All Episodes [Episode #134] – Storage Grows Up Nov 11 2020
[00:05:22] Chris Nelder: Welcome back Jason to the Energy Transition Show.
[00:05:25] Jason Burwen: Thanks, Chris. Glad to be back with you.
[00:05:27] Chris Nelder: You last joined us on the show way back in 2015, which was Episode #8. And at that time you’d just started at the Energy Storage Association, where you are now the vice president of policy. But the storage sector was really just getting started then and now it’s getting to be a significant business. So just to get us started here, why don’t you give us a quick recap of what has changed since 2015?
[00:05:48] Jason Burwen: Yeah, I feel very fortunate to have been present in front row seats for the last five years as the US energy storage industry has grown and evolved. So when I joined the Energy Storage Association in 2015. There were, I think, just over two hundred megawatts of battery storage operating on the grid, almost all of that was front of meter. Most of it was less than one hour in duration. And the reason that it was all mostly less than one hour in duration is because it was being used almost entirely for frequency regulation, which therefore meant that most of it was showing up in the two markets where the first economic case for energy storage, PJM and ERCOT’s fast responding regulation markets and these assets were again almost entirely standalone storage, directly connecting the storage assets. At the same time as that was happening, we in 2015 had yet to see a utility integrated resource plan seeking or selecting storage that was not pumped hydro power and certainly outside of California, which at that point was just getting its energy storage procurement mandate off the ground. That was it. There was no procurement happening outside of California.
[00:07:16] Chris Nelder: And let me just offer a quick clarification there. So when you say front of meter, that means it’s on the utility side of the meter. In other words, these are utility scale utility assets essentially that were being used to, as you say, provide frequency regulation, which is something that needs to happen on the grid, doesn’t have anything to do with what happens really on the customer side. And those storage assets were participating in, as you say PJM, which is the the wholesale market that operates in sort of the midwest-northeast part of the US and ERCOT, which is the structured wholesale market in Texas. So back then, in 2015, these were utility scale projects that were bidding into structured wholesale markets that were not really part of the retail utilities. They weren’t something that was happening on the customer side of the meter. And they weren’t really participating as what we now think of as DERs or distributed energy resources.
[00:08:14] Jason Burwen: Yeah, and we were all super jazzed because look at these awesome batteries providing frequency regulation, getting paid, managing to be like a profitable endeavor, which is why PJM’s market got suddenly a lot of battery storage. And it’s funny to think about that now because from where we sit here in 2020, I mean, that was incredibly important. You know, I think back then, Terry Boston, who was then the CEO of PJM, he saw this as being a really important means to bring battery storage into the electric system. And it wasn’t batteries that were first doing it. It was like flywheels that had kind of blazed the path. The folks at Beacon Storage had been really the pushing forces on things like FERC Order 755, which set in place the pay for performance rules. A lot of history here. I don’t want to bore you with the history, but it was just at that point in time, things were exciting. It’s been quite a journey in these last five years to where we are now.
[00:09:17] Chris Nelder: Right, so where are we now?
[00:09:19] Jason Burwen: Well, let’s see. Here we are in the second half of 2020. I have to double check exactly what’s been installed on the grid, but I think we are close to two gigawatts, that is to say, 2000 megawatts of new battery storage installed on the electric system. I think…
[00:09:39] Chris Nelder: So, that’s just to put that in perspective, that’s 10x what it was in 2015.
[00:09:44] Jason Burwen: Yeah… I don’t think we’re quite at the two gigawatt mark. I think we’re between one and a half and two. But it’s hard to track because new stuff keeps coming online like it’s a regular occurrence, whereas it used to be like each new battery was like its own celebration. And another thing to know about that is that a third or so of that installed capacity is behind the meter.
[00:10:08] Chris Nelder: So on the customer side of the meter.
[00:10:10] Jason Burwen: Exactly. That’s being driven in large part out of California, but also in Hawaii and some other jurisdictions where customer cited storage is really starting to move. We have, I think, just a significant amount of storage that’s in the pipeline as well, depending how you count. I’ve seen interconnection queue requests in the somewhere around the 75 to 80 gigawatts range. Obviously not all that will get built. But you’ve got contracted amounts showing up at the gigawatt scale in a number of states where we are seeing utilities now sort of taking storage on not at like a tens of megawatts, but in the hundreds of megawatts, often totaling gigawatt hours of stored energy capacity in one go. I think the biggest single procurement recently announced with Southern California Edison, 770 megawatts of storage in one procurement and another key change here certainly is that those durations are now reaching in general, I don’t think I’ve seen folks signing contracts and starting to install things these days that are anything less than four hours because energy storage is being deployed to provide resource adequacy. It’s part of the capacity of the system. It’s not just the sort of short run stabilization of the grid like those frequency regulation batteries, but it’s competing with power plants and other things that traditionally are considered the reliable supply of the electric system. Another thing that I think is exciting to see is that we have very diverse ownership structures. Back in 2015, those batteries in the PJM and other markets, those were IPPs, you know, independent power producers. Independent power producers continue to be a huge driver of storage. But one of the big, big changes here is regulated utilities who were more or less completely absent from energy storage procurement in 2015 are now significant owners and operators of energy storage systems for their electric system. And as I mentioned, customers too. The third of this installed being for customers. Outside of that, these assets are being put into increasingly hybrid configurations, primarily with solar power. But we’ve seen wind storage hybrids. The first hydro and gas powered storage hybrids are operating and there are plans now for hybridization with basically geothermal. I’ve heard folks talking about theoretically nuclear. There was just a desire to put storage on everything. And last but not least, it’s not just a part of the supply anymore. It’s being deployed for transmission and distribution infrastructure. In some respects, I like to think that the last five years had been largely a process of mainstreaming storage as a part of system supply. And it could be that these next five years are going to be a process of mainstreaming storage as a part of our electric system infrastructure.
[00:13:30] Chris Nelder: And storage projects are actually doing a lot more than frequency regulation now, too, aren’t they?
[00:13:35] Jason Burwen: Yeah, I mean, not only supplying resource adequacy. I mentioned there’s folks who are building these storage units as a part of complementing or even sometimes substituting for transmission or distribution system network capacity. Customers are using it to manage their bills, especially if they face things like demand charges or they have time varying rates or have resilience needs. So you’ve got some real broadening of the applications of storage in our electric system, diversity of the ownership models and expansion of the performance capabilities of these assets. I think it’s not too early to say storage has gone mainstream.
[00:14:16] Chris Nelder: Yeah, I mean, it’s sort of like the Swiss Army knife of energy, right? Like it can sort of do everything depending on how you can figure it and how you use it.
[00:14:24] Jason Burwen: This is the thing grid operators and utilities and asset managers figure out is that you’ve got something that’s just you know, I almost think that if you’re going to use an analogy, the smartphone is probably a better analogy. You’ve got something that is capable of doing what you configure it to do. And that flexibility provides you an enormous amount of operational capabilities. You can derive enormous amount of efficiencies if you use it right. And to be perfectly honest, this is where the smart folks are headed in the electric system, because it’s not just about selling kilowatt hours anymore. It’s about moment to moment making sure that you are moving energy across time to exactly when it is most valuable and that is a sophisticated game.
[00:15:14] Chris Nelder: And maintaining grid power quality and all that along the way. I think in the energy world, this, whatever it is, let’s call it 10x increase in capacity in just five years. I mean, that really counts as a very large and rapid shift. So what were the main enablers of this shift, like was it mainly state level utility procurement policies or was it just batteries getting cheaper? And so the market effects are really kicking in? Or was it FERC Order 841, the federal level order that instructed wholesale structured markets, the RTOs and ISOs to figure out how they were going to allow these newfangled storage assets to participate alongside the old fangled conventional generators? Or was it sort of all of the above? Like what were the main policy drivers here?
