If we want any chance of affordably and reliably building a grid powered 100% by zero-carbon resources, we need to triple the capacity of virtual power plants.
That’s the conclusion of a report released last fall by the Department of Energy, which examined the different business models and integration approaches for tying solar, batteries, thermostats, electric cars, water heaters, and other distributed assets into dispatchable power plants.
The US already has tens of gigawatts of VPP capacity, mostly in the form of “bring your own device” programs that harness thermostats or water heaters for demand response services. But there are new models emerging that harness rooftop solar, batteries, and EV charging to enable bigger, longer-lasting load shifts.
“I like to say that the term VPP is kind of like the term sandwich. There are lots of different kinds, they’re full of different ingredients, and they serve lots of different purposes,” said Jen Downing, an engagement officer at the DOE, who leads the agency’s work on the space.
The concept of VPPs has been around for nearly 30 years. But as the US faces a dramatic increase in peak demand by 2030 – and with distributed resource capacity set to double – the urgency for deploying them has increased.
“We’re going to need clean, firm [power]. We’re going to need more transmission capacity to transport that electricity. But one way to address that increase in peak is to use distributed energy resources to either serve that peak locally or to shift that peak outside of peak hours. And so that’s where VPPs come in,” said Downing.
This week on The Carbon Copy, we spoke with DOE’s Jen Downing about the different ways that virtual power plants are getting built – and the need to build many more.
Transcript
Stephen Lacey: In the clean energy world, it seems like everyone is talking about virtual power plants right now. But the concept dates back almost thirty years – to the late 1990s – when an energy economist outlined how a “virtual utility” could flexibly integrate distributed resources from third-parties for the benefit of the grid.
The term virtual power plant, or VPP, took hold in the early 2000s, when pilot projects emerged in Europe that tied together combined-heat-and power systems, fuel cells, wind parks, and hydro plants into a top-down dispatchable system.
But in recent years, as rooftop solar, customer-sited batteries, electric cars, smart thermostats, and electric water heaters have made their way into millions of homes – and power electronics and software to control those assets has gotten way better – VPPs have taken on a new shape.
Some people in the industry don’t love the term, prefering to use distributed power plants instead. But VPPs stuck – including at the US department of energy.
Jen Downing: We accept it, we use it. We’ve moved on.
Stephen Lacey: So I can imagine a group of you in a conference room somewhere taking a vote about whether to use distributed power plants, virtual power plants. Is that how it went forward? Someone banged the gavel and said, “Virtual power plants, it is.”
Jen Downing: It was a hallway conversation where we said, “Oh man, I can just see the headlines now. The haters are saying it’s virtual, it’s not real. We can’t rely on it.” We may have influence at the Department of Energy, but we didn’t think we had so much influence we could erase the term VPP from the market.
Stephen Lacey: Jen Downing is an engagement officer at the DOE’S loan programs office. That’s the organization that provides debt financing to groundbreaking clean energy projects. Jen led a major effort last year to craft a plan for how the department can help the VPP market scale. And the agency has thrown support behind projects including a $3 billion partial loan guarantee to SUNNOVA for 568 megawatts of rooftop solar and batteries that are tied together. There are a couple of reasons why DOE is focused on this slice of the industry. One is that all the enabling tech is already here or mostly here today. And the other is that we’re facing a dramatic upswing in load on the US grid.
Jen Downing: Now we are expecting peak demand to rise and rise pretty consistently. So between now and 2030, we’re roughly expecting to add about 60 gigawatts of peak demand. The same time there’s a lot of old coal power generation coming offline to the tune of potentially over 150 gigawatts of capacity.
Stephen Lacey: That adds up to 200 gigawatts of peak demand by the end of the decade. Now, there are many ways to serve it with utility scale, solar and wind paired with storage plus geothermal nuclear hydro, but it might not be enough.
Jen Downing: We’re going to need clean, firm. We’re going to need more transmission capacity to transport that electricity, but one way to address that increase in peak is to use distributed energy resources to either serve that peak locally or to shift that peak outside of peak hours. And so that’s where VPPs come in.
Stephen Lacey: This surge in demand is bringing a lot more urgency to the conversation around turning distributed energy systems into dispatchable power plants. VPPs aren’t just a cool technical concept. They’re a resource, it’s getting bigger every day and the health of the grid may depend on them.
