Please note that the transcript provided below is AI-generated and intended for reference. It may contain missing words, misspellings, or other small errors. To request a correction or clarification, please contact info@theclimatecenter.org.
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We’re going to go ahead and get started on our afternoon session on demand flexibility as affordability solution. Before I get underway, a couple things to thank our sponsors. Anybody from Peninsula Clean Energy here? Do we have our sponsor from Peninsula? Okay. Thank you so much for Peninsula Clean Energy for sponsoring this session on demand flexibility. There’s good talk about it this morning. Additional, thank you to our sponsors, Sunr,un Bay Area Air District, and others as noted here. If you are an organization that wants to basically help get the word out about the policy summit, you can become a promotional partner and that just asks you to send out information to your listserv to get people to attend. These are our session speakers, so without further ado, take it away.
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Arnab Powell, Deploy Action (00:02:00):
All right. Thank you, Kurt. And thank you to The Climate Center for putting this on today. I think I’ve told them personally, I’m a huge fan and I think a lot of other states could use a climate center. Not a plug for you guys to expand, but if you do, I think you’ll find some friends. My name is Arnab Powell. I’m the executive director of an organization called Deploy Action that I co-founded with former Assemblymember Phil Ting, and we help states deploy and promote clean energy across the country. We do a bunch of work in California and we’ve done work in Virginia and across the Northeast and a handful of PJM states. I am super excited to talk about the subject here today of demand flexibility. I think what makes demand flexibility, I think, unique and special is that it is a tool to fight climate change.
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It is a tool to reduce people’s costs, and it is a tool that we can deploy fairly quickly. That being said, for some reason when we think about solutions, demand flexibility gets forgotten, but that will not be the case this year, as there are numerous people that are championing it, and there are numerous proposals that we can talk a little bit about later that will bring demand flexibility to California. So with that, I’ll let the panel introduce themselves, and then each panelist will give a presentation here for around eight minutes and we’ll take some questions.
Kate Peters, Brattle Group (00:03:46):
Hi, everyone. I will be the first panelist. My name’s Kate Peters. I work at the Brattle Group, which is an economic consulting firm and do a lot of modeling about the electric grid. Many clients are in the room, but what I’m talking about today is a recent report that we put out for GridLab and the Utilized Coalition, which examined what the grid benefits are if you increase grid utilization. And so that’s what I’m talking about in the context of affordability, demand response, and demand flexibility today. So to set the context, we’ve seen a lot of rate pressure across the US, particularly in California, in terms of rate increases as of recent. And what this recent study does is we look at utilization specifically. And so when I’m talking about utilization, we’re thinking about the electric grid that has traditionally built the system to meet peak and that peak is usually concentrated in a couple of hours.
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And so all throughout the rest of the hours of the year, the system is underutilized. There’s more capacity that could serve more load if load was there in those hours. And what we see in this chart is nationwide grid utilization is roughly 50% today. And there’s a couple different ways to look at grid utilization from the generation system, transmission system, distribution system. I’m showing generation system there.
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So when we’re thinking about grid utilization, there’s a link between grid utilization and rate impacts. And so bear with me, we’re going to do some math throughout this presentation, but the concept is relatively straightforward. If you use more of something, the average cost comes down when you’re paying for that thing. And so the concept of utilization is the first step is to create additional headroom on the system. And so that could be identifying spare capacity or actually creating new space on the system. Then you’re able to interconnect more load and do that at a lower cost than the high cost to integrate the system. That allows you to increase sales, and that can in turn bring down rate pressure and apply downward pressure to rates. If you’re able to sell more on the current system that you have, that could create downward rate pressure. And that’s the underlying concept that we study and explore in this study.
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So just a little bit of an approach overview, and then I’ll talk about some of the significance and takeaways of our finding is what we did here is we did really a proof of concept analysis. So we looked at an illustrative mid-size utility around three gigawatt of systems with some more details that I won’t need to get into, but just wanted to highlight that this is an illustrative system that could take some of these concepts and apply them to everywhere in the US and also nowhere in the US at the same time. The first, or the second step of the analysis was we calculated what the rate impact would be in this illustrative system by adding new load without a utilization focus. And so what that does is we’re adding new load with traditional investment infrastructure. That means building new gas, peaking plants, expanding the transmission system, using investment strategies to integrate new load that we have done in the past decades.
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The third step is looking at it at a different angle. What if you’re able to interconnect new load and increase the utilization on the system? And so there, you’re increasing load, not just serving it through traditional grid infrastructure, but through demand flexibility or energy efficiency or other strategies that aren’t necessarily the traditional infrastructure investment kinds. And so what are some of the findings that we found in this study? Our status quo case, we looked at across a whole bunch of cases. So read the report, this is a plug. There’s a lot more that I’ll be able to talk about in my eight minutes. But what we found is the status quo case, all else being equal without any investments in increased utilization, rates could go up 1.4%. So that doesn’t account for how gas prices are changing. There’s all these other factors that we didn’t look into this study, but we see rates could go up 1.4%.
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Then with the utilization focus, if we increase the utilization of the system by 10%, that was our illustrative example, you could have a downward rate pressure of 3.4%. And so what this kind of proof of concept analysis really showed to us is there is a benefit of investing in some of this infrastructure that could lead to increased utilization to help reduce the rising rates in the phenomenon and the experience that we’re seeing a lot today with a lot of this increased rate load growth.
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And so now I want to kind of talk about how to actually increase system utilization. What are the tools that everyone in this room has at their fingertips in order to make this happen? There’s a couple different ways to add additional headroom on the system. One could be targeting, adding new load in areas that have excess capacity. So that could be on like a transmission or distribution system focusing on adding new load in areas that currently have surplus. Option two, what we illustrate here would be adding new loads at times of day that have surplus. Maybe that could be flexible interconnection agreements, customers that agree to interconnect to the grid without demand at peak times. And then the third example would be through like a demand response or distributed energy resources, which is actually incentivizing those technologies that can create that additional headroom.
