To meet AI-driven load growth utilities and big tech companies have been building — or reopening — big power plants. Georgia Power, for example, is planning to expand its fleet of natural gas plants. And Microsoft signed a deal last September to re-open Pennsylvania’s Three Mile Island nuclear plant
But could we meet a portion of that load growth with distributed energy resources? Pier LaFarge thinks so.
In this episode, Shayle talks to Pier, co-founder and CEO of Sparkfund. (Energy Impact Partners, where Shayle is a partner, invests in Sparkfund). DERs can come online much faster than large, centralized generation, Pier argues. He makes the case that utilities are especially well-positioned to lead what he calls “distributed capacity procurement” (DCP) of customer-sited solar, storage, and other assets. Shayle and Pier cover topics like:
- How host agreements work, using utility-owned assets sited at customer locations
- How the effective load carrying capability (ELCC) of DERs compares to large, centralized power plants
- The relationship between DCP and VPPs
- The key tradeoff of DCP: DERs are faster to build, but cost more and have lower ELCC than large, centralized plants
- Who should pay for those higher costs?
- Why vertically-integrated utilities are best-positioned to take advantage of the value DCP creates for capacity, distribution, and transmission
- The limitations of DCP at a systems level
Recommended resources
- Latitude Media: Can distributed energy answer AI’s power problem?
- Latitude Media: Jigar Shah: It’s time for VPPs to get simpler
Catalyst is brought to you by EnergyHub. EnergyHub helps utilities build next-generation virtual power plants that unlock reliable flexibility at every level of the grid. See how EnergyHub helps unlock the power of flexibility at scale, and deliver more value through cross-DER dispatch with their leading Edge DERMS platform, by visiting energyhub.com.
Catalyst is brought to you by Antenna Group, the public relations and strategic marketing agency of choice for climate and energy leaders. If you’re a startup, investor, or global corporation that’s looking to tell your climate story, demonstrate your impact, or accelerate your growth, Antenna Group’s team of industry insiders is ready to help. Learn more at antennagroup.com.
Transcript
Tag: Latitude Media: podcasts at the frontier of climate technology.
Shayle Kann: I’m Shayle Kann and this is Catalyst.
Pier LaFarge: It’s easier to build lots of small things quickly than it is to build a few really big things slowly
Shayle Kann: Coming up. Why are we talking so little about distributed energy to solve our load growth problems? I’m Shayle Kann. I invest in revolutionary climate technologies and energy impact partners. Welcome and happy New Year. So I think by now probably every listener to this podcast is familiar with the general state of affairs, which is that we have a lot of electricity load growth in the western world and in the United States that has taken the industry somewhat by surprise. It’s becoming a bottleneck as it pertains to the growth of AI and data centers and manufacturing and so on, and everybody’s trying to figure out what to do about this and there’s lots of components to it. One of the ones that I think is sort of overlooked though is that clearly we need a lot more electricity capacity and the discussion around that, at least most of the discussion around that that I’ve seen has been, okay, how do we build enough new big power plants and then how do we build enough new transmission distribution infrastructure to deliver that power to customers?
And so that’s where you get to these things like the spate of recent announcements about opening shuttered nuclear plants or building new nuclear plants and then obviously building a lot of new natural gas and building a lot of new renewables and storage too, but all at the centralized level. What we’ve been talking about less in this particular regard is whether distributed energy, small scale resources generally cited at customer premises can help alleviate that bottleneck as well. It’s not a new concept, right? This idea of virtual power plants and so on has been around for a long time, but I do think it gets less attention as it pertains to what it can offer, which is speed. You can generally build this stuff pretty fast because you’re building in smaller increments and you don’t have as long a timeline around permitting and interconnection, all this kind of stuff.
