Xcel Owns the Batteries, You Pay the Bill — Episode 269 of Local Energy Rules

Shannon Anderson:
Xcel’s proposal was sort of isolated from the opportunity that could be created. If it brought in third parties, if it brought in customers, if it brought in private sector innovation and competition, none of that was present in what Xcel ultimately ended up moving forward.

******

John Farrell:
What could we expect from a new utility-owned distributed storage program that made headlines when it was announced over 18 months ago? In early April, Xcel Energy finally won regulatory approval for its Capacity*Connect distributed battery storage program, also commonly called a Distributed Capacity Procurement or DCP. Joining me in April 2026, Shannon Anderson, virtual power plant policy director for Soul United Neighbors and Will Kenworthy, Senior Regulatory Director for the Midwest for Vote Solar, helped to peel back the layers of this decision by the Minnesota Public Utilities Commission to see where this program measures up and where it falls short of capturing the full potential of distributed batteries.
I’m John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self-Reliance, and this is Local Energy Rules, a podcast about monopoly power, energy democracy, and how communities can take charge to transform the energy system.

******

John Farrell:
Will and Shannon, thank you so much for joining me on Local Energy Rules.

Will Kenworthy:
Hi, thanks for having us.

Shannon Anderson:
Yeah, thanks so much, John. Looking forward to the conversation.

John Farrell:
I want to start with you, Will, because when this proposal first came out in October of 2024, there was a lot of excitement. Can you explain a little bit about what was so meaningful about this initial proposal that popped up out of nowhere, I should add, in the middle of an Xcel resource plan process?

Will Kenworthy:
We had been working in the Xcel IRP, going back to their previous IRP in 2019 to try to get the company to deal with distributed energy resources. We called it DG at the time, because this was sort of before storage and residential solar installations was a thing. We were trying to figure out how to get the company to deal with distributed resources as a resource, something that they could do something about way back to before COVID. So when Xcel first proposed this distributed capacity, what started off as being called the distributed capacity procurement in their IRP, in reply comments in August of 2024, they talked about using distributed energy resources to solve grid problems and not just bulk power system issues, but distribution grid issues and grid congestion generally. And we were very excited initially because we were like, “This is a great opportunity. We’ve been talking about trying to get distributed energy resources treated co-equally with other alternative solutions to solving grid needs for a long time.” And initially it looked like that’s what they were going to do.
Yeah. So it goes back a long time. The company recognized it and announced that they were planning to do it. And it had a big rollout at RE Plus, which is the big industry trade show in 2024 where the CEO of Northern State’s Power of Xcel Energy in Minnesota and the head of Spark Fund and Jigar Shah gave a big well-attended session at RE+ and talked about this. And that’s what they were talking about at the time. They were talking about solving all grid needs, not just focusing on bulk power.

Shannon Anderson:
And John, if I could just level set a little bit. I mean, Xcel is known actually as an innovator, I think, within the utility space. I mean, they’re not one of these entrenched utilities that fights DERs at every opportunity as much. And I think that’s partly why we saw them potentially as a partner. I think in the innovation of where this program could go, they’ve been doing good work in Colorado. They’ve been proposing things there. So we were really interested in, I think, what they could do in Minnesota. And yeah, we had some optimism on what they were going to do, and unfortunately that just did not play out.

John Farrell:
I love you for sharing that, Shannon, because for me, having been in Minnesota for a long time, I think of Xcel as a good complier with the law that it tends to be in service territory. Its service territories tend to overlap with relatively progressive legislatures in Colorado and Minnesota that have pushed it to do good things. So it has a reputation that in my opinion is somewhat unearned, but be that as it may, as you point out, Xcel was putting this out there, had demonstrated that it could deliver on those things. So not to get too much into a debate about whether Xcel was motivated here or not. So we got this proposal in, and as you said, Will, in reply comments, I think it’s worth pointing out that in a resource planning process, you are way down the road from the initial proposal when you get to reply comments.
Xcel has filed a multi-hundred page document saying how it’s going to meet things. Intervening groups like ours have already said, “Here are our concerns with it. Here are some changes.” There’s been some back and forth from a lot of different parties. So to have this pop-up reply comments was kind of like, “Oh, we’re going in a totally different direction here.” And as you mentioned, it was also kind of an interesting tangent because we were already deeply in discussion with them as part of this resource plan about distributed solar and how it could contribute. So here we have this DCP, as it was called, distributed capacity procurement. Will, do you want to give a little bit of flavor for modifications or ideas that we offered back in 2024?
Because we saw this come into that resource planning process, even though it came in a weird place and we’re like, “Well, this is an opportunity. Let’s say some things about what we think would make it work really well.” Could you talk a little bit about how we hoped that they would shape this program? And actually also, if you could just remind us, what was the initial proposal? What were the initial scope of the proposal that Xcel made in terms of megawatts of energy storage and whatnot?