Jen Downing: They’re taking these distributed resources that are increasingly added to the grid anyway as people are buying EVs and installing rooftop solar and batteries and creating a grid scale, grid quality resource for utilities and grid operators to tap into.
Stephen Lacey: If we want any chance of building a grid powered by 100% zero carbon resources and do it affordably and reliably, we need to triple capacity of VPPs distributed resources are ready, but orchestrating them requires a much more serious commitment from utilities and grid operators and a continued evolution in the VPP business model.
Jen Downing: People misunderstand the word virtual to mean not real, when these are hard assets on the grid. It’s not phone calls anymore, it’s software integrations and it’s large aggregations of small resources that really add up to something very valuable.
Stephen Lacey: This is The Carbon Copy. I’m Stephen Lacey. This week a conversation with Jen Downing of the Department of Energy on the different ways that virtual power plants are getting built and the need to build way, way more. To understand the potential benefits of virtual power plants, it’s helpful to compare them with the status quo. So to frame out our conversation, Jen and I walked through two different scenarios for utilities that are facing new loads, maybe from a lot of EVs or a data center or new manufacturing plants. And we started with an example of a vertically integrated utility that owns power plants, poles and wires. And this utility decides that it will meet the new demands on the system the same way it always does with a peaking power plant that burns fossil gas.
Jen Downing: So I think the traditional approach is let’s add peaking capacity. They’re going to need the transmission and distribution line capacity and all of the distribution equipment, substations, feeders, transformers, et cetera to handle that new peak. And that’s a lot of investment, and a timeline associated with procuring all of that equipment and citing it and installing it as well. That also means that if you are serving higher peaks without doing anything to smooth that load, if you look at the average utilization of your asset base, that peaker plant may turn on for 5%, maybe 10% of hours of the year, and you’re increasing the capacity of your transmission distribution lines to serve that higher peak. But then on average across the year, they’re running at maybe 20, 25% utilization rates. It’s really inefficient. We’ve spent a trillion dollars or so roughly, rounding that number to build and maintain the grid that we have. In any other context, any other industry we would want to maximize uptime of that machine. Why do we think about our grid any differently?
Stephen Lacey: What’s the second utility doing that is investing in distributed power plants or virtual power plants? Walk me through that potential scenario.
Jen Downing: Sure. So a utility who wants to explore the potential for a virtual power plant to serve that increase in demand, they would take a look at the distributed energy resources, the DERs that are already on their grid and they might also forecast adoption rates. And what that looks like is taking a look at your commercial industrial base, who has flexible load. That’s pretty well understood kind of sector by sector. You would look at EV adoption rates, you’d look at rooftop solar, the DOE National Labs have tools to allow you to forecast adoption rates and understand what types of assets are on the grid.
And they would look at what kind of capacity can I get from these distributed resources? And then they would consider, okay, well how am I going to orchestrate that? So utility could do what National Grid and Eversource are doing in New England and through their connected solutions program, and this is what’s known as a Bring Your own device program, they say, “Hey, as long as you have this set of brands of smart thermostat or of water heater or of battery, you can enroll in our program and we’ll pay you for shaving peak.” And through connected solutions, those utilities have access to megawatts of capacity that help them shave peak so that they are less reliant. In this case, it would be on ISO New England’s energy markets on peaker plants.
Stephen Lacey: And then what are the costs and reliability outcomes for these different scenarios?
Jen Downing: The utility choosing the peaker plant invests in the concrete and steel in the ground. And they are investing in the transmission lines and they’re paying for the poles and wires. They are paying for natural gas fuel every time they need to burn it. On the other hand, the utility who is choosing the virtual power plant, it could be 60% cheaper overall. This is based on a BRATTLE study that was done. Great study by the way. And I think what’s striking is the savings potential for a utility procuring peaking capacity from a VPP can be 60% cheaper than procuring it from a natural gas peaker plant.