So if the biggest problem in the market is speed, why don’t we look more at distributed energy or maybe we will. Anyway, somebody who is, is Pier Lafarge who is the founder of Spark Fund. Spark Fund, by the way, a portfolio company of my firm, Energy Impact Partners, but Spark Fund has been in the distributed energy game for a long time, more recently. Thanks. In large part to that IT dynamics in the market that we see today, Spark Fund has been promoting this concept of distributed capacity procurement, which is basically utilities saying, okay, I’m going to procure a bunch of resources to meet all of my low growth needs and to replace retiring generation and so on. Some of that should be distributed. Not all of it’s centralized. There’s a lot of nuance to what that would have to look like and the value would actually offer and so on. So I brought Pier on to talk about what that looks like and more broadly how distributed energy resources can and can’t help meet the load growth needs of our modern times. Here’s Pier. Pier. Welcome.
Pier LaFarge: Hi, Shayle, nice to see you.
Shayle Kann: Hi, nice to see you. It’s been a long time coming to have you on this, but the timing is good because you’ve been thinking a bunch about something that I’ve been wanting to cover here, which is I think that the average catalyst listener is probably well aware of the phenomenon going on in the power sector right now driven by a whole lot of unexpected load growth predominantly from data centers and to a lesser extent from other things and oh my God, how are we going to meet all this load growth and what are the implications on the market and so on. I don’t think we need to rehash all of that, but I guess before we get into how distributed energy may provide at least part of a solution to that, maybe at least more so than I think we are generally hearing in the discourse. Anything you would add from your vantage point? What are you hearing from the market from utilities about how this is playing out right now?
Pier LaFarge: Well, look, I think you’re right that the concept that we’re in this holy crackers load growth moment is well established. The point I’d make about it is how quickly that became conventional wisdom and how quickly the large macroeconomic trends like new manufacturing and data centers roared into being. And simply 24 months ago, electric vehicles were the biggest driver of electrification growth and now it’s a distant third, and that happened stunningly quickly and I just think that’s really worth pausing on and it’s been fun and exciting and I think we should give a lot of space for how much the entire energy transition market from utilities to regulators, to state legislatures, to startups and investors have to adapt to what that new shift means. I think my point would be downstream of that new conventional wisdom, there’s still a lot to figure out when it comes to the so what.
Shayle Kann: Yeah, the other thing I’ve heard a few times that has resonated with me about not just how quickly it has become the conventional wisdom, but the sense that the industry was a little flatfooted in responding. I think one of the reasons for that is that it took a little while for it to be clear how different this is. Then even pretty recent, previous waves, utilities saw a lot, many utilities, not all. Now it’s basically all but a few years ago, Bitcoin miners, a ton of wild west type Bitcoin miners were coming to them in their territory saying, I’m going to put hundreds of megawatts of load on your grid and I can be super flexible and all this. And then a lot of that actually, especially when Bitcoin prices crashed, a lot of that disappeared and so they got kind of burned some of ’em on that, and so they were a little slower this time. Same thing with cloud data centers. There was a lot of load growth coming from data centers. They had been seeing it already, and so there was a trajectory that now is just steeper, a lot steeper than it was before, but you can understand how it took a while to come around after even after GPT-3 or whatever your seminal moment was. It took a little while for everybody to come around to like, oh, this is a different paradigm and we got to figure out how to adapt to it.
Pier LaFarge: Yeah, great point. I mean even going back a whole generation further, the internet and personal computing was once forecast to create a legendary amount of new electric demand and it didn’t, and efficiency cut faster down than a huge wave of new devices in the home increased, right? So in some ways I think it’s really understandable when people say, okay, fool me once, fool me twice. Will this happen again? I think that that’s a sober and well anchored way to ask a question. But even when you think about it, seriously, I think what a lot of people miss in this moment is even if you haircut the forecast growth in data centers and manufacturing by 80 or 90%, you still double the grid. And something I think we need to say more as an industry is doubling the grid is not the high end reference case here. It’s not the sort of what might happen if it all comes to pass doubling the grid is increasingly a eroded baseline infrastructure case that has to be responded to and in and of itself is unprecedented almost.