Will Kenworthy:
Yeah. So they proposed it in the IRP. We, from the get-go, were saying, “That’s great. We understand this to be a front of the meter program, this focused on distribution value. You should also do a virtual power plant.” I mean, it’s probably not the last time we used the term VPP, but a virtual power plant as a complimentary program to what you’re doing with the DCP. And so they refused to do that in the IRP, but when the IRP settlement happened later that year, they agreed to file a DCP the following year. So that was going back to 2025. And then that settlement agreement was agreed to by the Commission in winter of 2025. And in that final agreement, they agreed to file a distributed capacity procurement in October. So last October is when the distributed capacity procurement was filed. And what they concluded and what they filed was a very limited program focused on front of the meter resources that would be serving, as they framed it, almost exclusively bulk power supply value, and completely wrote off the distribution value, which was one of what we thought was the most important part of the program that differentiated it from plain vanilla utility scale storage. So they sort of, what I say, whiffed on getting the distribution and avoided transmission value.

John Farrell:
And it’s worth noting too that there was this sort of odd disconnect between the structure of the program and the capabilities of it because … And we actually heard this in the hearing that happened just a few weeks ago with Commissioner Ham was saying, “If this isn’t going to do stuff for the distribution system, then why don’t you just build utility scale storage?” And that was kind of the weird thing is Xcel was saying, “We’re going to put these batteries all over the place on the property of commercial property owners, that kind of thing.” I mean, just imagine sticking batteries behind a target store or something like that. It’s sort of like the vision that they evoked with their program, but then they said, “Oh, but we’re not really going to use them for any benefit on that distribution grid.”
So Shannon, we talked, obviously they were not willing to offer up a behind the meter program. Do you want to talk a little bit more though about what kind of values we could be seeing from if those resources were better used, whether it’s front of the meter or behind the meter, what can we do with distributed energy resources when they’re placed on the distribution system?

Shannon Anderson:
I mean, first and foremost, there’s a connection to the customer, right? So again, these batteries think of a semi-truck full of batteries parked behind a Target. So they’re not powering the refrigeration in the Target or the lighting any of the other need in that Target. And so they’re really just used at, again, front of the meter for Xcel, essentially. There’s no customer benefit. So that’s the first disconnect is proposal. So if you get a behind the meter program that’s actually integrated into customer demand, customer use, there’s an inherent benefit for the customers where those batteries are located. And then so that’s for these proposals, which are one to five megawatt size batteries, they’re relatively large, but again, they’re sort of scaled for that larger commercial industrial kind of customer.
When you get to the residential side, customers have already bought batteries. They’ve already invested in them. They’re in their homes. And so they’re available to be used if Xcel would just connect them to the grid. As Will said, that’s really what was missing. Xcel’s proposal was sort of isolated from the opportunity that could be created. If it brought in third parties, if it brought in customers, if it brought in private sector innovation and competition, none of that was present in what Xcel ultimately ended up moving forward.

John Farrell:
So the proposal that we got in October 2025, it was, we’ll use some of this up well, is kind of like batteries on the distribution system, but basically we’re operating within the Midwest regional grid operator and we’re selling power or arbitraging, basically filling the batteries when it’s cheap, emptying them when energy is expensive. And what was also interesting, I think is probably worthwhile to mention is that Xcel’s proposal said essentially this is underwater from a cost benefit perspective, that even though we are going to try to use these larger grid values, it’s not going to pay off. Customers are actually going to have to pay up a little bit to make this work, which is in really strong contrast to all of the evidence that’s been out there about what you can do with distributed energy resources, which is that you have a chance to meet grid needs for less money.
Will, do you want to riff on that a little bit? What sort of was missed there and maybe talk a little bit about what did we then and other advocates that were in this proceeding try to say about how we should treat this differently?