But what’s even more striking is that the money that is spent on virtual power plants, the majority of those costs are actually participant incentives. So yes, you need the implementation costs, the design, there’s a lot of software implementation involved, the integration of different IT systems, but the majority of the cost if you look at that cost bar is in paying either on a per kilowatt-hour basis or a per kilowatt of capacity basis, paying consumers and compensating them for contributing a little bit of the flexible capacity of their devices to this clean grid resource.
Stephen Lacey: I want to get into the different flavors of virtual power plants in the US. And in your Liftoff report, the Department of Energy does take a broad view of what a VPP is. And so can we walk through some of the different types of VPPs around the country and how they speak to the reason why you took this broad approach to defining the market? I’d love to understand the different categories of VPP that you’re seeing being built right now.
Jen Downing: Of course. I like to say that the term VPP is kind of like the term sandwich. There are lots of different kinds. They’re full of different ingredients and they serve lots of different purposes. So I’ll walk through a couple examples. And there is, as you mentioned, lots of variation in virtual power plants. You could slice and dice the categories in lots of different ways. I think the easiest way to understand it is slicing to the categories by types of DERs. So a few examples: you have solar and storage virtual power plants, clean energy generation along with storage on a distributed basis. A good example of this would be Sunrun, and they participate in many different ways across the country in different markets with utilities, but they were the first to bid VPP capacity into a wholesale market. They bid capacity into ISO New England in 2019, and then delivered that energy in 2022.
So good example of solar plus storage, virtual power plant selling into the wholesale market. Another example would be pure storage VPPs. Examples here would be Swell has a battery VPP in Hawaii that’s made up of thousands of behind-the-meter batteries. They integrate with Hawaii Electric to orchestrate battery cycling on almost a daily basis. They charge when the sun is up, they dispatch during peak evening hours, and they also provide fast frequency response and that really supports Hawaiian Electric’s operations overall. Another example of a pure battery VPP is what Green Mountain Power is doing with their batteries, where they have chosen to offer batteries to their customers at a low cost instead of procuring that capacity from peaker plants. And Green Mountain power has saved millions of dollars and provided backup power for their customers while increasing the resilience of their grid.
Another type of example of VPP is managed EV charging. So essentially the VPP provider reschedules the charging of your EV to smooth that load over time. So an example of this here might be Weavegrid is a VPP that provides managed EV charging programs. They’re working with utilities like PG&E in California, Salt River Project to help reduce strain on their distribution systems and smooth that load. Other examples that are more traditional would be commercial and industrial flexible demand. VPPs like C Power, Voltis, Autogrid, Virtual Peaker. They are orchestrating flexible demand for peak shifting. And then you have smart thermostat programs. Lots of hardware players are getting involved here like Google Nest or EcoB. And then water heaters as well.
Stephen Lacey: So if we take this broad definition of VPPs that DOE has outlined, which is an aggregation of these distributed resources, which includes, as you have said, solar, behind-the-meter batteries, electric vehicles and chargers, water heaters, smart buildings controls, CNI loads, and you’re orchestrating all these DERs together, what kind of capacity do we have in this country?
Jen Downing: Depending on how you define it, we have about 30 to 60 gigawatts of capacity in VPPs today.
Stephen Lacey: Why that wide variation? That’s huge. What changes in definition brings you from 30 to 60 gigawatts?
Jen Downing: Well, we took a look at numbers across utilities and their demand response programs. That was around between 25 and 30 gigawatts. We also looked at demand response operating in wholesale markets, and that was also around 25 to 30 gigawatts. And we know that there’s a bit of double counting there. At the same time, it doesn’t capture everything, because if you have these ongoing flexibility programs that aren’t categorized as DER, we knew that the data wasn’t capturing everything. So 30 to 60 gigawatts was our best estimate.
Stephen Lacey: And how much do we actually need to meet the expected load growth that’s coming?
Jen Downing: Well, we have the need to serve 200 gigawatts of new peak demand between now and 2030. And at the same time, we have an incredible amount of DER capacity coming online. And I can put some numbers to that in a second. What that adds up to is an enormous opportunity for that DER capacity to be aggregated into VPPs to serve that peak demand. Now, we’re not saying we’re going to get every last smart thermostat, every last battery, right? But if we can triple the capacity of VPPs between now and 2030, we could serve 10 to 20% of peak load nationally through virtual power plants. And if we did that, because they are a lower cost solution, we’d be saving about $10 billion per year.
