Unlocking the full value of behind-the-meter battery programs

NOTE: This event has already taken place. See below for recording and event description.

Download the slides | Unlocking the full value of behind-the-meter battery programs (PDF)

Utilities across the U.S. and Canada are rapidly investing in behind-the-meter (BTM) batteries—but value stacking, customer expectations, and program design choices are getting more complex. The latest E Source research analyzes over 60 active programs to reveal what value streams utilities are using today, which are emerging, and how programs can evolve toward virtual power plant (VPP)–scale impact.

Why this topic matters now:

New technology, rising resilience needs, and increasing distributed energy resource (DER) penetration are reshaping the grid. Utilities are asking:

• Which battery value streams are viable today?
• How do we design programs that meet both customer and grid needs?
• What will it take to incorporate more advanced services that require technical or regulatory innovation?
• How do we prepare for future multiasset VPP opportunities?

This session provided the clarity and practice examples you need to move forward with confidence.

What we discussed:

• The real battery value streams utilities are using today. Understand why peak load reduction still leads, how resilience drives customer adoption, and where renewable energy optimization fits in.
• Lessons from leading programs. We’ll highlight insights from programs including ConnectedSolutions, Green Mountain Power, Xcel Energy, and Rock Mountain Power.
• How customer motivations should shape your design. We’ll share research showing why customers buy batteries and how to design programs that support customers and enable utility dispatch.
• Barriers limiting advanced value stacks. From data-sharing to device latency to DER penetration, we’ll break down what’s preventing broader value-stacking today and what’s needed for future VPP strategies.
• Trends impacting the market today. We’ll highlight market research on BTM installation trends, price trending, 2026 battery market expectations, and commercial and industrial options for battery programs.

Speakers:

Michael Hartnack, Senior Director, Customer Energy Solutions, E Source
Malcolm Hansell, Analyst, Customer Solutions, E Source
Bryan Jungers, Principal, Emerging Technologies & Innovation, Tucson Electric Power
Kristin Gaspar, Integrated System Planning, Xcel Energy

Transcript

This transcript was generated using AI.

Hey, everyone. Thanks for joining us today. We're gonna give ourselves about another minute or two for some more folks to trickle in, and then we'll get started.

All right, we'll give ourselves about another thirty seconds here as it's one minute after the hour. We have a bunch of stuff to get to today.

All right, well, the clock struck twelve zero two Mountain Time, so we're gonna go ahead and get started.

Thank you all again very much for joining us today. My name is Michael Hartnack, Senior Director of Customer Energy Solutions here at E Source. And I'm going to be guiding us through a conversation today with folks from both E Source and a couple of utilities to talk about battery value streams for your utility programs. I'm joined, as I said, by a couple of very smart folks here who you'll hear from as we go through the stuff over the course of the next hour. I did want to just call out my colleague, Ben Campbell, who's the manager of our battery research, won't be speaking on the webinar today, but he has contributed to a lot of the work that we've done in this space. So if you have any questions, if you have any questions or thoughts as we go through the directed event, feel free to go ahead and put them in the chat.

So, you know, this is a one hour long webinar, we've got a lot of content to share with you. We also have left time at the end for Q and A. So if you have questions as we go, go ahead and put them in the chat. We will do our best to address them either in an ongoing manner over the course of the hour by folks who may not be presenting actively, or we'll hold them for the end where we should have plenty of time for Q and A, ideally about fifteen to twenty minutes, depending on how quickly we get through the content here and how much we learn from the folks that are gonna be sharing.

Because of the way the platform is set up, there's no unmute feature for the folks here in the audience. So if you have a question, we go along, go ahead and put it in the chat. If you have a question at the end, as we're into the q and a session, you can definitely also go ahead and put it in the chat.

Really quick overview of what we're gonna be covering here today. I'm gonna be sharing a little bit about some of our US battery research, some market trends, some technology updates that are impacting the overall market. We're gonna hear from Malcolm, one of our analysts on the DER side to talk about some battery program research, battery value streams overview, and then we're gonna get into hearing from some of our utilities. Brian is gonna be talking from Tucson Electric Power, and Kristen will be sharing some of her experience and what they're doing over at Xcel Energy.

Without further ado, I can go ahead and get started. I'm seeing something about audio quality and there being an echo.

Anyone from the E Source side, are you hearing that?

I'm not hearing it, but it seems like a couple of folks are.

Let me Only two of them.

So if anybody else is hearing an echo, can you put it in the chat?

Okay, maybe it looks like you had two more.

I think let's just keep going maybe.

Okay, cool. Well, let's get started here. I always like to kick off a conversation like today by trying to make sure we all understand why we're here and talking about this. Why the interest in battery programs?

Why is this important? So some of you who have heard me present before, who have seen some of the research we've done in the battery space may be familiar with a slide like this or similar, but there are a couple of key market drivers right now in the market that are pushing utilities to leverage advanced load flexibility, technologies, programs specifically lead us to batteries as a potential solution. We're seeing a tremendous adoption in app based devices, right? Adding over a gigawatt of flexible load every month in the US, much of this is eligible like a battery would be for virtual power plant enrollment.

We're also seeing significant load growth. We'll get into data centers in just a few minutes, but the DOE estimates we'll need more than two hundred gigawatts of new capacity by two thousand thirty. As we retire traditional plants, we face connection delays, equipment the importance of customer site devices behind the meter growth is substantial. Right?