[00:16:02] Jason Burwen: Yeah, the biggest one, which I think you touched on, is certainly the rapid decline in cost. And that’s not because of the grid, that’s because of electric vehicles driving a massive expansion in the global scale of particularly lithium ion battery manufacturing. And so grid storage, grid battery storage has ridden the coattails of that expansion in those economies of scale. And that’s part of why the costs of these systems have dropped much faster than I think previous experience in energy system transitions have historically shown, because this is not being driven by the grid, it is being driven by different applications. This changes year to year, but I think certainly from where we were in 2015, the installed costs of battery storage on the grid were declining 50 percent every three to four years. So that’s getting you quickly down that cost curve. And that’s, of course, why storage could go from less than one hour to four hours, why it could go from being sort of smaller, maybe single digit or occasionally double digit megawatts to triple digit megawatts.
[00:17:18] Chris Nelder: It just occurred to me that there’s sort of a parallel here with solar in that what really enabled solar panel manufacturing to get going was the large availability worldwide of highly refined silicon, and that was being driven by computers who are using it to make semiconductors. So it was actually a very different industry that really helped manufacturers of semiconductor chips get down the cost curve. And that was a really key enabler of being able to manufacture solar panels at scale at lower and lower prices. In the same way here, now you’ve got battery storage on the grid, taking advantage of the massive cost declines and the scaling capabilities that were developed by EV manufacturers or battery manufacturers for EVs, kind of funny.
[00:18:10] Jason Burwen: Yeah. And before that, consumer devices too which lead this. So when you have those different industrial sector linkages, combined with the fact that these are modular, you know, you’re making tiny units that put together to put into the larger facilities and you have a product cycle time that’s very short. The amount of time it takes to iterate a production line of, say, lithium ion battery cell is way faster than turning over a new turbine design. So just the ability to iterate the production process to gain efficiencies in performance is it’s hard to find something that’s going to compete that quickly if you don’t have those built in advantages to the way this manufacturers and scales.
[00:18:57] Chris Nelder: Well, in addition to the cost declines, then, what are some of the other drivers? Because I think that really policy played an important role too here didn’t it?
[00:19:04] Jason Burwen: And I’m not just saying that as a complete policy geek or someone for whom the last five years has been a relentless exercise in pushing the envelope on public policy and energy storage. So certainly, you know, one of the most catalytic parts of this have been state storage targets. California, of course, the first among them, and a ton of credit for California’s energy storage procurement targets in driving much of the early investment and learning by doing that was one point three to five gigawatts by 2020, handily met before this year. But California wasn’t the only one we saw in Massachusetts in 2016, implementing its first target in New York, following in 2017. And, you know, a steady drip, drip, drip of these to where we are now here in 2020. The latest state earlier this year, Virginia establishing its energy storage target. 3100 megawatts by 2035, such that we have now across the seven states that have done this, over 11 gigawatts of storage deployment being targeted through these state policies. So that’s definitely a key part of the policy story here. I think another key piece that is perhaps equally important, particularly for the distributed segment, are some of the incentive programs here, California’s self generation incentive program. Now, New York has its market acceleration bridge incentive program, again, to sort of just a grab bag of different states where we have now over one billion dollars that have been put into sort of incentive programs to drive the early installations and get the soft costs down of energy storage installations. That’s been key. And again, particularly for the distributed segment, something that I think is underappreciated. I’ll get to FERC Order 841 because there’s obviously plenty to talk about on the first side. But one other piece on the state side that I think is definitely worth mentioning is the planning reforms that have been undertaken in a number of different states. My hat’s off to the Washington State Commission back in 2017 with really the first policy saying, hey, you know, if you’re a utility that has a resource planning requirement, you have to look at storage and you have to look at it appropriately. You can’t just check a box here. You have to really try. And several other states have followed by passing integrated resource planning reforms, whether by regulation or by legislation that’s been complemented with utilities in some states, taking it upon themselves to actually start including energy storage in good faith in their integrated resource planning. And looking ahead, I’m fond of saying IRP is the new RPS. When you are in a world of cheap clean energy technologies, this is now about how do you look at the portfolio and analyze what’s going to be cost effective going forward? Because that is, that is an exercise that is non-trivial. And I think that more and more attention is being paid to integrated resource planning precisely because that’s where a lot of these decisions upstream of the procurements are being made. So now we have I mentioned in 2015, there was no storage in integrated resource plans that wasn’t just pumped hydro. I count now north of 18 gigawatts of storage being selected economically. Integrated resource planning is just saying this makes the most sense for the ratepayer, 18 gigawatts over the various 10 to 20 year horizons of these plans across the United States. It’s not just coastal progressive thing anymore. You’ve got storage and integrated resource plans in places like Georgia and New Mexico and Indiana. It’s showing up everywhere. And I think that is really important and impactful. On the FERC side, you mentioned Order 841. Certainly that’s another thing that has changed since 2015. In 2015 we were yelling and screaming to get attention to this issue that storage is a square peg in the round hole of wholesale market rules. We have to call it a generator, but it doesn’t look like a generator. So we were running up against challenges, energy storage industry members were being told nope you’re not allowed to participate in our ancillary services market or energy markets because you don’t look like what we think you need to look like.
[00:23:50] Chris Nelder: Well, it looks like a generator when it is supplying energy to the grid, but when it’s recharging, pulling energy from the grid, then it looks like a load. And I think that was a complication for wholesale markets to accommodate too, wasn’t it?
[00:24:02] Jason Burwen: Sure. Absolutely. And then, you know, a key thing that’s in between those is you have state of charge. This is an asset that is about sort of managing as optimally as possible, a limited amount of energy, which you can charge up over time. But managing state of charge is the name of the game. That’s what you’re doing with an energy storage asset. And so if there’s no way for the wholesale market platforms to understand that, they’re just assuming, oh, you’re a generator, like you have fuel, we’re just going to run you. And it’s like, no, no, no, no, you can’t actually do that. This thing runs out and it needs to be some way to reflect the state of charge and the physical operating characteristics of energy storage. And that’s really what was at the foundation of FERC’s Order 841, which was ultimately finalized in 2018, even though we started talking about it in 2015 I think the NOPR was in 2016. These things take time. And Order 841 was really just a at a high level, was about removing barriers to storage, directing the wholesale market operators that are FERC jurisdictional in the United States to create a market participation model for energy storage, a way in which storage can provide all the energy, ancillary services, capacity services and other nonmarket services it’s technically capable of providing to have some, whether it’s bidding parameters or other means by which you can reflect the unique physical and operating characteristics of storage. You know, regularizing the sort of the way the buying and selling of energy for charging and discharging storage happens and two really key pieces here setting a minimum size requirement that cannot be more than 100 kilowatts. So that was actually you can put a pin on that one if we want to talk about some things that have been happening recently at FERC in terms of Order 2222. But that hundred kilowatt minimum size was basically in so many words saying, yeah, this is also going to be for distributed storage. And that was a central part of Order 841 that was ultimately challenged first at the commission and then at the DC Circuit. That order 841 was open not just to storage connected to the transmission system in the bulk power system, but also to distribution, connected storage or customer sited storage. And that was a significant change that I think made some parties unhappy because they saw it as sort of overstepping the line between state and federal authority with respect to managing distribution systems. And again, so many pins, I got a lot of pins to throw out and put in for this conversation, but we can definitely put a pin in that because I think one of the things that comes out of Order 841, besides the fact that now the markets are regularizing how storage is going to participate in them, but also that now storage is going to increasingly sit at the intersection between state policy and wholesale market operations, which are federally regulated. And that is going to be a extremely active site for public policy going forward. Anyway to bring it back to Order 841, the outcome of Order 841, which again has only been implemented relatively recently and is still under implementation in several markets, is now you’ve brought in an asset that’s supposed to operate regularly. Folks are starting to build those storage assets to participate in markets, and it’s creating all sorts of second order consequences that are updating other parts of the rules in wholesale markets.
[00:27:50] Chris Nelder: Why don’t you give us an example of that?