Shayle Kann: Okay, so we are in this new paradigm now and there is all this expected load growth and at least enough of it seems real to your point, doesn’t all have to be real for it to be pretty game changing. I think what a lot of the broader discussion in the industry is focused around is, okay, how do we build enough new generation and enough t and d capacity to meet all this new load growth? What you’ve been focused on, which you’ve been focused on for much longer, but now has sort of new applications in this new world, is how can utilities take advantage of distributed energy resources DERs to deliver some of the power that they need to deliver I guess to meet this moment. So I want to talk a little bit about what that looks like, what it can actually offer, compare and contrast a little bit, but talk to me about this concept that you’ve been promoting, which is you’re calling distributed capacity procurement.
Pier LaFarge: It’s pretty simple in some ways. The first layer of a distributed capacity procurement is just asking a utility to be a utility, which is plan how much it needs to generate and move electricity, where it needs it and what type of assets would do that and then go buy them and put them into the world and run the grid. So at its simplest, it’s really just an extension of the thing that has been happening for a century in terms of utilities, but there is obviously that first letter, the distributed piece of it is really different. It’s a different type of asset and I think the focus that we have on it really comes from the fact that it’s easier to build lots of small things quickly than it is to build a few really big things slowly and building big things in the country is hard for permitting, for environmental regulations and interconnect queues and capital formation, all sorts of different of well understood reasons, certainly by the folks who listen to Catalyst and that time lag of building new big central generation and transmission and distribution projects, I think is a big reason why distributed resources have an opportunity.
Shayle Kann: When you talk about distributed resources, are you talking, is the delineation for you, is it scale, I dunno anything under 20 megawatts or something like that or anything at the distribution level, not the transmission level, or is it about it being customer cited? I think that drives a big difference because on one hand, so what utilities, if you remove the D from distributed capacity procurement, it’s just capacity procurement. What utilities traditionally do, they say, okay, I’m going to file my integrated resource plan. I’m going to determine what resources I need. I’m going to say, okay, I need whatever. I’ll give a small number. I need 500 megawatts of new capacity. Okay, I’m either going to build that and reap base it or I’m going to go off and I’m going to buy power from some third party owner, and that’s the model. The thing you could imagine being very similar but just smaller is we’re going to do the exact same thing. We’re just going to build a bunch of smaller things or we’re going to buy power from a bunch of smaller things. The thing that’s a little bit more disruptive I guess to the model is where you’ve got something that has dual use. I think because it is cited at a customer site and the customer also wants to use that thing for something, that’s what makes it a little bit more complicated in my mind. So are both of those included in the model you’re describing or is it predominantly the latter?
Pier LaFarge: That’s a great question. It’s a really well phrased way to get at this basic tension and look, the exciting answer is we’re all figuring this out in real time together and it’s going to be different in different utility territories. But our view or my view is that it’s more the later the latter that most of distributed capacity will end up being customer cited and have some aspect of dual use, even if that dual use is primarily just a new, the grid functions, and this is where it gets a little nuanced. If you put batteries and solar all over a region, let’s say one feeder that has 900 buildings, if you put batteries and solar on 500 of those 900 buildings, that feeder with the ability to generate and store electrons in a way that makes that feeder so reliable that I think it blurs the distinction and we need new ways to talk about then what is resilience, what is reliability?
What is the boundary between the grid and the building services? We’ve talked about the two with a lot of delineation when we sell resilience to a customer as a service, that is sort of the inverse of the service they get from the grid. And I think that boundary along with a couple of other boundaries like behind the meter and the front of the meter, I think are going to start to blur. The real reason that a distributed capacity procurement focuses more on customer cited assets than just size format is actually a pretty pragmatic reason, which is in a lot of the places of the grid where you need the capacity, there just isn’t space to put that many assets unless you use customer addresses. You sort of have to, it’s like if you look at a downtown in Atlanta or Minneapolis, the place you could put batteries that is relevant to the distribution grid is on or around buildings.
Shayle Kann: People have been talking about in this sector for, I dunno, well over a decade, the concept of virtual power plants and at first blush, I think they sound kind of similar to what you’re describing, just taking your first example there, you’ve got a feeder 900 buildings, you’re going to put solar and storage on 500 of them. You’re going to sort of control them. We haven’t talked about control yet, I guess which we will, but presumably you’re going to control them in concert in an aggregated fashion that sounds like a virtual power plant. Is there, apart from terminology, is there any difference in what you’re thinking distributed capacity procurement looks like versus just a bunch of virtual power plants?
