 It's great to be here at Stanford, my alma mater. Changed a lot since the days I was here, but anyway, thank you for having me here today. I'm going to go to the next slide. I'm going to talk about the work we've done at Peninsula Clean Energy. Next slide, please, about achieving 24-7 renewable energy. So just what we'll go over today. I'll give you an introduction and a background about Peninsula Clean Energy and what we're trying to do, and then talk about how we model the 24-7 work, but the results are and where we go from there. So what is Peninsula Clean Energy? We are a community choice aggregator, which means we are the generation provider for a certain portion of the state, and we represent San Mateo County. So each city and town voted in 2016 to become a part of Peninsula Clean Energy, to aggregate their electric load, and have us be the provider for that rather than PG&E. Our load is about 3,700 gigawatt hours annually. The population that we serve for the county, and also for the city of Los Santos, is about 810,000 people with 310,000 customer accounts. We are an investment-graded institution, we have an investment-grade rating for PG&E fish, and higher than PG&E's rating, I might add. And since we started delivering electricity to our customers in 2016, we have set our rates 5 percent below PG&E. So we've been delivering a cleaner and greener product, since we started for less money, and because of our discount, we saved our customers over $90 million over the last six years, which has stayed in their pockets, rather than going in PG&E's pockets. Next slide. So what is community choice aggregation? So this first graphic on the left, shows where the territories are of the investor-owned utilities in California, and the blue area is PG&E, and this shows where community choice energy programs have started up since then. Most of them are along the coast. We're right here, we're San Mateo County, and also the city of Los Panos in Merced County and we're hoping to expand further in Merced County, and there's 25 CCAs that are now serving. And the way it works is that we are the generation provider. So we provide, and our board, and our customers decide what our priority is, in terms of what our energy mix is going to be. We contract for that generation. We then put it on the grid, and then PG&E spoke with the investors. Here's, they send the bills to our customers, and we have a line item on the bill and a page on the bill. And then, so we as Peninsula Clean Energy developed a strategic plan back in 2020. And I should say we have, we are a public agency, we're called what's called a joint powers agency, and we are a not-for-profit. Each of the cities and the county that we represent, there's 21 cities, 20 in San Mateo County, City of Los Panos plus County of San Mateo, they each have a seat on our board. So we have 23 members on our board. They're all elected council members from each of those cities plus two counties supervised. So I essentially have 20 customers that I need to respond to. We developed a strategic plan back in 2020, and we have two organizational priorities. One of the top priorities is by 2025 to deliver a hundred percent renewable energy on an hourly basis. And this is a leading industry sector, no one else has done this for the first day to do it. I've been in this industry for a long time, and to me, this is where we need to go to get to a more sustainable future. And then we also will get to a hundred percent GHG free in those areas that use a lot of electricity, namely, or that we want to use a lot of electricity, which would be transportation and buildings, transition those away from fossil fuel use into using that clean electricity that we're providing. So why do we have this goal? So our mission as an organization is to reduce greenhouse gas emissions by expanding access to sustainable and affordable energy solutions. And our vision is a sustainable world with clean energy for everyone. So our goal is to deliver that clean electricity to our customers and to do that on an hourly basis and to not rely on system power or the grid for any of that electricity. And we're trying to take the lead among load-serving entities in the state, in the country, and as it turns out in the world, to show that this can be done and to show that we can do this in a cost-effective way. January 10th, I know no one uses paper anymore, but this is what it looks like if you print it out. We just printed a second white paper. We published our first white paper in December, 2021, talking about our goal and why we were doing it. And now we can go to the next slide, next one. We just published this on January 10th, which is how we will achieve 24-7 renewable energy by 2025 at costs that are competitive through today. So if we can do this, which we are gonna show you that we can, then we're on our way to more sustainable energy future. And if we can make it the same cost or less expensive, then no one's gonna object to that. If people can save money and have a superior product, they pretty much will go along with that, whether they believe in human change or whatever, kind of cost them less money, they're gonna go. So let's go to the next slide. So the way energy is looked at from a regulatory standpoint and from a reporting standpoint right now, as we look at it on an annual basis. So for example, we have a 3,700 gigawatt hour load. Right now, our product in 2023 is 50% renewable, 50% the same amount is from large hydro. So we looked at the course of the year, we have 3,700 gigawatt hours, we're gonna buy 17, 50, 18, 50 gigawatt hours