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There’s a couple kind of key components about increasing grid utilization that I want to emphasize. I think what this study really showed us and some of the collaborators that we worked with was that the proof of concept works. The concept makes sense. If you increase the utilization of the current grid, there is the potential to apply downward rate pressure and be able to interconnect the load that we’re seeing today at lower cost. There’s a couple kind of components that are really important to remember. The first is system fundamentals. When you’re thinking about utilization across a grid, it differs a lot when you’re focused in a utility region that has very industrial heavy customers versus a utility region that has very residential focused customers. The natural shape of the load pattern is very different. And when you’re thinking about utilization policies and targets, you need to reflect that.
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Another one that I want to call out is cost effectiveness. You really need to make sure when you’re thinking about improving utilization, that that’s not the target. The target is using increased utilization as a strategy to apply downward pressure on rates. So when you’re thinking about how to increase grid utilization, it’s important to compare the cost between the distributed energy resources and the traditional grid infrastructure and whatever other tools you have at play.
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I just want to leave with one DSGS example, because I feel like we’ve talked about this program a lot, just to bring it home to California, and just illustrate how this program hits some of those targets and serves as a way to increase grid utilization in the California example. So what I’m showing here is a July test event that was called this past summer, where these distributed batteries, and this DSGS program is a CEC program in California that compensates customers with the distributed batteries to dispatch at a certain period of time for grid resiliency. And what I’m demonstrating here is on July 29th, these batteries were dispatched all at once. And I’ll leave this here as my final slide, as we can talk about this more as the panel goes on, but how DSGS is able to use these batteries specifically to, as you can see, as illustrated here, reduce the net load in the California system in a way that could be cost effective, definitely can be scalable.
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It only happened over the course of a year or two. And now I think the question is if it’s long lasting given the current policy questions. So I’ll stop there and move for the rest of the panel.
Dr. David Reichmuth, Union of Concerned Scientists (00:12:27):
Sorry. Hi, everyone. My name is David Reichmith. I am research director for the Clean Transportation Program at the Union Concerned Scientists, and I’m going to be talking today about how electric vehicles can save the grid. I say that because about 10 years ago, the question I would get all the time is, “Wait, you want all these electric vehicles? That’s going to kill the grid.” And no, it’s not. It’s actually the opposite. It’s going to save the grid. And in California, last three years, about one in five new vehicles has been a plugin vehicle. We now have over 1.5 million battery electric vehicles in the state. And over time, if you look over the last decade or so, the range of average vehicle has gone from around 100 miles to 300 miles, and that’s because, and that has led to increase in battery capacity in these electric vehicles.
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So we’ve gone from over doubling from below 40 kilowatt hour average battery size to around 80 kilowatt hours now. But what does that mean? What does 80 kilowatt hours mean? If you look at a Tesla power wall, which is a home energy storage system, that’s about 14 kilowatt hours. So the vehicles that are being sold today have about the equivalent of five to six Tesla power wall in terms of battery capacity storage. And the vehicles that we drive, the passenger cars and trucks that we drive, they are sitting for about 95% of the day. So we have this incredible resource that’s much bigger than these battery systems we’re putting in at homes, and they’re just sitting there not being used. And so this gives us this advantage to use those electric vehicles to benefit the electric grid. And one way we could do it is, there’s many different ways that the vehicles could help the grid.
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I have here here, generation, electric delivery and consumer uses. I mean, I think that the right side there, consumer uses is the easiest one to understand. It’s if you’re electric vehicle, you can hook it up to your home and it can provide backup power. And that’s a pretty simple thing to think about, but the benefits could go much bigger than that. If you think about the generation, can we use managed charging, also known as V1G, to use to charge batteries when electricity is cheaper and cleaner, like when we have an excess of solar or wind power, or ramp down charging when power is dirtier or more expensive, that’s another one that we can do. But if we can actually have vehicles feed power back to the grid, what’s also known as V2G, we can potentially save money in that middle section there on electric delivery in terms of can we reduce the peak load on the distribution system so that we can reduce upgrades to substations, reduce upgrades to that very expensive delivery system that we have.
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And so at UCS, we did a study where we looked at different VGI enrollment scenarios, looking at a situation where we had essentially full electrification of the passenger fleet by 2045. And what we found was that the savings to the electric system, the electricity grid were between two billion and close to $12 billion per year in 2045, depending on whether you had a small amount of managed charging all the way to a large number of vehicles doing fully bidirectional charging.
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And the largest section of that was … And I don’t have time to go into detail here, but the yellow bars there are the electricity delivery. So that’s the largest piece of savings we saw in this report was from the savings on transmission and distribution. And this is a unique capability for the electric vehicles is that not only can they sync up with generation at the right time, but those vehicles are at the end of the distribution system and can provide power that can save money on that delivery, as well as saving money on the generation.
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And if you look at that on a per vehicle level, for participating vehicles, the savings would be somewhere between 500 and $1,200 per vehicle, potentially. Now, that’s savings to the grid. Now, presumably some of that savings would just go to reducing costs overall and put downward pressure on rates overall, just as Kate mentioned, but it would also … Some of that would probably also go to an incentive to make sure that we get the EV drivers participating. Now, one question, that is a scenario looking out to 2045, but I want to bring this back to today. What do we need to do today? Is this just something like, “Hey, we need to plan for 15 years, 20 years out? ” No, I mean, this is something that we can actually do today. Managed charging, there are pilots in different … I know Marin, sorry, MCE has a pilot program doing managed charging.
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This is from the LA Auto Show last November, and this is GMs showing off their bidirectional home energy system right there. So this is things that the manufacturers can do today, and all of the GM vehicles, that’s Chevy, Cadillac, GMC, battery electric vehicles, all those vehicles are capable of bidirectional charging right now. So this is something they’re doing today. A lot of the manufacturers, this is again from the auto show, highlighting the fact that if you buy their Silverado EV truck, you can power your home. So they have an incentive also to help to produce these bidirectional vehicles so that they can provide another benefit for having electric vehicle beyond the reduction emissions, beyond savings on fuel. This can also be part of your home energy system. So this is something that can be done today, but we do need the right policy mechanisms in place.
