Here’s the dream: millions of controllable devices—from EV chargers to thermostats, fridges, and batteries—working together to inject power back into the grid. They reduce load when there’s not enough electricity supply to meet demand. They ease transmission congestion and maintain grid frequency. And these devices, collectively called distributed energy resources or DERs, are all controlled remotely by grid operators.
So how far are we from this dream?
In this episode, Shayle talks to Mathew Sachs, senior vice president for strategic planning and business development at CPower, a company that aggregates DERs and sells DER services to the grid. They talk about where we are on the long and winding path to large-scale deployment of DERs and what it takes to monetize them. They dig in on:
- EV chargers, the fastest growing category of DERs, as well as V1G and V2G
- How much easier it is to share your financial data with a credit check than to share your energy data with a DER aggregator
- How current rules create obstacles to monetizing DERs
- Federal Energy Regulatory Commission (FERC) Order 2222 and the status of new DER rules in NYISO and CAISO
- Positive developments like the declining costs of DERs and rising watts per customer acquired
Recommended Resources:
- Canary: FERC Order 2222: Experts offer cheers and jeers for first round of filings
- Canary: Is ‘vehicle-to-everything’ charging ready for prime time?
- Catalyst: Tapping the gold mine of consumer energy data
Full Transcript:
Shayle Kann
This week, come along with me on a journey to monetize and distribute energy resources. I’m Shayle Kahn. I’m a partner at the venture capital firm Energy Impact Partners. Welcome. Picture this: tens of millions of controllable electric devices distributed in the world amongst homes, businesses, and industries all being operated in concert to relieve stress on the grid, complement the growth of intermittent renewables and reduce the need for new peak electricity generating capacity. You’ve probably heard that vision before because we’ve been talking about it for over a decade. I would say it’s the dream of the Distributed Flexible Grid enabled by aggregation and monetization of fleets of DERs, batteries, EV chargers, thermostats, controllable load and much, much more. So is it still a dream? Or is it actually becoming reality? Honestly, I think it’s kind of hard to tell. It’s happening for sure, but in pockets. Is it held back by market structure and regulation, by pricing, by the rollout of the distributed energy resources themselves, by the unit economics or the business models? I think the answer is probably yes. But better than my thoughts are those of my old friend Mathew Sachs who has been monetizing aggregated distributed energy resources since at least 2015. He is today the SVP of strategic planning and business development at CPower, which is one of the largest DER aggregators in the country. So let’s hear what he has to say about it. Here’s Mathew. Mathew, welcome to Catalyst.
Mathew Sachs
Thank you. It’s great to be here.
Shayle Kann
It is great to have you and to talk about distributed energy resources. I don’t want to spend too much time on this but I do think it is important because people use this term DERs to mean lots of different things and depending on the context, that can have an impact on what we’re actually talking about. So when you think of distributed energy resources, how do you define them?
Mathew Sachs
Yeah, I think that’s a great point of clarification, Shayle. And when we say DERs or distributed energy resources, what we’re really referring to is anything that stores, consumes, or generates electricity, that’s located in the distribution grid and be can respond to a signal. So a battery is a great example. But also your refrigerator. If that refrigerator is, let’s call it tech-enabled enough to respond to us it.
Shayle Kann
Got it. So it’s an expansive definition here – anything that can respond to a signal. I also want to delineate between or figure out what the relationship is between DERs that are active on the grid and the concept of demand response, which has been around longer, I think, than at least the term DERs, but there’s a fair amount of overlap between the two. So do you distinguish between those two things? Or do you think of them as being one is like a market mechanism to enable the other?
Mathew Sachs
Yeah, I think it’s important to distinguish. Personally, I probably didn’t historically, but when I joined CPower about four years ago, I found it really important to distinguish because demand response means a lot of different things to people. To many people demand response means seasonal peaks or running, controlling demand to avoid seasonal peaks, and really capacity product but what it means to me is really modulating demand to provide any type of grid service, whether that be a capacity and energy or an ancillary product. And in fact, we’ve gone and started calling it DER monetization, A) to avoid that confusion, but B) also because we’re starting to see opportunities for the DERs to inject into the grid if if they do have that ability, which is going past where I would classically define demand response.