We're also in a scenario with an affordability crisis, rising costs, rate volatility, being pushed higher than ever. Our data suggests that one in six Americans is behind on their energy bills.

Regulators are coming to folks like you to ease the burden on their system and on their customers. We're also seeing an evolution in the market. Policy reforms like FERC two thousand two twenty two are now legitimizing aggregators.

While you see more states, more jurisdictions are reshaping rules for customer compensation for cost benefit assessments of things like battery programs.

So with all these trends converging, load flexibility options like battery storage are standing out as potential prime solutions.

I need the last sig of coffee here. Before I get into our battery technology and market update, I wanted to set the stage again before we get into more details on battery value streams. I wanted to dive a little bit into what we're seeing broadly or what we expect broadly in the battery market. A little bit about battery technologies, battery chemistries. You may think, well, I'm not concerned with what materials are inside my battery, but there are actually some pretty significant impacts of the battery chemistry on your utility programs and ultimately on the value the customers get.

So right here, you see a couple of charts, residential and C&I. I wanna start just by taking a look at the growth that we're expecting to see behind the meter. This is behind the meter centric, this is centric, this is an install.

These are our battery market forecasts. These are updated constantly and come to us as I mentioned, courtesy of Ben Campbell and the battery research team here at E Source. So thanks Ben for sharing this data with us.

We see similar shaped growth curve, not on the same scale for both C&I and residential battery installations, more on the residential side. Now the growth overall, we think is gonna be driven primarily by an improvement of customer economics and falling battery costs, combined with improved battery performance with things like increased cycle life and decreased per cycle cost. So diving in a little bit more on the residential side, we are expecting a slight slowdown in installs, as you can see here over the next eighteen months, which primarily will be driven by policy changes, specifically the expiration of the consumer tax credit.

This is similar to a trend we saw in the EV space. The looming incentive expiration pulls demand forward. Consumers are making early purchase decisions, including me. I bought an EV on like September twenty eighth of last year, aimed at capturing incentives, similar situation in the battery space.

But we are seeing new residential business models, right? Leasing, resiliency as a service, reliability as a service, capacity as a service, helping us sustain the kind of market growth that you see forecasted.

We're also seeing per battery capacity increase, right? So that is gonna compel more folks to go out there and get batteries to add to their homes, their businesses, and then ultimately enroll in your utility programs. So in light of the current policies, we still think we will see growth across both the residential and the C&I space. Now the C&I curve is a little bit different. It's a little bit of a different shape. It also is lower on a scale.

It's typically been a lot harder to capture new business for market growth in the C&I battery space. Right? These projects are large. They're very unique across projects. Right? Different load shapes, different electrical infrastructure, different operational constraints, which makes the projects harder to standardize.

Added to that, the C&I projects are a lot more expensive, so you've got a longer payback period and potentially on certain revenue streams, you see a little bit of a suppressed adoption from a total value perspective, but the curve is still shaped in an exponential growth curve.

So, a large portion of the reason why you see the growth curve shape the way it is, We're seeing more and more batteries, more and more customers deploy batteries to manage things like demand charges, To improve reliability and resiliency to hedge against volatile electricity prices. Those are all reasons why we still think the battery market for C&I is going to continue to increase alongside the same trends as on the residential side, declining battery costs, you know, installation process improvements, and then add in participation in the larger utility and wholesale market programs.

I think we'll continue to see the C&I growth that we have modeled out here over the course of the next decade or so.

Beyond the market factors, there's also some battery technology components that are driving the growth that we expect to see. Battery durability is improving, battery cycle life is improving. We think battery cycle life based on the technologies that we're looking at right now is gonna double over the course of the next decade or so. This is primarily due to new cell designs, new electrolyte formations, and different technology that's improving overall stability, and notably reducing cell degradation. As cycle life increases, the cost per cycle decreases. And that's important for your programs because the degradation every time you call in a customer's battery becomes a much smaller share of the batteries overall lifetime value.

So now you've got a couple of options, right? You could lower your incentive because you're actually costing the customer less on a per cycle basis, or keep the incentive the same and know that that customer is now able to get more value from their battery than they were when it was costing them more. So this is a dollar amount per cycle. This is modeled out across battery technologies, across battery manufacturers and OEMs.

And it's a really good indicator of really the upside of batteries as part of your programs. When you're looking to cycle these. Some utility programs are cycling batteries hundreds of times per year. This is when that starts to become really important.

So speaking of cost per cycle, that's not the only shift that we are seeing that's adopting or that is impacting battery adoption. There's also some impacts, some changes on the battery technology side, the battery chemistry side.

Unsurprisingly, we are seeing battery pricing fluctuate as we're navigating evolving policy, tariffs, supply chains, trends, and overall battery system prices changing. Generally, we've seen price trending downwards throughout twenty twenty five. But looking to twenty twenty six, we are seeing some market signals across the supply chain that may start to increase the price of both residential and C&I prices. That is largely driven by rising lithium prices.

You can see here the two different lines. Each line here shows the price of a battery cell from six months ago first today. You can see both the lithium ion cell types, which are the top two lines. You're looking at a substantial increase in the cost per kWH.

The third line, which is sodium ion cells, you can see that as the price of lithium cells grows, the sodium ion cells are now becoming more cost competitive than they have in the past. Now this is includes both total cost of ownership and upfront cost.