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And so one thing that UCS has done, we sponsored a bill along with the Climate Center with Senator Becker. It’s SB1282, which would allow the California Energy Commission to do a study to look at what level of grid connected batteries we need to drive these benefits to the state, and then allow the CEC to initiate regulations that would make sure that we get these grid connected batteries delivered and available for use in the state. And so I’m happy to talk further about that effort or more details about the studies we’ve done later in the Q&A. So thank you.
Erik Lyon, Renew Home (00:20:34):
All right. Hey, everybody. My name is Eric Lyon. I am the energy regulatory manager for California and the West at Renew Home. For those who don’t know, Renew Home is a residential demand response and distributed energy resource aggregator. We operate primarily thermostat enabled load flexibility at this point with Nest thermostats. We operate across 40 states and over a hundred utilities, including three independent system operators, and yes, Kaiso is one of them, and yes, I am also wearing my Kaiso socks today. Nationally, we have over five million households connected to our platform with total load flexibility of over four gigawatts.
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So I’d like to start by laying out Renew Home’s vision for unlocking the potential of residential demand response to address energy affordability, as my fellow panelists have discussed. So traditional bring your own thermostat type DR programs have only managed to reach early adopters and more sophisticated energy users, like Leah Stokes types, and many of us in this room. They typically require jumping through quite a few hoops to enroll, and typically we’ll adjust your thermostat for three to four degrees for three to four hours. Accordingly, we’ve only ever managed to reach something like 15 to 20% of smart thermostat owners. And at Renew Home, we believe that many more users are willing to participate, but they’re not all that willing or able to go through the trouble to dig up a utility, account number, or a password and enroll in a program. So our vision is a streamlined low friction enrollment in load flexibility programs to get that participation rate from 15 to 20% all the way up to 70 or 80%.
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So first, we make it simpler for people to participate. We ask thermostat owners to allow us to adjust their thermostat, to support the grid at setup, and then also nudge customers, existing users, to allow us to do so. And that’s pretty much it. We also assume this cohort is a little bit less engaged, a little bit less sophisticated, so we apply smaller shifts and shorter durations, typically one to two degrees for one to two hours. We also personalize these shifts so that users that have historically opted out will get smaller shifts. And while the per customer impact of this approach is somewhat lower, the sheer number of these customers means that overall capacity grows significantly. And so what does this look like in practice? Last September, Renew Home ran a test event with over half a million of these users across California, and the results are really staggering.
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We estimated a two hour load reduction of over 200 megawatts. We ran this event as a randomized controlled trial, meaning we compared the participants against a random control group of over 60,000 homes that we withheld from the event. This plot shows the results in two ways. Up top, you can see the average load of the control and treatment group, and on bottom you can see the aggregate load impact, which is the difference between the two multiplied out by the number of households in the treatment group.
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We measured the amount of time that each air conditioning system was running and used that to estimate the average per home load in 15 minute intervals, assuming 2.5 kilowatts per air conditioner. That value is deliberately conservative to make sure we’re not overestimating the results, but it probably means we’re underestimating them a little bit. And this is all just to illustrate the magnitude of the resource that is available to California right now, if we can access it. So how do we unlock this capacity that is sitting on the sidelines? I want to show sort of where we are now compared to where we want to get to across four different categories. There’s more I could get into, but I will spare you all. First, identifying a customer is a critical step to enrolling them. Today, we typically use the utility account number, which in practice means utilities have to log into their utility website, and we’d like to get to a world where users and their homes are identified by their street address for the simple fact that people know their street address.
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That’s something you can enter without leaving the app or finding an old bill or logging into your utility website. Second, how do we measure load impacts? One reason we have historically required an account number is because your account is tied to your electric meter, and we’ve needed that meter data to measure load reductions. However, we can access data directly from the devices that we control. And for thermostats, that’s the HVAC runtime data that I mentioned before, but solar and storage systems have onboard generation, charge, and discharge data that aggregators can access directly. Also within this category of measurement, DR and California typically relies on historical consumption baselines. To estimate load reductions, those are really prone to errors. I won’t get into the nitty gritties of that. And you can make some adjustments to them, but they’re ultimately not very good. Renew home strongly prefers randomized controlled trials, as I mentioned before, and it’s a much more robust and unbiased way to measure the causal impact of what we’re actually doing.
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Next, measuring load impact at the meter means only one aggregator can enroll a customer, but what if somebody has a nest thermostat and they also have a home battery? If we’re measuring load impacts at the device level, multiple resources can be managed by multiple aggregators, and those resources can coexist at a single location without worrying about double counting or double paying for the same load impacts. Finally, and this is relevant to batteries and not so much to thermostats, but it’s also really important to include exports in performance and compensation. The current rules treat exports the same as zero, meaning you can’t really get the full value out of a solar and storage system.
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So next, I want to touch on some efforts to move us closer to this future state. One which we’ve heard a lot about today already is DSGS, the Demand Side Grid Support Program. Previously, I worked at the California Energy Commission where I was a primary author and designer of this program. I’m really proud to see the continued work on this program and the success and growth. So big shout out to CEC and the team for that excellent work. But when I talk about DSGS today, I’m really talking about option three for batteries and option four for smart thermostats. DSGS is a great example of this future state and with the exception of randomized controlled trials, and my team never lets me hear the end of it, but you can see I added another row to the bottom of this table. Demand response is currently integrated into our system reliability planning or resource adequacy framework, and rightfully so.