of large hydro to meet the clean heart. And we think it's renewable part to fill that 3,700. It's looking at it annually and not at an hourly basis. And that's how everyone does it right now. And that's the industry standard, it's the regulatory standard. So in 2021, when we reported our annual emissions based on our mix, our emissions were five pounds of CO2 equivalent for megawatt hour. But if you were to look at it on an hourly basis, hour by hour, what words that we were actually delivering to our customers, the equivalent hourly emissions were actually 222 pounds CO2 per megawatt hour. So there's a very big difference. And for the grid overall, this is on an annual basis, the California grid was 456 pounds CO2 per megawatt hour. So we were way ahead of the overall grid, but still that five that we reported, which is great, doesn't really reflect what the actual hourly emissions are. If you could go to the next slide, this shows the power content label that we send to every customer. If anyone here pays their electricity bill, you should have gotten this from your electricity provider that tells you what the power content of your power was. It's like the good housekeeping seal of approval that everyone gets. And so in 2021, we reported five for our main product, zero for our 100% of renewable products. And that compared to the California utility average of 456. Just wanted to show you what you might see and what every one of our customers sees. But if you look at the footprint, this is a heat map of what our emissions were in 2021. And this shows the days of the year along the bottom here and then hours of the day. So there's 8,760 pixels in this graph. You can see in the summertime, when the sun is out, we're getting a lot of solar. There's a lot of wind that's blowing. The summer, we're pretty green. We're pretty much, our emissions are pretty low. But in the winter time, when there's less solar generating, there's less wind, then that's where you see more of the emissions impact. So that's what our goal is to make this thing all green. And that's what we're gonna do. You probably know this already, but looking at how California looks at renewable energy and how it's defined here in our state, it's different in other states, but renewable includes solar, wind, geothermal, small hydro. So hydro of 30 megawatts or less is considered renewable in California. If it's larger than that, it's GHG free, but it's not renewable. Biogas, wave, biomass. And so large hydro and nuclear are considered carbon free, but they are not renewable. So our goal is to be 100% renewable just using these sources of power. And if we go to the next slide, the resources that we're looking at are solar, wind, onshore, and eventually offshore. Offshore wind makes back to be available possibly by the end of the decade. Geothermal, small hydro, and then ocean wave, tidal current, we modeled that, but those technologies weren't selected. They're not really available yet. And then a lot of storage. So storage is a very important part of being able to meet the goal. So how did we go about this? So the first steps are to figure out what is our portfolio going to be made of? How do we diversify our portfolio? And the black line here is our load. This is just on an average annual basis, but the load is lower in the morning. It picks up in the later morning, pretty flat during the daytime, picks up in the evening when people come home and do whatever they're gonna do, and then it goes down in the evening. And then if you look at the supply resources that can meet that load, we have geothermal, which is the red here on the bottom. It's pretty much a base load resource. There's a little light blue line here of small hydro. Then the dark blue is wind, which is, you can see kind of the load profile or the generation profile of the wind. It's mostly picks up in the late night and then in the late afternoon. And then the solar which starts in the morning and then stops in the evening. And you can see that there are areas where we're not able to supply renewables basically in the evening and in the morning. And then there's times when we have excess generation. Question? Do you own any generating assets that produce wind, solar, anything that you contract everything? We contract for everything at this point. Next slide. So the next step is to use storage to shift the excess renewables to meet our load in those hours that were gray. So the hashed green lines here are where we are adding storage and using the excess renewables to charge that storage. And then the solid green is where we're discharging the storage to meet our needs. And then eventually the next slide shows how we would use demand side resources in the future to shift and shape the load as well. So this is our original load profile. If we can move some, since we have a lot of excess generation in the afternoon, we can add some more load in the afternoon, have people charge their cars or whatever in the afternoon, and then reduce their load in the evening. We could use another demand side resources to do that. For our 2025 modeling, the amount that demand side resources to contribute was negligible. So we didn't really model that in, but in the future, as we look at future years, that should have a greater impact. So the modeling approach that we had was to kind of come up with the scenario overall. We developed a model called the match model, which was a model that we derived from another model called the switch model. And then we had a PhD intern from UC Davis, sorry, it wasn't from Stanford, who worked on this model