Pier LaFarge: We see the distributed capacity procurement concept as a part of the virtual power plant moment. I think A DCP is just one way to achieve that outcome and the assets would be installed on customer locations. They’re paid for by a utility as part of their infrastructure to run the grid. They are operated and dispatched by the utility, whether there’s a third party that has some sub derms or an aggregator that then feeds into a utility. Derms, I think is an open question. So there’s space for a couple layers of control probably, but ultimately it’s the utility that needs to know when it needs capacity and of what type and make the decision to dispatch or energy. And in that context, we think that A DCP is basically a utility LED VPP one Other distinction draw is that when we talk about distributed capacity procurements, the conversation is starting with but not limited to batteries and solar, the kind of hard assets stuff you install that’s net new capacity either in storage as a distribution asset primarily or and or solar as a generating asset, but there’s lots of room for distributed capacity procurements including downstream of that thermostats, connected assets, water heaters, even vehicles.
Shayle Kann: Yeah, well I think it makes sense because as we said before, the sort of traditional, what a utility does is procures generation and capacity, which is effectively generation and storage. If storage is acting as a capacity resource to some extent or at least shifting generation. So this is doing that at a smaller scale in a different paradigm. It gets a lot more complicated when you add thermostats and electric vehicle chargers and things like that because shifting load around, you have counterfactuals, all these other things. But you did get to the core of I guess the business model piece here, which is as you think of distributed capacity procurement, this utility is owning and operating stuff at customer sites. This is obviously going to be situation dependent, but so what is the contract or what is the agreement between the utility and the customer whose site you’re putting this at?
Pier LaFarge: It’s a host agreement. What we’ve seen work in the first procurements that we’ve as Spark Fund have helped a utilities deploy is a hosting agreement where you go to a customer and say, can we put this asset on your building and we will pay you, we will rent the space from you and give you a long-term risk-free annuity. So it’s great for the building owner or the landowner because you get money with no debt, you don’t have to sign up for any sort of financing, you don’t have to sign up for maintenance or any other obligation. You’re really just getting a payment stream that’s risk free for the duration of the asset life, which could be 10, 15, 20 years. So it’s a nice long-term annuity to the customer, but that customer then becomes a host and they’re hosting a piece of the grit.
Shayle Kann: And are they being offered any, are they getting backup for example?
Pier LaFarge: It can, yeah. I mean this is up to every utility program design and to regulators to some extent. But in most cases what we’re seeing is utilities giving either first priority to backup to a customer in an outage event or some sort of residual charge. Like say the customer gets a guaranteed access to 20% or 50% of the battery or the fuel. So yeah, the customer gets that resilience benefit. Again, I’ll go back to my feeder sort of example where if you have a feeder that has so much storage and solar on it that it becomes basically totally reliable like fractal, I think of that as fractal reliability. All of a sudden how often they need that resilience is another question. If all of your neighbors had these things, right, is that just the grid being reliable or is that everyone having resilience? I mean I think you can talk about it both ways, but that’s kind of back to my point of we need some new ways to talk about some of the distinctions that have been with this industry for decades, but are starting to blur.
Shayle Kann: Let’s talk about the capacity value I guess that this is offering. I mean, in your mind, does a kilowatt of solar at a customer site or a kilowatt of energy storage or kilowatt hour or whatever, is it the same? Should we think of it from a capacity value perspective as being the same as centralized procurement? If utility says, for example, in their IRP, we think we need two gigawatts of solar and a gigawatt of four hour energy storage in the next five or 10 years. Is your idea just sleeve off a quarter of that or whatever the number is and do that through distributed means? And do you think of that as being equivalent or are there key distinctions we should be thinking about?
Pier LaFarge: So yes, I think about it as taking a piece of the needed growth and delivering it through distributed resources, but there’s definitely some other key considerations like fundamentally the ELCC ratings for distributed resources like solar and batteries are not as high as they are for say, a gas plant, right? I mean the just simple reality of all renewables.