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That should not change in the future state. But DSGS has always been incremental to and operated outside of this framework, and it had to be this way, so that we could try all these new and innovative program designs. But here at the end of my last slide, I’m finally going to connect this all back to affordability, as promised, to really get cost savings out of these resources, they can’t just be stacked on top of resource adequacy. That’s just buying more resources and paying for more resources. To save California’s money on their electric bills, they have to compete in the resource adequacy market and offset other more expensive and dirtier resources. And that’s where SB 913 comes into play, which Ellie mentioned this morning, and this is another bill authored by Senator Becker, who you also heard speak earlier today. What’s exciting about this bill is that it takes the successes and lessons learned from DSGS and moves them into the resource adequacy program.
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And that, in my view, is the key to leveraging these resources for affordability, getting them off the sidelines and into the market where they can provide the greatest value. And that’s it. Thank you.
John Taggart, WeaveGrid (00:29:40):
All right. Thank you all for having me here. Thank you, Kurt, for inviting me to join the panel. Really excited to be on this esteemed group. I think I might sound like a bit of an echo the next couple of minutes. I think the focus on grid utilization, cost effectiveness, really the potential for EVs and how do we drive participation and real results I think are really all of critical importance to what we’re trying to do. So I’m John Taggart. I’m the co-founder and president of WeaveGrid. We’re a software company based here in California, just down the road at San Francisco.
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We work on grid orchestration of DERs with a particular focus on electric vehicles. Right now we have more than two dozen active programs across the country, including with seven of the 10 largest utilities and are invested in by several leading automakers as well. So we focus on EVs because they are really a unique resource, as I think David highlighted. They’re growing really fast, doubling every couple of years. They’re very high power and high energy. It’s not just the battery size, it’s also the demand they place on the grid. And then how that demand impacts how we operate the grid and how we need to plan to upgrade it over time. There’s significant impacts, particularly down at the distribution level.
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But they’re not primarily DERs. People buy them as cars. They want to use them as cars, they drive around. And so that experience is really critical that you’re not impinging on how people are trying to use their car. But if you can unlock the participation, they’re extremely flexible resources and increasingly bidirectional. So these are some facts that I think are not a surprise to anyone in this room. California is on one level, a leader in EV adoption. We have two and a half million Zevs, one and a half million bevs. We’ve been over 20% new sales percent for the last five years. But at the same time, we also have very high electricity costs. And a huge percentage that cost is distribution and a capital investment in the poles and wires below the transmission network. So bear with me a second. This is my riskiest slide.
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We have a few choices and I’m going to grossly oversimplify them here. One, we have the status quo. We do some R&D pilots. We kind of look at each other, plan to make a strategy, and then a few years kind of get mad at each other and point fingers because it’s both expensive for the EV drivers and it’s expensive for everyone else. Now we can do what California likes to do a lot of times, which is say, “Hey, this new technology, let’s get really excited. Let’s go and subsidize it. Let’s see if we can throw money at the problem, find a few hundred million dollars, just laying around and make sure that we can encourage adoption, encourage people to take this up.” That of course has consequences for everyone else.
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And I think in an environment today where we are budget constrained, it’s not a particularly popular option here in Sacramento. You can go the other way. You can shift the costs to the new users and say, “Hey, we’re going to grandfather everyone in all the existing uses and users and try and shift all the costs onto the new users.” This is often very popular with data centers, I think less so with EVs. I think there’s another way. The Goldilocks is the thing in this quadrant. How do we keep costs low for rate payers and how do we keep them low for EV owners as well? And I’ll tell you a little bit about that in a second. Fortunately, that opportunity does exist. So there’s a port came out recently from the public advocates office showed that we could save somewhere between five and $18 billion through distribution level orchestration.That’s over half of the distribution level investment that would otherwise be required absent that orchestration.
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Our company built the tool to do that. So we call it Disco, distribution integrated smart charging orchestration since rebranded to system capacity orchestration as we’ve added other devices. This has really required digging in deep to both sides of the equation, both working very closely with automakers to understand their roadmaps and experience and software and how we integrate, but then also working closely with the utilities and their IT stack so that we know the context on the system and the needs that it has so that this can be trusted as an operational tool. And so this creates effectively that loading order that we were talking about earlier. Customer needs first, customer needs their EV if they need to drive, but let’s protect the system next. Okay, if we have flexibility and we have open capacity, let’s really try and optimize for that bulk system and where those renewables and low cost power.
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How we do this today though is often without any of that intelligence. So without any managed charging, you typically see behavior like this, people come home in the early evening, start charging, peaks a little after the bulk system peak because more residential feeders, and then kind of declines over through the night. With time of use rates, with traditional plan response programs, even dynamic rates, it does a really effective job of shifting that bulk peak away. A lot of EV drivers will set their timer on the car and say, “I’m going to charge after 9:00 PM or 10:00 PM or whenever the off peak time starts.” In areas w-ith high EV adoption, that leads to snapback effect where you get actually higher loading on the assets than you would’ve otherwise had. So by incorporating the grid context, we can solve for both. So we can take in information on what’s happening on that feeder, as well as what’s happening in the bulk system, as well as what the customer needs, and find when the right times to charge are for those vehicles and coordinate them together.
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We’re doing this today, both in Southern California Edison and Pacific Gas and Electric. In SoCal Audison, we have a CEC grant where we’re doing this for thousands of vehicles targeting congested feeders in low-income and disadvantaged communities in particular, also adding in the layer of bidirectionality and V2G. And in PG&E, we also have focus all the way down to the low voltage transformer. So the last pull top asset that you see before it goes to your house.
(00:37:00):
These are operating at thousands of vehicles, both, and delivering real results. We’re seeing reduced frequency, duration, and extent of overloading at both the feeder and the transformer level, and that’s the kind of results that leads to real savings in terms of having to go and upgrade the system otherwise. So these are some results from PG&E and the project there where we’re operating across more than 6,000 vehicles and 4,000 service transformers, where we showed that we can consistently reduce the number of overloads, reduce the frequency of overloads. And in this case, I think that this month we didn’t have any by doing this grid orchestration in an intelligent way. And I think the challenge here next is how do we scale? How do we make sure that we take this potential, all the different opportunities, whether it’s EVs, whether it’s thermostats, batteries, and find a way to set that long-term strategy that Siva suggested at the beginning of the day and really move towards making this a reality.