[00:27:52] Jason Burwen: Sure. Well, one of the pieces I’ve been most excited about and most involved in recently has been capacity market participation. In reviewing PJM, the mid-Atlantic Grid Operators Compliance Plan for Order 841, after comments from folks like yours truly and other parties to the Federal Energy Regulatory Commission, FERC weighed in and said, hey, PJM, you have this rule PJM put forward in their Order 841 compliance plan that storage would be qualified for capacity at the duration it can sustain over 10 hours. There is no really good reason for that, which was a large part of what we pointed out.
[00:28:35] Chris Nelder: No good reason for what?
[00:28:37] Jason Burwen: For requiring storage to discharge for 10 hours in order to qualify its capacity at that.
[00:28:43] Chris Nelder: I see the 10 hour requirement, OK?
[00:28:45] Jason Burwen: And, you know, our analysis and others showed that no there’s plenty of value in resource adequacy for storage of shorter durations. Out of that, FERC said we need to examine this. This is not clearly just unreasonable. And that was a decision that was made late in 2019. Here we are coming close to a year later, PJM has just concluded a stakeholder initiative to reform the capacity accreditation methods for energy storage, which is a extremely wonky way of saying there are now in the works rules that will allow storage to more readily participate and get the value to be able to be compensated for the contribution it actually provides to resource adequacy in wholesale markets.
[00:29:35] Chris Nelder: So what was the second order effect?
[00:29:38] Jason Burwen: Well, that’s in this case, the second order effect is Order 841 did not require changes to capacity markets. But now we are seeing because energy limited resources like storage aren’t exactly, again, a neat fit into the conventional resource adequacy framework, New York, ISO, PJM, SPP, CalISO have all been revisiting how storage is accounted for and resource adequacy. My understanding is that ISO New England and MISO are also going to be revisiting their resource adequacy rules. The resource adequacy construct as a whole has been something that folks in the clean energy industries have wanted to revisit for a while, and storage is cracking that door open because it is such a key part of the value of storage, is being there to back up the system.
[00:30:30] Chris Nelder: So speaking of resource adequacy, that is kind of at the heart of the questions that are swirling around what happened in California a few weeks ago as they had this record heat wave that really covered the whole western part of the United States. And California found itself caught a little bit short on capacity as people cranked up their air conditioners. And then, of course, everything was in smoke because of the wildfires, which caused a lot of people to have to stay indoors. And just that heat that was blanketing the whole western part of the US limited the ability of California to import power from other states. And so they had a situation with some rolling blackouts. And I think we’re still in the forensic process of figuring out exactly what went wrong there. I mean, the proximate cause was that there was a gas power plant that tripped offline and that appears maybe to have been the result of an errant instruction from CAISO, but that also there was a wind plant that wasn’t performing as expected as the wind died down and then there was solar output was less than it should have been because everything was covered in smoke. But these are all… They kind of feel like details when you’re talking about a fundamental resource adequacy problem across the state of California. And as it turned out, there was a major storage project that had been deployed by LS Power and they had just come online in time to help prevent further blackouts. So clearly, storage as a resource adequacy asset is becoming a very front of mind consideration here. This isn’t some afterthought that you roll into an IRP. This is like, oh, my God, let’s get more storage on the grid right now, isn’t it?
[00:32:17] Jason Burwen: Yeah, well, I think that the larger question of what happened to cause the blackout, maybe I’ll leave that alone and just note that you have, I think, somewhere close to 3000 megawatts of storage in various stages of development and procurement in California. Obviously, bringing on more of those assets would be really valuable and really important for resource adequacy. I think in California, some folks have observed that sort of things have retired before, new assets have been commissioned to replace them. The nice thing about some of this energy storage, though, is that it is able to be deployed extremely quickly. LS Power’s project that you mentioned that has been brought on one year ahead of when it actually contracted to be deployed. And there are storage resources sitting in California’s grid that may not have been used effectively because if they are, for example, distributed energy storage systems, those may not be visible in the same way to the California ISO and there may not be the right, whether it’s visibility or operational dispatch decisions being made, recognizing those assets are there, similarly, I noted that when those blackouts first occurred, folks had home batteries that were responding to the storm that was occurring that was sort of part of what was the weather that led to some of these challenges in this heat wave. And there was a sudden recognition that the default settings on some of these assets needed to be revisited to make sure that those storage systems weren’t sort of holding on to their energy for the resilience of the customer, but actually sending it back out to the grid or at least reducing the demand of the customer to help shave the peak. So there’s a recognition here that allowing storage to actually, for example, send energy back to the grid effectively during emergencies in a systematic way could be really helpful for the larger system.
[00:34:27] Chris Nelder: Well, you know, policy has clearly played an essential role in helping storage grow up into a commercial business and FERC Order 841 was clearly a watershed moment, unleashing a very large new opportunity for utility scale storage assets. But now we also have Order 2222, which FERC just passed, which seems more aimed at smaller assets such as distributed and behind the meter or on the customer side storage systems. So can you tell our listeners a bit about Order 2222 and what it means for the storage sector?
[00:35:00] Jason Burwen: I would like to say right now, this is Order quad deuce. That’s what we’re going to say for now.
[00:35:07] Chris Nelder: I like it.
[00:35:07] Jason Burwen: We need fewer syllables. I don’t know that I can say 2222 for the rest of your life. Two, two, two, two, two, two, two, two. That’s what I hear when I say that. … We need a good name for this thing. Quad deuce. So this order which was released earlier this month, we’re talking here in September and this is sort of the bookend to Order 841 because Order 841 actually grew out of a rulemaking that included two pieces, storage and distributed energy resource aggregations and back in 2018 FERC made the determination that the storage piece of that rulemaking was mature and well enough fleshed out to turn into an order. But at that time did not think that the DER aggregation site was well enough worked out and so held off on issuing an order then. I think that the experience of Order 841 and particularly the legal challenges to it being ultimately successfully upheld at the DC Circuit was critical to also making sure that Order Quad Deuce has a strong legal basis. So what FERC is doing here is not unlike Order 841 FERC is directing the wholesale market operators to create a participation model for distributed energy resource aggregations in their markets. So a very similar template to what 841 did for storage, Quad Deuce does for DER aggregations across the entire range of distributed energy resources. So not just storage, but also solar and demand response. Interestingly enough, Chairman Chatterjee of the commission focused on electric vehicles being a part of aggregations and whether or not you agree V2G is a key part of our future, it’s certainly something that is a part of a potential distributed energy resource aggregation in this order.
[00:37:11] Chris Nelder: Well, you can have a DER aggregation of electric vehicles that has nothing to do with V2G energy by just getting hundreds or thousands of cars that are plugged in to a charger to turn down or turn off their demand for charging and a demand response fashion whenever grid conditions warrant that whenever you’re in a constrained situation. So this is really more of a G2V than V2G thing. You know, my work at Rocky Mountain Institute has focused on what is the value stack, as we call it, that you can get from managing charging. And really, most of it has to do with that. It has to do with turning chargers down or turning them off or turning them on at the right time more than it does actually vehicles supplying energy back to the grid. And because each vehicle only really has a very small amount of demand that you can control, you do need to aggregate them into bigger chunks. And so, for example, in California, to bit into the CAISO wholesale market, you have to come up with a minimum bid of 100 kilowatts. And so BMW, for example, in one of its early pilots in CAISO pasted that amount of response together by using some portion of 100 vehicles that signed up to participate in the pilot that might have been plugged into the charger at any given point and then supplemented whatever the missing increment was to get to that 100 kilowatt minimum bid by drawing on some stationary batteries, second life batteries, actually, that it had at one of its facilities in Silicon Valley. So, you know, this kind of aggregation is really important, I think, with electric vehicles. But as you say, this really applies to all sorts of distributed energy resources. It applies to EVs, it applies to storage, it applies to solar. It could even apply to other loads that are more flexible, like heat pumps and water heaters and that kind of thing. They can all be aggregated and controlled together in the hundreds or the thousands to provide that kind of a response. So FERC Order 2222, just to kind of complete the thought there, enables that.
[00:39:20] Jason Burwen: Quad Deuce.
[00:39:23] Chris Nelder: I don’t know if I’m going to get used to Quad Deuce – 2222 rolls off the tongue pretty easily for me, but I’ll give it a try. Anyway, so that order defines a requirement essentially to develop these opportunities for these various kinds of aggregations to participate.