Shayle Kann: I suspect 25% of Catalyst listeners know what ELCC is, it’s a scientific guess, but can you explain effective load carrying capacity?
Pier LaFarge: Yeah, so effective load carrying capacity is when you have groups like PJM and MISO that say, here is what this asset is allowed to count towards what you need. So if a utility says, I need a gigawatt, if your carrying capacity factor is 50%, well then you need to build two gigawatts of that thing to have the gigawatt.
Shayle Kann: It’s like the capacity credit you get for a given resource.
Pier LaFarge: Yeah, it’s like you times nameplate times a percentage and you get less than what you hoped. I always think of it as the regulatory version of sort of entropy in the world where this doesn’t work quite how you think it works as much of the time.
Shayle Kann: So you’re saying ELCC for distributed stuff is lower. In other words, it’s sort of been determined that a given resource with the same nameplate capacity will have less capacity value at the distributed level, which means you need to build more of it for the same value, which I guess gets to maybe a bigger picture question for me, which is all things equal, my presumption is that building out a suite of distributed resources is going to be more expensive just from a CapEx perspective than building. I mean, I know this to be true, right? Of course, it is true that it is cheaper. There’s economies of scale, it’s cheaper to build big things, so in aggregate’s going to be more expensive and there’s a little bit less capacity value, so you got to build even a little bit more of it for the same value. So is the trade here faster time to power or faster time to capacity in exchange for a slightly higher cost? And if so, is that the kind of thing you think should be borne by the new large load customers in the way that some of these utilities have been thinking about these differentiated tariffs for the hyperscalers and things like that where they do have higher willingness to pay in exchange for faster time to power? So does this fit into that paradigm in your mind?
Pier LaFarge: So I’ll start with the end and then work backwards. Yes. I think that high load customers like manufacturing and data center operators can and will be a really big part of this moment in grid history. They will pay in much of the incremental cost because of how they value time to power and total availability of power. And just to pause on that for a moment, I think there’s a really simple but really interesting reason why they’re willing to pay. It’s not because they’re rich, it’s not because they have tons of money. It’s actually because to get the economy we want that has more onshoring manufacturing that can compete with China, that has data centers that are in Kansas and Ohio, not in Saudi Arabia. There are reasons we want these buildings in the United States. They’re economically valuable, they’re geopolitically important, and we want them here. So to have that economy, they create jobs, they create municipal tax revenue to unlock that economy from 2025 to 2050, say we need to build a bunch more power infrastructure.
So everyone including society has an incentive to build the power infrastructure that unlocks that economy with new onshore American manufacturing and data centers to fuel generative ai. The metaphor I would draw is 1947, we invested furiously in our power infrastructure through the electric grid because we wanted the economy that would be created by auto manufacturers and tire companies and washing machine appliance makers, right? General Electric Ford. They delivered the post-war economy and it was unlocked by a historic upfront investment in the US electric grid. That’s the moment we’re in. And electric infrastructure in the United States in 2025 is now a gating item to have the flourishing economy we want for the next 20 or 50 years.
Shayle Kann: Back to the question though a trade, do you think that, is it appropriate to think of this as a trade between faster time to power, slightly higher cost of capacity?
Pier LaFarge: Yes, with a couple of steps. The way to think about it is a value stack distributed resources are much more expensive than centralized resources, and their accredited capacity is much lower, right? A gas plant in PGM is close to 80% accredited load and solar with no storage is 8%. So it’s not even that close.
Shayle Kann: Well, but I guess I was trying to compare, I mean, that’s not a fair comparison. The fair comparison would be a rooftop solar project as compared to a centralized utility scale solar project.
Pier LaFarge: Sure, that’s true. Yes, that’s a good point. And then you have a little bit more similarity, and really what you’re talking about is overcoming the incremental cost of installing a smaller amount of things, in which case the cost of the project is divided over fewer megawatts. So yeah, for sure it is both less accredited than centralized fossil resources. But also if you’re comparing renewables to renewables, it’s just more expensive per megawatt because of the construction costs
Shayle Kann: And I think soft costs as well, notoriously higher for small stuff. The smaller you get, the more your soft costs start to really hurt.