What's interesting about this is there are benefits. There's the cost effective benefits, but there's also safety performance benefits to sodium ion, that go above and beyond what you get from lithium ion. So now that it is becoming more cost competitive, we expect that there'll be more sodium ion batteries, in storage applications here in the US. So as you're looking to, this is probably more of a commercial industrial play with the different battery size or different battery chemistries.

But it's just interesting because you'll start to see batteries emerge with different strengths across different applications.

To dive just a little bit deeper, now this is a bigger picture, both a deeper dive and a bigger picture. It's kind of a modeled interpretation of some of the outcomes from the previous slide, which showed the difference in prices. This shows that we'll see growth in non lithium ion battery chemistries over the course of the next decade. So you can just see, we're starting to see the different market shares.

Lithium ion is improving in cost and performance, but safety regulations are tightening in some areas, which can make it fairly challenging to cite lithium ion based data battery storage projects in densely populated urban areas, which can often coincide with where you or your customers want the batteries the most. This does open the door for new emerging technologies like sodium ion. These batteries often offer superior safety profiles in lithium ion, things like flow batteries as well, we expect to gain an increase in market share.

So without further ado, just wanted to kind of, without further ado, I'll hand it over to Malcolm to talk about battery program value streams, but I wanted to talk a little bit about what we're expecting to see on the battery forecast side, the battery market, as we now will spend the rest of the time today diving into the battery programs and the value streams that you can hope to expect. So take it away, Malcolm.

Thanks, Michael. Yeah, always a pleasure to get to see some of our more technical research on here.

There's some good questions coming in the chat, so enjoying that as well. Keep it up.

I do want to start, if you could advance the slide by level setting a little bit on some benchmarking work we've done for program design for behind the meter batteries before we get too deep into the value streams weeds. So this is some figures from one of our recent reports, a catalog of battery programs that we've compiled through our databases.

I should quickly note that only active subscribers of our DER strategy service and battery next service will be able to click on this link as it's paywalled. But if you're interested in learning about this and other things that you can get through these services, please feel free to reach out to Ben, Michael, or I.

A couple of notes on these figures. The map is not exhaustive, but it is focused on utility customer programs that offer incentives.

And then, of course, when we think about demand response participation, most programs do require that. But just because programs don't mandate demand response participation doesn't necessarily mean that it isn't the primary focus of a given program.

Slide, please.

So when we think about the program landscape, of course, we have to start with the customer. Clearly, the residential sector is still getting the most attention, but commercial and industrial or dual focus programs are still a meaningful component.

Notably, while C&I enrollment can be an order of magnitude smaller in terms of the number of customers participating, aggregate total capacity for each category is typically quite similar, or it can be, as is the case for connected solutions, for example.

The reason for that, of course, is that C&I batteries tend to be much larger on average, and so you shouldn't overlook that as a customer segment for particularly bulk power service oriented use cases.

Slide, please.

Okay, so to get a touch more specific about actual program design features, we pulled together some quick hit, looks at key program design criteria that we've pulled from my database. So I just want to highlight a couple of these. Of course, if you have questions about any of them, please always feel free to drop them in the chat and we can go into more detail. But of course, event seasons is something where we're starting to see a little bit of movement.

Historically, these have almost always been summer only programs. That's when most utilities have their peak. But as we see increasing electrification, winter peaking, things of that nature, we are seeing some programs begin to add or increase their winter components. So that could either be offering a reduced incentive for performances program in the winter, as we see in certain states in the New England ISO market, or it could just be starting to offer a winter season at all.

And we expect in the future, we'll eventually see programs that are offering equal compensation for both event seasons. The other thing I want to call out on this slide really quickly is event length. So as we know, with all forms of DER programs and traditional demand response, event length can make a huge impact on customer perception and customer experience.

But there's also specific implications with batteries as it relates to program design and incentive design. So we'll talk about performance based programs more in a second. But when you have a program where the customer incentive is tied to specific delivered value changing the event length will influence their kilowatt contributions and therefore the incentive they receive, and so these things are interlocked and as we. Consider this holistically you have to make sure that your program event length is lined up with your incentive level if it's per kilowatt incentive based on the way that those are typically calculated.

Next slide, please.

So just to round out the program design overview, as I alluded to, incentive design is probably the most variable component that we see in these programs. So in the programs that we track, there's an average upfront rebate of close to three hundred dollars per kilowatt hour. That's based on several things. It's kind of hard to get an exact average because many of them have ranges, adder incentives, and some have base incentives only.

But this is sort of the ballpark figure that we see as of late twenty twenty five. On the flip side, the average performance incentive is close to two hundred dollars per kilowatt. So like I said, if you have a four hour program event, then versus a two hour program event that might influence the battery's discharge rate in kilowatts by half, right? And so that has a huge impact on customer economics and customer incentives.

So it's important to consider what is your grid need in terms of event length, If you should stagger these, call more specific vocational events. And then if you do that, what's the impact on customer economics?

Slide, please.

So just to consider this continue this conversation about the customer, right, and thinking about the customer, we wanted to include a quick snippet of our market research on DER customer adoption trends that can help make sense of where customers are at a national scale with this technology. We do also track this data at the state and more granular levels, but of course, and for Canada, but we're looking really just at the US at large here today. So you can see some year over year trends in the top. But the thing I really want to call out is that we can see that more than two times as many customers are not at all familiar with this technology than are familiar and not considering it.