[00:39:38] Jason Burwen: Yeah, create a participation model. And I think that the order enumerates 10 sort of specific line items within which there are sort of lots of nuances probably would require its own show. But I think the key thing to understand here is that a large part of what’s in here kind of traces Order 841. So, for example, addressing the metering and telemetry requirements for distributed energy resource aggregation, that’s a key part of Order 841 in terms of Order 841, creating a definitive pathway for distributed storage to enter the markets and therefore for the RTOs tariffs to address the metering and telemetry requirements for distributed storage just as a single asset, not as an aggregation, with the idea being that those assets could be multiple use between both the wholesale market and the local distribution system or the end user where the storage is sited. So these DER aggregations again are kind of following those tracks in some respects, but there’s a bit more to it because of course now you’re putting multiple things together, not just a single asset. And that raises some interesting and new questions that Order 841 does not have in them, things around, for example, the interconnection process and what we can potentially expect to see as DER aggregators seek to create these aggregations and put these assets on systems of distribution utilities, how that coordination is going to occur alongside with the wholesale market. Those are creating some new new areas of regulatory development that have yet to go forward pretty much everywhere, even in some respects in California.
[00:41:26] Chris Nelder: Well, let’s shift focus a bit and start looking forward. What are some of the key policy issues that you see coming in the next few years for storage?
[00:41:33] Jason Burwen: Sure. One of, again, the things that has changed over the last few years has been the amount of attention that energy storage is getting in Congress and in the federal government outside of the Federal Energy Regulatory Commission. So I think that you’re likely to see continuing efforts in Congress to admit energy storage into the various clean energy tax credit provisions as its own standalone asset, because right now, storage can get an investment tax credit when it’s integrated with, say, ITC eligible solar assets. That’s probably going to remain a push by many folks in the energy storage industry for some time to come just to give that sort of level playing field. A complementary focus that we’re seeing in Congress is also to really increase significantly the innovation investments going into energy storage. That’s things like the Better Energy Storage Technology Act and the Promoting Grid Storage Act, which would elevate energy storage in the DOE portfolio in terms of its importance. And we’re already seeing that kind of reflected by the energy storage grand challenge that the Department of Energy has recently launched and is sort of creating a multi-technology, multi-application roadmap for its grant making and R&D activities for the next decade. So there’s a real elevated federal interest in energy storage I think as there’s a recognition that one, this is an extremely widely applicable technology, and two, that it’s really popular, it is pre-partisan. There is not too many people who don’t think storage is a good idea outside of sort of those efforts I’ve already made sort of reference to these kind of follow on conversations from Order 841 at FERC and in wholesale markets, and, you know, I see a very large array of conversations coming through the RTOs and at FERC. So as Order 841 implementation finishes, we are, I already mentioned sort of how storage factors into resource adequacy and capacity accreditation, another important conversation that’s occurring as hybrid resource participation. So when storage is integrated with, say, solar or wind generation, there are not clear rules for the interconnection market participation and capacity accreditation of hybrid resources.
[00:44:11] Chris Nelder: Yeah, we discussed that a bit with Will Gorman in Episode #122 on hybrid power plants.
[00:44:16] Jason Burwen: Yep. And he has certainly done a lot of the evidence base for what’s showing up in generation interconnection cues, that strikes us as just simply it’s a matter of time. You need to have clear rules for how these resources are going to work. You could almost argue too that DER aggregations is potentially going to be a little bit of a path blazing, at least in some way, because, you know, an integrated hybrid resource, it’s not the same as an aggregation. These are assets that, if they’re truly integrated, will share a control architecture in a way that maybe an aggregation will not. But you see some reflections of the concept here that you’re starting to be able to use portfolios of resources in an integrated fashion in markets. Another topic that is very current is storage as transmission. We’ve seen the first ever sort of RTO promulgated framework for storage as a transmission asset recently approved just last month, FERC approved the Mid-Continent Independent System Operator’s storage as transmission only framework, not without some controversy, but we are certainly aware that other markets PJM, SPP are themselves working on storage as transmission initiatives. And there’s a lot of interest here for how storage can be a part of the transmission infrastructure. Beyond that, I will take you into the extraordinarily geeky weeds – there are issues associated with how do you do, say, energy market mitigation with energy storage resources. This is a novel question. It’s never really had to been dealt with, but now as storage starts to participate in energy markets it’s a really important and meaningful question because if I can encapsulate it quickly, if you have a limited state of charge, you’re going to want to hold on to your energy for when it’s most valuable. These markets are built around the assumptions, though, of fuel based generators and have things like offer obligations and requirements that people not physically withhold because that could be manipulative of market prices, right? Well, energy storage is not necessarily trying to manipulate market prices. It’s just folks are trying to use their limited energy in the most impactful way if they’re waiting to, for example, shave the peak of the day. So how you think about energy market price mitigation for energy storage bids? It’s arcane. I’m not going to lie, but it’s going to become really important. And finally, these intersectional issues that I mentioned, especially as DER storage starts showing up more, whether because of 841 or Quad Deuce, now you have a rising set of issues around that intersection between sort of what’s happening at the distribution utility or in state policy and what’s happening in the wholesale markets. So this question of multiple use, you know, in Order 841 and again in 2022, FERC made very clear that it is creating a pathway, but it is not stepping on the distribution utilities jurisdiction to manage its distribution facilities. Well, now we have this issue of what are called they’re called different things in different places, but wholesale distribution, access fees. So if I connect front of meter distributed energy resource, say, a storage resource to a distribution system, but I intend to use it for wholesale market service, the distribution utility can say, OK, well, you’re going to impose some costs on our distribution system for its use to get you to the wholesale market, ergo, here’s a fee structure or rate structure that we’re going to apply to this asset. And that has become a flashpoint because of varying perspectives, disagreements over what the actual cost to a distribution utility for hosting, say, a DER storage asset that is connecting so as to participate in wholesale markets. Again, super wonky. I feel like I’m putting you to sleep, might be putting myself to sleep. But these kinds of intersections are going to increasingly color a lot of the discussion around certainly distributed storage, which is going to be looking to maximize its value as it plays between, say, bulk power system, local grids and end user services to be able to maximize the value that you can get out of the single asset.
[00:48:58] Chris Nelder: That whole pay to play strategy from the distribution utilities just keeps coming up as various designers start to become more functional and bigger players that encroach on the utility of traditional business. We saw that with solar, with them claiming that, well, if you connect your rooftop solar system to our grid, you’re imposing a cost on us or on our other customers. And there was a lot of argument and disagreement about that. We find the same thing with connecting EV charging stations to the grid. And now that storage is becoming a big player, I’m not at all surprised to hear that that argument is being made about storage interconnection, too. And, you know, it’s easy to make that claim without evidence. And sometimes the utility can get away with that, frankly. But I think we’re going to be cutting more and more into a world where if you want to make that claim, you have to demonstrate it. You have to prove that this thing connected to your grid is actually imposing a new cost that you now have to recover and isn’t just riding on the existing capacity that’s already been paid for. So that’s one of those evergreen questions. You know, I want to return here for a minute to this concept of pairing storage with wind and solar plants, as we discussed with Will Gorman in Episode #122, because it is one of the key trends that I’ve noticed in the procurement of storage over the past year or two, so many of these new utility scale wind and solar projects are coming equipped with battery storage arrays as part of the initial design, instead of sort of adding them on as an afterthought to an existing wind and solar plant. And there’s a lot of reasons why that makes sense, although it makes more sense in some markets than others. Do you think that’s an important trend in storage deployment? Is that going to continue to be a big part of the impetus for deploying storage at the utility scale?
