Catalyst with Shayle Kann - The journey to monetizing DERs

Episode Date: January 26, 2023

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 Full transcript here 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 Catalyst is a co-production of Post Script Media and Canary Media. Catalyst is supported by Antenna Group. For 25 years, Antenna has partnered with leading clean-economy innovators to build their brands and accelerate business growth. If you're a startup, investor, enterprise, or innovation ecosystem that's creating positive change, Antenna is ready to power your impact. Visit antennagroup.com to learn more.

from the studios of PostScript Media and Canary Media. I'm Shail Khan, and this is Catalyst. If you want to interconnect a battery or a solar pile 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. That could just be one hour or two or three out of 8760 in a year,

and that's very limited. This week, come along with me on a journey to monetize some distributed energy resources. When utilities need flexible capacity they can count on, they turn to Energy Hub. Energy Hub works with more than 170 utilities, coordinating over 2.5 million devices to manage 3.4 gigawatts of flexibility, built for the moments when utilities can't afford uncertainty. Energy Hub builds and operates virtual power plants that utilities actually stake their grid planning on, coordinating EVs, batteries, thermostats, and more through a single platform built for utility scale. Predictive, verifiable, and designed to perform when it counts.

Learn more at energy hub.com. I'm Shale Khan. 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 Matthew Sacks, who's been monetizing aggregated distributed energy resources since at least 2015. He is today the SVP

of strategic planning and business development at Sea Power, which is one of the largest DER aggregators in the country. So let's hear what he has to say about it. Here's Matthew. Matthew, welcome to Catalyst. Thanks, Shale. It's great to be here. 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? Yeah, I think that's a great point of clarification, shale. And when we say DERs are distributed energy resources, what we're really referring to is anything that stores, consumes, or generates electricity that's A located in the distribution grid, and B 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 a signal.

Got it. So it's an expansive definition here, anything that can respond to a signal. I also want to maybe 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? Yeah, I think it's important to distinguish personally. I probably didn't historically,

but when I joined C-Power 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 a capacity product. But what it means to me is really modulating demand to provide any type of grid service, whether that be a capacity, energy, or an ancillary product. In fact, we have gone and started calling a DER monetization,

A, to avoid that confusion, but also because we're starting to see opportunities for DERs to inject into the grid if they do have that ability, which is going past where I would classically defined demand response. 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's various versions of it, obviously,

but it is a way to leverage, sometimes leverage DERs, and sometimes not, right? I mean, I guess just turning off your system. The original version of demand response was basically going to industrial customers and saying, like, 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. Yeah, I certainly agree with that. I think demand response has evolved in itself, or DER monetization has evolved over time, where it started off, you know, historically. really with a more manual process, right, where we had 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 signal C power 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 kind of evolutions. I would say on the regulatory side, regulators used to be fairly skeptical. Then we got to FERC 745, where it was demand response was firmly accepted by FERC as a resource.

We've kind of even moved past that to where it's being encouraged with orders like FERC 2222. The DR types that have participated, you know, classically they were industrial loads, maybe HVAC. They really expanded to DG, things like energy storage, microgrids, even EVs now, certainly thermostats. So we're seeing a lot of different parts. And maybe the most important evolution is what it's used for or what problem is it solving in the grid. Originally, I mentioned it 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 peter. All right, so I want to dig into a few of the things that 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, it could be a battery behind the meter, it could be some industrial load, but there's some controllable load.

On the other end of the stack is whoever operates the grid. So, and we should talk about this, in some markets, that's an ISO, an independent system operator, and 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 sort of complicated and depends on the situation. So how do you think about layering the stack from bottom to top of an aggregated DER monetization? Yeah, I think it's probably a great place to get grounded here.

More than a stack, I kind of think of it as a sandwich, as you kind of 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. So they take their own DERs and connect the grid. but that's really the exception. More often, there's kind of a middle ecosystem inside that sandwich, and that's really, chiefly, what's often called aggregators or sometimes CSPs. And here, you know, the aggregator has a few advantages or services, that it provides the customer and the grid. The first of those is it kind of spreads the fixed costs,

call it regulatory technology, M&V, expertise, and compliance over a greater kind of base. So it just becomes more economical. The second is on the portfolio side. Certainly 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 C-Power has really been doing over the last five or six years, and I think more and more in the industry will get here, is this aggregation of kind of small pieces,

that small pieces of load and DERs that couldn't participate on its own, but assembling them in a way that together these pieces could comply with a program's regulations, rules and requirements, say taking, you know, a very simple example is taking summer heavy thermostats and say PJM, combining it with excess winter industrial load in PJM and making a full seasonal product to participate in their capacity market. One of the things that has always occurred to me as I spent 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, you took it, 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, or 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 the economics are not that rich.

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 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? 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 later in between that may or may not be owned by that resi regulator. So it does get complex. Where I'm not sure I agree 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 we're starting to see those value streams emerge.

And what we're really seeing happen is a thermostat's 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 in and really is a switch for your HVAC system. I don't know what it costs, but let's say it cost $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 in a box and send it to you for $599. So their cost went down 80, 90% to do 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 you resi loads. It's not just a thermostat. It could be an EV, it could be your 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, you're basically, what does that mean?

