisy signals that are coming in at various time intervals and create a synthetic telemetry signal back to the utility that accurately represents all that in a way that strips out the irrelevant noise, but keeps the core of it necessary for the utility operator. That would be an example of something where, in aggregate, that is clearly on EnergyHub to solve.
And you presumably have a room full of nerds somewhere?
Exactly.
David Roberts
Beavering away on that project.
Seth Frader-Thompson
Hundreds of nerds working on that. But that’s not a real problem today. If I look at where the real problems are today in the industry, there are things like, when I push the button and I tell one of our DER partners to dispatch 200,000 devices, do they get it done in one minute or do they get it done in 15 minutes? If they’re not getting it done in one minute, it’s probably because they never really had a reason to in the past. Nobody told them that was important. There’s just engineering work to refine data pipelines to make that better. That’s where I think most of our partners are.
You then have a bunch of things that are just pieces of pure accumulated brain damage over the years — vendor A will only allow us to put their devices into 100 groups. Someone made a decision in 2015 that said, “How many groups would I ever need? 100.” They never made the decision, “One utility might have 5,000 individual groups where we need to map the distribution grid to devices.” A lot of this stuff is really boring, random, practical decisions that got made a long time ago that have to get undone and have to be aligned across the industry to make the thing work coherently at Level 2 or at Level 3.
David Roberts
Are those software?
Seth Frader-Thompson
Yes.
David Roberts
Software cruft — mostly what are you talking about?
Seth Frader-Thompson
Software cruft. That’s a great way to put it. Yes.
David Roberts
That’s on the utilities, then, to update their —
Seth Frader-Thompson
No, that’s generally on the DER ecosystem. What’s on the utilities tends to be in some of what you need for Level 3 and 4. It’s common, for example, that a utility would say all of the data feeds that a DERMS platform like EnergyHub’s would need, say, to read the conditions on the grid, those data feeds are completely locked down for very real security reasons.
Someone needs to come up with a highly secure, practical and scalable solution to expose that to a system like ours. Then you just need to go through rounds and rounds of testing to make sure that these systems talk together, they begin to make automated decisions together. Then you need to figure out, is the behavior what you’d expect, or are there weird emergent things that come out of that that have to be discovered and dealt with one by one?
David Roberts
One of the things you hear — I did a whole pod on this a couple of years ago — is that VPP can’t take off in certain places because utilities just won’t share that data. You have all this smart meter data that is required to coordinate VPPs that utilities won’t share. Is that a substantial barrier? Have you run into that? How big of a deal is that for you? Do you think it’s changing at all?
Seth Frader-Thompson
I don’t think it’s a substantial barrier, but I think my lens is maybe very different than some of the other folks you’ve had on the pod or who might be listening. I don’t think most utilities want to or should expose a lot of this stuff to very many other systems out there. There are very good reasons why some of that stuff is really locked down and this is essentially why utilities choose a relatively small number of systems to run their operational stack. Part of the role of a DERMS — the acronym Distributed Energy Resource Management System — is about primarily managing the DERs.
It’s not a grid management system, but it needs to be thought of as a utility system for them to get comfortable opening this up to one system. The way we view it is that our DERMS ends up getting very tightly coupled to a few pieces of utility system and then everything that’s downstream from us is completely uncoupled. I think that is the correct architectural design for these things. Sometimes people look at this and they hear the things that we’ve been talking about — access to these data feeds, security issues, or the complexity of this — and they say, “Wouldn’t it just be simple to do all this with price signals?”
David Roberts
I’ve got several listeners, Seth, who are on the edge of their seats, this entire pod with that on the edge of their lips.
Seth Frader-Thompson
Unfortunately, I think that they have settled on the one thing that would be even more complicated. How are you supposed to come up with some complex price discovery mechanism that not only represents conditions in an incredibly complex, scalable way, but also allows for something that’s a plannable resource? Something where you’re making future, forward-looking, forecastable decisions and something that any consumer wants to or can wrap their head around.