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So thank you.
Arnab Powell, Deploy Action (00:38:27):
All right. So what we’ll do is I’m going to ask a couple questions of our panel here, and then we’re going to open it up to the audience. We have Kurt as the mic runner, or do we have an actual mic runner? Awesome. Okay. And part of this was answered in your presentations, but I would love to dive into this a little bit more. In many of these situations, load flexibility is a way to save money, definitely in the long term, and in some situations, just short term. And my question to you all is, what do you all see as the barriers in place as to why this is not being implemented quicker, especially as we’re in a moment of an energy affordability debate across the country? And when I say flexibility, I’m including utilization as a piece of that, utilizing more of the grid as being more flexible.
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So Kate, I’ll start with you and then we can go on down the line.
Kate Peters, Brattle Group (00:39:35):
Yeah, that’s it. Is this on? You guys hear it? Cool. Okay. Yeah, I think that is a really good question. And I will say, as of recent, there has been a lot more momentum in the space, at least in terms of what I’ve observed from utilities taking initiative to invest in distributed energy resources, to explore more effective demand response programs than they have been doing historically, which was really kind of more commission mandated or really just targeting the large industrial customers. I think now we’re at this inflection point where we have a whole bunch of electric vehicles coming on the grid or smart thermostats or customers adopting this electric equipment that could be an issue for utilities to have to deal with in order to accommodate the load growth, or on the other side, a solution. I think one of the biggest barriers that still exist today in terms of being able to unlock all of the value that we all just talked about is actually having enough trust in the system to monetize that value.
(00:40:37):
I think like we talked about for DSGS or some of the distribution planning that John just showed, there’s value that’s on the table, but it’s not necessarily integrated into resource adequacy frameworks, capacity markets or distribution planning constructs. And I think it’s starting to get there. There’s some utilities that, or a lot of utilities actively do incorporate some distributed energy resources into their modeling before they invest in a new substation upgrade, but it’s going to take kind of more examples and more proof of concept in order to actually unlock all the value that we’ve identified in these studies.
Dr. David Reichmuth, Union of Concerned Scientists (00:41:17):
Yeah. On the electric vehicle side, I mean, a couple things. One is that, I mean, it’s a relatively new product. If you think about 10 years ago, there was really a low number of sales compared to the gasoline vehicles. So it’s only in the last few years we’ve had, maybe five years, we’ve had really significant sales. There have been pilot projects at different utilities to get this. And I think the next big thing is like, how do we get from pilot project to actually deployment? Because I think we’re at the stage where we have the number of vehicles now. On the technology side, we are starting to see, I think about 20, 25% of new EVs have that bidirectional capability. So we’re starting to get there with the bidirectionality that’s going to grow. And the other thing that we’re going to see is, I think Rivian said with there R2 that’s coming out, that they’re going to have AC power out, which that’s going to drive down the costs in terms of doing the bidirectional, the hot costs on the home side to putting power back on the grid.
(00:42:24):
So that’s another thing that’s going to help drive down
Arnab Powell, Deploy Action (00:42:26):
Costs. And by technology, do you mean the technology, the EV or the grid to be able to handle it? I’m
Dr. David Reichmuth, Union of Concerned Scientists (00:42:32):
Looking at the EV side in terms of like, how can we drive those costs down? Because I mean, the other thing that’s happening is that we are having the cost of EVs come down. So getting more EVs out there means it’s going to be easier to do these, get this beneficial load on the grid and do those, essentially the demand response. So that is part of it, is making sure we get those vehicles out there because while the thermostats aren’t going anywhere, but there is this problem that I think that you mentioned, John, is that the EVs move around. We can’t, like as an aggregate, we can count on that resource in the future, but not the potentially the specific vehicle. And so just you need more EVs out there that can be participating so that we can ensure that we have the response that we need.
Erik Lyon, Renew Home (00:43:35):
So this one on. Okay. Yeah. Okay. That’s actually a great tie-in to the thermostat question, believe it or not. But I think what ties it together is historically we’ve wanted perfect and I think we’re at a place where perfect is the enemy of the good. And so in the EV charger scenario, your EV moves around, maybe it’s not plugged in that one time. For us, if we’re moving to this future state I described where we’re identifying you by your address and we’re measuring your runtime data and not looking at your meter, we can get like a huge bump in enrollment, but historically we’ve wanted to have that meter data, right? KISO has wanted to know where are the specific customers who are participating, how much load do they have at any given time? And so I think we are at a point where, what if we say, “Okay, let’s ease off a little bit about every specific customer and start looking at the aggregate more.” And I think when we sort of change our philosophy around that, we can really increase in enrollment and I think it applies across resource types.
John Taggart, WeaveGrid (00:44:51):
I think fundamentally the biggest challenge is market coordination. So even just looking in here in California, we’re a very large and diverse state. We have a lot of ideas of how to run things and what are the best policies and sort of who are the good actors, who are the bad actors. The biggest thing that can create is market uncertainty that makes it very difficult for the actors to invest. That can be in companies like ours, that can be automakers trying to invest in greater interoperability, that can be sort of utilities even trying to figure out what their portfolio is and whether they can count on these resources going forward. So I think the biggest barrier at a high level is clear lines of ownership and accountability, and then that long-term plan that we can all work towards and count on.
Arnab Powell, Deploy Action (00:45:38):
Yeah. So specifically thinking of California, look, I think it’s partially a policy barrier and I think I’m going to plug things that have already been plugged today, but there are initiatives on the table, including SB 913 around resource adequacy and we have two bills on grid utilization, both in the assembly and the Senate to set those targets and to help drive what could be a tech neutral marketplace here. I guess the question is, what is it specifically? Is it just the policy and that inability to coordinate is making it hard to create adoption, be hard to raise capital to create the investment? Is it the wait times at the PUC afterwards is taking too long? Because I think outside of electric vehicles, I’m not sure if technology is the primary barrier. I think it’s partially policy and I think we have a couple of solutions for that here that we’ve been talking about today.