for two years and developed it for us. And then this was a deterministic model, meaning that you put one set of inputs in, you get one set of outputs out. So we ran lots of different runs of this model to see what the different portfolios were that would come out. We analyzed the results, then we would put it into another model called PowerSim, which is provided by a company called Ascend Analytics. And that's a stochastic model, which means we can, it looks at the different variables, whether changes in generation output due to whether changes in load. So it looks at lots of different aspects of it and analyzes the risk. And then we would look at those results, go back, do it over and over and over again, and then come up with our final recommendation. So that was kind of the approach that we used. And we based this on planning forecasts. So we have a, we forecast every day what our load is going to be, how much electricity our customers are going to use. And then we schedule power into the California independent system operator, the PISO, to serve that load with our generators. And then, but there's always differences. So we expect a load to be a certain amount on one day. It's going to be different. We expect generators to generate a certain amount of power every day. It's always going to be different. But that's what our initial work so far has been on planning forecasts. Eventually we would like to use real-time data to be able to more closely match exactly what we're doing. We don't have access to all of that data right now. We're dependent on PG&E for a lot of our load data. They don't necessarily give that to us in a timely manner. So we get that, but it's kind of after the fact. So we, at this point, are basing this on planning forecasts, which are going to be pretty close. That's some future work we're going to be doing. So we looked at a number of different scenarios. So we compared the annual renewable, and I talked at the very beginning about what it was the annual versus the hourly. So we looked at our current portfolio and how do we do our procurement right now on an annual basis. Getting to the computer is going to be useful. The music work here has got some pages that we put in. We also looked at adding more power purchase agreements, which is what a PPA stands for, to be 100% annually, as I said right now, we're 50% renewable, 50% clean. So what would it be to be 100% renewable in 2025? And then we looked at four different hourly scenarios. 90% hourly matching, 95%, 99%, and 100%, all of them being 100% renewable on an annual basis, but different levels of matching on an hourly basis. So those were all the different scenarios that we were looking at. And I'll go over those results. And then in terms of the market, we had two different market scenarios. In 2021, our pit was pretty good, fast and clean down. The market conditions looked good. And so we had done a lot of our modeling looking at that kind of condition. In 2022, things changed. Worldly frames started, energy crisis has been high. Natural gas prices went high, natural gas being the marginal fuel that prices are based on and certainly in California, there are other supply chain issues from COVID, commodity crisis, high inflation. So the market changed and the cost of power changed a lot. In 2022, we had been negotiating with certain contractors or developers for their projects. They were coming in and saying, hey, we need to change the prices and change. So we had two scenarios. The conservative case based on those more difficult economic conditions and then the oftenness. So most of our results that I'm going to talk about today are based on these are the results. So if we look at the conservative case, which are the blue bars, which is the more difficult economic conditions, and we look at the constant energy, because that's like what's the cost going to be to try to do hourly matching, giving you the results, and then we'll get into more on the specifics here. So if our current portfolio, if it's 100% of whatever base cost is, what we found was that going to hourly 99% matching was only 102% more. It was only 2% more expensive to do matching on 99% hourly basis as opposed to what we're doing right now, which is a fantastic result. I mean, it looks like, whoa, I can't see. So that's very encouraging. Interestingly, when we look at 100% though, it was at 112%. So that going from that 99% to 100%, that last 1% appears to be 10% more expensive. And then if we look at the optimistic case, basically the market conditions in 2021, and if we look at our current portfolio at 97% compared to the conservative case, we find for the hourly matching at 99%, it's about the same cost. So if costs go down, and we're hoping that the Inflation Reduction Act that was passed last year, which brings back some certainty for having the investment tax credit, production tax credit for solar and wind and a lot of other incentives for renewable power, will hopefully bring more stability back to the market and bring costs back down. So in any event, it looks really positive for us to be able to do this. So we're planning to adopt the 99% hourly and that is our goal to reach that in 2025. How do you define cost? Our cost is overall cost of all of the resources to meet our load, dollars per megawatt hour, or the total cost. So our total cost for meeting our load is about 200 to 220 million annually depending on where market prices are. And if you divide that through by our load, you can come up with a dollar. Roughly, what's the percentile over the bad of the storage? Or let's pick the 