I don’t see any path that doesn’t involve a small number of companies — EnergyHub and a few of the folks who are in the control room figuring out some complex integrations. Every other solution is even more complicated.
David Roberts
I’m going to do a pod devoted to that subject soon because there are people out there who are very enthusiastic about the ability of prices to do this. I can see how price signals could do the short-term coordination, just the day-to-day diurnal stuff, some peak shaving stuff like that. But as you say, these long-term goals, long-term plans — do price signals contain that information? Do they contain our long-term intentions and goals? We will dig further.
Seth Frader-Thompson
The one thing I’ll say is even if you’re just thinking about system-wide resources, if you look around the world at places where they have more complex time-varying rates, where you tend to have a deregulated industry and people can sign up for a supply plan that has 24-hour ahead, 15-minute intervals, or hourly or 5-minute whatever, you don’t see hugely successful VPP programs running in those countries. The only place that I’m aware of where you have really successful large-scale VPPs is in the US and it tends to be concentrated in places where you have regulated utilities. If price signals were the solution, we would see it working.
David Roberts
It’s interesting to me. I heard you on the DER Task Force pod talking about this and I’m curious — just to frame this for the audience — you would think VPPs being a distributed, market-sensitive thing would be cropping up where there is market competition. But instead, as you say, where you are seeing them is where there are vertically integrated utilities, where there are central planners. Is there a capsule explanation for that? Is there a 30-second explanation for that? Why is that?
Seth Frader-Thompson
There is definitely a 30-second explanation. The great unsung benefit of having a utility is that the utility abstracts all the complexity of planning and running the grid. You flip the light switch and the lights go on and you don’t think about it. Utilities do an amazing job of just rolling up all these costs and coming up with a simple way to charge you based on the amount of power you use. Now we are at a point where we need to advance that a little bit, but we don’t need to go all the way to dynamic local marginal prices.
David Roberts
This will be a fun debate to track over time.
Seth Frader-Thompson
Somebody said to me, “I didn’t expect to become a full-blown regulated monopoly apologist, but I have been all over the world talking to utilities about this and every time I come back saying, ‘Okay, I see what you guys are trying to do, but just look at what’s working in the US and try to copy it a little bit.’”
David Roberts
Interesting to me. I’ve been doing this for 20 some years now and I’ve seen elite energy opinion swing this way and that on the merits of —
Seth Frader-Thompson
I love that — elite energy opinion.
David Roberts
Yeah, vertically integrated utilities versus competition. I’ve noticed a lot of people coming back around after a long journey, coming back around to the merits of good old-fashioned monopoly utilities. Then of course there are other people who hate them more now than ever. It’s an interesting dispute.
By way of wrapping up, I wonder if there are any easy regulatory or legislative changes that you think would help accelerate the process whereby VPPs evolve from Level 2 to Level 3, Level 4, and beyond. Are there easy things you can tick off here?
Seth Frader-Thompson
Probably the first thing is for regulators to keep it simple with utilities. Give the utility a goal. It can be in megawatts, it could be in an area of focus, DER class. Generally you want to leave it open beyond that. We see complexity creep into regulatory orders that does not need to be there. “You can only run this resource for this many hours” or “Anytime you want to call on the resource, you need this many hours of notice” or anything like that.
David Roberts
Is that PUCs injecting that over-engineered — overactive PUCs?
Seth Frader-Thompson
Yeah, that’s exactly what it is. Don’t do that. That would be number one. Number two would be to give utilities the green light — or the encouragement — to come up with hypotheses around some of these future value streams around deferring distribution and other things out into Levels 3 and 4 and allow them to be doing these things at scale alongside what they’re doing with the system-wide VPPs.
