How Virtual Power Plants Could Strengthen the Electrical Grid

The U.S. electrical grid is under growing stress, raising concern that recent widescale power outages may signal more grid challenges to come.  In recent years, electricity demand has grown at an accelerating pace while, at the same time, power supply has tightened as existing power plants have retired and grid operators have struggled to bring new sources of power online.

Yet one promising solution to the grid’s challenges may already be in place, if grid operators and regulators can figure out how to use it to full advantage. ‘Virtual power plants’ can combine small, distributed energy resources such as rooftop solar and demand response into a single, virtual whole that grid operators can deploy like a traditional powerplant. VPPs hold the promise of delivering large amounts of readily available and reliable energy services, if a number of regulatory and technological challenges can be overcome.

On the podcast Ryan Hledik, a principal with electricity market consultancy The Brattle Group, explores the potential of virtual power plants. He explains how VPPs work, discusses hurdles to their development, and considers policy solutions to speed their growth.

Full Transcript

Andy Stone: Welcome to the Energy Policy Now podcast from the Kleinman Center for Energy Policy at the University of Pennsylvania. I’m Andy Stone.

The US electrical grid is under growing stress, raising concern that recent widescale power outages may be omens of more grid challenges to come. In recent years, electricity demand has grown at an accelerating pace, while at the same time, power supplies tightened, as existing power plants have retired and as grid operators have struggled to bring new sources of power online. Yet one promising solution to the grid’s challenges may already be in place, if grid operators and regulators can figure out how to use it to full advantage.

Virtual power plants can combine many small, distributed energy resources into a single virtual hole that grid operators can use like a traditional power plant. Virtual power plants hold the promise of delivering large amounts of readily available and reliable energy services, if a number of regulatory and technological challenges can be overcome.

On today’s podcast, we’re going to explore the potential of VPPs with Ryan Hledik. Ryan is a principal with electricity market consultancy The Brattle Group. He focuses on grid regulatory issues, and his work has been cited in federal and state regulatory decisions. He’ll explain how VPPs work, discuss hurdles to their development, and explore ways that policymakers might speed their growth. Ryan, welcome to the podcast.

Ryan Hedlik: Thanks for having me.

Stone: So could you start us out by defining for us what virtual power plants are and how they work?

Hedlik: Sure. And I guess I’ll start by saying, you know, this isn’t entirely a new concept. We’ve actually been doing something similar in North America for decades. What we used to do was called “demand response”. And there, typically the approach was as little as possible, to reach out and reduce customers’ peak demand at times when demand on the electricity grid was spiking and you needed to turn on every last megawatt in order to make sure that the lights were kept on. That was traditional demand response.

That has since evolved into something that we refer to as “demand flexibility”. And the idea there is to take the same approach, but to manage electricity demand on more of a 24/7 basis, to try and help to incorporate intermittent renewable generation into the power system. Virtual power plants are an evolution of this same concept. What’s really new and unique about virtual power plants is we now have customers who are not just consumers of electricity, but also generating their own electricity from rooftop solar panels, from behind the meter batteries, or even potentially from electric vehicles, and pushing those electrons back onto the grid.

So virtual power plants are really about taking all of these customer-sighted technologies, whether it is an EV, a battery, or managing a customer’s air conditioning load or their water heating usage, and doing that in a way that provides benefits to the power system.

Stone: So there are a range of resources that can be part of a VPP. There’s megawatts, which would be such as the power output of a solar panel or kilowatts, and then there are negative watts— for example, demand response, you just mentioned.

Hedlik: That’s right. It could be either. It’s both of those.

Stone: So what is the problem that VPPs can solve for us at this point in time with the electric grid?

Hedlik: There are lots. I tend to think of VPPs as a Swiss army knife. They’re well-suited to a variety of different grid needs. What I view as the biggest issue to be addressed right now in the near term, is something that you mentioned in your introductory comments. Which is, we’re currently in a situation where when we look out over the next five or ten years, the demand for electricity exceeds our ability to supply that demand. And what’s driving that in particular is new load, new demand for electricity, that’s coming from hyperscaler data centers, from converting building heating from being based on fossil fuels— natural gas— to being coming from electricity. Consumer adoption of electric vehicles are driving an increase in demand, and also onshoring manufacturing is driving demand as well.

So we need new resources that can help to keep up with this pretty rapid rise in demand growth and constraints on the availability of generation, supply equipment, interconnection delays associated with actually getting new power plants connected to the transmission system, and just more broadly, concerns about energy affordability are going to limit our ability to keep up with demand. At least from conventional resources. And so where I see virtual power plants really having an opportunity to step in is to bridge that gap and provide the capacity that we need to serve all of this new load.