99% scenario, right? What's the percentile over the storage on your either very mobile scenario roughly? What's the percentage of the cost of the storage? Yeah, the cost of storage. So we are a public agency, but we are in a competitive market, so we don't share the cost of storage. So that's why we're showing this in percentages as opposed to showing the actual dollar amounts and the costs are varying right now. But yeah. Next slide, please. So this is just kind of a summary of it. In the conservative case, the time coincident at a 99%, amount could be achieved with only a 2% cost increase, whereas as the 10% jumps to go up to 100%. So that's our goal as the 99%. So if we look at what we need to add to our portfolio to do this, this is kind of our next goal is to procure the electricity and the resources that we need to achieve this 99% matching. So in our current portfolio, we have about 1,230 megawatts of capacity that consists of some geothermal, small hydro, about 500 megawatts of solar, 320 megawatts of wind, 116 megawatts of storage, and then some short-term renewables contracts to get us to our 50% renewable, 50% clean. So what we need to add to get to the 99% hourly is to get to a total of 1891 megawatts. So there's going to be some over procurement there and we'll talk about that a little bit more, but in order to do that matching, we need to have more than what we need. And so it's going to require that we procure another 200 plus megawatts of storage, another about 250 megawatts of wind, about 250 more megawatts of solar, small hydro and not too much because there's not too much of that available and then about 100 megawatts more of geothermal. So that's our goal in our procurement. And right now we have a request for offer out there. We're expecting proposals from different developers that are due on Monday and we'll look through what we find and hopefully the prices will be good. We'll put them into our match model, run it and see which ones will help us get to our goal. Question? What is it all about? That's the spectrum. So we're going to pass it to the visual. What is the capacity factor of the solar project? We're really. Yeah. I don't know. Each project is different. I think the wind is usually between 30 to 35% capacity factor, the solar. I don't know what the capacity factor is. I think that's about 20% of something like that. Yeah. I mean, they produce more in the summer, less in the winter. And actually. I have a related question. Did you focus on purchasing energy, purchasing capacity or both? Both. What's the, how does that come across? How do you balance your capacity goal and your energy goal? And are they interrelated? Does it affect the way you make your choices? Yeah. Does everyone hear the question? How do we balance? Are we buying energy or capacity or both? And how do we balance those? So this, this focus is mostly on energy or what I'm presenting today as mostly energy, but we do have a capacity requirement in terms of reliability for the state. So the public utilities commission tells us how much we need to procure. I think we'd have to be 116% of what our load is. So there's a planning reserve margin, like 16% for us. So for our projects, we get a certain amount of capacity credit for solar projects, certain amounts for wind, more for geothermal and storage. That's related to what he's saying. Yeah. Yeah. And they vary the regulatory uncertainty and the regulatory changes are difficult to deal with because you think storage, for example, that it's all there. Like if you put in 100 megawatts of storage, you should get credit for 100 megawatts of capacity. But the way the public utilities commission is looking at it over time, they, because more and more storage is going to be added to the grid, they reduce the value of the capacity from those storage projects. Yeah. So it's like, well, we have to add more, even though we haven't, we have to keep adding more to meet the regulatory requirements. Sometimes those come in conflict with what our goal is. Yeah. Like the function that you get after the credit, but I was just wondering how much is the total of the supply of, how does that kind of like, are that 100 megawatts of storage, what happens if it's probably between like, how much is that effect to the total? Yeah. So we have to buy capacity. We have to go outside of just our own resources to fulfill the capacity requirements. Because like for solar, if you have a 100 megawatts solar project, I don't know what the percentages, maybe five or 10% of that qualifies for capacity. So we have to go elsewhere to purchase that. It's called resource adequacy. So we just go into the market and buy it as does everybody else. And cost of that has gone way, way up because there's so much demand for it. And the Public Utilities Commission keeps saying you need to buy more and more and more. And it isn't there. So it's one of the things we're trying to manage as are all those serving entities. Did I answer your question? Numbers around how much you have to do externally versus what you can distill on your own and curious to know more about like, how reliable you are outside. You know, I don't have in my head what percentage of the capacity need is provided from our own resources versus going out and buying just excess capacity from other resources. I don't know what that is on hand. Probably figure it out, but probably at least 50%. I would say probably from outside resources. So it's a separate product. Something that affects our budget because we have to spend so much money on it. Okay, so let's go to the next slide. So