Pier LaFarge: The good news though is when you pair solar with storage, your accreditation rating goes back often into the high fifties or even low sixties. So part of where I was going with that is solar and storage together have a pretty strong contribution to grid needs. Let’s just take that example where you need a gigawatt of capacity, and let’s just say that to achieve that gigawatt of capacity, you need 1.6 gigawatts of nameplate solar and storage. I’m sure there are people who listen to your podcast who know how to do the math more sophisticatedly than I do, but that’s roughly how I think about it. It’s like to get one, you need to build 1.6, and the way to decide in a given utility territory, if that’s a good idea or not, is to stack value. So you can say, okay, if I have a accredited gigawatt of solar in storage, how does that compare to the cost of a peaker plant or other generation?
So there’s already some value you can compare there. The next step is because I put that solar in storage because it’s distributed now all over my grid in the places it needs it most, that also target places that have congestion, then I have a capacity or congestion value that a lot of utilities and grid operators know how to price. So that adds some money. Next you say, well, if I had transformers that we’re going to overload with this grid growth or because they’re old and now I don’t need to replace them because the battery can absorb the times where there’s a big spike in usage or transmission that would otherwise overload them. Well, great. I can take the money that I was otherwise going to spend on a bunch of transformers out of my budget, and that’s good because transformers are both very expensive and very supply chain constrained, and we’re going to need to build a ton of them anyway.
And then after that, you have that same experiment of avoided infrastructure costs repeated for, well, do I not need to rebuild this substation? Do I not need to double the size of a feeder and even into transmission? So you start with generation, you go through the capacity and congestion of a grid, and then you go into the distribution and transmission where by putting a bunch of solar and storage everywhere, how much less money do you need to spend and how much value do you create to achieve the same grid outcome that then supports those manufacturing facilities and data centers? And when you run that math, as far as we can see, and look, it’s early days, a lot of utilities are in the process. A lot of regulators right now are starting to get their hands around that math. But it seems like when you stack up that value kind of stacking bricks of value, it’s actually a pretty good idea and a pretty cost-effective idea to put solar and storage everywhere.
Shayle Kann: It seems like you could also, this rests in the hands of the utility, but the utility should have visibility into where it has most value in their system. You mentioned the feeder with the 900 buildings. Well, if that’s the feeder that would see the highest distribution cost value, then that’s where you start potentially where the value stacking is strongest.
Pier LaFarge: That’s right. Although I would say being in real conversations with real utilities and regulators right now about, okay, which feeder, it is amazing in some ways how they’re just starting to do some of that thinking and modeling. The grid was run big centralized stuff out into big straws, which are transmission that push into lots of little straws which are distribution, and then you turn on your oven or your toaster and running that with more steps backwards of where do I put lots of small things that can change the need of each piece of those system of straws I think is very new thinking and has some real complexities. There are definitely companies out there that know how to do that math, that have software for it, and this is work that’s going to get done. But I actually think one of the real values of the distributed capacity procurement idea is that when a utility brings a gigawatt of distributed resources into their central planning process, they put it into that plan. All of a sudden they then ask the question, okay, what work do I need to do downstream of that to know where to put it and how to optimize the value. Actually what utilities and regulators do in an IRP is they say, how much do I need of what type? Where do I put it and how do I optimize the value?
Shayle Kann: I guess just to wrap it up, I mean you mentioned this can be faster. How scalable is it? In theory, you could do the like, well, how many buildings can we put solar on and how much space is there for batteries? And you can imagine, right? Lots of building, it’s a huge number. But from your experience, what actual, what are the rate limiters on scalability here?