So when you think about growing these programs and not only enrolling existing customers, but driving customers to adopt batteries, addressing the customer segment of folks who are not at all familiar with the technology may be a good way to support program growth, and at the same time, can position the utility as that trusted energy advisor.

Slide, please.

Okay, so to switch gears quickly to the main event, we should start looking a little bit at battery value streams, right? That's kind of the key for today, right? How are utilities justifying these investments, these programs, these incentives?

I should add, by the way, if there's questions about program design, please do feel free to put those in the chat, and I'll get to them after I hand things off to Brian. The purpose of this figure here is just to show that there are many, many possible value streams or theoretical value streams for behind the meter devices. And crucially, that includes a couple of important value streams that are not going to be easily accessible to centralized energy storage.

So solar optimization and some distribution grid benefits, you're not going to necessarily be able to capitalize on those opportunities with utility scale centralized storage. So as you move from front of the meter to behind the meter and increase that distribution and reduce the scale, you unlock new value streams, which can compensate for the reduced economies of scale.

Slide, please.

Okay, so I just threw a giant list of possible value streams at you, and we'll dive into them a little bit more specifically. So no need to have thought about all of those immediately, but it's important when we think about the world of theoretical possibilities that we could take advantage of, that these are not just a random grab bag of services that we can chase after. They're an ordered stack of prioritized energy services, just like a supply stack.

What we see is that peak load reduction, so energy and capacity value, is by far the most lucrative or valuable value stream in nearly all circumstances. And so that's the main goal of most programs we look at.

Still, many programs do also target secondary services. It's something batteries are particularly well suited to do, given their back charging to the grid nature. So those are commonly customer or grid resilience, solar optimization, as we'll hear about later, reducing congestion on transmission or distribution circuits, and occasionally other services as well. The other thing that we've included here too are qualitative benefits and future values.

So when we think holistically about a program, there is the value stack itself. But then there are things beyond the value stack, Customer experience, customer satisfaction, future value. So a program might have a present value stack, that's one thing. But when we consider five, ten, fifteen years down the line and things like IRPs, there might be additional benefits that we can capitalize on then from investments that we're making today.

So all of these things should be factored into our program design and decision making.

Next slide, please.

So beyond the theoretical, we've highlighted here the most common utility program specific value streams that we're seeing for biennium meter batteries.

So you can take a second and read these all. It's going to be nothing surprising, I would imagine, mostly peak load reduction. We do also see some other grid services, solar optimization, resilience, of course, that can be both for the customer or for the grid. And then environmental benefits is an interesting one.

But which value streams that your utility targets should be based on unique system value, right? So that could be grid resilience in Vermont. It could be power quality services in Utah. It could be environmental benefits in Massachusetts.

There's a lot of different ways that you can tailor these value stacks based on the specific context of your organization. And really, that's going to be the key to finding success here.

Like I said before, it should also be based on both present and future needs. Not all grids are going to be distribution constrained. And so maybe a locational add or incentive doesn't make sense for an organization in that situation.

Conversely, for places like Colorado or Arizona with high and increasing distributed solar penetration, maybe solar duck curve mitigation has higher future value and is worth pursuing.

So of course, this topic at large is a little bit too big to comprehensively cover today with the time that we have, but we would be happy to follow-up with any specific questions. You can always drop them in the chat, or you can reach out to any of the folks on the panel today, and we can continue the conversation.

Next slide, please.

There's one other important consideration when we think about designing these value stacks. So on the last slide, we looked at some of the things that you might consider including, but there's also the way in which we include them. So how can you actually stack these things? Some value streams are going to be mutually exclusive. It's more nuanced than that. But let's say, for example, if you need to discharge batteries to get one hundred percent of their energy arbitrage or peak load reduction value, that will conflict intrinsically with resilience value, which comes from not discharging batteries. Still, you can pursue both of those value streams, and we've seen many programs do it successfully.

But you have to use smart program design elements, such as reserve battery requirements and intelligently managing event days to avoid times when outages are likely. And so when we think about these things, it isn't to say that you can't or shouldn't pursue multiple value streams at the same time.

Really, what we're saying is that the program goals and design features have interdependence, and so we need to think about these things from a system perspective.

Slide, please.

Okay, so I want to quickly jump into one quick case study before turning things over to Brian. We'd like to highlight this case study that was shared at EASP National last year as one of the few published value stacks that targets multiple benefits and assesses the relative value, especially when we think about solar attachment, which is required for a few programs, but encouraged and not required for many others. And as we see transitions to net billing away from net metering, we may see higher solar attachment rates as well.

So we see overall net value is very high, which supports these assets in the investment. But that value is contingent on certain things, greenhouse gas value, certain things that may not be accessible to all jurisdictions or might be quantified differently. So a couple of things to look at in this data is that adding solar increases the system value by almost forty percent, And that doesn't factor in any changes to customer economics, which of course will also be largely changed by a paired system. The bulk of that increase comes from avoided energy and CO2 emissions.

So that'll depend, obviously, on your context, but it does bump the value in all categories. Really, the most instructive thing I think about this is to look at the overall value. The deferral value for transmission and distribution grids that they found was very low. Of course, this is a very small pilot. It's possible that with higher penetration rates, you might see something different or in a different grid context. But when we think about designing programs for a present day use case centered around locational services, I think it's important to consider, make sure that we're really quantifying the value that we're going to get from that before we get too deep into pursuing it.