You're getting more watts per customer acquired. So now your kind of acquisition costs go down, and you put that together, and you could start seeing it become competitive with where, say, C&I demand response has been over the last five, ten years. The one thing I would add to that is it doesn't really, Resi demand response doesn't really compete with C&I demand response because if you take the duct curve in California, when does it start? Four, five, six, all pretty big C&I load pockets, but when does it end, say nine o'clock, right? 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 this is something that I think is a big value add. We could leave it to grid operators, and some do put this together themselves and run a Resi program in a C&I, and that's great. But a lot have struggled with that, especially as that time has changed. So I think by putting that Resi and CNI load, they naturally complement each other, and you kind of 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?

Yeah, totally. I think that's a good point, the difference between when Rezi load typically peaks, as you said later in the evening, and when CNI 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. Like, the more you have a diversity of load and load types, the more able youth should be, at least in theory, to mix and match them and control them all different. I think the challenge we've always seen, like 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 have just been a million, it's like death by a thousand cuts that have made this challenging, right? The who is the aggregator? What is the customer experience? What is the market mechanism? sort of, as you said, is there actually a mechanism to sort of trade between resi load and see an eye 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? Has it not changed at all? 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. We talked, 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 that's 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, you know, it's a fixed cost.

But really, it's C-Power. 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, right? There's a lot of redundant costs there. where we have to often put in our own meter, even when there's an AMI deployed. And that's always bugged me, right?

And so that's, you know, why can't those AMI, more AMI units be kind of enabled, Zygmy 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 getting, 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 these basically gaining customer approval.

It's kind of an old process. For many utilities, you still need a wet signature, certainly a signature that's returned back to the utility. If I want to go, I don't know, get a mortgage or apply for some type of credit, I check a box on the screen and it's approved. And 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 cost to come out there. Maybe in a whole, you know, and this is probably the biggest barrier here is coordination.

I kind of put this on the market structure side. And let me riff here for a second, but the distribution grid that all these DRs are located in it has really been designed to operate at a static condition, you know, typically peak load. So, for example, if you want to interconnect a battery or a solar pile 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 limiting.

Utilities need to, and I would argue in many cases, at least from my discussion, want to move to our dynamic model where they can operate and assets can inject if it's feasible at that instant, not based on the most used hour of any day or year. And this requires, though, a lot of alignment between utilities, their regulators, the DR 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 DRs regardless of all this. And without this coordination, it's 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 and their regulators to evolve, 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 probably is 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, the largest D.R. 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. Virtual power plants are becoming a reliable way for utilities to manage capacity. But enrolling devices is just the start. What really matters is

confidence, knowing those resources will perform when dispatched and being able to prove it, from the control room to the living room. Energy Hub's platform handles the full picture, from near-real-time forecasting, locational dispatch, and the kind of rigorous verification that holds up when regulators, grid operators, or leadership ask, did it deliver? Easy enrollment creates momentum, proven performance builds trust. That's why more than 170 utilities rely on Energy Hub to manage over 2.5 million devices delivering 3.4 gigawatts of flexible capacity.

See what that looks like at energy hub.com. So I want to talk more about that fur quarter, 22, 22, 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 or you can't interconnect without a distribution grid upgrade. There's a good reason behind that, right? You know, utilities are sort of 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 if 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. 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. 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 U.S. or in ISOs and RTOs, some or not. There's 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 represents a big chunk of the country that FERC regulates.

And it 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, 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? 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 and kind of layman terms. 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, what, more than five years hence from the order itself. What has happened since then? Well, a lot has happened, maybe so. 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 on and considerably more time. But maybe just to come back to what it is, there's probably 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 to fail the program's requirements.

So that's great. And that's big. And then maybe in the longer run, it will allow for DRs to inject again, or not again, but allow DRs 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's in the details, what's taking so long, so maybe it's a quick update here. All six ISOs and RTO proposals have been filed with FERC. Two have approved, have been approved.

That's New York ISO and Cal ISO. The other four are pending. And, you know, with Glick having held his last session late last year, we're hopeful a 2-2-Ferk commission can continue to make progress. But what's holding it up? There's really an assortment of issues here that we're hoping that FERC will come and ultimately decide in favor of DRs and we think it makes sense. But things like MISO wants to delay implementation until 2029. That's a pretty long time sitting in even 2023 in the ASS last year. Another big kind of issue that the FERC in the sector is 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 kind of 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 and think about it, if you have to aggregate in your house, you're not going to get a lot of benefit from that aggregation. Of course, a node's a little bigger, but not that much bigger. Just to maybe clarify that. So 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 take it up a few levels from that even. So 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. Yeah, 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 have been approved. They are still working through implementation. These are kind of like the very nuanced stuff like telemetry and other 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 DSASP or their ancillary service markets. In California, it doesn't have a lot of, if any, behind the meter or DER is participating in its ancillary services or similar markets. So I think it'll take a little while to rent megawatts. Can we talk about the resources themselves and how they've evolved 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 CNI industrial load, and now we've got little pockets where stuff like thermostats and EV chargers and microgrids are participating. Yeah, well, it's a good question. Maybe to start with, I think 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've 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 automatically or in some cases, in many cases, customers don't want us to have direct control, so we send a request and they have to click okay, right? Yes, this is acceptable, but that's fairly, you know, those are kind of 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 a