Shayle Kann
So the way that I think about it, you can tell me if this aligns: DERs are the resources themselves, right? These are the things that you can control in response to a signal as you said. Demand response is a market function. There are various versions of it, obviously, but it is a way to sometimes leverage DERs and sometimes not, right? I mean just turning off your system – like the original version of demand response was basically going to industrial customers and saying, shut down now, when we have a system peak. You’re not really leveraging DERs to do that, right? It’s pretty manual. But it’s a market mechanism into which DERs can participate, sometimes.
Mathew Sachs
Yeah, I certainly agree with that. I think demand response has evolved in itself, or DER monetization has evolved over time from where it started off historically with a more manual process, where we add manual controls, maybe phone banks and things. There’s some truth to those stories that are probably lodged in many people’s heads. But it has since become very automated, where really every single CPower sends out is an automated signal, and what I would argue is it’s quickly moving towards optimized or optimization, where it’s looking at what product could make the most value for the grid and for the customer at any specific time. So that’s really where the communications and controls have evolved. There’s been a bunch of other evolutions, I would say, on the regulatory side. Regulators used to be fairly skeptical, then we got to FERC 745, where demand response was firmly accepted by FERC as a resource, but we’ve even moved past that to where it’s been encouraged with orders, like FERC 2222. The DER types that have participated, classically they were industrial loads, maybe HVAC, then they really expanded to DG, things like energy storage, microgrids, even EVs, now certainly thermostats. So we’re seeing a lot of a different parts. And maybe the most important evolution is what it’s used for, what problem is it solving in the grid. Originally, as I mentioned earlier, it was really used to reduce seasonal peaks. And now we’re seeing it used really to provide a full spectrum of flexibility services, things to firm renewables to respond to more frequent grid disruptions, or really it is the new “clean peaker.”
Shayle Kann
Alright, so I want to dig into a few of the things you mentioned there, certainly some of the regulatory stuff and all the different types of resources that are providing grid services at the moment. But I think maybe one thing that’s useful to walk through to start is the vertical stack of DER monetization. As it stands today, you can imagine on one end of this stack there’s a device, it could be as you said, a refrigerator, could be a battery behind the meter, could be some industrial load, but there’s some controllable load. On the other end of the stack is whoever operates the grid. And we should talk about this: in some markets that’s an ISO, an independent system operator, in other markets, that is a utility. But there’s somebody who’s responsible for maintaining supply and demand balance on the grid. And then there’s a bunch of stuff in between that I think is complicated and depends on the situation. So how do you think about layering the stack, from bottom to top of an aggregated DER monetization?
Mathew Sachs
I think it’s probably a great place to get grounded here. It’s more than a stack. I kind of think of it as a sandwich, as you’ve alluded to. On one side, you have the customer, the home or the business that adopts DERs, and devices, assets, and let’s just call them suppliers of flexibility. On the other side, you have the grid that needs flexibility. And we could certainly unpack that a little bit. But those are buyers of flexibility, and how are they connected? Some customers are big enough, understand markets well enough and really active enough to go out there and just connect themselves, right. So they take their own DERs and connect grid, but that’s, that’s really the exception. More often, there’s a middle ecosystem inside that sandwich and that’s really chiefly what’s often called aggregators or sometimes CSPs. And here the aggregator has a few advantages or services that it provides the customer in the grid. The first of those is it spreads the fixed costs, call it regulatory technology, M&V expertise and compliance over a greater base, so it just becomes more economical. The second is on the portfolio side. Certainly having, if you have one resource connected to the grid, there’s a ton of performance risk. But if you have 17,000 resources connected to the grid, there’s some mitigation of that risk of performance. The last, and this is something that CPower has really been doing over the last five or six years and I think more and more of the industry will get here is this aggregation of small pieces that include small pieces of load and DERs that can participate on its own, but assembling them in a way that together these pieces could comply with a program’s regulations or rules and requirements, say. Taking a very simple example is taking summer-heavy thermostats in say PJM, combining it with excess winter industrial load in PJM and making a full seasonal product to participate in their capacity market.