So that's kind of our quick hits on that. With that being said, I'll turn things over to Brian. But please do feel free to drop any questions in the chat.

We're always happy to talk about this going forwards. Thanks.

Thanks, Malcolm.

Yeah, thank you, Malcolm. Hi, everyone. I'm Brian Jungers. I'm a principal on the Emerging technology and innovation team at Tucson Electric Power, and I'll talk a little bit about our battery journey as it has evolved over the last ten years or so.

To give you the obligatory service territory map, we have just under half a million customers in southern Arizona that we serve with infrastructure that spans the state of Arizona and New Mexico.

Our peak summer demand is about two and a half gigawatts that we set along with the other large utilities in Arizona last year, and our DSM portfolio has delivered about two thousand three hundred and seventy five gigawatt hours of savings, and that includes efficiency and demand response over the last twenty years since DSM rules were initiated in Arizona. To give you a flavor of what sorts of programs we offer, our biggest Flexload programs are Smart Rewards Thermostat Program, with over twenty thousand thermostats enrolled, upwards of thirty eight megawatt, kind of peak first hour, event performance, last year.

We've been running that program for, almost three years now, and what I'm gonna talk a bit more about is our battery program that we just launched last August, Still very new, and we're still in the middle of our first year running it, but we're already, pretty excited about some of the initial results, which I'll talk about on another slide, and we are also trying to launch a managed EV charging program this year after failing to launch last year.

Next slide, please. So just to give a sense of how we've come to where we are today, we started demonstrating and piloting distributed energy rE Source management systems and related technologies around twenty seventeen, we partnered with EPRI, the Electric Power Research Institute, we ran a demonstration where we were trying to manage lots of different types of end use devices, electric vehicles and chargers, solar inverters, heat pumps, water heaters, and distributed batteries, and what we found was that we were able to technically make it work, but, operationally, it was not feasible for us.

Too many communication drops, too many protocol and standards interoperability issues, it was pretty messy, and I think we came away from that project, which we call Project RAIN, with this feeling that we just weren't ready to deploy a DIRM system, and that we would focus perhaps on more grid scale storage. So go to the next slide.

We, I'd say since that time, have been much more focused on deploying utility scale storage. We have several large systems on our grid now that are providing benefit, I think it was a lot easier for our company to make that decision to invest in this infrastructure, it's capital, we can include it in the rate base, we can manage it ourselves every day, we get a lot of value from absorbing a lot of the solar, like you can see in this picture, we have a lot of solar on our system, we know how to operate these lithium based batteries and get the value out of them, and so it's something we were more comfortable with, but I would say after several years of making those investments, we're now turning back to take another look at distributed storage, how can we unlock more value for our customers, how can we use distributed batteries potentially to achieve some of our affordability goals, and how can we really meet our customers where they're at in terms of what they want from energy services and energies in their home and in their businesses.

So that's kind of what I'm going to talk about the rest of this presentation. Next slide, please.

One of the things that we're still trying to get full alignment on are exactly what the use cases are and, the applications that are most valuable for us from distributed storage systems. So whether that's meeting federal requirements as we move into a regional market next year with the markets plus in the Southwest Power Pool, which we are doing for the first time, and you know, potentially bidding into regional markets, whether it's, improving our our interconnection process and streamlining queue management for, solar and battery customers, or, if it's trying to get the most value from our demand response programs or to really try to orchestrate different rE Sources in as part of like a power plant, we are still uncovering those use cases and quantifying them and getting very clear across our company on what these are, but I'd say as our existing programs grow, it becomes more clear to us what we can achieve and what kind of value we can get. Go to the next slide please.

I'd like to spotlight the energy storage awards program I mentioned before. This program is really spearheaded, designed, stood up by my colleague Julie Donovan, it's managed by my colleague Gabby Abouzade, and we've really only kind of the first half of a one year implementation plan, we've run a summer season, we haven't finished running winter seasons, we don't have results, but for the summer, we had eight events that were called from August through end September. We had almost one hundred and fifty customers that were enrolled. We had very high participation rates on the order of about ninety four percent, and we got on the order of about one point three megawatts in our best event, so that's still pretty small, I mean that's too small for our operations folks to really get too excited or for our rE Source planning team to look at this and say that this is a real rE Source, but considering that we did this in a very short order and that we're getting very high per device KW dispatched, I think things are looking really promising and so some of the things we want to test are can we leverage this along with our thermostat program to manage snap back effects since that program is already rather large and those snap back effects are getting to be larger, as well.

So that's something we're hoping to test out, in the summer and into the future.

Next slide, please.

I also wanted to talk about something that's not exactly a battery program, but, it is a very interesting battery project on our distribution system. We are partnered with the city of Tucson to help them build a microgrid at a community center that has been designated at a as a resilience hub. You may or may not know we've been experiencing extreme heat down here in Tucson the last couple of weeks, the hottest days we've ever seen in March, and the summers get even hotter and they can be very prolonged. And so we have cooling centers, dozens of them scattered all throughout our communities, they help to provide cooling to folks that are unhoused or to folks that do not have cooling in their home or otherwise, just need to cool off, get water, get ice, and the heat of the summer coincides exactly with our storm season for monsoon, and so it's also the highest likelihood that we're going to experience an outage.