a shift, right? But that's, you know, especially with today's pricing and productivity, that doesn't happen that often. You should think of those types of assets is 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 kind of the other side of that, the device and asset side of that equation, still small, you know, from our standpoint where we're, you know, I'd say just around a sixth of our portfolio is these assets. So it's grown a lot from over the, you know, over the last three, four, five years. And those are typically machine to machine controlled and allowed for us to, you know, control them automatically, completely automatically. But that's also one of the

quickest growing parts of our portfolio, which is why I want to kind of highlight that. And it includes backup gen and microgrids and batteries and thermostats and all that stuff. But I think if you looked forward five, ten years, you might start to see that split start to break down. Although kind of going back to what I said before, I think until we really work out this injection piece, that demand response, classic demand response behind the meter is going to be a bigger DR than the others from a grid restore sign just because you, you, you, you, you won't get the benefits of injection quite yet. Speaking of injection,

I want to talk about electric vehicles for a minute because that is, you know, maybe the clearest sort of coming wave of potential DER resources. I should say electric vehicle chargers rather than the vehicles themselves act as the actual, the connection to the grid,

if not the resource itself. And the interesting thing about EVs, sort of 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, in a peak event, you can automatically shut off an EV that is charging or shut off a charger that is charging. 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 the EV battery directly into the grid.

There's terms for all this, V1G being the controllable stuff, V2G being the injectable stuff. I guess my two-bar 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 V to G,

injecting into the grid, which is like a very, people have strong opinions about it? Yeah, well, let's start with maybe V1G. It's happening today. We're doing it. Where we've had particular, particularly, 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 kind of where I get an EV and you get an EV and we both install charges and we're living on the same cul-de-sac and it works for one of us but not

both of us and that's where you see this V-1G or managed charging come back in that says we could both draw, you know, we could take turns or we could both charge at 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 like, oh, 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.

Right, and it's happening now. We're doing it. Others are doing it, and I'm pretty bullish on V1G. To go to the second part of your question, V2G or can these in check, yeah, well, they're mobile batteries, right? And I do see that future, 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 I said that we have with. the 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 kind of work to replace as we retire dirtier peakers. These will help relieve that burden and create new, clean, peaking, flexibility sources. And to put some numbers on that in, you know, We believe that grid services will more than triple by 2030 to well north of 100 gigawatts in North America, really the U.S. This is not specifically for EVs. You're just saying grid services from DERs in total.

Yes, yeah, 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 than after C&I building curtailment, which still it's starting from a much larger number. That's interesting. I mean, to contextualize that, I guess, as you said before, so C-Powers portfolio currently about a sixth of it, I think you said, is the sort of smaller aggregation is a smaller

behind-the-meter resources as opposed to the bigger historical, industrial and commercial loads. So that's, you know, 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 percent more than a sixth, right? So the pace of growth of EVs as 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. That's correct, and I'd put batteries right behind EVs.

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 in the U.S., a market meeting 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 projected to install over a gigawatt hour, over the next in five years. And several of those markets will tap, break that gigawatt hour. So, yeah, 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, you have two, and then four. But now we're going to get to the other side of the exponential growth, where we're, I think, you know, partially spread on by the IRA, or maybe accelerated by the area, but we're going to see some pretty, big deployments there and same things with EVs, whether it's buses

or other kind of commercial fleets or really personal vehicles. Sounds like what you're saying is that the exponential growth, I mean, it's always been exponential growth, but the curve has been, all this stuff has been growing, but it is not, I would say, if I can editorialize,

I would say that sort of DER aggregation has to date not lived up entire 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. I think that's right. Which DR 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 DR program.

But that's small and very limited to which markets you could even monetize that. So solar is not, I don't want to say solar is not the best grid services, 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 could pretty much do everything.

And as that grows, whether it's through mobile batteries like EVs or just stationary storage, we're going to see that take off. All right. then what we'll do is we'll have another conversation in, you know, a year or two, and we'll see what that, what the slope of that curve looks like at that time. Yeah, spot on. You know, and hopefully the markets also value it, right? We haven't talked too much about that.

But right now, 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 of for central station assets and kind of shoehorning, all these distributed technologies into that. They're not always ideal, and they don't always see where the – 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 and has been off the chains. And that's, you know, that's why we've invested in technology to kind of optimize. because it's very, very hard to see where that mole's going to pop his head right now. I think as that starts to stabilize and gets a little simpler and others can entry, you'll also see that drive. And in general, I think the grids 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. something's at a tune of 50 gigawatts over the next, I think through 2030 is what I read last. All right, lots more to discuss here, but we will do it at another time. Matthew, thanks so much for joining. Yeah, thanks, Yel. Matthew Sacks is the Senior Vice President for Strategic Planning and Business Development at Sea Power. What questions do you have for the show, as always?

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