Shayle Kann
One of the things that has always occurred to me as I spend time in DER aggregation worlds is just how many layers there can be in that stack, or I guess, fillings in the sandwich perhaps, if you’d prefer. Sometimes it can be very simple, as you said, like some large industrial customers are just sophisticated enough to do it on their own. But the other end of the spectrum I feel like is – so thermostats, that’s a good example. So there’s a thermostat in somebody’s home, somebody needs to control that thermostat in response to a grid signal. So there’s some measure of control that somebody needs to exert other than the homeowner, because they’re not going to do it. So you can aggregate up a full home load with a bunch of different things where you can aggregate up a bunch of thermostats across a bunch of different homes or some combination of those two things, and exert a bunch of control. But as you said, there’s other things that need to be done, too. There’s M&V, measurement and verification, there’s the grid access level, and that’s sort of interfacing with either the utility or with a wholesale market and getting qualified to participate in all those things and then monetizing it. And so in some of these cases, I’ve found you can have multiple intermediaries between the load – the customer – and the grid. And one of the challenges with that I’ve always thought is just the economics are not that rich, like the amount of economic value you can extract from a thermostat in response to grid signals, is not nothing, but it’s not enough to allow for, you know, three different intermediaries to take a slice of the pie. So I guess one thing I’m curious about is do you think that it should be? Do you think that this should be a really streamlined market? Where there’s a customer with a DER? There’s somebody in between interfacing with the grid, and then there’s the grid? And if so, how do we get to that point?
Mathew Sachs
Well, maybe just to start first, I think you’re right, particularly with really small quote unquote pixels like resi. From our experience, we are not really the aggregator there. We provide market access and we work with resi aggregators. And there’s also often a software layer in between that may or may not be owned by that resi regulator. So it does get complex. Where I’m not sure I degree is on the cost side, and is there enough to go around. And I think that’s been true historically. I think it depends market-to-market right now of where we are, but starting to see those value streams emerge. And what we’re really seeing happen is thermostats are a great example. If a utility wanted to do a resi Demand Response Program 15-20 years ago, they would drive a truck to your house, put in some little box that has some type of communications packet and really use a switch for your HVAC system. I don’t know what it costs. But let’s say it costs $1,000 to roll a truck. Now they take a smart thermostat that costs, I don’t know wholesale 50 bucks, maybe 100 bucks, put it in a box and send it to you for $5.99. So their cost went down 80-90% to dod that install, and that’s making it lower. And that’s the install cost. But now if you look at the actual customer acquisition costs, we’re seeing resi loads more and more controllable as resi loads. It’s not just a thermostat, it could be an EV, it could be a refrigerator like we said. Basically everything could be enabled and controlled. Some may not be economical to do everything, but some may not have the flexibility from the demand side but something like a refrigerator certainly does. And certainly an EV and certainly a water heater and certainly the thermostat. So as you put that all together, what does that mean? You’re getting more watts per customer acquired. So now your your kind of acquisition costs go down and you put that together and you could start seeing it become competitive with where C&I demand response has been over the last 5-10 years. The one thing I would add to that is resi demand response doesn’t really compete with C&I demand response because if you take the duck curve in California, when does it start? 4, 5, 6 o’clock – all pretty big C&I load pockets. But when does it end? Say 9 o’clock, somewhere around there. By then a lot of that C&I load has dissipated, at least in many regions and zones. So where does it go though? It goes home. So I think there’s a big value-add. We could leave it to grid operators, and some do put this together themselves and run a resi program in C&I. And that’s great. But a lot of struggled with that, especially as that time has changed. So I think by putting that resi and C&I load, they naturally complement each other. And you get that whole area under the curve, whether it’s a duck curve or whatever shape it might take. Did that make sense to you?