Stephen Lacey: Okay, so then do we actually have the distributed energy resource capacity to support all that?
Jen Downing: We will. We are about to experience a tsunami of DER adoption across the United States. And the way we think about that is across three different categories of DERs: those that generate electricity, so think rooftop solar or fuel-based generators. DERs that consume electricity at flexible times, so think EV chargers or commercial industrial loads, or electric water heaters. And then DERs that store electricity, so behind-the-meter batteries or even EVs. With these DERs, we are experiencing a higher and higher capacity addition every year. So with DERs that generate electricity, we’re getting about 20 gigawatts added to the grid each year. In 2025, that’s going to increase to about 35 gigawatts added to the grid by 2030. And that’s nameplate right? If you look at flexible demand of electricity, we’re adding about four to six gigawatts of flexible demand to the grid each year in the form of smart thermostats, water heaters and commercial and industrial load.
Now roughly four to six gigawatts of flexible demand is the equivalent of about 50 peakers worth of flexible supply per year added. And then you have about five to 15 growing to about 25 gigawatt hours of behind-the-meter battery capacity added to the grid each year between now and 2030. Now, those are enormous numbers, but they pale in comparison when you take a look at the capacity coming online in the form of EV chargers and EV batteries. So between now and 2030, we’re adding roughly 20 to 90 gigawatts of charger demand per year. And on the battery capacity side, we’re adding hundreds of gigawatt hours of capacity. Now to be clear, not every car is plugged in all the time, and when they are plugged in, they’re not always charging, and not all of that charging is flexible to be shifted over time, right?
You stop at a Tesla supercharger on a road trip, you’re not going to want to wait an hour because there’s a grid event. But even if a fraction of that capacity is available to virtual power plants, that’s an enormous amount of capacity that could be used to make the grid more efficient.
Stephen Lacey: I want to talk about how these services are going to be controlled and bid into the market, but I’m kind of interested generally about the utility landscape. If we’ve got all these DERs coming online and we’ve got all this potential to serve this load more efficiently, if we go back to the tale of two utilities that we outlined in the beginning of this conversation, certainly there are utilities that are sort of thinking about procurement, they’re building pilots, they’re learning from those pilots, but there are a ton that if you look at their procurement plans, they just want to build a bunch of new gas plants. And I’m curious if you can characterize the industry broadly, how much of the industry is thinking about VPPs and its future procurements and how many of them are just ignoring it?
Jen Downing: Definitely a spectrum. We have somewhere around 5,000 different utilities or load-serving entities across the United States, and some are more forward-thinking, sophisticated, others, as you mentioned, want to stick to traditional tools in their toolkit. I’ll mention a couple examples of the forward thinkers, and this isn’t a DOE endorsement. This isn’t things I’ve picked up in our LPO pipeline, but it’s just through my conversations with utilities in writing the Liftoff report have seen a lot of great leadership across the country. So different forward-thinking utilities are taking different approaches to implementing VPPs, and you’re seeing a lot of different partnerships and different business models.
You might have a utility who wants to procure VPP capacity in a similar way that they would procure peaking capacity from a peaker plant. And so sometimes this is referred to as a turnkey VPP where utility issues an RFP that says, “Hey, give me this many megawatts it needs to deliver on these hours of the day.” And then it’s up to a provider to find that load on the grid or work with customers who want to adopt distributed energy resources and give them the incentives to do so.
You have other utilities who are building programs in-house, where they are signing up the customers themselves. They may be working with their state energy offices who are giving incentives for adopting clean devices. I think what’s happening in Massachusetts is actually a really interesting example. I’ll name names here, and this isn’t a DOE endorsement, but you have National Grid, a big investor-owned utility. They’ve built their connected solutions, VPP, which is a bring-your-own-device program. The Massachusetts government offers customers discounts or cheap financing for things like smart water heaters and batteries, that can then enroll in the connected solutions program. And then you have the Massachusetts regulator, the DPU, running what they call their Clean Peak program that offers compensation for shaving peak.