Stone: And that’s because these resources are already connected to the distribution grid, at least at this point, right? They’re already there.

Hedlik: That’s exactly correct. Yeah. Customers are are going out and buying electric vehicles and smart thermostats not because they want to sign up for a virtual power plant program, but because they want an electric vehicle. Because they want to have a smart thermostat that looks cool on their wall and can be controlled from their phone. And so what virtual power plants allow us to do is to tap into this existing infrastructure, this existing asset base that’s already out there behind customer meters, and use that to provide services to the grid.

Stone: And again, that’s so important at this point because we’re having such difficulty bringing new resources on. Take advantage of what’s already there. One of the interesting aspects of these virtual power plants is they can actually participate, as you mentioned, as an aggregation of smaller resources acting as a larger power plant in competitive electricity markets. The wholesale markets. In 2020, the Federal Energy Regulatory Commission issued an order— 2222— to help these aggregations work in the wholesale markets. Can you tell us about the importance of that order?

Hedlik: Sure. And so FREC actually, prior to Order 2222, several years before that, had issued a couple of orders that were intended to open up the wholesale markets to what I was describing earlier as more traditional demand response, and create a level playing field for demand side resources in the wholesale market. What’s new about 2222 is FERC was really looking ahead and saying, “Okay. In the future, the demand side opportunity is not just about demand response, the megawatts. It’s potentially also going to be about customers who are now pushing electrons onto the grid and selling their own electrons into the wholesale market as aggregations.” So FERC, I think really wanted to get ahead of that and make sure that each of the system operators, or the wholesale market operators, were setting up rules that could accommodate that two way flow, the sale of electricity from consumers into the wholesale markets.

Stone: What is the potential of virtual power plants in terms of their size, in terms of the solution they can provide to the grid? Are they relatively small, or can they be a significant resource really solving our problems going forward?

Hedlik: They can be a very significant resource. You know, our estimate is that, depending on how you define it, there could be roughly 30 to 50 gigawatts of virtual power plants already existing in the US today. Mostly in the form of traditional demand response. But participation levels in these types of programs can be very large.

To give you an example, Xcel Energy, in the upper Midwestern US, has a residential air conditioning load control program where, when it’s needed, they’ll manage the air conditioning of participants in this program in order to provide extra capacity to their system. They’ve gotten to the point where more than half of eligible residential customers have voluntarily enrolled in this program. And the last I checked, it was producing over 500 megawatts of capacity for that one utility. And there are other examples where utilities have more than 10 percent of their peak demand under some type of control. So if the right ingredients are in place, this is a resource that can scale pretty significantly.

Stone: So there are a lot of tailwinds, and it sounds like there’s a lot of development of virtual power plants at this point, but I also understand that in many areas, they really haven’t gotten past the pilot phase. And there are a number of headwinds to their development that I want to talk about— and there’s quite a few here. But one of them is the fact that the virtual power plants can run against the grain of the traditional utility revenue structure, incentive structure. I wonder if you could talk about that.

Hedlik: And I think that has been, and I see it continuing to be, one of the biggest challenges or barriers to getting more traction with virtual power plants. And the issue there is, the way investor owned utilities are regulated in the US today, they earn a return on investments that they’re making, capital investments that they’re making in the power grid— whether that’s the distribution system, the transmission system, or in generation. They don’t earn the same return when they’re going out and paying their customers to use less of their product. That doesn’t mean that the benefits to the power system aren’t the same. And some of our research has shown that virtual power plans can provide the same degree of system reliability and resource adequacy that you can get from conventional resources. But the utilities don’t have the same financial incentive to go out and pursue these resources. So I think one of the really important aspects of the broader regulatory model that needs to be addressed is aligning the utility’s financial incentive with this opportunity.

Stone: Are there methods of doing that?

Hedlik: There are. There are a few different names for it. But one example is referred to as performance incentive mechanisms, where, for example, a state energy regulator could tell the utility, “If you reach x percent demand reduction by a certain date, you’ll get a boost in your earnings as as a result of achieving that target.” Or a regulator could tell a utility, “Conventionally, you’ve earned a return on capital expenses, but not operational expenses. When it comes to VPPs, we’re going to allow you to effectively earn a return on the operational expenses that you’re paying into that program,” since that tends to be the nature of a utility’s costs associated with virtual power plants. So there are different ways to structure it, but at the end of the day, the carrot that the the regulator is able to hold out for the utility are various earnings boosts that could be associated with success with a virtual power plant.

Stone: That are outside of building new infrastructure and outside of selling more electricity.

Hedlik: Exactly.

Stone: Another one of the issues is the technological complexity. So we’re talking about, with a virtual power plant, having many different technologies. You might have batteries, you might have solar. You have demand response. From my understanding, it can be complex to bring all those resources together to act as a single power plant. Technological issues. What are those about?