Shayle Kann
Yeah, totally. I think that’s a good point, the difference between when resi load typically peaks, as you said later in the evening, and when C&I load peaks, which is earlier, in the day, or in the afternoon, and so if you combine them, it’s similar to also what you just said before about PJM and different loads. The more you have diversity of load, and load types, the more able you should be, at least in theory, to mix and match them and control them all differently. That’s been the promise, since day one of excitement around DER aggregation, and the challenge has never really been does this make sense? Is this a good idea? It’s always been a good idea. It’s always made sense. The challenge has been implementation, and there’s just been a million – it’s like death by 1000 cuts that have made this challenging, right? Who is the aggregator? What is the customer experience? What is the market mechanism? As you said, is there actually a mechanism to sort of trade between resi load and C&I load in any given market? And so I think what we’ve been, you know, as the market has evolved over the past decade, or whatever it has been, there’s always been this dream of what ultimately is like a fairly open, fairly free market that allows lots of innovation at various different scales and with various different resources. But nothing is that simple in the electricity market ever. So I’m curious where you think we are on that journey, like relative to when you started doing this are things simpler now? In order to monetize DERs, are they more complex or has it not changed at all?
Mathew Sachs
I’d say it’s slightly simpler, but probably not moving quite fast enough. Luckily, I believe in exponential change. So we’ll speed up on the back end. But it’s not really a technology challenge. We have technology, we talked a little bit about pairing different loads and putting them together. What we haven’t talked about is we do a lot of site level optimization with the larger clients that really allow a battery or microgrid to, or even load that’s controlled, to find the most optimal way to be dispatched hour by hour. So that might be going to a grid, or it might be a bill saving kind of mechanism, like a demand charge management or time-of-use. So this is not a technology problem, which I think is where it’s often confused. Maybe it’s a scale problem as you develop technology. You know, it’s expensive if you don’t have scale. But as scale comes that technology is a fixed costs. But really at CPower, we’re not seeing that, we have the technology to do what we need and can certainly develop more as it evolves. Where I do think there’s issues is on the data side. There’s a lot of redundant costs there. Where we have to often put in our own meter, even when there’s AMI deployed. And that’s always bugged me, right, and so that’s why you can’t just buy more AMI units be ZigBee enabled or whatever kind of network that they’re using to allow us to get that real-time data and save that truck roll to there. And that’s particularly important for resi where it’s just never paid to go out there and get that real-time data. Because if it’s not you’re flying blind. You’re basically getting data the next day, which doesn’t help with real-time programs. I think on the data part, there’s also just the letter of authorization or gaining customer approval. It’s kind of an old process. You know, for many utilities, you still need a wet signature, or certainly a signature that’s returned back to the utility. If I want to go get a mortgage or apply for some type of credit, I check a box on the screen and it’s approved. I mean, I think everyone has their own view on things but I’m going to be much more concerned with my financial data getting out there that’s in a credit check, than how I use my electricity. Not that it’s not private, but why can’t we digitize it like the financial industry has and why do we have to spend so much time going back and forth? So there’s a lot of costs to come out there. You know, this is probably the biggest barrier here is coordination and kind of put this on the market structure side. And let me riff here for a second. But the distribution grid, where all these DERs are located, has really been designed to operate in a static condition, typically peak load. So for example, if you want to interconnect a battery, or solar power, or whatever to the utility today, they’re going to look at the worst hour or when the most demand was on that line of the entire year and tell you if you’re allowed to inject or not based on that. And that could just be one hour or two or three out of 8760 in a year. And that’s very limited. Utilities need to and I would argue, in many cases, at least from my discussions, want to move to a dynamic model where they can operate in and assets can inject if it’s feasible at that instant, not if based on the most used hour of any day or year. And this requires a lot of alignment between the utilities, the regulators, the DER community, ISOs and RTOs, that they operate within. And this is and has taken a long time. And it’s a little scary, I mean, putting a lot of our goals for flexibility and be able to do this clean aside for a second. But customers are adopting DERs regardless of all this. And without this coordination is going to become really scary for grid operators to operate with all this unpredictable load behind the meter. We’ve had FERC 2222, I think it’s a big step here. And it’s brought all the parties together to have some of the more difficult discussions and they’re ongoing. But even as this passes, and each ISO comes up with their plan, it’s going to take a while for utilities to and their regulators to evolve. And you know, which is going to limit the amount of injection, you could get out of DERs in the term. Maybe if there’s a silver lining here, and it’s probably demand response, because demand response is modulating load, there is no injection for that. And that’s really where we’ve where we think is going to kind of be the right on ramp if that’s the right word to kind of build this and that’s why demand response is and will be for the immediate future to largest DER, but don’t sleep on the batteries and microgrids and other assets that can inject, as I think we’re going to see a lot more of that.