(00:46:46):
I think partially it’s marketing. I mean, maybe we need to do a demand flexibility TikTok video and have it go viral. I have no idea, but what can we specifically do outside of championing these bills, which I do think is the first step to get there because we don’t have time for five years of pilots or 10 years of pilots. I think we have low growth now and I think we have bills that have gone up now. So we can start on the other end, and I hate to be poignant about the question, but actually I don’t.
John Taggart, WeaveGrid (00:47:18):
Okay. Well, I’ll start by saying that we tried the TikTok video thing. It didn’t work very well. So we’re moving on to other ideas, other pilots, if you will. Maybe an example of this, just looking at bidirectional charging specifically, because that’s, I think, an exciting one, but also a difficult one. We often describe it as kind of a five-sided chicken and egg problem. You have the automaker who has to make it capable, you have to have the equipment that is yield certified and safe for the grid. You have to have utility interconnection process that is smooth and easy to understand and follow. You have to have an export rate or some way of getting compensated for it if you’re using it to justify the investment and then, oh, you got to convince the customer at the end of this. So it’s exactly that. It’s not a technology problem fundamentally.
(00:48:09):
It’s a coordination problem between all those different actors trying to do their piece, but not do it too soon. So the biggest unblock to that, create the opportunity and make people scramble for it’s a gold rush rather than a wait and see what happens.
Erik Lyon, Renew Home (00:48:30):
Yeah. I think from Renew Homes perspective, we’re trying to be good citizens of the grid, starting by enrolling into DSGS option four for smart thermostats, which we’re very excited about. And we hope someday soon we’ll have a pathway that that really gets into California’s energy systems. But I think from the sort of policy and regulatory purpose, that means I’m also educating my company about how best to operate for the grid, right? How do we respond to policy needs? How do we respond to decarbonization needs, capacity needs, utilities needs, and yeah, that’s what we do.
Dr. David Reichmuth, Union of Concerned Scientists (00:49:14):
Yeah. I mean, I think what you said earlier about, Eric, about not letting perfectly the enemy of the good is very important. Bidirectional, there’s definitely, there’s a lot, as you mentioned, John, there’s a lot that goes into that in terms of like the technology and then making sure you have communications and everything on the home side. For things like managed charging, I don’t want to say it’s simple because I mean, I’m sure you can tell me all the complexities, but in terms of almost every EV out there could do managed charging today and there are very few, I don’t know how many are right now, what percentage, John, I don’t know.
John Taggart, WeaveGrid (00:50:03):
In California right now, it is very low, single digit, if that.
Dr. David Reichmuth, Union of Concerned Scientists (00:50:09):
Yeah. And so, I mean, I think this is the question about how do we … We need to make these plans for like a fully electrified future and grid and making sure we have the right policies in place to get there, but there’s a lot we can do right now also with the right policies.
Kate Peters, Brattle Group (00:50:30):
Yeah. I have two different ideas in terms of how to answer that, kind of both to John’s point of like, let’s have it be a gold rush. I think one is the kind of customer behavior aspect of it. I think all the solutions in terms of demand response and demand flexibility, a lot of those do revolve around like residential customer behavior, that’s where the opportunity is. And I think there are a lot of companies like the panelists before me that have made a lot of great improvements about how to sign up customers upon purchase of a smart thermostat and a vehicle and et cetera, in order to turn those immediately into a grid asset. And so I think there is a lot of progress in order to kind of create just opportunity based off of customers installing vehicles and other technologies today. I think the other one, which may be less relevant to California specifically than probably other jurisdictions that are dealing with it, but just the data center driven demand growth, I think while that can kind of create a lens of all of the issues that we’ve talked about in terms of rate pressure and like really like the need, it can also create the opportunity and the financial backing for a lot of what we’ve talked about today.
(00:51:42):
I know we’re working with Google on this like bring your own distributed capacity model, which is where Google can participate and agree to flex down their load for different interconnection requests for utilities, but they have this kind of other model where they would pay all of us or residential or small CNI customers to install distributed batteries or install thermostats and enroll in these utility programs. And that’s kind of a new innovative business model that utilities aren’t used to where having these huge hyperscaler budgets be able to fund some of these programs. And I think that’s an opportunity that the market’s able to take advantage of now.
Arnab Powell, Deploy Action (00:52:26):
Yeah. And look, I’ll piggyback off your study. I think one of the really important parts of looking at this utilization framework, and for those of you that are keeping notes, that’s AB 1975 and SB 905 in California, it could ideally, that target or that development of those metrics and that data can help create the long-term marketplace for all the things you guys talked about just now without doing the old model of let’s subsidize the technology and see how much we can get out of it and move it up the adoption curve. So I do think there’s a lot of potential here. I think I hear you on where the barriers are. And I think the reason why we’re focusing on this so succinctly here is because we think it’s a solution that’s ready for the moment based on all the things we need to accomplish in terms of clean energy, affordability and climate.
(00:53:23):
Should we open it up? Questions?
Speaker 8 (00:53:38):
Hi. I hope there’s somebody over there. Great panel. I know you guys are all in the spotlight. Meredith Alexander with Gridwell, I think most of you know me. Really great panel, great presentations. I loved all the data. I think you proved that we don’t need more data. We don’t need to run more pilots. We know what to do, but we’re missing the economic incentives or the economic ability to compensate homeowners for supporting the grid. So I think this question is for Dave and John mostly, but also for others. I think it’s interesting that on the grid utilization and maybe even on VGI, the commercial EV charging has maybe jumped over residential because in California, and I don’t know if everyone is aware, but in the energization proceeding at the CPUC, there’s a flexible service connections process whereby basically a commercial EV charger can say, charging company can say, “I am going to ensure that our utilization doesn’t go up to our potential peak, so please energize me faster.” And it’s kind of shocking to me that that happened so quickly when in the residential space, like we’re saying, managed charging is simple, there’s no downside and yet we haven’t made a lot of progress in the last … I was on the VGA working group in 2019.