Will Kenworthy:
Yeah. So let me back up just a little bit to explain to people. I think most people understand this, but just in case, there’s three main sort of cost components that we consider in grid planning. And one is bulk power supply, and that is in Minnesota, which is part of the Midwest Independent System Operator or MISO, MISO has a market for energy and capacity, and that is a regional market and Xcel is just a part of that market. And Xcel’s bulk power resources are dispatched according to rules that MISO sets and operates day to day. Every resource in the MISO wholesale power market is dispatched by MISO. And so that’s wholesale power level.
At the next level down is the transmission, which is the wires that are like, I think you’ve used it before, like the interstate highways of the power grid that move power between markets, between sub-markets, between Xcel and Wisconsin Electric Power or wherever energy is cheaper to generate and it is dispatched and it’s a regional market also.
And then the distribution level, which is the poles and wires that you see every day and that run the power to your system. The distribution level is where growing a percentage of the costs of the system, of your electricity bill are on distribution. And in the last decade or so, distribution costs have been going up and also distribution costs have been subject to some serious inflation in the last couple years too. And so transformers have doubled in priced since COVID and copper wire and wood poles, all those things are fixed costs and they have become an increasingly important part of the system. And so avoiding future investment in the distribution system has a lot of potential value and increasing utilization of the distribution system also has a lot of value. If you can move more electrons across the same wires, then the denominator and the charge becomes smaller and you can actually recover the investment that’s needed for that system over a broader set of customers and electrons.
And so like increasing utilization and increasing the efficiency of how you use the grid is a huge opportunity and avoiding big investments. So when you invest in new substations or new circuits, that’s a very large capital cost and that can drive costs. And so if you can avoid that, even for a couple of years, you can do that. And so that’s the opportunity with distributed energy resources. Distributed energy resources we’ve been talking about for years in grid planning, we talked about non-wires alternatives and non-wires alternatives is when you are able to use solutions that are hyper-local at the local level to avoid those big distribution capacity upgrades. And again, when I was saying at the beginning that Xcel was talking about solving grid congestion, that’s the problem that you’re trying to solve.

Shannon Anderson:
Yeah. And there’s also benefits for more DERs and distributed energy resources by doing some of those things as well, because you free up hosting capacity issues and solve some interconnection concerns, deal with, again, sort of allowing more solar and storage to be on the grid and to be used more effectively for the grid. And Xcel could have, I think, dealt with some of those problems through this proposal and really offered some solutions that wouldn’t have just been for them, but for their customers at large who want to be part of their solution and contribute to the innovation that the company could create.

John Farrell:
So let’s talk a little bit about how the Commission modified Xcel’s proposal. So when it came in October, it was, as Will outlined, basically a bulk power proposal, not really taking advantage, as you were saying, Shannon, of being located near customers, being able to help with grid utilization, helping customers with demand. It seems like the Commission heard that particular argument pretty strongly because especially in the hearing, it was like six hours of hearing and we spent at least half the time with the Commissioners really digging into this issue of, “Hey, you’re building these batteries all over the place. Tell us how you’re actually going to use them to get us some benefits that are other than that broader bulk system benefit.” I don’t know which of you might want to take this one, but what did the Commission then order Xcel to do in terms of helping to capture distribution value? What is that process going to look like?

Shannon Anderson:
Essentially, there’s going to be a lot more process. So there’ll be reports and information and analysis and all of that for many years to come. So lots of opportunity for folks to, I think, still weigh in and get involved in the proceedings that the Commission will be holding into the future. But ultimately, as you noted, the Commission did really, I think, take a hard look at this issue and forced Xcel to go beyond what originally wanted to do and I think what it could promise to do, and I will take your critique seriously that Xcel, I think, has the right people within the company to do some of this work, but unless a Commission says, “Yes, you must do this work,” or a legislature tells them to do the work, they’re not likely to do it. And partly utilities, as you know, are cautious and risk adverse.
And so Xcel naturally didn’t want to promise what it couldn’t 100% deliver. So the Commission made them stretch a little bit and made them look at that distribution value and they’re going to have to come forward and set a value for that and they’re going to have to propose it within their distribution planning process and hopefully come up with a way to use these batteries that will create better benefits for their customers on that distribution level. And they have to do it within a year and a half. So it’s not way out into the future, but it gives them time to see what these batteries do, test them out a little bit, understand the relationship to MISO, but then also again, force them to get to a place that hopefully we all can agree with eventually in the future.