Hedlik: Yeah. There are some challenges there. There are a lot of companies that are out there working on this issue and creating software platforms that can orchestrate the management of these various technologies in a pretty coordinated way. I think one of the issues that we’re running into is there isn’t always an open standard that’s been adopted for communicating with each of the technologies. And sometimes that’s deliberate, because the manufacturer of these technologies is trying to make sure that the opportunity exists for them to be an important player in this space. Even if that means not making it easy for every company that’s out there to come in and communicate with their technology. So one of the the issues that needs to be addressed, and I don’t know if it’s so much of a technical issue as it is one of regulation and policy and financial incentives, is to make sure that standard, transparent communication protocols are being adopted broadly across the industry.

Stone: One of the other issues that comes to mind, particularly if we’re looking at the virtual power plants participating in the wholesale markets, are jurisdictional challenges. So a lot of these resources, be they demand response or rooftop solar, are part of the distribution grid and they’re under the purview of the state regulators. Whereas if you look at the wholesale markets, those are regulated at the federal level by the FERC. And there’s a prior order, I think that you’ve mentioned— Order 719 from the FERC, on demand response participation in the wholesale markets— that allows the states to have an opt out. Allows their resources not to participate if they say, “Our resources cannot participate in the wholesale market.” And there are a number of reasons behind that. But what are the reasons that a state might not want its resources to participate in the wholesale markets, and how can that be managed?

Hedlik: One of the challenges that’s raised sometimes— just to give kind of an extreme example— you could imagine a situation where in the wholesale market, in a given hour, there’s a significant need for capacity. And so distributed energy resources that are participating in the wholesale market might all receive a signal to discharge their energy to the grid to serve that wholesale market need. It could be the case that those resources are located in a clustered location of the distribution system, where if they’re all receiving the signal to discharge their energy at the same time, that could lead to overloading local circuits or transformers on the distribution system.

And so there’s a very significant coordination issue there that’s associated with not creating a new problem at one end of the system when you’re trying to solve a problem at another end of the system. I think that’s at least cited as a reason for potentially not allowing distributed energy resources to participate in wholesale markets. What is probably a more constructive solution to that problem is defining the participation rules in a way that ensures that while you’re providing one benefit, you are avoiding creating another problem elsewhere.

Stone: Well, there’s a related issue here. So, if you are the owner of an electric vehicle, you also want to make sure that if you’re involved in one of these programs, or enrolled in one of these virtual power plant programs, that your vehicle is going to be powered up and ready to go. We both have kids. Got to take kids to soccer practices. I assume you do as well. All these kinds of things. And you don’t want to get in the car knowing that you’ve got an hour-long ride coming up and the battery’s only 20 percent charged. What kind of safeguards or backstops are that prevent that?

Hedlik: It’s always the case that VPP programs are designed with that in mind. I think any utility, any VPP aggregator that has deployed one of these programs, has understood that we need to be able to get our kids to the soccer game on time. We need to be able to leave for work and have our cars charged in the morning when we want it. We probably have limits on the number of days per summer that we’re willing to allow our utility to mess with our smart thermostat.

So typically, these programs are designed with pretty strict limits on how often and when the program administrator is allowed to control whatever technology is sitting at the other end of the line. The other really important feature in a lot of these programs is, they usually allow participants to opt out of events. So if you know you’re going to be hosting a party tomorrow, and you don’t want to run the risk of that air conditioner being turned down right at the hottest point of the day, you have the ability to opt out of that the event. What we typically find is participants don’t use that option too often. But knowing that that option exists is enough to get customers over the hurdle of participating.

Stone: Let’s talk about the incentives for customers to participate as well. What is the incentive? What is the payment? How attractive is it to participate?

Hedlik: It really varies from one utility to the next, just depending on the economics of that utility’s system. Often the payment will be structured as an upfront payment. Either a discount on the technology that the customer needs to participate, or just an enrollment incentive to get the customer plugged into the program. And then in addition to that, there’s typically an ongoing incentive payment to keep customers engaged and participating in the program.

That’s one type of incentive structure. The other type of incentive structure is to put customers on a rate where the price of energy varies over the course of the day, and allow them to use their technologies to respond to that price signal in order to save money on their electricity bill.

Stone: Also, there is the assumption here that consumers, homeowners, are going to have the technologies in place to participate, right? So I would imagine at a minimum, you need a smart meter. Ideally, you might also need a smart thermostat, Internet of Things, connected washers and dryers and what have you, to actually respond to the signals from the market.