And they have a distribution circuit multiplier, where if you use DERs on constrained circuits to shave that peak, you get double the compensation. So there, you’re actually getting the locational value of the DER on the grid, in addition to the bulk power system value of avoiding peakers, Massachusetts having clean energy goals that helps them reduce emissions. And the utilities, their role is to actually orchestrate the VPP in line with how they’re operating the grid itself.
Stephen Lacey: Let’s talk about the point of control for these virtual power plants. Will there be one dominant point of control? And I’m thinking about two different scenarios; one where the utility controls the devices and the others is the aggregators are bidding these assets together and then bidding them into wholesale markets when eventual rules come together in wholesale markets, do you see either of those points of control dominating in the future?
Jen Downing: It is interesting. The way that I think about the dichotomy that you set up is will VPs sell to utilities? If I am Voltis, C Power, Virtual Peaker, Swell, is my best bet to write a bilateral contract with a utility or is my best bet to bid into a wholesale market that has implemented for a quarter 2222? I think when you have virtual power plants bidding into wholesale markets and earning a price that represents the value to the bulk power system, it’s an incomplete price, because it’s not taking account of the value to the distribution grid. And when you have a utility contracting with a virtual power plant, a distribution utility, they can take into account what the value is of deferring investment in a substation, because they can flex the demand behind that substation. And so you’re getting not only the avoided peaking power cost at the wholesale level, you’re also getting the value of deferring an investment in your distribution grid.
So I think when it comes to where virtual power plants will succeed in the market, right now you have participation in wholesale markets because as a straightforward way to bid into basically an auction, and it’s a bit more cumbersome to write a bilateral agreement utility by utility, when we have thousands across the country. But that’s where the real value lies. And so I think what you’ll end up seeing is utilities recognizing the value that they can get out of these VPPs, and procuring VPPs directly. Now, will the utility be hitting the button on every individual battery? I don’t think it’s in their core competency to be optimizing around customer experience.
They want utility scale resources. And so you’ll see utilities contracting with these platform players, who have lots of experience managing heterogeneous portfolios of assets, almost like playing Tetris, with flexible loads of different shapes and sizes and fitting them all together into one brick that a utility can choose, just in the same way that utilities traders would choose a utility scale asset.
Stephen Lacey: So the simple answer is it depends. And you mentioned, which is obviously the case when something this nuanced and complicated, you did mention FERC order 2222, which is really important here. All the way back in 2020, FERC issued this order, and it basically said that regional grid operators need to be able to create rules that allow distributed resources. All the stuff we’ve been talking about can bid into these wholesale markets and it’s up to the independent system operators to implement. And so that could help VPP providers offer these services on a regional level, but the ISOs have been slow in creating the rules of engagement here. So I’m just curious where we are regionally with adoption of FERC Order 2222, and what are the consequences if it’s really slow to roll out? I mean, some are delaying and saying it’s really complicated, and then if we do get it right and we start to see the rules come together, what’s the upside if they meet the order?
Jen Downing: Yeah, I think at the very basic fundamentals, when you’re allowing VPPs to participate in your markets, you have more supply. So that’s supply of capacity where you have capacity markets, it’s supply of energy, it’s supply of ancillary services. And that will bring down prices for any given level of demand. That’s why given the capacity of DERs coming online in the upcoming decade, given the capabilities that VPPs have to orchestrate that into reliable resources, the Order 2222 promises to bring that capacity to bulk power systems to increase the reliability and resource adequacy of the grid.
Now, different ISOs and RTOs are writing different rules and implementing that order on different timelines, and they’ve cited various challenges that are region specific, right? You have MISO saying that they have multi-year timelines for the IT systems that need to be upgraded to implement this. You have New York ISO saying, we don’t have the staff capacity to register large numbers of very small DER, so we’re setting a minimum size there.
And those challenges, it’s going to take region specific-resources and solutions to overcome those barriers. But it’s very much a live conversation. As of October, you had FERC going to MISO saying, “Hey, sharpen your pencils on your target implementation date.” And I think we’re still waiting on news for revisions to their plans. One thing I would like to see is more inclusive, but also more consistent rules across ISOs and RTOs. I mean, it’s pie in the sky and they all manage their markets differently. But I was talking to one VPP provider who said, “I have 16 different programs across the country and I can’t staff my program managers across them because they are so different.”