Will Kenworthy:
I would just say we did initial comments in December and then reply comments in January. And in both sets of comments, we relied and pushed really hard on getting back to the distribution values. And the Commission saw that and heard that and sent a very clear message to Xcel that they needed to identify and spend more time doing the analysis to identify what that distribution value is. And I think that that is a real benefit, not just to Xcel and to the rate payers, Xcel’s customers, but also to the whole industry because valuing distribution value, like putting a value on what that kilowatt of service at this location is worth is really hard and it hasn’t really been done very well anywhere. And you now have Xcel that has an interest in showing that there is some value to this distribution value and the Commission telling them to figure out what that is.
And that’s what this … I printed off because this is like one of my favorite things, this decision option that they ultimately adopted was I feel like a really strong signal to get it right on what this distribution value is. And so we can take that to other forums where we’re considering compensation for distributed energy resources. And I’ll take … I’m not talking about just in Minnesota, I’m talking about everywhere. The methodology that I’m hoping that they will develop to do this would be applicable broadly. And you could take that methodology anywhere and just apply it to the books and the situation of any particular utility. So I think that that part of this will be very valuable and is worth the effort.

John Farrell:
And I always love to emphasize for folks about the interests and the incentives that Xcel has around this program. So one of my frustrations with the outcome, and you mentioned Shannon, that they have about a year and a half that they’re going to get to test this program and have to do a lot of reporting. One of my frustrations is that the PUC’s ultimate decision essentially made a lot more work for them and for everybody else who’s been involved in this because they didn’t say, come to us with a tariff that actually takes a first step at these prices. They didn’t say, create a market whether folks can participate where we can actually evaluate what is happening based on market reactions. We’re going to have them do their own experimenting. We are hopefully going to have them share publicly good data in order to inform the decision-making process, but we all going to have to be back in a hearing room again in 18 months, probably having some kinds of arguments now about the data that Xcel had and whatnot.
And meanwhile, Xcel is going to make its money off of this program just by installing the batteries. There’s no financial incentive here for Xcel explicitly in terms of the system design for Xcel to make money by, say, for example, to what Will was saying, dispatching these batteries in a way that actually increases distribution grid utilization. We don’t have performance-based regulation in Minnesota. Xcel’s going to make money by just putting those batteries out there by expending the capital and not necessarily for operating them. We weren’t necessarily proposing to solve that to be clear in our comments, but what we were talking about was some other things that we thought the Commission could take on. And I’m kind of interested, Will, you were leading along with Erica McConnell at Environmental Law and Policy Center and others in our group. Could you talk a little bit about some of the other things that we put on the table that we thought would have made this even stronger that the Commission didn’t really take a look at?

Will Kenworthy:
Well, I mean, the most disappointing thing is that we didn’t get any acknowledgement or push to move the ball down the field on doing behind the meter virtual power plants. I mean, I think that’s a huge opportunity that is still on the table and still available to the Commission and to the company and so far that they have not moved on. That’s the main one.
I think there was also an opportunity to try to make some of this available to third parties to try to make the investments that are needed in the grid to, like I said, avoid distribution capital investment. It’s hard. With bulk power stuff, we have markets, we have wholesale markets, we have good price signals on what that service is worth, the energy and capacity services in the bulk power market. We don’t have good market signals for what avoided distribution capital is worth, and we don’t have a market for it in the United States.
The UK does have markets for distribution grid services, and that’s something that we can and should talk about. But if you’re talking about, I’ve used the example, like we don’t have a market for what a substation upgrade is worth, right? But that’s really what you’re trying to get at when you’re trying to talk about distribution. We could experiment with that. We could allow some third party development or say, “Okay, we need a big battery here to avoid this distribution grid upgrade.” And within the parameters of somewhere along this circuit, we need this service and let developers who have experience with developing energy storage projects go out there and try to develop that project and deliver that service at a competitive rate. There is no interest in doing that at this point, but it’s something that I think that there’s a real opportunity for, and I think down the road should be explored because it is potentially more cost-effective for customers and that’s what this is all about.