So what we're doing is deploying a battery, front of the meter to pair with solar that already exists behind the meter, we're going to use that as a resilience, rE Source as needed, if there is an outage, but the rest of the time when there isn't, an outage, which is most of the time, we're looking at how can we use this battery to provide grid services. We already understand the resilience value. We've got that well quantified. We understand kind of peak loads, solar absorption, and and kind of arbitrage value, but, what are the other values we could potentially unlock?

Go to the next slide, please.

Now this is trying to just illustrate. These are not real numbers, but based on the visibility that we have on the system today, which is essentially throughput of power at the substation and then metered power at the end use, at the community center, we're actually showing that there might be voltage problems caused by this microgrid if we can only look at it at that very high level. And so, you know, we have our investment amount, we have some arbitrage amount, and then we're not able to really see or quantify all the other theoretical values that exist, such as black start report, support frequency regulation, peak shaving, and so on. And so, because of the fact that we don't have sensors everywhere in the system, because of the fact that historically we've never tried to quantify, and account for these things, we're kind of left with a bit of a black box.

If you go to the next slide, what we're hoping to build oh, sorry, I guess I'll just say what we're hoping to build is a digital twin of the feeder that that microgrid sits on, and also deploy high, high fidelity sensors along the grid edge, pull that data back in, and actually quantify, what kinds of grid services that microgrid can provide. So, it's an exciting new project that we've just started working on, and I think this is the sort of thing that we need in order to verify that these stacked values actually exist on our system. Thank you, and I'll hand it over to Kristin.

Thanks, Brian.

Hey, good afternoon, everyone. My name is Kristin Gaspar and I'm with Xcel Energy. I work within our Integrated System Planning Department focused on non traditional solutions. So all opportunities and different ways of supporting the grid needs that are different from large scale generation.

But today I'll talk about our kind of behind the meter and distributed storage design and program offerings that we have going on today.

All right, so about NexLynergy quickly, we do serve eight states. We have about three point nine million electric customers, two point two million gas customers, quite a bit of connected DERs with one hundred and twenty five thousand installations, mostly solar and storage. And we've been recognized in several areas for being a leader in wind energy, energy efficiency, carbon reductions, innovative technology, and storm restoration.

And I'll move through this kind of quick because I know we want to get to the meat of the presentation here with a few minutes left.

All right, next slide. So our our two thousand thirty goal is includes eighty percent reduction in our electric carbon emissions, while also encouraging electrification and reducing emissions from natural gas operations. By two thousand thirty five, we're planning to build out our charging infrastructure to support one point five million electric vehicles and converting twenty percent of our XL's fleet to EVs as well.

And then our two thousand and fifty vision to achieve zero carbon electric emissions and provide net zero gas service and ensuring zero carbon fuel is available with one mile for customers that will enable widespread adoption of clean fuels.

So quite a bit going on here in the next twenty years.

And then looking at our excellent energy grid flexibility vision as it relates to our clean energy vision.

You know, today, we use daily demand response in our time of use rates and programs like our renewable battery connect program for load control to shift customer usage away from those high cost times and high emission peak hours.

But our plan is to transition from traditional planning to our grid of the future, which centers on bringing DERs, like solar storage EVs, demand response and microgrids, directly into our distribution system planning process.

So like most utilities, Xcel is preparing for increased electrification, variable renewable generation, growing demand from data centers, and more.

And we need these grid flexibility strategies to support our commitments to becoming a net zero energy provider by two thousand fifty. Next slide.

So let's dive into our behind the meter energy storage journey.

So in twenty seventeen, we published our first energy storage guidelines that defined eight different design configurations for battery interconnection, including AC coupled, DC coupled, one hundred percent renewable export and non export options for operating in parallel with our grid.

Then in twenty twenty one, EXL launched an eighteen month pilot for a residential battery demand response pilot to better understand customer side and storage and grid as a grid rE Source.

And the pilot tested real world demand response performance, including peak load reduction and solar time shifting.

So in twenty twenty three, we introduced Renewable Battery Connect program, which is the next generation offering larger upfront incentives and a key requirement for the battery to be one hundred percent charged by on-site solar. So it's important to note, though, that this was made possible by state legislation designating batteries charged entirely by renewables as renewable energy rE Sources. So this enabled the same customer funded incentives used to pay solar incentives and pay for the lucrative incentives as part of Renovo Battery Connect. So in just over two years, the program has enrolled nearly three thousand five hundred batteries totaling forty seven megawatts of nameplate capacity.

So we're pretty excited about that. Next slide, please.

All right.

So this is where data becomes the backbone of our program design and operations and the path to a true VPP.

So in our pilot phase, we really wanted to learn about what batteries can actually do. So our goal was to understand real customer behavior and the technical capabilities of those batteries, like battery usage patterns. So what we learned is that batteries naturally charged and discharged daily without events to understand kind of the baseline usage, which was critical to understanding usage patterns.

Event performance, we learned that when we dispatched the batteries, the batteries are delivering more energy than they would under normal operating conditions, confirming a strong Doctor value during an event.

We also learned about high customer interest and their willingness to participate and also customers value that they had with about having a battery for backup purposes along with receiving those higher incentives.

We also learned about OEM software capabilities. We wanted to learn how dispatch schedules, telemetry quality of data, and the remote control varied across different OEM platforms.

And then moving on to the program phase, where we wanted to evaluate battery performance at scale and understand operational impacts.