(00:55:03):
It’s been a while. We’ve known about this. This isn’t news. So how is it that the commercial sector has jumped so far ahead and how can we try to bring in that inherent incentive that we have for energizing these bigger things into the residential space? Because it just seems like waiting for the utilities to develop programs isn’t going to happen. Besides GSGS, which we have, we do have charging in option four, right? Eric’s nodding four. Kind of. In theory. So we can pilot the fact that these chargers will show up and they could in theory export, which leads me to my actual question, which is, is the battery warranty still a problem for V2G for bidirectional charging? And do we think that that’s part of what is still holding us up here? And then, yeah, how can we actually provide an incentive to homeowners to participate besides a pilot?
John Taggart, WeaveGrid (00:56:03):
All right. I’ll do my best to start here and then hand off to David, but I think that the reason you see the show up in the commercial with flexible service connections rather than residential is there is no interconnection process for residential. You buy a car, you take it home, it just happens. It’s much more by necessity for these really high power, often DC fast charging sites pulling hundreds of kilowatts, if not megawatts at a point in time. The utility literally cannot connect them quickly enough, and so this is a stop gap before they can go and upgrade the grid. I think that’s a lot harder to see at the residential level because it’s so distributed and so heterogeneous. It’s not one graph with one impact. It’s a thousand graphs with a thousand impacts and you have to figure out how to basically aggregate that up to really test that cost effectiveness piece that was highlighted at the beginning.
(00:57:05):
Second question on the battery warranty side, I don’t think any OEMs figured it out yet. I don’t think it’ll be a huge problem. As soon as an OEM wants to use this as a selling point, they will figure that out.
Dr. David Reichmuth, Union of Concerned Scientists (00:57:19):
Yeah. And I mean, there are starting to be studies out there looking at the impact on degradation and right now it looks like the degradation due to bidirectional is lower than just the inherent differences between different manufacturing processes. So it’s not really showing up as an issue right now. The other thing is, I mean, when I showed some data from a study we did, and one is we didn’t assume any … We assumed only level two, we didn’t assume any contribution from DC fast charging in that. But when we looked at the high VGI case, we were looking at a fleet-wide average of, I think less than 800 miles, the equivalent of less than 800 miles per year of utilization. It’s actually a very small number of hours per year that you require significant contributions for bidirectional power export. And there’s many hours where you maybe just need a small number of power export, but especially if you spread that intelligently across the fleet, the per vehicle utilization is relatively small compared to driving.
John Taggart, WeaveGrid (00:58:48):
Just adding quickly, because I know you also asked the question about utility programs and how do we get those to scale for managed charging. I want to make a clear distinction between programs like DSGS that are there to support the bulk system and when the overall California grid is strained and what we’re trying to do down at the distribution level where it’s much more of a long-term daily type of activity, going through utility programs can be hard and it can take a long time. When you’re dealing with distribution, it’s also something that’s pretty much unavoidable because they are the ones that operate, maintain that system and have all the data, have all the understanding of what the constraints are and when they need to go and upgrade something. So it’s hard, but it’s not something that I think you can do the same way that you necessarily do for bulk system capacity or market type systems where you say, “Hey, here’s just a program that we’re going to do everywhere, just follow this
Arnab Powell, Deploy Action (00:59:48):
Rule.” Great. Let’s take a couple more questions. I can’t really see anyone over there. We got some hands up. Do you want I’m going to run the mic over.
Speaker 9 (01:00:04):
Hello. My name’s John Sardo. I work with a company called dcbel. We provide a residential V2G charger, V2HN, V2G. And what I want to ask is, being that the utilities, a lot of their profit comes from building generation and distribution assets, do you think that they’re maybe intentionally kind of keeping this technology tamping it down a bit because it is a bit of a threat to their business model?
Kate Peters, Brattle Group (01:00:40):
Yeah, I can start with that one. I would say, I mean, I haven’t been in the industry that long, but historically, yes. I think there has been competition between distributed energy resources and more traditional investments from a utility profit perspective. At least what I’ve seen in terms of the different utilities that I work for and their interest in the space is they a lot see there to be an extreme rate pressure concern that is driving more affordable solutions. The traditional way to interconnect load and serve their system of investing in transmission and distribution substations and traditional generators just isn’t palatable right now in terms of the load conditions, the supply chain constraints and generally the rate pressure appetite. And so while there may be not the best revenue requirement incentives in terms of the line that it hits on utility balance sheets, there definitely is appetite across utilities in order to find those more cost effective solutions because of rate pressure that they’re getting from commissioners or just customers in general.
Arnab Powell, Deploy Action (01:01:54):
Awesome. We have time for one or two more. If you want right up front.
Speaker 10 (01:02:04):
Oh, hi. So I recently discovered that PG&E has this, what do they call it? Flex pricing plan that looks like anybody can sign up for it. And there’s various apps like eV.energy that can handle managing the charging. It sort of looks like these things are available to anybody, but I didn’t know about it and I follow these things pretty closely until I just stumbled upon it. Are those just generally available or are these really … I don’t know. Just if there’s something you know that I don’t know, tell me. I guess that’s it.
John Taggart, WeaveGrid (01:02:46):
So I think that the particular one you’re referring to is the dynamic rates pilots that the IOUs, SCE and PG&E were instructed to do. The hourly flex pricing pilot. I think there’s a lot of promise in sort of trying to push dynamic rates and signals to end users. The challenge is most customers are not probably like people in the room here. They’re not that engaged with their energy bill. They don’t like paying it. No one likes paying large energy bills, but they’re not at the level where they want to look at what’s happening day to day and hour to hour and optimize what’s happening around that. And so that is one pilot that is out there, but hasn’t gotten a lot of uptake yet. PG&E has a number of other pilots as well. SCE has a number of other pilots as well. I think they’re always testing out new concepts and things to do.