*****

John Farrell:
We’re going to take a short break. When we come back, I ask Shannon if it’s accurate to call the approved battery storage program a virtual power plant. We also learn about the Colorado virtual power plant policy by the same utility that’s already in operation, and we put this decision into the larger context of electrification and affordability. You’re listening to a Local Energy Wheels podcast with Shannon Anderson, virtual power plant policy director for Solar United Neighbors and Will Kenworthy, Senior Regulatory Director for the Midwest for Vote Solar. Hey, thanks for listening to Local Energy Rules. We’re so glad you’re here. If you like what you’ve heard, please help other folks find us by giving the show a rating and review on Apple Podcasts or Spotify, five stars if you think we’ve earned it. As a bonus, I’ll gladly read your review aloud on the show if it includes an energy related joke or pun. Now back to the program.

*****

John Farrell:
Just a couple thoughts about this. And Shannon, if you want to jump in, I also have a specific question for you too to tap at some of your expertise. The one reason we like the idea of third party participation is, of course, coming back to that idea of incentives, a third party who participates in this program, who, for example, is paid for the delivery, like the value, has an incentive to actually deliver the value, right? It’s not a capital investment return necessarily. We would actually be trying to align in the way that we want some of those benefits we could get around grid utilization, avoiding upgrades with the payment we make to those.
Now, I totally agree. We don’t necessarily know what those numbers are to start with. We’re more at the conceptual stage of, “Oh, there’s congestion on this line. This substation is near capacity. We know we need something and we can describe that something, but we don’t necessarily have yet a great way of pricing what should we pay for it other than saying to Xcel, what would you charge customers to do that substation upgrade?” And that’s our benchmark, but then we’re sort of stuck in this weird space. I was thinking of this as we’re sitting in the hearing room of like, “Okay, so what’s the right amount to pay someone to avoid the substation upgrade?” You don’t want to pay them the same amount. The point is that it was supposed to be cheaper, but we don’t know how much cheaper it could be because we haven’t really done it much. So is it 50%? Is it 75% of the substation? Is it 25%? So I don’t know. Maybe you want to talk about that a little bit, Shannon.
But I also wanted to ask you then too, Jeff St. John and his Canary Media piece about this decision called it a virtual power plant. And as someone who in her title is a director of virtual power plant policy, is this a virtual power plant?

Shannon Anderson:
Yeah, no, it’s not. It’s not managed the same way through software and deployment. It doesn’t solve the same problems that virtual power plants solve. And inherently, again, it doesn’t link those customers and their resources to the grid, which is a virtual power plant. So virtual power plant, just to kind of level set a little bit, two pieces. The virtual piece is essentially the software that connects all the devices. And then the power plant piece is when you have resources distributed along the grid that are coordinated and managed as if they were a single generation unit effectively and deployed at times of peak power needs or to provide other grid services. And so it’s essentially, again, taking customer resources, bundling them together, managing them through software, and really creating essentially a very big power plant with all of those resources. And at SUN, I would say, I mean, we’ve taken a pretty hard line that virtual power plants, particularly behind the meter resources, shouldn’t have utility ownership or really even control because again, the beauty of a virtual power plant is that you have customer investment that is separate from utility capital spend. And that’s what makes virtual power plants 40 to 60% cheaper than any other thing that utility can do. And that’s because the utility isn’t spending capital on those resources. It’s not charging ratepayers a rate of return and it’s not adding them to their O&M expenses and management expenses over the lifetime of the resources. And so the difference here, of course, is that Xcel is maybe not building the resources, but owning the resources, managing them, paying for upkeep, charging rate payers, rate of returns on them, using that capital spend. And that is what, ultimately, John, what creates this project being underwater, as you said, just because it comes from a different sort of philosophy of how these resources can be deployed to the grid. So yeah, it’s not technically a virtual power plant. I think Xcel would argue it’s a gateway to a virtual power plant.
It’s maybe a pathway to some technology development that the company has been interested in doing that, as Will said, could maybe realize that the value of some of these resources and understand them better for their system, which is good, but it’s not doing what is available right now for the company to do. And really, I think using the opportunity of customers and third party innovation and technology development that we know is real in other places.