Hedlik: So some of the programs that target a specific technology, absolutely, that’s a prerequisite for enrolling, is that the customer would have that technology. Where I think rate design is interesting, is it does create an opportunity for any customer to save money, regardless of whether they have an electric vehicle or not.

One good example of this is, some utilities offer what’s referred to as a “peak time rebate”, where they might tell their customers, “Tomorrow is going to be a critical grid day. If you can reduce your usage between four and 8pm, we will pay you for what we estimate to be your usage reduction during those hours.” And it’s up to the customer to decide how to respond to that price signal. It could be through technology, or it could just be behavioral change to save a little money. And what’s really attractive about that approach is it creates an opportunity for all customers, not just the ones that have the technology.

Stone: That gets to another point. I would imagine there would be equity concerns around this as well, right? We think about people who may have the technologies in place to participate. Generally, think of a more economically well-to-do household versus another. How do we ensure that everyone gets to participate and enjoy the advantages that a VPP can provide?

Hedlik: Sure. In addition to the example that I just gave related to rate design that allows for behavioral response, there are two other thoughts, approaches, that come to mind. One is, we, in our research, find that is often the case that there may be enough cost savings associated with deploying the VPP program that not all of those cost savings need to be passed back to the participants in order to induce program participation. So what I mean by that is, there’s a portion of the cost savings that can be reserved as a benefit for all customers and lead to an overall rate reduction. So that’s one way of making sure that all customers benefit from these programs, and not only the customers who can afford a Tesla.

The other approaches we have seen where utilities have energy affordability goals, goals of creating opportunities for low income customers, that additional incentives can be provided for participation in these programs. And it’s actually the case that there have been a few utilities that literally have decided to, rather than providing a discounted battery to low income customers, have literally given that battery to the customers for free because it aligns with their energy affordability goals and is a cost-effective way of serving that customer’s energy needs, rather than making expensive investments in the distribution system.

Stone: So Ryan, for renewable energy, renewable portfolio standards have been a key driver of their growth. Can that structure also be used for VPPs?

Hedlik: The potential is there. There was actually some legislation that was considered in California earlier this year that would do exactly that, and basically would have required that utilities meet a certain portion of their peak demand from virtual power plants as it was defined in that legislation. That legislation wasn’t ultimately adopted, but I thought it was an interesting model to consider as we think about other state policies and how those might drive scale in virtual power plants.

Stone: At the federal level, are there any incentives that exist or are being considered to accelerate the growth of VPPs?

Hedlik: Yes. The IRA, actually has, has included incentives that reduce the price of adopting some of these technologies. And we’ve also seen that the Loan Programs Office that Jigar Shah is leading has been very proactive about trying to create opportunities to provide low interest loans to accelerate the development of VPPs.

Stone: I was reading lately about one of the potential barriers to investment in virtual power plants. These are residential consumers who will be involved as energy resources in the larger virtual power plant. And there’s the potential for these consumers to come and go. They sign up for the program, but then they leave. And that creates some uncertainty about the size of the resources that are available, and the business going forward. Is that a significant barrier to investment in VPPs?

Hedlik: I think it depends on the scale of the virtual power plant. It is true that any virtual power plant program is going to have some churn, right? Customers entering the program, customers leaving the program. But when the virtual power plant program has reached scale, then when you’re looking at its capability in the aggregate, you’re not going to see all of that noise, right? The law of averages means that it’s going to continue to appear as a significant resource on the system. And while that, to a degree, may be a risk, I also see that flexibility being a benefit of virtual power plants.

The reason for that is, you know, if you’re just making investment in a conventional power generation facility, once the steel is in the ground, that’s a 20- or 30- or 40-year investment that you’ve just committed to, and there’s no turning back on it. Whereas with a virtual power plant, you can grow the program as your demand growth materializes. And if that demand growth doesn’t materialize, you aren’t stuck with having overbuilt capacity for the next ten years. You can pump the brakes on growing your virtual power plant program, or even dial back the incentives to reduce the amount of money that you’re spending on capacity that you don’t necessarily need. So that option value, I think, is actually a really positive— hard to quantify, but positive benefit of virtual power plants

Stone: Are these virtual power plants expensive to set up? I mean, I’m thinking about them as basically a software solution. And obviously, you have to enroll customers. But what is the upfront expense to get these things rolling?

Hedlik: That’s right. There is the software that’s needed to connect to all these customer devices. Really, the largest cost in these programs is the incentive payment that’s going back to customers. And I actually think that’s a really powerful quality of virtual power plants, the fact that we’re paying customers to be part of the energy transition.

Stone: And that gets back to that churn question. If you obviously have economic incentive and see savings from this, then hopefully you’ll stay in.

Hedlik: Exactly.

Stone: Ryan, thanks very much for talking.

Hedlik: Thank you. I loved it.