(01:03:44):
But I think the call and the push here is like, are there ways we can do something scalable and engage some of those users who are not energy wonks who have the assets, but otherwise wouldn’t be participating in supporting the Galvan grid.
Erik Lyon, Renew Home (01:04:02):
Yeah. I mean, I think the keyword here is pilot. I think these are still pretty small scale. I’m not exactly sure who is eligible to enroll right now, but really agree with John’s point that like not everybody is super sophisticated and able to manage their load in response to these time signals or price signals. I think for average residential customer, a TOU rate sends a really salient, consistent signal. Let’s try to not do our, run the dryer at 7:00 PM, that kind of thing. I think it’s really on the aggregators, the third parties to come in and help them manage their other loads in ways that are beneficial to the grid. So I actually love the price signal that PG&E is putting through. I think they should be passing that to us as opposed to a residential customer. If we are able to shift two or three hours of really valuable load and that load shows up two hours earlier and two hours later and really cheap hours, we should be able to sort of manage that arbitrage and get paid for that.
(01:05:15):
And that’s really different from what we do in the ISO. Well, it’s similar, but what’s different about it is all those capacity costs, all those transmission costs, even some of those distribution costs are baked into that price signal in a way that we only see the sort of wholesale marginal cost of energy at the CAISO level. And so it’s just like a really different way of approaching load flexibility. –
Dr. David Reichmuth, Union of Concerned Scientists (01:05:41):
Yeah. And I’ll just add, I mean, for the EV driver, it has to be simple. I mean, you can choose like, “Okay, I’m not going to run the dryer. I’m going to shift this a few hours,” but you certainly can’t easily shift your EV from, “Oh, I want it to finish charging at 2:00 AM. Oh no, I’m going to wake up at 3:00 AM and plug it in now.” It has to be … And I think you’re right that people just don’t understand. If you drive by a gas station and it says $2 a gallon, you’re going to immediately know what that means. If you drive by, it says $8 a gallon, you know what that means. If you tell the average person that’s not in this room, “Do you want to buy electricity at 10 cents a kilowatt hour?” I don’t think, correct me if I’m wrong, I don’t think people know what that means.
(01:06:36):
It’s got to be simple, like I need to start my commute at 7:00 AM. I need to be able to go this far and PG&E, figure out MCE, Ava, figure out what needs to happen for the grid and for me to get where I need to go.
Arnab Powell, Deploy Action (01:07:00):
Right. I think we have time for … Do we have time for one more?
Speaker 5 (01:07:03):
I’ll close it out of here if that’s okay. So hi, Julia Piper with Good Leap. So I did miss the beginning of the panel, so bear with me, but maybe to tie it up in a bow, what can California do to Lee? That was sort of one of the main stage panels we saw, obviously a lot of leadership on creating DSGS and so many innovative programs here, but as working at a company called Good Leap that participates in DSGS now, we’re also following a lot of different developments. You have time of use rates, demand flexibility or demand flexible … Excuse me. You have various pricing signals. You have DSGS, you have time of use rates, you have utilities potentially having varying levels of control and customers kind of stuck in the middle and service providers wanting to help and work closer. You have hyperscalers maybe doing their own thing.
(01:07:46):
It feels like now we’re in this very cluttered kind of policy environment. What would you think the state needs to do now to lead again and create some really clear vision? If you could wave your magic wand, what is the next best step we could take as a collective to make sure we’re really leveraging and utilizing the grid better as I know Deploy and our Knob and others have talked about? What do you think that low-hanging fruit would be where we sit today?
Erik Lyon, Renew Home (01:08:12):
I can jump in. I think the thread that’s sort of tying all the things that I’ve worked on together is that it’s all based on price signals. We just had a question about dynamic pricing. I think that’s a great signal for an aggregator. I talked about responding to prices in the wholesale market and CAISO and wearing my CISO socks, just DSGS, price based response, not load based response, right? DSGS is triggered by the highest price hours. I think what California needs to do, and ideally consolidate these down to a smaller number of programs that are RA eligible, is tell the providers, tell the market through these price signals what they want and when they want it. And that’s what I’ve been trying to do. That’s what I’m trying to get Renew Home to do. That’s what I’ve been trying to get the state to do.
(01:09:01):
So I would like to see more of that.
Dr. David Reichmuth, Union of Concerned Scientists (01:09:07):
I mean, I think for me, you need more grid connected batteries out there as soon as possible. There’s a lot of stuff that has to happen to make vehicle grid integration happen, but you can’t do it with a gasoline vehicle. You can’t do it with a vehicle that cannot be integrated with the grid. It has to start with that. It’s a necessary condition. I mean, there’s other things that have to happen, but we need that. I mean, I mentioned in my presentation, SB 1282 that is designed to let the CEC do that, to make sure that we get the grid connected batteries out there. And so, I mean, that is something we absolutely have to do. We can’t wait for a new administration. We can’t wait for 10 years and then start doing it to get those batteries out there.
Arnab Powell, Deploy Action (01:10:05):
We’re exactly at three o’clock.
Kurt Johnson, The Climate Center (01:10:16):
Thank you everyone and furthering remarks from David. So SB 1282, Senator Becker’s vehicle grid integration bill is going to be heard before the Senate energy committee on the 21st. So in a week at 9:00 AM, the bill recently got some opposition popping up. So on the climate center’s website, if you type in SB 1282, there’s a button to take action and it will send a email to your representative senator who’s on the energy commission. So you can do that. I recently learned that my dishwasher has a four hour delay button. Anyone else notice that on the dishwasher? So every night, I pushed that four hour delay button, so I’m not paying for electricity before 9:00 PM. So there’s a lot we can do, but we need to do a better job of figuring this all out together. Thank you everyone. We will reconvene in this room at 3:30 for the electric school bus session.