John Farrell:
I just will note that I’ll put in our link in our show notes, Solar United Neighbors has some great resources on model virtual power plant legislation. I can share ILSR’s recent calculator on excessive utility return on equity, which kind of informs that whole issue of this program being more expensive than perhaps a VPP program might’ve been. I wanted to mention one other thing too about the process. One of the things I found really frustrating about the conversation that happened at the Commission, we’ve had this robust back and forth over months, six months since it was proposed in October, filing comments, having reply comments, et cetera, we spend most of the time during the hearing on this issue of distribution value, which I think Will, as you pointed out, we came out with a good framework that may lead to a decent methodology for the first time in the US that gives us a sense for what are the value, what value can we get from distributed storage? What should we be willing to pay for it in order to avoid distribution costs?
One of the options that was on the table was this idea of doing a behind the meter virtual power plant. We were advocating that even if it wasn’t going to be created at the same time, that it was at least like, let’s set a timeframe for Xcel to do this knowing that the learning processes and the kind of coordinated operation of these resources is leading us in that direction. The Commission brings it up and notably talks to nobody in the room who’s an expert on virtual power plants. They went to two witnesses, one of whom was the utility, the other one who was aligned with the utility, and then basically punted and said, “We’re going to look at what Colorado’s doing 18 months from now and decide at that point whether we should continue to talk about this.”
I don’t know if either of you is a little more familiar with what’s going on in Colorado, but I think it’s worth pointing out. So Xcel is a parent company for these subsidiary utilities in Colorado, New Mexico, and Minnesota. The Colorado utility is doing a virtual power plant program as we speak. So I felt a little surprised, honestly, that the Minnesota Commission was so dismissive and was like, “Well, just tell us in 18 months if something’s working.” It’s like, well, they already have something going. Could either of you talk a little bit about what’s happening in Colorado and why you think the Minnesota Commission was so gun shy about taking advantage of that in a much earlier timeframe?

Shannon Anderson:
Yeah, sure. So SUN was really involved in the Colorado proceeding as well that set up what’s called the Aggregator Virtual Power Plant Program. And it just launched this month, actually the day before the Minnesota hearing, and it allows what are called third party aggregators. So they’re in the name of the program to essentially, again, bundle these distributed energy resources, manage them, use their tech, all the apps, all the information on their end, and really provide those resources to the utility. There’s set compensation within the program structure, really good, I think, value identified that will create cost savings for the utility and its customers, and it’s ready to go. Xcel has developed the technology on their end needed to make it happen. Customers are being enrolled in the program as we speak, and we know that it will create value. And we know that because Xcel has already invested at a company level in the program, we know that they could do something exactly the same in Minnesota.
Interestingly enough, one of the excuses or reasons, I should say rationales is perhaps not excuse, the Commission used to justify its decision is that, again, Xcel in Minnesota is part of this MISO that we’ve been talking about, this regional transmission organization in Colorado Xcel isn’t part of an RTO essentially, although we can debate Western RTO is a whole different show. So essentially, like the Commission said, you need to be not in an RTO to be in a virtual power plant program, which is just the opposite of what most virtual power plants around the country are. Most of them are in PJM or some other sort of RTO structure. You can do them in a vertically integrated utility without an RTO. We have programs in Arizona, for instance, that operate that way. We have programs that work in an RTO. It doesn’t matter whether you’re in an RTO or not, whether you can do a virtual power plant.
So I was a little disappointed in just, I think, the lack of sophistication and maybe the information the Commission was getting just was not really accurate on how these programs really work and what the potential and opportunity really is.

John Farrell:
All the more reason to ask someone who is an expert in the room, that will.