[00:50:45] Jason Burwen: The interconnection cues tell us that it’s going to continue. I think, you know, in paraphrasing what I’m sure Will, Gorman said previously, just over half of the storage megawatts in California’s queue today are in hybrid configurations. Similarly, in ERCOT’s queue, I think for units that have online dates in 2021, two thirds of storage megawatts are hybridized and in 2022 it’s 80 percent of storage megawatts are hybridized. So hybrid configurations are driving the recent deployments in many respects and there’s a variety of reasons for that. Stop me if I’m going into territory you’ve already discussed. But I think there are certainly developer considerations. The tax benefits, if you integrate, certainly for solar storage hybrids, why they are so popular, you get cost reductions from the shared control systems and land and soft costs. You might have more efficient use of your generation by reducing cycling or effective use by capturing clipped energy or minimizing forecast errors. One that I think is interesting to think about in the further future is it will allow conventional generators potentially to adapt to low load conditions, something that starts to show up when you get to much higher levels of, say, renewables, as places like South Australia are experiencing. And then and this is probably one of the key ones. It’s a hedge. You add storage to a wind or a solar plant, you’re not sure what energy prices and what your revenues are going to be for that renewable asset in the further future, when you add storage to it, you have some optionality now, you can do different things with this asset. You can move the energy around to different times than just when the wind blows and the sunshines. And that has real value from a sort of risk management and hedge standpoint. And so that’s I think it’ll continue to be a driver for a lot of these hybrids. Outside the developer stuff, you have rules and RTO specific conditions in terms of value, and that’s certainly where a large part of the conversation has been. For example, in the recent FERC technical conference on hybrid resources, do you have really a lot of interconnection availability or is interconnection scarce? If it’s scarce, hybridizing is a way you’re going to make a most efficient use of that scarcity if your market participation rules are flexible in terms of bidding behavior or if they’re not, what kind of requirements they have will lead you to want to either bring those assets together or separate them. Capacity accreditation, I think, is somewhat similar in that respect. So there’s a lot of those questions that are, again, right now literally being worked out as we speak. CALISO and ERCOT, I think have been moving ahead the fastest on coming up with a framework for hybrid resources. But it’s a current discussion in certainly in New York, ISO, PJM, SPP, MISO has just started up some more work on this. So it’s showing up everywhere.
[00:53:57] Chris Nelder: One of the other trends that is near and dear to my work is using storage along with high speed EV charging stations as a way of mitigating the demand charges, which is a component of the utility bill in some cases that these high speed charging stations have to pay. And it can really ruin the business case for owning and operating a DC fast charger when those demand charges are particularly high. So some operators of these fast charging networks are starting to deploy storage along with the charging station and then pulling on that resource instead of on the grid from time to time in order to reduce the demand charges that they have to pay or to do peak shaving or to take advantage of a time of use rates or something of that sort. So that, I think, is an interesting application. I don’t necessarily endorse that specifically where it comes to demand charges, because that’s a problem that you could actually fix at the stroke of a pen by just fixing the rate design rather than larding up an already very challenged business case with additional massive costs for storage projects. But it is a growing sector where the storage assets being deployed along with high speed public charging stations are effectively becoming a part of the grid buffer, if you will, aren’t they?
[00:55:19] Jason Burwen: Yeah, and I think that where that case is probably going to show up quickest is in these really heavy duty cases of electric transportation. So one of the things I get really animated about because I am again a terrible geek is maritime electrification. I think that there’s probably no greater no brainer than electrifying near coastal vessels that run fairly predictable short run schedules and those batteries are huge. I think I heard from the folks at the Washington State ferries that when you charge up an electric ferries battery, you might be pulling 10 megawatts just for charging one boat. So imagine doing that at a port, not just at a ferry terminal for one boat. You’ve got some real significant potential, very short term, very instantaneous demands on the electric system where you could see storage and not necessarily just lithium ion battery, but different kinds of storage, providing that buffering between the demands on the distribution or transmission system and the electric vehicles needs.
[00:56:33] Chris Nelder: Right. Because instead of having to pull 10 megawatts all at once straight off the grid, you could pull a megawatt for hours and then discharge it when the ferry needs to pull in and recharge and then go on with your life. So that’s a great point. And I hadn’t really thought about that, frankly, even though we’ve talked about numerous ferry electrification projects over the years on this show, in the news segments, it’s also certainly going to become an important element of deploying other kinds of heavy duty EV charging infrastructure, like for truck stops, for bus barns as we continue to electrify transit bus fleets and that kind of thing.
[00:57:13] Jason Burwen: Yeah, and I think this is sort of an instant case that the larger trend, which is that storage gives you a really good resource for the coordination of where electrons move in your system because of the high controllability. This is going to be an integrating infrastructure for transportation, electrification, probably for some amount of building electrification and other parts of potentially industrial processes.
[00:57:39] Chris Nelder: Yeah, you know, one of the evergreen questions that keeps coming up in our long conversation about energy transition on this show is the question of just how much and what kind of storage will need as we get to high shares of renewables on the grid, and especially as we try to get to a 100 percent renewable grid. My view has always been that we should try getting to say 80 percent renewable power on the grid before we worry too much about that last 20 percent, because for now, we can supply that last 20 percent with the existing fleet of gas fired power plants, among other things. So worrying about exactly what it takes to operate a fully 100 percent renewable grid at this point when we’re at closer to 20 percent renewables and not 80 has always seemed kind of premature to me, not to mention the question of how much it will cost to provide whatever storage we wind up needing at that point, because the cost of batteries have been falling so steeply for the past couple of years that nobody can predict what it’s going to cost several decades from now. And for that matter, I’m not even sure how much of that storage component on a mostly renewable grid will even be battery storage. I suspect that we could actually meet a lot of that demand, especially in windless winter weeks in the northern countries using thermal storage systems of one kind or another to store and use energy as heat directly, rather than converting electricity to heat, because a lot of those demands are going to be for heat. So what do you think about that question now that battery storage has evolved so much over the past five years? Do we have the technology we need for a 100 percent clean energy transition, or do you think there are essential storage technologies or refinements that we still have to develop?
[00:59:16] Jason Burwen: That’s a great question, and I think the answer is that we have certainly something that will get us a long part of the way there. The lithium ion battery, which is now the workhorse, can get significant amounts of, say, renewables integrated without really much in the way of significant continuing cost declines and performance increases. There is an enormous amount of potential for storage even at four hours, let alone say six and eight hours of potential duration at its rated capacity in the electric system. NREL – Paul Denholm, who I think has been a guest on your show, you’re a great study of exactly that potential for storage as a standalone asset, providing system capacity in the United States and found that these durations which are in use today, we do have eight hour batteries currently operating on the electric grid. Those are in the northeast, that right now you could use perhaps 70 gigawatts of those existing assets to serve as reliable, peaking capacity, and that if you add more solar penetration, that number goes up and up and up. And that’s using, again, four to eight hour storage, which we have today, maybe slightly higher price point than those studies would need. But, hey, guess what? If you’re going to go to much higher shares of renewables, that’ll take time and that gives you the time for that cost curve to bend down. I think, though, that there’s definitely a value and a case for longer duration storage, certainly, depending on your view of how the clean energy system develops, if you see a very high share of renewables showing up and you don’t think overbuild is a potential pathway, longer duration storage is certainly going to be a key part of the case here. And that’s not just me saying it. California, just to return to the Golden State their recently affirmed integrated resource plan, which is taking the state towards 100 percent clean energy. That integrated resource plan is not only calling for nine gigawatts of current battery storage technologies, it also calls for one gigawatt of long duration storage. Storage that’s going to be providing, I think they say, in excess of 10 to 12 hours of stored energy capability at it’s rated capacity. There’s a lot of folks who are developing technologies to meet that and longer durations at scale. There’s an enormous amount of interest there. And that I think – that is the long term use case, that folks in the longer duration storage technology space are aiming at. There are various other studies out there as you start pushing up past 80 percent that indicate a significant need for longer duration storage technologies in the absence of something like gas with CCS or flexible nuclear, which are sort of posed as the alternatives for a clean energy system that has that flexibility. I won’t weigh in on the likelihood of those other technologies. I’ll just note that there’s already an enormous amount of attention to longer duration storage. And we’re seeing those units now starting to be deployed. So, for example, you mentioned thermal storage, I think thermal storage is actually one of the sleeper hits of the longer duration storage world, because a lot of our systems throw thermal mass waste heat and in addition to that, also there is real benefit in being able to store energy as thermal mass in a world in which we oftentimes spend a lot of energy converting various fuels into something that can create steam or create something superheated to drive a turbine. And there are companies out there working with things like molten salts, alternatively, not just heat, but coolth. Yes, coolth. I love that word. Heat and coolth are both opportunities here to have a potentially fairly low cost, longer duration solution because it’s a material combined with a containment device and system for moving usually a fluid through it. So that has some real capabilities if what we’re dealing with is more materials than mechanics, and especially if it can integrate into, say, the thermal loop of, for example, a nuclear facility, if that’s part of the clean energy future you envision.