Shayle Kann
So I want to talk more about that FERC Order 2222 in a minute. But first, maybe just repeat back to you in simple terms what it sounds like you’re describing. So current state of affairs is you say I want to interconnect this thing to the grid, the utility says, Okay, let me look at what is probably going to be the worst, most difficult hour of the year. And if you’re likely going to tip us over the edge where we might have an outage as a result of your thing, then even one hour a year, then you can’t interconnect you can’t interconnect without a distribution grid upgrade. There’s good reason behind that, right. You know, utilities are incentivized toward reliability above all else, or above almost all else. So it makes sense that they look at it that way. But what you’re saying is what’s not taken into account, is the possibility that some of the things on that distribution line could actually serve to alleviate the stress at those peak hours. And so in that distribution planning, or in that interconnection process, the utility was saying, Well actually, there’s a bunch of behind-the-meter batteries on this same network we could dispatch into the grid, and we have confidence that we could do so at those same hours, then maybe it’s actually okay to plug in that EV charger, you know, two houses down the road or whatever it’s going to be, but it requires the utility or the grid operator to have that level of certainty that they have visibility into the resources and that they can dispatch them when they need to.
Mathew Sachs
I’d say right, and that level of certainty comes from that coordination between the different stakeholders, namely the customer, the utility and the ISOs.
Shayle Kann
Right. Okay, so let’s talk about FERC 2222. So this was when it happened – So FERC regulates all of the organized wholesale electricity markets in the United States. I think something like 70% of customers in the US are in ISOs and RTOs. Some are not, there are some vertically integrated. Somebody will tell me whether that number is right or wrong, but it’s a recollection from an echo from a decade ago, when I actually knew the number. Anyway, the point being it represents a big chunk of the country that FERC regulates. And there was this watershed Order 2222, which if I can summarize and you tell me if this is right, the order originally basically said all ISOs and RTOs, every organized wholesale market, must introduce rules to allow aggregations of distributed energy resources to participate, because prior to that, some had and some hadn’t. The rules were murky, sometimes qualification was uncertain. And so this was basically saying, Nope, this is a class of resource, it has the right to participate in the market, now go off and define the rules for it to do so. Do I have the gist of it about right?
Mathew Sachs
Yeah, you definitely have the gist right. I would just add that they are allowed to compensate. They are allowed to participate and then be compensated in kind as other generators in layman’s terms.
Shayle Kann
Right. Okay. And so it was this big, big deal. At the same time, a lot of people were saying, “Well, let’s be clear, this is the start of what is going to be probably a long journey to implement,” to do the rulemaking processes, and so on. So we are more than five years hence, from the order itself? What has happened since then?