Will Kenworthy:
Yeah, I do. I was very disappointed that the Commission didn’t take us up on that at all. I think it was well teed up. I thought we had set some record on that and they just chose not to at this point. One thing I’ve learned about the Minnesota Commission though is it’s a long game and you keep going. And we have been talking about VPPs and other forums. We’re in a subset of our group from the DCP proceeding was also in the rate case that Xcels currently has pending before the Commission. And we’ve established what, again, I think is a pretty strong record in support of the company moving forward with a virtual power plant. We made the point that this is … There was a really good paper that came out that Energy Hub put out last year on the VPP maturity model where they talk about stages, like four stages or five stages, I can’t remember, of VPP development.
And the first stage of a VPP looks a lot like thermostat programs that a lot of companies have already in place where they’re turning people’s thermostats up and down to shape load. And Xcel actually has a thermostat program and actually has a lot of these programs already in place in Minnesota and they are proposing investment in distributed energy resource management systems, DERMS, in their IDP that’s currently also pending before the Commission. And so the point we’ve made is two things. One is they can do this as an evolution of programs they already have in place. And so it’s not a huge lift. It can be incremental and they could have easily done that in this case. They can do it still in the distribution plan case or in the rate case. And secondly, they want to make these investments in these control systems without doing anything. And so the point we’ve made in the rate case here was you want to make these investments in order to make those investments cost effective, you need to be doing something with it.
And we made that case in Michigan, in the consumer’s energy rate case, and the Michigan Commission bit hard on that and basically told the company, “Don’t be coming to us to make these investments in DERMS and other types of systems that would support doing these customer programs if you’re not going to include a VPP.” And the Michigan Commission used the D word, right? They talked about disallowing investments that didn’t adequately consider alternatives like a VPP.

John Farrell:
And just to emphasize, that is a big word in Commission speak because it’s saying to the utility, you either can’t recover the cost or you’re not going to make a profit on it, which is fundamentally how the business model works. So that is a big word.

Will Kenworthy:
Right. That gets utilities’ attention.

John Farrell:
Right. Before we wrap up, is there anything else that we haven’t talked about that was kind of on the table at one point or another? I wanted to just check in if anybody wanted to talk about the original proposal had solar and storage and the solar disappeared in the year between the resource plan reply comment and the actual filing on this docket, but was there anything else that your organization had been talking about or that could have been included in this that was sort of a missed opportunity in terms of what the Commission ultimately went forward with?

Shannon Anderson:
Yeah. I mean, I would just say, again, the lack of competition and third party involvement is really troubling and it’s troubling from a customer cost perspective, as we’ve mentioned, but it’s also troubling from just a business growth and innovation opportunity for Minnesota question. There’s a lot of growing interest in the solar and storage industry. And in Minnesota, there’s a lot of companies that want to be partners to Xcel and be, I think, again, solution creators for Xcel on some of these problems that they have. And to kind of X them out of the proposal is troubling and sends a message that Xcel thinks that they can do things their own way. And without private sector involvement and competition, which ultimately, again, I think takes Minnesota’s solar industry and its clean energy economy is step backwards for job creation and development and innovation, which is why the parties that aren’t us, but the solar industry and the community storage industry and a lot of folks were very much at the table in this proceeding because they had a direct stake in the outcome as well and were notably very disappointed in the Commission’s decision.
And then there’s issues with using the renewable energy standard rider, interconnection queue issues, some nitty-gritty parts of the decision too, that again, are very troubling to the solar industry as a whole.

John Farrell:
I think the interconnection one is worth actually mentioning because it’s maybe not as weedy as the renewable energy rider for people who don’t do rate case stuff, but actually for a lot of people who are listeners to this podcast, we talk a lot about interconnection and notably what the Commission decided to allow Xcel to do was Xcel had proposed, we want to install our batteries without going through the standard interconnection process that a third party owned project would have to go through. We and many others expressed concern about that being unfair since Xcel is the monopoly grid operator of the distribution grid. And the Commission, I guess I feel like they whiffed on this one because they said essentially, well, Xcel has to do the best that it can to avoid causing adverse impacts to others when it skips the line, but essentially said, yes, you can skip the line. Is that pretty accurate?

Will Kenworthy:
In my view, this goes back to the original sin of prioritizing bulk power value here. If these systems were being prioritized for distribution value, it would be creating opportunity and capacity for additional DER, not penalizing it or not potentially jumping the queue on projects that developers already have in queues. And so there’s no way that anyone who’s already in a queue who’s trying to develop a project should be at all hurt by this. And I’m sure if any customers end up paying a price because Xcel jumped in front of them in the queue with their own project, there’s going to be problems. And I think the industry’s really sensitive to that and I think they have a valid point there. If these projects were used to create hosting capacity and create additional capacity for additional load and generation on the grid, then that would never be a problem.