[01:04:11] Chris Nelder: What about control systems, dispatching systems, that kind of thing? I mean, it seems to me that as we get to more and more storage systems that are interacting with the grid, we also need some software systems, probably some hardware devices as well, to help us control and manage all these devices, which is not something that I ever really hear people talking about. But it seems to me that that is another place where we do need some real R&D work still.
[01:04:43] Jason Burwen: Well, I don’t know if I have too much to add to sort of the suite of controls other than to sort of note that storage will sit at the center of that because storage gives you the fidelity of control that’s sort of computerized, that computer level of fidelity, of moving again, electrons exactly when and where you need them on very minor timescales as opposed to these sort of more, quote unquote, analog system of things spinning and moving less precisely… But there’s a saying some in the industry are fond of, which is storage is software. The battery does not do anything by itself. It’s a capability. The way you use that capability is through software, is through a highly sophisticated control regimen which can be developed through folks who are using machine learning to monitor grid conditions and effectively prepare storage assets before events show up because of the predictive nature of those algorithms, folks doing extremely sophisticated models that you can load into the storage control logic, because it’s the one thing that you can say, all right, I’m going to move you on a subsecond to subsecond basis based on my sophisticated modeling. You have that capability. And so my sense is that this is where a lot of the focus on smart controls is going to be, is in how they utilize not just all distributed energy resources together in say an aggregation, but specifically the storage section of that being in many ways a controller. And that’s part of why they are increasingly a central asset in things like micro grids, because that’s the role they’re going to play.
[01:06:35] Chris Nelder: You know, since you’ve had a front row seat to battery storage growing up from an early stage technology to a commercial technology over the past five years, I wonder what kind of perspective you have on the sector just sort of at a higher level, like are there any key lessons that you would extract from the experience of the next five years that would be particularly instructive for us looking forward?
[01:06:56] Jason Burwen: That is a great question. Now, I must think. We talked a little bit, I think, about some of the benefits of having a highly modular technology that’s almost in some ways a commodity as a rapid scaling capability. I think another thing that we’ve seen is just the way in which storage has oftentimes been a story of use it and then you realize how useful it is, which is hard to do when it comes to things like electric grid technologies. It’s not often you get to use it before you commit to it. But I think in in the US, we’ve had a lot of opportunities to get energy storage into grid operators, systems, into utilities. Dispatch control into customers premises, and that has been really powerful for showing off what these assets can do, and they’re not capital intensive, at least certainly not compared to a lot of other technologies. So I think that modularity optionality, low capital intensity, fast product cycles, those have been really key contributors to the success of the technology. And as folks look forward towards storage technologies that are not, for example, lithium ion batteries or to other grid technologies, it’s worth bearing some of that in mind from the perspective of policy, gosh, it really helps to have an asset that everyone has an argument for why they should use it. You know, the question of who should own and who should operate is something that, because of the extraordinarily diverse use cases of storage, means every stakeholder on the grid has said, oh, yeah, this is of use to me. And also there’s a reason why I should use it and maybe not someone else, which can lead to some very heated disagreements about policy and regulation, but at the same time has created a extremely broad set of folks who are advancing the nature of regulation grid operations to integrate storage.
[01:09:09] Chris Nelder: So maybe I would summarize that by saying there’s a certain element of learning by doing right. Like, you deploy this thing and you start using it and then you start realizing other ways that you could use it or other people start realizing ways that they could use it or other aspects of the system change as a response to it participating – is that kind of what you’re driving at there?
[01:09:32] Jason Burwen: Yeah. And then finding champions who want to make sure policy keeps up with technology is very critical. I mean, that has been so much of what storage has. I think at each major inflection point of this industry, there’s a policymaker or regulator sitting behind that who was really forward thinking and said, hey, let’s do this. Let’s figure out a way to bring this onto the system, whether that’s FERC Order 841, whether that’s California AB 2514- the storage target, whether that’s any number of other inflection points. And so if you are looking at energy transition, having a proactive policymaker, or regulator is hard to find. But that proactivity has, I think, been a real foundation for why storage has advanced so rapidly.
[01:10:19] Chris Nelder: But also, I mean, it’s a lot easier to make regulation or policy around things that everybody can look at that exist and we can all see how they operate than it is to make policy regulation around something that’s still on the drawing board and not to mention just getting political support and constituents and advocates lined up behind it. That’s just a lot easier to do around things that exist.
[01:10:45] Jason Burwen: Yeah, and not only that exist but are rapidly improving. I mean, I think it’s interesting if you look at, say, our cousins in the wind, in the solar industry, those industries really had to start with, I am sure, grossly generalizing, so I will take my licks from people who are like, that’s not how it went. But things like investment tax credits or production tax credits were really key drivers to getting those assets into the electric grid. And storage didn’t really start with that. Like, yes, currently a solar storage asset can get an investment tax credit, but that’s not how storage got started. Storage got started doing things like fast frequency regulation and building a series of use cases and value propositions. And there’s something to be learned from not just the importance of getting regulation right, when I think a lot of these arguments are sometimes policy arguments, legislation that changes things with broad brushstrokes, but also secondarily, the political valence you carry when you’re arguing about arcane market rules is different than when you’re showing up to Congress or state legislatures saying, I need this thing. And, I’m sure that that is, again, overly broad generalizations all around. But certainly in my experience and perhaps because of the complexity and sophistication of storage, getting the rules right, the follow through in the implementation and regulation is as if not more important oftentimes than the headline grabbing bill.
[01:12:21] Chris Nelder: Well, I mean, again, by comparison, for the better part of 30 years, solar was an off-grid technology before it became an on-grid technology. Right? It was it was people using it for off-grid homesteads and farming and all sorts of stuff. The biggest applications for wind, the better part of 100 years ago were for farmers. And that was not grid connected stuff, so, you know, there’s definitely a lot to be said for learning by doing, I think, and being able to form policy and regulation and business models and so on around things that we can all see how they work and know what they cost and so on. You know, I want to talk a little bit about technological evolution. We’ve seen a lot of interesting little ideas and demonstration stage projects in storage over the past couple of years. For example, I’ve seen some really interesting designs that just keep coming up, but I haven’t seen them turn into commercial technologies yet of like containers of hot rocks being used as thermal storage systems that could actually generate electricity via a heat transfer fluid and using a conventional steam generator. Or there was that one design that I think a lot of folks saw a year or so ago that involved a crane sort of apparatus lifting and stacking heavy blocks, essentially using the potential and then the kinetic energy as a kind of a mechanical storage device. And of course, there’s this perennial interest in using underground aquifers as heat storage systems, like for providing space heating for residential applications and so on. You know, not to mention any number of other new battery chemistries or refinements in lithium ion batteries and various labs. I mean, just yesterday was this battery day that Tesla did where they unveiled a number of enhancements and refinements they’ve made to their battery manufacturing process with apparently excellent results. So what are your thoughts on what’s coming in storage? Are you anticipating any major breakthroughs in battery storage or perhaps expecting any non-battery storage technologies to become commercial in the next couple of years?