this is the supply stack for the 99% scenario. And in each season of the year, spring, summer, fall and winter, and it shows our load profile for each season which slightly changes. And actually our load is highest in the winter time. We're a winter peaking agency because in San Mateo County, it's like here, the weather is pretty nice. There isn't a lot of air conditioning load in the summer, at least not right now. Getting hotter, that might change. So this is how things stack up. And you can see in the summer or in the spring of the summer, we have a lot of excess solar. And so a lot of that is going to be used for charging the storage, but we'll also have some excess as well. But in the wintertime is really the challenge because the solar produces way less in the wintertime. And so the amount that we are able to charge the storage from the solar, the excess solar in the winter, doesn't quite meet our needs in the wintertime in the late night hours and the early morning hours. So one way to solve that is to procure a whole lot more solar so that there is more solar available in the winter for that. But then we'd be way, way excess in the summer in the spring. And that's kind of the challenge of getting to that 100%. So we would, we go back, go back one slide. We see that, can you go back one? Yeah. To get to the hourly 100%, instead of having like 1,900 megawatts of resources, we need 2,600. So we have to buy, procure 700 megawatts more resources just to meet that last 1%, just to meet those last 1% of 8,760 hours. How many is that? 87 hours. So we're not going to do that. That's why it costs so much more. But to get to 99%, that's pretty good, you know? Around 99% it rounds up to 100. So that's really the interesting result that we found from this, at least for our load and for the resources that we have available. If we were able to get more geothermal or more what we call firm clean resources, like if it's geothermal, then that would help us meet the winter requirements. And then we could reduce the amount of solar that we need. So if we look at the emissions reductions, which is the overall goal of this, right? Is to get emissions reductions down. So we find that the carbon intensity reduces over time as we go from less hourly to more hourly. And what we find for the hourly 99% matching is that we will be able to get down to 26 pounds of CO2 per megawatt hour in that scenario. It's not zero because the geothermal does have some carbon emissions. We didn't have any geothermal, we could get that down to zero, but we need to have that geothermal. But overall, that's still pretty good. So we go from 195 of what we expect our hourly emissions to be 2025 from our current portfolio to 26 in the 1990s. And then if we look at the heat map for the next slide. So if we were to just do the annual 100% in 2025, this is what the heat map looks like. We're down to 155 pounds CO2 per megawatt hour compared to what we are right now. I think we're at 22. So it's an improvement, but there's still a lot of emissions. And instead, if we go to the 99% which was the next slide, we see that we're pretty much all green, which is our goal, except in the winter nighttime and morning hours. So we're hoping that someone might come up with a product that we can use for those hours that would help us. And then we look at the incremental cost of reducing these emissions. So it's like, what is the equivalent carbon price that we're paying to reduce the emissions? And again, when we look at the 99% hourly matching, it's about $22 per megawatt hour. And if one was to assume that the price of carbon is $50 per megawatt hour as has been proposed and think by the Biden administration where everyone has their own number, what this shows is that it is worth it to go ahead and do this, because the cost to reduce the emissions is less than the cost of that carbon. However, for the 100% it's more. So... It's a touchscreen. Oh, this, I was wondering why it says nothing on it. Sorry. I'm drawing it too. I don't wanna talk to anyone. For the 100%, it looks like it's not quite as cost effective for the emissions. And then if we go to the next item, which is looking at the risk premium. So I noted that we did the stochastic modeling and we ran like 50 different scenarios in the stochastic model to look at what is the risk that we have that the results are gonna be different and that the cost is gonna be different. And what we find is that the risk is actually lowest for the 99% hourly matching. And so it's saying that the risk premium is 6%. So instead of that 2% increase in cost, it could be another 6% increase. On the other hand, if we were to do the stay with what our current portfolio is, the risk is even higher because it's 11.8%. And so the why is that? Part of that is because we're contracting for all this renewable power. When you contract for renewables, it's a set price. Most of the cost is at the very beginning for the infrastructure, but the fuel is free. And then we're also over procuring. So we have kind of a hedge against if our forecasts are off that we have a lot of excess renewables. Although we do want to be able to dispel those. So that's my spirit, but yeah. So basically the risk is lower with because we're over procured. So we are over procured and I didn't put the slide in, but one of our assumptions is that because we are over procuring and we're gonna be over procuring by about 45%, more of what we need, we're purchasing. And our goal is to resell that back into the market or to other load serving entities. And our assumption is that we can resell 75% of that. 