Where we have seen regulators really get it wrong is by — again, some of it is over-engineering — saying, “If you’re running a smart thermostat demand response program that has to be totally separate from the distribution deferral study that you could be doing with the same smart thermostat demand response program,” or “Run an EV program but only use the EVs for price response,” or something. All of this stuff is just give the utilities goals but don’t over-engineer the requirements.
The final thing is long-term stability. Success at scale here requires the entire industry to come together. Where we see this really work — we always point to Connected Solutions in the Northeast as the best example of the regulator getting it right — saying, “There’s a five-year guaranteed revenue stream for any battery provider or any aggregator that gets involved.” Those folks can look at it and say, “If I put batteries in, there’s $250 per kilowatt year available to me. I know that’s going to be there for five years.”
By the time that trickles down from Tesla or Sunrun to the local installers to the customers, it takes time. You want to get to the point where you have momentum, where neighbors are telling each other, “Hey, did you get a battery? They’re basically half off if you sign up for the VPP.” That’s the stuff that really makes this thing work.
David Roberts
Just between us and the listeners who have held on for this long, I like the idea that diversity is our strength here, that diversity of devices is a strength in the VPP market. I like the notion of it. But just between you and me, is it not batteries that are really doing the work here? If you lost everything but batteries, but you had a lot more batteries, would you really lose any capacities, any capabilities, any abilities? Isn’t it really batteries that are the workhorses here?
Seth Frader-Thompson
I see what you’re saying. If everyone had a free battery of unlimited size, would this be easier? Yes, but in a typical home or office building, the vast majority of the load is HVAC, so it would be a mistake, even if you have a battery, not to be able to control the load as well. As a matter of fact, we think of an HVAC system or a water heater as a thermal battery. You can pre-charge it, you can discharge it.
David Roberts
That’s what I mean. Storage of energy is timed storage and release — that is the magic here.
Seth Frader-Thompson
I see that. But I think if you go too far with that analogy, then you get into, “Is Bitcoin a battery?” or “Isn’t gasoline a battery? It’s a store of chemical energy.” I love batteries. They are the most high-performing resource. They’re fast, they’re stable, you can command them to do exactly what they do. They have no impact on comfort. But a battery in a car is not the same as a battery on the side of your garage. An HVAC system is still most of the load in most parts of the US, so I think it makes sense at the very least to have all three of those.
David Roberts
Do you think we’re going to get to a point where every device that consumes electricity is communicating bidirectionally and is involved in grid coordination in some tiny marginal way? Do you think that’s just going to be the default state of everything on the grid at some point? Is that where we’re headed?
Seth Frader-Thompson
The short answer is yes, but I think that you do see some categories of appliances where the companies that make those products are just not digitally native. I’m not sure that they’re ever going to be. Who? I own a fancy fridge and induction stove and oven and my Sub-Zero, whatever it is, my Wolf Range, it can do one thing — send me a notification when the oven reaches its temperature. But the Wi-Fi forgets the Wi-Fi password all the time or I get signed out of the app. I’m not sure that that’s worth solving. Just go back to making the stove. I don’t need an app.
David Roberts
Presumably the ability to do that will get commodified and will standardize.
Seth Frader-Thompson
Presumably. But here we are 15 years after IoT hit mass scale and we’re still not there. A better example here would be if you look at the HVAC companies themselves, they are at least a decade behind the smart thermostat manufacturers in terms of delivering a really first-class digital user experience. That is not a criticism of them so much as a statement that they sell to — their customers are HVAC technicians who then install them in people’s homes. It’s a piece of equipment that’s largely out of sight and out of mind.
That’s unfortunate because the world really needs the heat pump manufacturers to get digitally native more quickly than they are.
David Roberts
Let me ask about that — why? The reason I ask is because replacing resistance heat or natural gas heat with a heat pump — a heat pump is very low consumption. It’s low stakes in terms of VPPs. If there’s one appliance that you’re just not going to bother with, it would be heat pumps. Just because there are so few kilowatts involved. Is that wrong?