Pier LaFarge: Well, no one knows because we haven’t tried this at this scale. I am proud to say that I think Spark Fund has some insight into that from the decade we’ve been doing this with utilities in some ways that are very similar and some that are different. But the way I’d answer the question is really a thought experiment shale, which is, let’s think about the three mile island example. Microsoft famously contracted for the power from a resurrected three mile island through with Constellation, and that was 800 megawatts of Baseload capacity with a really high accreditation rating. So when that turns on, they’ll get 800 megawatts and that’ll go onto the grid. They’re not going to build a data center right next to it, as far as I know. So it goes onto the grid and then they just buy that much power. So theoretically, that 800 megawatts could be anywhere on the grid. It just has to be in the grid so we can buy it. So the thought experiment would be, well, if you had 800 buildings and you could build 1.6 megawatts of solar and storage, which you can in some buildings, mediums size and big buildings, then great. Go find 800 buildings that can host 1.6 megawatts each of solar and storage. And there you go. You’ve got a new legacy nuclear power plant that’s just located on 800 buildings.
Shayle Kann: Yeah, I think as a first order of thought experiment, that makes sense to me. I guess the pushback you would get is absent outages, nuclear is operating 24 7 and solar plus storage, even with higher accreditation thanks to the storage is still not, I mean, so you can do that at the individual level. You can’t do that at the full system level, that analysis. You can say, okay, could this amount of solar plus storage replace a single three mile island? Probably yes. But at the system level, ultimately you’re still going to need some kind of either more storage, more generation and more storage if you want it to go 24 7 or some backup of some sort, probably natural gas. And so I think that does make sense, and this is where things always get wonky when you get into these debates about this kind of stuff is like these things work at the micro level and micro can be big. Micro can be 800 megawatts for sure, but there’s some limit to it,
Pier LaFarge: Right? Look, I think this is a really exciting boundary of understanding, and I think this is where my expertise in how accreditation, for example, works in the physics part of the grid. The way I understand a capacity rating is that if you take the name plate of solar and storage and times it by that number, you should get the amount of energy and capacity that you can use on the grid, like anything else, it’s a way to standardize that variability with that calculation. But I would honestly love to hear in the comments of this from the readers, I don’t know if that breaks down at some system scale because of the details and the physics from inertial balancing to load management and conductivity temperature. The grid is a really, really, really, really complicated machine as you well know. And I think that at a simple ish level, the accreditation math should allow you to say, okay, by building 1.6 megawatts of solar and storage on 800 buildings and timesing it by that factor, that’s the amount of capacity you should be able to sell.
But I think you’re right that it’s possible that that’s a little bit more of a contract and market function than it is a physics reality. And I think this is also going back to sort of my core argument here. One of the reasons why utilities and particularly vertically integrated utilities are so well suited to this, is that they are the grid operators that can see the whole darn grid at once transmission, distribution and generation. And their job day in and day out is to live in those nuances, in those physics, in the onic act of having the grid keep your lights on, your shower is warm and all that stuff. So it is grid operations that ultimately is where the rubber is going to meet the road because the grid is not a metaphor or a set of contractual optimizations or just a commodity environment. It’s a very physical thing that does real work for real people.
Shayle Kann: And regardless, I think the more immediate point, right? I’m talking about long-term macro replace the whole grid kind of thing, but realistically, in the near term, it is clear to me that we’re entering this period of what appears to be really high load growth. It is an all hands on deck kind of a situation throughout the power sector. Obviously, we should be considering distributed energy within the mix of the things that can help solve that problem. And it does have some unique advantages in time to power in particular, but others as well has unique challenges. But for every conversation that we see publicly about a three mile island or a nuclear restart or something like that, there should certainly be one about the 900 buildings on a feeder that can host a megawatt of solar and storage. So happy that you’re, I completely agree, pushing that idea forward and as always, very fun to chat with you. So thank you so much for the time, pier.
Pier LaFarge: Of course. Thanks, Shayle. Thanks for having me on.
Shayle Kann: Pier Lafarge is the co-founder and CEO of Spark Fund. This show is a production of Latitude Media. You can head over to latitude media.com for links to today’s topics. Latitude is supported by Prelude Ventures, prelude backs, visionaries, accelerating climate innovation that will reshape the global economy for the betterment of people and planet. Learn more@preludeventures.com. This episode was produced by Daniel Woldorff. Mixing by Roy Campanella and Sean Marquand. Theme song by Sean Marquand. Stephen Lacey is our executive editor. I’m Shayle Kann, and this is Catalyst.