Stephen Lacey: So where do you think all the innovations in this industry are going to come from? Are they going to be largely technical? Are they going to be regulatory and enabling a lot of the bidding of these projects? Will they be around customer acquisition and enrollment? Where do you see the most innovations happening right now?
Jen Downing: It really is coming from all angles. I think what’s right in front of us from DOE’s perspective is the regulatory innovation. And I’ll say a bit more about that, but I think what I’m most excited about is what’s a little bit further afield from DOE is the consumer experience. So on the regulatory side, there is a long list of improved regulatory measures that we’re seeing, utility regulators in particular, adopt. So right now, a minority of states are doing integrated distribution system planning where they’re taking a look at what capacity they have on their distribution systems in relation to the bulk power system needs. But more and more states are adopting that.
They’re doing more DER adoption to understand those potential resources. You also have performance-based regulation or performance-based rate-making where commissions are realizing that the utility business model of compensating CapEx spending with maybe a 7 to 9% margin and passing through OPEX at cost to the consumer does not give utilities the right incentives to choose low cost options such as VPPs. And so you have innovation happening within commissions who are really better aligning utility financial incentives with what is optimal for the system.
But when it comes to other innovations that are really going to transform this market, you have to look at what’s happening among consumers. The VPP companies who are enrolling these customers are optimizing consumer experience. So this is just frictionless for them. And I think what I’m really excited about is for customers to, in a very low effort way, start to optimize when their car charges or when their water heater heats back up the hot water after they take a shower, or thinking about batteries for backup power instead of a generator, because with a simple app on their phone, they are notified of all of the savings that the VPP company has achieved for them, and that’s great, and it offsets the upfront purchase price. I think that consumers will be interacting with their energy usage in new ways that saves them money, decarbonizes the grid and makes the entire system more efficient.
Stephen Lacey: And so the big question is what does commercial liftoff look like? If we look out to 2030, what is a healthy thriving VPP market in your view?
Jen Downing: Well, it definitely means more capacity. I do think we have the potential to manage 20% of peak demand with VPPs. And so what that megawatt or gigawatt number looks like for every individual utility is going to be different based on their needs, based on the DER capacity. But I think qualitatively what commercial liftoff looks like for VPPs is one, it’s accessible for all communities, not just EV owners and rooftop solar owners, but anyone with a water heater or electric heat and a smart thermostat can be participating in these programs because they are so widely implemented by utilities.
Now, what does that mean? On the utility side? It means that utilities are looking at VPPs on the same menu of options when they are looking at investing in distribution system upgrades, investing in peaking capacity, building a new transmission line, they’re always taking a look at what they can be doing on the demand flexibility side. And then you have to go upstream of utilities to what’s happening on the regulatory side where you have the right planning requirements in place. You have the right financial incentives for utilities. And what all that adds up to is electrification progressing and increasing without delay while we decarbonize the grid and use the existing assets on the grid more efficiently and take advantage of the resources that consumers are already spending on.
Stephen Lacey: Jen Downing, engagement officer at the DOE Loan Programs office and VPP aficionado, thank you so much for breaking this all down for us.
Jen Downing: Thank you so much, Stephen. It’s such an exciting time to be working in clean energy, but in particular, it’s an exciting time to be working in VPPs. So I hope I got your listeners excited as well.
Stephen Lacey: That’s going to do it for the show. The Carbon Copy is a production of Latitude Media. It’s produced and written by me. And Sean Marquand is our technical director. He mixes the show and wrote our theme song. Go to latitudemedia.com. You will find a transcript of this show and all our back catalog episodes, show notes with links, and you can just get all our stories that inform our coverage. We’ve got a ton of stuff going up every single day, and you can send up for our newsletter to get it compiled in your email box.
We’re supported by Prelude Ventures. Prelude backs visionaries accelerating climate innovation that will reshape the global economy. Learn more about their portfolio and investment strategy at preludeventures.com, and spread the word about the show. Anywhere you spread the word about things. Whatever social media that you’re using. We’re active on LinkedIn and X, and I know people are moving over to Blue Sky and wherever you are having conversations, we would love to be a part of it. We will catch you next week. Thanks for being here. I’m Stephen Lacey. This is The Carbon Copy.