Seth Frader-Thompson
If it’s a heat pump for space heating, yeah, that is wrong. Unfortunately, as I found out, I electrified my house during the pandemic and I have heat pumps all over my house and my electric bill is very high in the winter.
David Roberts
Are you in California?
Seth Frader-Thompson
No, I’m in New York. The power in New York City is incredibly reliable, but it is very expensive. It’s expensive because the poles and wires are all buried. That means that it’s very reliable — but very expensive. There are a bunch of pieces if you unpack this. One is that I have no gas bill, so that’s cool. I don’t pay a gas bill anymore, but now my Con Ed bill has gone up by a bunch. I’m not necessarily thinking every time that my gas bill went down. I think this is part of a broader issue in the electrification trend: every customer who eliminates their gas bill has a corresponding increase in their electric bill. That’s one part of it.
The other piece is that the system architecture is different. If you have a standard forced air HVAC system, you probably have one or two thermostats in your house, whereas I have ten in my house. There is a thermostat for every single heat pump unit. As an interesting thing, I accidentally booted one of those thermostats offline and I know a lot about smart thermostats and how to connect things to Wi-Fi. I had to call my technician to come in and take the thing off the wall and access some wireless module to reprogram it. It is a different control system — it was not envisioned in most cases to be simple and digital first.
David Roberts
I wonder whether, and I wonder if this is the model of change in your head too, all this preparatory work is going on right now. I think a lot of it is probably not visible to normal consumers. But a lot of people, you say, you’ve got a room full of nerds working on telemetry. People are working on the pieces of this. Do you think this is the kind of thing where it’s going to be slow, slow, slow, and then all of a sudden? If so, are we close to the all of a sudden?
Seth Frader-Thompson
Yeah.
David Roberts
Or are we in the midst of the all of a sudden?
Seth Frader-Thompson
I think we’re in the midst of all of a sudden. People who have not been following EnergyHub’s journey over the years will check in with me and they’ll be shocked to find out the size we’re already at. I still get questions from regulators about when the thing is going to go beyond pilots. I’ll tell them that we’re running 500 megawatts of VPP in their state. I do think that it’s one of those ten-year overnight successes. At the same time, the goal we’ve set for ourselves is 100 gigawatts by 2035 and we are today approaching 4 gigawatts.
While it’s very large in the context, three and a half gigawatts is two nuclear power plants. That’s great. I’m happy with that result. But to have an impact at a societal level, we need to be at that 100 gigawatt scale, which is approaching the size of all of PJM. It’s larger than Texas or England.
David Roberts
Part of what I’ve been wondering is if VPPs get that big and we get to a place where being involved, participating in a VPP is something close to the default for big appliances and big systems and houses and everything else. I wonder if eventually this is just going to be part of what it is to be a utility and it’s not going to sound like a separate thing. It’s not going to require a separate... Somehow it seems like this is just going to become what utilities do.
Seth Frader-Thompson
I completely agree with you. I think you nailed it. It becomes just what you do with the technology in your home or in your business, and it becomes just part of how the utility runs itself. When you talk to customers, you have a lot of different segments out there.
There are definitely folks who are saying, “I’m participating in this program because it meant that I got a smart thermostat for free or I got half off my battery.” You also hear a lot of people saying, “Why not? This has no downside and it’s one of the few tangible things I can do as a consumer to have an impact.”
From a utilities perspective, the average utility, especially today, has overwhelming pressure on their system. There are many cost pressures that they are on the back foot in trying to figure out how do we keep the system affordable while keeping it safe, reliable, and serving all of these new loads that are coming online. If you can say, “Look, partnerships with your customers in the form of VPPs are going to lessen that pressure,” almost every utility is enthusiastic.
David Roberts
It’s the cheapest — I can’t tell you how many times I’ve said this on this pod. Everybody wants capacity, everybody wants grid capacity. This is the grid capacity that is the fastest to get because it already exists. It’s already there. You just need to go aggregate it. How long is it going to take utilities and all these big, rich, wealthy entities that desperately want more grid capacity to arrive at this, what seems to me a pretty obvious conclusion?