[01:14:24] Jason Burwen: Sure, this is a really exciting space because there are so many bets being laid right now and certainly for lithium ion. Yes, yesterday we saw the large form factor, lithium ion cell that is a series of really mixture of process and materials improvements. And I think for lithium ion, that’s exactly what you’ll see. Is it a breakthrough? These are incremental progress. But I like to say a breakthrough is usually a series of incremental advances that accumulate that’s just as important as the quote unquote breakthrough. You can spend several years consistently reducing the cost and increasing the performance of these things. And so lithium ion has still got some ways to go. But outside of that, certainly there is in the electrochemistry space, there are folks who I think are focused on, again, keeping in mind duration storage technologies, electric chemistries that can potentially work for longer durations and potentially have longer cycle lives. We’ve seen zinc based batteries coming back into, I think a lot of vogue, flow batteries have been around for a little while. And then one of the more interesting things in electrochemistries is Form Energy with what appears to be a sulfur based battery chemistry yet to be revealed. But this is speaking of Tesla, this is the former battery unit head at Tesla – Mateo Jaramillo is now heading up Form Energy which got its first contract earlier this year for delivery in 2023 of what they are saying is a one hundred and fifty hour battery electric chemistry. And, you know, it’ll be interesting to see what actually comes of that. But there’s folks who are working on electrochemistries outside of that I would say in terms of non battery technologies, you’ve got folks you mentioned working underground. Well, there’s I’m just going to do a quick tour through – you’ve got things like Quidnet, which are doing geomechanical pumped storage. So it’s pumped storage, but it’s not using a reservoir. It’s using, say, an abandoned well. You’ve got folks who are doing liquid air storage, so they’re using not pressure, but temperature to reduce the volume of air. And then you let it reheat, it expands and you can drive a turbine. So there are ways to play adiabatically with a system in order to create a storage system and Highview Power, I think, is the folks who are pioneering. There are folks who are working on new kinds of mechanical storage you mentioned, I think, Energy Vault, which is sort of stacking blocks. Similarly, you’re also going to see folks who are working on pure chemical storage. This gets into maybe a little bit more of a controversial territory, but power to gas is being held up by a number of interested businesses and now utilities as the way you’re going to solve longer duration, so you’re going to create, for example, hydrogen as a chemical carrier, and then it looks more like a conventional fuel, but it doesn’t have carbon associated with it. And you can use it similar to a fuel as a storage medium. How you derive that hydrogen is a non-trivial point when it come to clean energy transition. And I think folks who are excited by this are premising this on green hydrogen running anelectrolyzer, for example, with clean energy sources, maybe blue hydrogen using some sort of carbon capture and steam based reforming approach to methane. But at the end of the day, we’re seeing folks starting to migrate into this. From a policy standpoint. I have just seen my first ever comment from an oil and gas industry group in an energy storage dockett saying, hey, we’re going to be a part of this hydrogen. So there’s a lot of discussion to come as to what we expect to see in the future that’s going to be these sort of new technologies. And I think one of the interesting things will be how they get deployed, how they get financed. What is the use case? Because a lot of these, as I noted, are based on going to longer duration. And one question will be, well, if you don’t have massive shares of renewables today, what’s your market entry path and how that gets figured out? I think it’s going to be very interesting whether that’s a resilience niche or maybe more of an infrastructural like storage as transmission type niche. There’s just an enormous amount happening in this space. And I look forward to getting another five years at least of front row seats to how this all unfolds.
[01:19:30] Chris Nelder: Yeah, well, we’re going to have to do a show on hydrogen one of these days. I’ve got this massive research file, I just haven’t figured out what to do with that. You know, over the past year, we’ve seen Trump playing all sorts of games with tariffs on imported Chinese batteries. Last August, he raised them and then he lowered them again in January, you know, as the shifting winds of politics blowing around. And then there have been various parties that want to apply a made in America requirement to storage procurement when China is actually the largest battery producer worldwide by far. How do you think these issues are going to affect battery deployment in the US in the coming years, these trade considerations?
[01:20:08] Jason Burwen: You know, it’s an interesting question, partly because there’s a lot of uncertainty about it. But also I think it remains to be seen how effective this will be in changing some of these decisions. Will tariffs on their own create Made in America? My sense is probably not, because unless those tariffs are global in nature, you can move your supply chain around. And indeed, I think that’s probably been the experience of the solar industry. And I wouldn’t be surprised if it’s the experience certainly of the lithium ion battery industry if, for example, there are focused trade actions or other actions against the Chinese supply chain. There’s no reason why these batteries can’t be produced in a different country. And those countries still might be a place that you can produce it cheaper than in the United States. So just using the stick, so to speak, probably doesn’t get you there. I think that demand is going to be the main driver. If you don’t have a very significant domestic demand, then you will not have as compelling a business case to locate your production processes near that demand. And I think China is deploying something like hundreds of thousands of electric busses and over a million electric vehicles a year. So that’s a real good reason to keep your batteries in China.
[01:21:34] Chris Nelder: So you’re saying that we’re going to have to build more demand for these batteries in the US before we really significantly scale up domestic production?
[01:21:42] Jason Burwen: I think that that’s a necessary factor. I don’t think that a low domestic demand is going to be a really great foundation on which to build a manufacturing base. On the other hand, even if you do get that, you have some other things you need to think about and deal with. So one of them is, for example, when we say Made in America, what are we talking about? What’s being made? Are we talking about just the manufacturing or are we going further upstream in the supply chain? I think there are some folks who want to see more raw materials extraction because of concerns over things like critical minerals, rare earths and the like. Am I mistaken that you had Morgan Bazilian on your show previously?
[01:22:23] Chris Nelder: You are not mistaken. We did indeed to talk about that very issue.
[01:22:26] Jason Burwen: Oh, my god, I’m going to collect them all man. I’m going to name every single one of your previous guests. So name dropped. But the nature of this is that that doesn’t matter if you’re chemical processing capability does not exist. If those raw materials get extracted in the US today, even in significant volumes, we’re still sending them outside the United States to get processed into industrial inputs, so…
[01:22:50] Chris Nelder: Well, one of the biggest issues there was cobalt, and I was pretty excited yesterday to see Elon Musk claim that they’ve figured out how to get cobalt out of the battery completely. I hope that’s true.
[01:23:01] Jason Burwen: I mean, you have lithium ion phosphate batteries today that don’t use cobalt too.
[01:23:05] Chris Nelder: True. True. That’s a very popular technology in China, something that I believe BYD Motors is using in their electric vehicles. You know, another topic that’s come up several times on this show over the past couple of years has been the future of gas fired power plants in the U.S. and the potential for battery systems, especially those paired with wind or solar projects, to occupy the niche that gas peakers have filled and supplying power during those few hours or days of the year when various grids are really stretched to the max and you need that extra a little bit of peaking capacity. So what do you think about that? Will affordable utility scale storage obviate the need to build new gas fired plants, or might it even start pushing existing plants off the grid?
[01:23:47] Jason Burwen: I think that it’ll definitely compete with a significant part of them – the case that most folks are focused on right now is peaking capacity. So very low capacity factor plants. And that is indeed, I think, sort of a fairly rich niche for energy storage to fill, because the oftentimes underutilized nature of that capacity means there’s a lot of value in putting in something that can meet the runtime needs while also giving you more value than just the few tens or hundreds of hours a year that it’s actually needed for. And there’s another twist to this which you should bring on another guest to evaluate, because I am not that person. But this twist is that if you add more and more wind and solar, for example, to an electric system, your combined cycle gas plants start to have an operational profile that looks less like a mid-merit generation and much more like a very fast cycling combustion turbine. And so that is I think it’s an interesting hypothesis that this may happen, that you may see the operational profiles of these plants change in such a way that you are not only talking about CTs anymore. Now, we are also talking about where storage plays in terms of its competitive niche vis-a-vis CCGTs, perhaps as part of a portfolio of wind, solar and storage. And indeed, I think just recently in New Mexico, there were regulators who approved the retirement of coal generation units at the San Juan facility and replacing it with an entirely wind-solar storage portfolio and said this will actually cover the needs in our system, which is really exciting. This is sort of the place that folks think we are going in terms of being able to use these portfolios of resources in lieu of, say, a fossil power plant for replacement capacity. In terms of new incremental capacity, I think that that remains to be seen. And certainly, again, until, for example, some of these longer duration storage technologies are available, we may still see some amount of these gas fired plants being built in the mid-merit space to be able to provide the system and resource adequacy it needs as that portfolio shifts. There’s a certain crossover point where actually you do start to need longer duration. And so that’s what we’re keeping our eye on. And that’s in the event that gas plant operators don’t just hybridize with storage themselves.