Shannon Anderson:
Yeah. I think again, it just goes back to the ownership and control kind of issue that we’ve been talking about because typically these resources haven’t been owned and controlled by the utility in this way before. And so the queue that we’ve been talking about with interconnection right now is all third parties. It’s all private sector developers, it’s all customers, it’s every resource under 10 megawatts. So that includes rooftop solar systems and other sort of smaller systems on the grid as well. And that’s all private people sort of getting into the queue and jumping in and sort of making it work. But when you throw in larger batteries from Xcel into that queue and into that process, it just shakes it up in a way that I think the Commission hasn’t fully contemplated what’s going to happen.
So John, as you said, the standard is, it’s really vague. I think it’s going to be hard to enforce for folks. It’s a little bit troubling on what this is going to look like, but as we’ve been talking about, it’s not the end of the process. There will be plenty of opportunity for people to, I think, revisit this issue as well. But I know from the solar industry, this was one that was particularly concerning for them because again, this is their queue. This isn’t Xcel’s queue and Xcel kind of made it their queue. Interestingly enough, there was a really, I think, good back and forth on the Commission about who actually owns the grid during the proceeding. It was sort of a little bit theoretical and high level, but the grid is owned by rate payers and it’s rate payer money that has built the grid. And so the ultimate benefit should flow back to them, not to the company.

Will Kenworthy:
My goal in this is always, and the same reason that I’m in the grid modernization proceedings and the same case, the reason I’m in rate cases is we have broader electrification and decarbonization goals, and especially in states where we have specific decarbonization goals like Minnesota, like Illinois, where I also work, like Michigan, where I also work, the goal of grid modernization in that case is making the grid ready for electrification because we want a lot more load on the grid. We want more heat pumps doing building electrification. We want electrification of transportation. And the grid is the platform on which all of this stuff will happen. And so it’s really important for us to think about making the grid ready for that electrification by making sure that there’s capacity available for transportation and electrification and building both generation and load. There was some modeling done a couple years ago by a coalition called Local Solar for All that included us also where Vibrant Clean Energy used their wisdom model to model system electrification.
And the conclusion of that was that we need a lot more distributed resources, and that was both distributed storage and distributed generation. And so that’s what we’re trying to get to. And so when you make decisions that limit that and that are constraining that addition of additional generation and load, then you’re holding back that process, which are set by broader policy goals. It’s not just about the grid and Xcel’s grid, it’s about the overall goals that we’re trying to achieve.

Shannon Anderson:
Yeah. I mean, starting with affordability and making sure the system is affordable and benefits the people who need to be benefited the most.

John Farrell:
Well said, Shannon. I was actually just going to say that myself. That’s actually a great place to wrap up. I think, well, I really appreciate you taking it back to the broader context of these are the kinds of programs we need to make energy affordable to meet the future grid needs. And when we don’t get them or when they take a very long time to get developed, it is holding things up and can make energy more expensive for everyone. So I just want to say it was such a pleasure to work with both of you on this issue, which we’ve been in now for almost two years, and I just really appreciate the wisdom and knowledge that you bring to the conversation. So fingers crossed that we’ll see some more progress in Minnesota and in other places around the country, but thank you both for your work on this and for joining me today to talk more about what happened in Minnesota.
Yeah,

Shannon Anderson:
Thanks, John. It’s a pleasure.

Will Kenworthy:
Awesome. Thanks, John.

*****

John Farrell:
Thank you so much for listening to this episode of Local Energy Rules with Shannon Anderson, Virtual Power Plant Policy Director for Solar United Neighbors and Will Kenworthy, Senior Regulatory Director, Midwest for Vote Solar.
On the show page, look for links to my prior Local Energy Rules podcast interviews on the subject, including episode 241 with Shannon Anderson on virtual power plants and episode 247 with Will Kenworthy, which was specifically about this battery storage program. In addition, you can interact with ILSR’s utility bill calculator, which shows how much utility customers in every state overpaid due to excessive return on equity that’s approved by state regulators, a problem that will persist in this Capacity*Connect program because of the utility owned batteries. We’ll also link to model virtual power plant policy from Solar United neighbors and to some of the detailed filings that ILSR and other parties submitted to try to improve this important program.
Local Energy Rules is produced by myself and Ingrid Behrsin with editing provided by audio engineer Drew Birschbach. Tune back into Local Energy Rules every two weeks to hear how we can take on concentrated power to transform the energy system. Until next time, keep your energy local and thanks for listening.