Mathew Sachs
Well, a lot has happened, and certainly we’re encouraged by the progress. But I still do think it’s going to take some time to see the full effect and considerably more time. But maybe just to come back to what it is, the two core innovations here. The first is to allow heterogeneous aggregations, so I don’t need to put a bunch of batteries together and sell that as a resource. I could put a battery and a thermostat and some load together. If I could put it together for the right program’s requirements. So that’s great. And that’s big. And then maybe in the longer run, we’re talking it will allow for DERs to inject again or not again, but allow DERs to inject it. And I think that’s going to prove super important as we talked a little bit about. But as you said, devil is in the details, what’s taking so long? So maybe a quick update here. All six ISO and RTO proposals have been filed with FERC. Two have been approved. That’s New York, ISO and Cal ISO. The other four are pending and with Glick having held his last session late last year, we’re hopeful the FERC Commission can continue to make progress, but what’s holding it up. There’s really an assortment of issues here that that we’re hoping that FERC will come and ultimately decide in favor of DERs and we think it makes sense. But things like MISO wants to delay implementation till 2029. That’s a pretty long time sitting in even 2023 and they asked last year. Another big issue that FERC and the sector are sorting through is some ISOs RTOs are asking for nodal aggregations. So this nodal aggregation is a pretty small pixel to aggregate around and this removes many of the benefits of aggregations, and also seems to fly in the face of the original order’s call for I believe it was the “broadest possible aggregation.” So if you have to aggregate in your house, you’re not going to get a lot of benefit from that aggregation. Of course, the nodes a little bigger, but not that much bigger. Just to maybe clarify that. So the more the more resources you can aggregate and then bid in as a single entity, or the more diversity of resources, as we’ve talked about, that you can aggregate basically, the more value you can accrue, as opposed to if you have to bid in as an individual thermostat or an individual home or, you know, take it up a few levels from that even so, the the trade off is at what level is an aggregation, basically a single resource that can be treated as such on the grid. And if it’s too small a granule, if the aggregation has to be too narrow, then those resources just aren’t going to have as much value. Yes, spot on. That’s it. Maybe just to complete the thought here. We talked about the four that haven’t been approved, but Cal ISO and New York ISO both had been approved. They are still working through implementation. These are the very nuanced stuff like telemetry or another type of very nuanced tech requirements. But we expect that to progress. If you’re a betting person, I would say New York will likely lead in megawatts initially, and this is more because New York has assets participating in programs that will be directly transferred in, namely their DCS or their ancillary services markets. And California doesn’t have a lot of, if any, behind the meter DERs participating in its its ancillary services or similar markets. So I think it will take a little while to ramp up megawatts.
Shayle Kann
Can you talk about the resources themselves and how they’ve evolved from from a megawatt perspective? I mean, as you said, one of the things that has happened over the years and this was always the promise as well is that customers are going to start adopting more different kinds of DERs not because they can be aggregated and monetized in the grid, but because they want them for other reasons. And then they happen to be able to be monetized on the grid. Is it now a much more even split across a wide variety of resources that are actually participating today? Or is it still predominantly, you know, the old school C&I industrial load? And now we’ve got little pockets where stuff like thermostats and EV chargers and microgrids are participating?
Mathew Sachs
Well, it’s a good question. Maybe to start with, I think it’s, the vast majority of participation is load. Is it the old school industrial load or some new, more automated load is, I think, where you probably seen the biggest transition, or the biggest megawatt, where things like building automation systems have enabled you to really run those buildings almost as if they were batteries, or maybe that’s a poor analogy, but run them as a resource and run them automatedly or in many cases, customers don’t want us to have direct control. So we send a request, and they have to click OK, or, Yes, this is acceptable. But those are the two more automated ways. Is there some industrial processes out there that they shut down? Yeah, at some price, it makes sense for a steel plant to send home a shift, right. But that’s, especially with today’s pricing and productivity, that doesn’t happen that often. You should think of those types of assets as good for one, two, maybe three dispatches a year, where we have some programs that are dispatching 60 times a year. Just to circle back on the other side of that device and asset side of that equation. Still small from our standpoint, where I’d say just around a sixth of our portfolio is these assets. So it’s grown a lot from over the last three, four or five years. And those are typically machine to machine controlled and allowed for us to control them all immediately, completely automated Lee. But that’s also one of the quickest growing parts of our portfolio, which is why I want to kind of highlight that and includes backup Gen, and micro grids and batteries, and thermostats and all that stuff. But I think if you looked forward five to ten years, you might start to see that that split start to break down, although going back to what I said before, I think until we really work out this injection piece that demand response, classic demand response by a meter is going to be a bigger DER than the others from a grid resource side just because you won’t get the benefits of injection quite yet.