So we evaluated how batteries operated under time of use rates and under non time of use rates and how the batteries behaved before, during, and after demand response events, and how customer bill impacts from participating in grid events affected the dollars of customer bills.

The other use cases we were testing were how batteries can support grid needs through peak demand reduction, twenty four hour charging and discharging schedules, and managing that evening ramp up on the grid.

And then moving in to our VPP phase, where our goal is to build a DER portfolio that behaves like a dispatchable grid rE Source.

So we want to move towards a pay for performance compensation structure that better aligns payment and delivering grid value.

So for Renewable Battery Connect, we specifically have classified all of our feeders into summer peaking feeders, winter peaking feeders, dual peaking, and focus on a target demand area.

And so we're using these feeders to categorize and test different operational schedules in the Renewal by Better Connect program over the next one to two years.

So we're hoping that this phase of the near term VPP will unlock locational grid value and shape dispatch strategies by feeder needs and form the foundation for a fully advanced virtual power plant.

Next slide, please.

So we've developed a few models that are directed at the same goal. So beyond just renewable battery connected behind the meter batteries, we want to leverage distribution batteries and DERs in a way that can provide meaningful system benefits to all customers.

So here we're showing kind of four different flavors of programs that are utilizing distributed storage, two front of the meter programs and two behind the meter programs where these distribution connected rE Sources have a high potential to provide benefits to the bulk and local distribution system.

But their primary use cases are different.

They all require evolving planning practices and emerging technologies to operate the grid of the future. And so you'll see that the primary use cases are focused either on the bulk system capacity or distribution system, or there are additional benefits where the peaks are overlapping.

So these programs are really designed to value the where, when, and performance to maximize system benefits away from simple energy credits to compensation that reflects where on the grid the DER is located, when it delivers load relief or provides capacity, and how well it performs when dispatched.

So for example, our upcoming aggregated virtual power plant and dispatchable distributed generation programs, they compensate based on our avoided costs. So for example, DDG bid prices, because it's a competitive solicitation, the bid prices are compared against our avoided costs for generation transmission distribution.

And the aggregator virtual power plant, the aggregators receive a share of our total avoided costs with providing ninety percent of our avoided costs for year round participation and seventy percent of that for summer only rE Sources.

And for ADPP and DDG, we also apply an additional distribution system adder when DERs are located on feeders that are heavily loaded or have peak demands that coincident with the bulk system peak.

So these increase performance payments where DERs provide both bulk system and distribution level value. So that's improving benefits for all customers.

So basically, we're moving away from our best effort program to a pay for performance where it matters design.

Next slide.

All right, so building on the design of the program, batteries can deliver multiple stacked benefits, but really based on that primary use case determines the dominant value stream that the program will provide.

So on the bulk side, batteries provide system wide capacity and shift energy from low cost periods to high demand periods. This is the classic energy shifting and peak capacity value that most people associate with storage.

Then moving on to the coincident peak where the local peaks on the feeders line up with the system peak, batteries can manage those local peaks and improve hosting capacity, and that can all help with integrating even more DERs onto the system.

And then there's capacity deferral in areas with specific constraints. A battery can defer or avoid upgrades at substation speeders or transformers. And those are things like non wires alternatives, targeted domain areas, and even VPPs.

Then the last piece is transacted energy. So batteries can generate market revenues by participating in wholesale markets and provide flexibility to the broader grid.

For Excel, this is a long term value stream that becomes more important as we move towards virtual power plant model and behind the meter generation participation options in wholesale markets.

Next slide, please.

And just to show a simplified DERMS architecture, so how do we make this all happen would be showing the major components of utility enterprise DERMS structure.

So this tech stack resembles a puzzle where you have your ADMS and DERMs integrated with AMI data and OEM platforms, and each piece really does matter. And so for the grid DERMs, it's centrally integrated with our utility ADMS that's creating our utility distribution operation center.

And the grid derms is what directly communicates to our larger scale DERs via a DER gateway.

And then our utility aggregator derms is integrating with more of our small scale behind the meter DERs and directly with DER aggregators that will accept the signals from the aggregator DERMS to dispatch events and receive telemetry.

Next slide, please.

And so distributed storage values only become real when you can prove it. And so we've learned this along the way where data and measurement verification are so important, especially as we scale into thousands of customer batteries and move towards a virtual power plant model. That measurement and verification becomes the foundation for everything. So the operational decisions, planning, regulatory approval, and compensation frameworks. So internally, our NMD really needs to quantify real grid impacts, feeder level peak reduction showing load shape changes, showing operational risk reduction, and whether storage actually extends or defers upgrade timelines.

And then on the regulatory side, you know, regulators require clear, repeatable methodologies that link storage dispatch to avoided costs and locational benefits. I mean, we have a distribution system plan that we're asking for, you know, dollars two billion in investment on the distribution system. And our regulators are asking us to think about that strategy differently. And so having this data and information to show them how VPPs and behind the meter storage can support that distribution system plan is really important here.

So performance certainty, accountability matter, especially we move towards pay for performance models.

So ultimately, unlocking the full value of distributed storage is not just a technology challenge, it is also a measurement challenge.

I think that is the last slide for me. Back to you, Michael.

Awesome.

Thank you all. Thank you, Kristen, Brian and Malcolm for chiming in, sharing some of your exciting research. We've got a little bit of time here. We've got about eight minutes left in the time slot here today. If anybody has any questions about what you heard from me, from Malcolm, from Brian or from Kristen, go ahead and put them in the chat.