Seth Frader-Thompson
I think that those wealthy entities that want service, that want to get a service hookup for their data center, are ready and willing to build, for example, on-site storage to help firm that power supply. This goes back to things that regulators can do and there is plenty going on with this right now — making it easy for a data center or any other large load to come online and co-locate storage that from day one has the ability to either help firm the supply capacity or export to the grid. There is no reason not to do that everywhere in the US right now.
David Roberts
I would go beyond that — this was my other final question, by the way I remembered it. This is really going to be, I think, my fifth but definitely final, final question. You’ve got all these hyperscalers who desperately want to build their data centers. They desperately need grid capacity. I think you could go beyond asking them to build on-site storage. Why not ask them to fund VPPs?
Seth Frader-Thompson
We are doing that.
David Roberts
Why not ask them to build? They have all the money. When I interviewed the guy from Piclo, the guy who set up a marketplace for this, he did the calculations. Three percent of the money that’s flying around in the data center world could get you 100 gigawatts of VPPs. It’d be $40 billion of new revenue for the VPP market. It would be good for the utilities, it would be good for the data centers, it would be good for the VPP operators. It’s all upside. What the hell — is that going to happen? Are you talking to data center people?
Seth Frader-Thompson
We are. That will happen. I think that both makes sense from a rational economic perspective. It’s an obvious win if you think about the level of community anxiety about these data centers. An opportunity for someone to say, “Hey, we are funding batteries everywhere around.”
David Roberts
For a utility to say, “Look, a data center came, they wanted to hook up, we brought them to heel, we forced them to fund heat pumps for you. Here’s what you’re getting from this data center showing up. You’re getting a heat pump.” What a win for the utility.
Seth Frader-Thompson
There are models for this. For years it has been common — someone wants to build a manufacturing plant or a data center and they say, “We’re going to put money into the community to upgrade roads or whatever it is.” It fits with that pattern. I think it is going to take a couple of years for that to start happening at scale. From the conversations we are having right now, that looks pretty promising.
David Roberts
That to me is interesting. It’s a win for everybody. It’s a win for the data centers too. They get their capacity quickly. They look like Santa Claus passing out gifts rather than the Grinch coming to steal all your power. Customers get VPPs, they get better grids. It’s a win all around.
Okay, Seth, this was awesome. This is exactly what I wanted. I’ve been talking about VPPs for a while, but it’s really helpful to dig in and remember that there are kinds, there are stages, and I think the most exciting thing to come out of this conversation is that we are on the cusp of VPPs really becoming what they could be — becoming true, important, predictable, reliable participants in day-to-day grid stability.
Seth Frader-Thompson
I’m glad you’re excited about it. We are also excited about it. This nerdy stuff is all we do.
David Roberts
You’ve been at this since 2007. Respect, Seth. I started doing what I’m doing in the early 2000s and kept doing it. My wife is the same. Just a shout-out to people who figure out what they want to do and do it.
Seth Frader-Thompson
Thanks, I appreciate that. I want to say for anyone who is also excited about this and has strong feelings about this framework that we put in the paper, the purpose was to start a conversation. I have already heard from some folks who are important in the industry saying, “Hey, I have a different take on what the requirements are for this or that.” We want to hear from you. By all means, please reach out to whoever you know at EnergyHub or just knock on the digital front door.
David Roberts
Thank you for listening to Volts. It takes a village to make this podcast work. Shout out, especially, to my super producer, Kyle McDonald, who makes me and my guests sound smart every week. And it is all supported entirely by listeners like you. So, if you value conversations like this, please consider joining our community of paid subscribers at volts.wtf. Or, leaving a nice review, or telling a friend about Volts. Or all three. Thanks so much, and I’ll see you next time.
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