Shayle Kann
Speaking of injection, I want to talk about electric vehicles for a minute, because that is maybe the the clearest coming wave of potential DER resources, or I should say electric vehicle chargers rather than the vehicles themselves act as the connection to the grid, if not the resource itself. And the interesting thing about EVs is they are similar to a battery in some ways. They can act as demand response, they can act as control and that means demand response in the sense of a peak event, you can automatically shut off an EV that is charging or shut off a charge or the discharging. They can act as controllable load by shifting the time at which the charging occurs. And they can in theory, act as injection, as you says bidirectional and inject from the EV battery directly into the grid. There are terms for all this: V1G being the controllable stuff, the 2G being the injectable stuff. I guess my two-part question here is one, how much of that are you seeing already today with the EVs that are showing up on the grid? And second, how do you think about the future there particularly with regard to V2G, injecting into the grid, people have strong opinions about it.
Mathew Sachs
Let’s start with maybe V1G. It’s happening today. We’re doing it. Where we have particularly been successful has been in around fleets, particularly school bus fleets. And we’re pretty optimistic that that will continue to grow quickly. But maybe just to frame the problem is you have these EVs come out there, they take more load to charge. And you kind of have two effects here. The first is a rising tide lifts all ships. So whatever balancing services we need, we just need more because we have more load. The second part is the cul de sac problem, where I get an EV, and you get an EV and we both install chargers, and we’re living on the same cul de sac. It works for one of us, but not both of us. And that’s where you see this V1G are managed charging, come back in that says, we could both draw, you know, we could take turns or we could both charge and 50% or something along those lines. And that’s happening. That’s really most of what we’ve done. Even on the fleet level with the school buses I mentioned right now, and I think that’s a big part. And people sometimes kind of roll their eyes as I go “it’s just V1G it’s old.” Maybe, and I’m not saying it’s putting the next man on the moon here. But what it is, is it’s solving the problem that EVs create by using EVs to solve it. So we could take a lot of EVs, we could fit a lot more EVs if we just get V1G right. And it’s happening now we’re doing it. Others are doing it and you know, and I’m pretty bullish on V1G. Go to the second part of your question V2G. Yeah, they’re mobile batteries. And I do see that feature and I do think there’s value there. There’s a ton of problems and challenges to work through right now from manufacturer warranties that could be voided to the same dynamic versus static grid that we have with a battery here. But all in all, I do think it makes sense. V1G will help EVs solve the problem that EVs create. V2G will help EVs create an additional value that will work to replace – as we retire dirtier peakers these will help relieve that burden and create new clean peaking flexibility sources. To put some numbers on that, we believe that grid services will more than triple by 2030 to well north of 100 gigawatts in North America, or really the US.
Shayle Kann
That is not specifically for EVs. You’re just saying grid services from DERs in total?
Mathew Sachs
Yes, we believe grid services in total will triple and get to around 100 gigawatts. And we expect by 2030, that EVs will make up somewhere between a fifth and a quarter to that contribution. So it’s a lot of growth. It’s really the second largest kind of growth that we’ll see then, after C&I building curtailment, which still we starting from a much larger number.
Shayle Kann
That’s interesting. I mean, to contextualize that, I guess, as you said before, so Cpower’s portfolio currently, about a sixth of it, I think you said is, is aggregation of a smaller behind the meter resources as opposed to the bigger historical, industrial and commercial loads. So it’s taken however many years to get to a sixth there, and what you’re saying is over probably roughly the equivalent number of years looking forward by 2030 or so, EVs will reach something like 20 to 25% more than a sixth, right? So the pace of growth of EVs is a grid resource you’re saying will be faster than the pace of growth of all these other things: thermostats, behind the meter batteries, microgrids over the past seven years.
Mathew Sachs
That’s correct. And I’d put batteries right behind EVs, and but we’re still seeing these things get deployed. Battery numbers are a little closer in my head but right now, I don’t believe there’s a market or in the US market, meaning an ISO RTO, that has over a gigawatt hour of batteries installed behind the meter at C&I locations. I think if you looked, there’s three or four markets that are going to and that are projected to install over a gigawatt hour over the next in five years. So and several of those are many of those markets will tap break that gigawatt hour, so yeah, the they haven’t been deployed yet, right? They’re still coming. I mean, they have been deployed, but it’s a bit of the law of small numbers. If you have like one battery and have two and then four, it’s go. But now we’re going to get to the other side of the exponential growth. We’re, I think, you know, partially spurred on by the IRA and maybe accelerated by the IRA, but we’re going to see some pretty big deployments there and the same things with EVs, whether it’s buses, or other kinds of commercial fleets or really personal vehicles.