[01:26:30] Chris Nelder: No, that’s true. You know, a lot of storage is getting deployed because vertically integrated utilities see it as an opportunity to expand their rate base while using it to support more wind and solar generation on their systems and decarbonize their supply. So that’s kind of a win-win with regulators and customers. But a lot of independent power producers, IPPs might also see that as a threat to their business. So how do you look at this issue? Is this really a problem? Should we even care about that? Or is it really mainly a concern for the IPPs and the rest of us don’t care?
[01:27:03] Jason Burwen: I think this is a really fascinating question because, again, gross generalization of history. I think until relatively recently, a lot of vertically integrated utilities have tended to be resistant to or even actively opposed to clean energy. And so what that meant was that you had an alliance between competitive providers, IPPs who are competing to provide generation and clean energy or environmental advocates who want to see decarbonization of system supply, competition and cleanliness, were hand-in-hand for a large part of our recent history. Now you’ve got a lot of utilities saying we’re going 100 percent clean, we’re going to go get an enormous amount of wind and solar and storage, I think Xcel, Colorado, made a lot of waves in 2018 when its CEO there, Ben Fowke said we’re doing steel for fuel. We’re going to invest in nonfueled assets, which, frankly, a good return on equity if you’re not burning fuel. And that’s our path forward. And that suddenly creates the split potentially between these previously 100 percent aligned environmental and clean energy advocates and competitive providers. Because if you’re a clean energy or environmental advocate that’s been spending years advocating go get clean energy, go get clean energy, and then the utility turns around, says we’re doing it, we’re going to go get a bunch of clean energy. You should probably be happy about that fact. But for a competitive provider, I think that raises some questions. Ultimately, is it a problem? I think it’s a problem if you stop getting really good price information revelation and progress that competition can provide. That’s one piece of this. So, for example, is your vertically integrated utility doing, for example and all source RFP? Are they under any sort of pressure to not just work with, say, a utility affiliate to procure? These are important questions, because if you don’t have openness and some amount of transparency, it’s not necessarily a given that you’re getting the most cost effective option for your system. So that’s something that’s worth bearing in mind. But also secondarily, there are ways in which a competitive model keeps people moving. If you have to really work on cost because you are making a competitive bid, that’s going to push efficiencies in what you’re doing that I think are going to be important to making sure that the clean energy system we live in remains cost effective. The last piece of this, though, is certainly a recognition that this is being brought forward in part by this discussion of DERs, is that we have models for wholesale markets creating sort of competitive services markets. There are a lot of folks knocking on the door at the distribution level, and that distribution level is not currently a market anywhere, as far as I’m aware, even if there might be folks in places like New York who have been trying to do that. And I think you’ve probably had Lorenzo Kristov on your show.
[01:30:25] Chris Nelder: More than once.
[01:30:26] Jason Burwen: Did it – got another one. He, I think, has presented an idea which is, again, gross generalization, taking the RTO model and bringing it down to the DSO level as potentially a valuable way to, again, drive some efficiencies and innovations in the supply for the system on a distributed basis. All this to say that I don’t think that we can agree that there’s one right business model for getting clean energy done at this point. And that’s not to say that vertically integrated utilities shouldn’t be rate basing some of this. I think there’s actually some real value to that, especially things like, for example, longer duration storage. That’s probably going to be really good in terms of how it gets financed. But overall, diversity of business models is really going to probably be something that will benefit consumers as long as it remains around.
[01:31:24] Chris Nelder: One final place where storage might be seen as a competitor to the existing business is as a competitor to new transmission lines as our so-called no-wires alternatives or NWA in general. How should policymakers look at that tension? Like does it really matter to the grid’ss performance or to customers or does it just really come down to cost?
[01:31:48] Jason Burwen: So that is a really interesting tension. It is hard. One of the things that I think is important to bear in mind is that a non-wires alternative is a regulatory distinction. Storage can be a transmission or distribution system asset. It can also be an alternative to a transmission or distribution asset in the sense that it is not, for example, rate based or cost recovered in the way that a transmission or distribution infrastructural asset is. And so that’s the distinction here, is that we are seeing storage in part because of its versatility is both a non-wires alternative and a nontraditional wires asset. Those are the twin conversations that are happening at the same time. And so when you talk about being a competitor to new transmission lines, the first storage as transmission projects have been deployed in California, another I think, is in the works in MISO, which was the driver of MISO’s storage as transmission tariff filing to the Federal Energy Regulatory Commission. There’s this desire to figure out how do you incorporate storage into the transmission asset framework. And in that MISO decision, there is a tension here because that framework says you have to be a transmission owner to operate storage as transmission, which, yeah, if it’s a transmission asset, you should be a transmission operator. But functionally a non-transmission asset that is storage can provide very much the same service. It can be owned by someone different. So it’s really a regulatory distinction in many respects. And that is that is a challenging tension to deal with because you kind of have to open all sorts of things. The non-transmission alternatives framework that Order 1000 tried to establish has not generally brought forward NTAs so that seems broken. And at the same time, there are some ways in which storage as transmission, I think it can be used very effectively as a part of the transmission system reliability. But there are concerns about sort of where is the line between a legitimate use of storage for transmission and something that then crosses the line into, for example, interference with competitive market price formation. To what extent do you see a transmission owner potentially have decision making power over the withdrawals and injections of a storage as transmission asset when there’s a whole bunch of generators who are making strategic calls about how and when to generate? Is that problematic for competitive markets? So all that to say that this is really one of the next horizons in energy storage and public policy? I think it’s really important to get right both because there’s real value to the grid’ss performance. If you can use storage in combination with conventional transmission or distribution infrastructure to make that infrastructure have greater capabilities at lower cost, what’s being called sort of grid enhancing technologies in FERC parlance. And that should lower costs to customers conceivably. And then beyond that, I’m really bullish about it, because as I’ve sort of noted, some of these longer duration storage technologies I think are well suited to provide this kind of infrastructural role as their first use case, well before there’s enough renewables on the electric grid to warrant a sort of renewables integration business case. So for a whole bunch of reasons, I think it’s important to get this right. But it is going to be a regulatory fraught space. And the experience to date on nonwires alternatives, certainly at the distribution level, is that, again, there’s a whole different set of approaches. There are folks who are looking at it from sort of an identify solution by solution and procure a solution. There are folks who are sort of moving more towards a let’s provide a price signal, some sort of value of DER that captures the locational value. There’s utility programs like the Bring Your Own Device programs in the Northeast where the utility has assessed what the potential value to say a distribution deferral is, and is creating a price signal for customers through a utility program to provide some sort of service, either on contract or in a pay for performance manner. So there’s not, I think, a extremely well established approach to getting this right, other than just to note that there’s plenty to do in the space and storage is likely to be, again, one of the central assets in that discussion, no doubt.
[01:36:34] Chris Nelder: Well, I think we’ve squeezed all the juice out of this lemon. So thank you, Jason, for coming back on the show and sharing your expert knowledge of all this stuff. It certainly has been an interesting conversation to catch up with you and to kind of talk through a lot of these issues. I mean, this is stuff that I really, frankly, don’t have the time to fully stay on top of. And so I just think it’s fascinating to talk to somebody like you who lives and breathes this stuff every day and see where you think this is going. So thanks a lot for coming back. It’s good to have you back on the show.
[01:37:07] Jason Burwen: Thanks for having me, Chris. And hey, man, after five years, I have learned so much from listening to your show. I’m really glad to be able to come back and be a part of the continuing education for so many other folks out there doing great work, too.
[01:37:20] Chris Nelder: That’s awesome. Thanks very much.
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