I'll give you guys a minute of silence here to go ahead and formulate those questions and throw them in the chat and we can pose them to the folks here. Again, you don't have the ability unmute yourself. So if you do have a question that you want answered, go ahead and type it in the chat. We'll take a little break.

Okay, question from Tara.

What VPP software providers are others using to manage the batteries? I think a great place to start is probably to talk with Kristen and Brian, if you guys are comfortable, I think I saw a little bit on your slide, Kristen, talk about software providers and maybe some decisions that went into ultimately choosing that.

Yeah, absolutely. We did a lot of research on software providers or derms providers probably two years ago where we got down to, I guess, seven different vendors and did deep dive demos with each one.

We put out there one hundred use cases and one thousand requirements that we were looking for a piece of software to provide.

That really narrowed down the field to what software platforms were able to kind of take that on. But ultimately for our aggregator derms, which is our edge derms, we selected Itron.

Some of the reason for that also was that we also have their meters. And so integrating AMI data into the platform was a bit easier to do. And they've already stood up Renewable Better Connect in the platform. We are now going to be standing up our Aggregator Virtual Power Plant program in that platform as well.

It hasn't come with any bumps. We've definitely run into kind of communications challenges. And I think that is one thing with that whole tech stack and that being such a puzzle piece and all the connected pieces together is that the communications with the integrations to all the different systems is so important and coming up with like a standard communication method across the system is challenging.

So right now for our Aggregated Virtual Powerpoint, for example, we are accepting Open ADR and texture as the two kind of communication methods to communicate with our derms system.

So that's just our experience so far.

Great. Chris, we have another question for you here. What baseline methodology are you using for your VPP programs?

Yeah, great question. So we had an extensive stakeholder discussion on several aspects of our VPP program, and we landed on a standardized baseline for AMI measured DERs, where it will be a five of ten with a forty five day look back and weather adjustment day out. So it'll be standard for all DER types because the program is technology agnostic.

It'll be that standardized baseline to start with. And then specifically, energy storage systems do not have a baseline for the first two years of the program. So we'll be paying strictly off of what the batteries are providing during the event period from telemetry data from the inverter.

Great, thanks. Thanks, Kristen. A question that may be a good place for both of you guys to weigh in on, what are the groups within your utility that you're working on this with as stakeholders part of the planning process, the execution, I think aligning internal stakeholders in the utility I know we've talked about has been an interesting process. And there are folks within the utility that may not have any idea that this stuff is happening, even though it's directly applicable to them. So Brian, if you want to start us off, if you wanna talk a little bit about who internally at Tucson you're working with and how that all kind of shakes out.

Yeah, sure. So I'd say we often view our system controls and operations system control and reliability as kind of the customer for our FlexFlow programs and VPP development, so we want to make sure that there are programs that they can call upon reliably, get the rE Source that they expect, and that they meet their needs functionally. We also coordinate with rE Source planning, customer insights, forecasting rates, all of those different teams as we design a new program and set it up, launch it, and evaluate its performance. I'd also say on the software side, we work with EnergyHub right now, on our thermostats, battery, program. Yeah. And that's, we went to RFP with the, I don't know, twenty twenty one, I think, and and got them as sort of our Flexload pilot partner.

Great. Brian, what about you, Kristen?

Yeah. And with such a focus on our programs on location load flexibility and that distribution adder, we certainly worked very closely with our distribution planners to do that feeder analysis to understand which ones are our constrained feeders. We have eight thirty so feeders in our Colorado territory, and we identified a third of which are constrained and get that additional devalue as we're looking at avoided costs and providing that benefit. So they were certainly well involved. Regulatory, certainly another big player to navigate all of the filings, letter, timelines for these programs. And I should have mentioned some of which were required out of statute and Senate bills.

We've done the best we can with the page and a half of legislation to develop dispatchable distributed generation and aggregated virtual power plant. Both of those were from Senate bills.

And then our customer team, our customer energy solutions teams who will ultimately have to be running these programs.

So our kind of planning strategy is what are the grid needs and then dictating what those needs are down to our customer solutions team and product development team to say, here are the needs that are on the system and develop a program or product that meets those needs that customers can participate in.

Good stuff, guys. Well, we've got one more minute.

I think this is an important question. If either of you guys wanna try to get to it in one minute about upfront versus ongoing incentives and anything you've learned real quick before we let these folks go today.

I'll just quickly say we converged on performance based bring your own device just because we really need to tie incentives to performance and grid value.

Yep.

Yep. I think it's a classic question of rebates and incentives, where remember when people started getting solar, we had high rec prices, right? Like to get a solar system and a twenty year rec purchase contract.

Over time, those incentives should step down and they have very much so from twelve cents per kilowatt hour down to two cents. And we've done fully away with our small solar works program altogether because we've shifted to batteries and incentivizing batteries because they are dispatchable and they can dispatch when and where we need them.

So certainly the upfront, we might still have a little bit upfront just to help support the purchase of the battery and then pair that with some more pay for performance compensation.

But I think in the future, fully moving to pay performance compensation is where we're headed.

Outstanding. Thanks guys. Well, again, another round of thank yous for the folks here on the line from the E Source side, Malcolm, Ben behind the scenes on the question answers, Brian and Kristen. Great conversation as always. Thank you all for joining us. And that's us signing off.

Have a great rest of your day, guys.

Thanks.