Shayle Kann
It sounds like what you’re saying is that the exponential growth, it’s always been exponential growth but the curve has been, it’s been all this stuff has been growing. I would say, if I can editorialize, I would say that sort of DER aggregation has to date not lived up entirely to the promise of a decade ago, when people first got excited about it. Not to say it’s not happening. But if you had said a decade ago, when there was all this excitement around it, like, where are we going to be at 10 years from now, how much of the grid is going to be enabled by DER aggregations? I think we’re behind that metric but that might first of all just be the reality of how long market shifts take, and particularly regulatory shifts take in the electricity sector, but also that the adoption curve, like we’re hitting that inflection point now and so if you take a step back on the chart, and start to look at what the exponential growth curve looks like, over a longer period of time, maybe we’re just in that moment right now, where it starts bending upward fast.
Mathew Sachs
I think that’s right. Which DER have we seen really accelerate and grow exponentially? Solar. We do have some solar enrolled in our portfolio in what we would call a passive DER program. But that’s small and very limited to which markets you can even monetize that. I don’t want to say solar is not the best grid services asset because I do think the inverter could do things and we could get into some very interesting local controls. But that’s not the easiest one to make work. And I don’t think that’s the right way. I think a battery, conversely, is the ideal grid resource that can pretty much do everything. And as that grows, whether it’s through mobile batteries, like EVs or just stationary storage, we’re gonna see that take off.
Shayle Kann
All right. Well, then what we’ll do is we’ll have another conversation in, you know, a year or two and we’ll see what the slope of that curve looks like, at that time. Yes.
Mathew Sachs
Spot on. You know, and hopefully the markets also evaluate, right? We haven’t talked too much about that. But right now, it’s, it’s a little bit like Whack a Mole pricing out there, right, where because we’re working in kind of a regulatory scheme market design that was set up for Central Station assets, and kind of shoehorning all these distributed technologies into that, they’re not always ideal, and it’s not always clear where the next value is going to come from. So you could take like MISO capacity prices are up, but PJM is down. But PJM, you have ancillaries, like SR had a pretty good December as well as energy pricing has been off the chains. And that’s, you know, that’s why we’ve invested in technology to optimize because it’s very, very hard to see where that mole is going to pop his head right now. I think as that starts to stabilize and gets a little simpler and others gain entry, you’ll also see that drive in general, I think degrees will continue to value flexibility more, and as there’s more value on it I think that will come in. And maybe lastly, the other thing holding up that value driver is retirements right? How much coal has retired – a lot to be frank – but there’s a lot more to come out, to the tune of 50 gigawatts, I think through 2030 is what I read last.
Shayle Kann
All right, lots more to discuss here. But we will do it at another time. Mathew, thanks so much for joining.
Mathew Sachs
Thanks, Shayle.
Shayle Kann
Mathew Sachs is the Senior Vice President for Strategic Planning and Business Development at CPower. What questions do you have for the show? As always, it’s a great time to send in either thoughts, questions, ideas for we should cover. We welcome them as always. To send them in, just tag us on Twitter or LinkedIn with the hashtag askcatalyst that’s hashtag askcatalyst. Or you can send them to us directly by sending a voice memo or an email to catalyst at postscriptaudio.com. If you liked the show, as always go over to Spotify or Apple podcasts and leave us a rating and review, we do appreciate that. The show’s a co-production of Post Script Media and Canary Media. You can head over canarymedia.com for links to today’s topics. And as always, Post Script is supported by Prelude Ventures, a venture capital firm that partners with entrepreneurs to address climate change across a range of sectors, including advanced energy, food and agriculture, transportation, logistics, advanced materials and manufacturing and advanced computing.
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