75% of the excess renewables, 75% of the excess capacity that we're gonna end up having and that will still get us to those results. But we find even if we aren't able to sell all of that, the impact on our costs is only about another 2% or so. That won't kill us, but it will be good to be able to resell those excess. And then also, yeah. Your contracts, is there a performance requirement for energy availability? And is it 100% or something reduced and is it factoring into your risk? Yeah. So in our contracts, like for solar, there is a performance guarantee that they have to generate a certain amount or that they guarantee there's gonna be a certain amount of production per year. It might be averaged over two years because there's always variation, the same with the wind. And if they don't do that, then there's a payment they need to make to us because then we'll have to go elsewhere to get that energy. Was there a second part? Just a question, you know, that there's forced outages and sun doesn't shine sometimes. So it may factor in to this risk premium, how many market real-time transactions do you need to be doing it? Yeah. You're accounting for that. So the stochastic analysis gets into that. Like what if it doesn't generate as it's supposed to? Whereas the match model says, now it's gonna do what it says it's gonna do. The Ascend Analytics PowerSim modeling looks at what's really gonna happen, what could happen and what's the worst case. So the other question is, how does this affect the overall grid, what we're doing? And what we, in California, they calculate what is the net peak. So there's the peak when there's the maximum electricity use in the state. And the net peak is looking at what's the maximum when you subtract out the renewables. And that's kind of what the focus on is in the state these days. And so the question is, are we helping or hurting that net peak? And what we find is that we are helping the net peak, that we're helping to reduce that net peak because of all the renewables that we're putting onto the grid that helps to bring that net peak down. So we're not exacerbating any problems as the state has in trying to meet the load. And then the next slide is on, so I talked at the very beginning that we're looking at this from a planning perspective, from a forecasted perspective. And when we look at, if we say, okay, we're gonna hit 99%, I won't touch that. If we look at what might happen in real-time operations, the expectation is that we'll be a little bit less, that the time coincident target will be off by about one to 3%. So even though we're on a planning perspective, we're planning to become time-coincident 99% of the time, what will likely happen is that we'll be time-coincident 96% to 98% of the time, which is still pretty good. But we'll find out more as we actually do it and as we actually have more data available to be more closely aligned on the time pool. In summary, what we find is on the conservative case, the 99% time-coincident will increase our costs by only 2% at most. And it could even decrease it by 1% to get more back to what they were in 2021. And then doing this results to the benefits society because we are reducing emissions overall and we're helping the grid to be more efficient. So all of those are good results. We talk about the risks. So I mentioned our expectation of reselling the excess renewables, the excess recs and resource adequacy. So we're hoping that we can resell 75% of that. I think we can. I don't think that's gonna be hard to do. But if more and more load serving entities like ours decide to do that, is that gonna change that? Or can we work together and work with each other so that someone else's load complements are so that we can sell our excess summer resources to them. Maybe they have excess winter resources they can sell to us and we can work together in synergy there. Certainly there's sensitivity to market conditions, what's gonna happen in the market who knows what's gonna happen in the world. We can't control that too much. Our ability to contract for resources can we find what we need? And are we going to be able to come to terms with our counterparties to meet the cost targets that we have regulatory uncertainty. There's always changes coming from the public utilities commission. In fact, a week ago, they came out with the new proposed order that we need to procure, that the state as a whole needs to procure an additional 4,000 megawatts of resources for reliability purposes. And it's like, now how does that match in with what we're doing? And what is the timing of that? And does that kind of conflict with what we're doing? Because we're gonna do what we need to do and we're gonna provide the reliability we need. But then when they put these other requirements on and sometimes they specify what type of resources those need to be, that might conflict with us. And then there's no official tracking system for tracking the renewable energy on an hourly basis. Right now there's a tracking system that tracks renewables on a monthly basis. In the West, it's called Regis. And so we receive the RECs. We receive a renewable energy credit for every megawatt out of renewables that is generated, that goes into our account. We calculate add all those up together at the end of the year to show what we've done. But those aren't being generated right now on an hourly basis. So the Regis system has contracted with a new provider that does have the capability to produce the hourly RECs. But those aren't being done right now. Hopefully those will be done by 2025. There was a bill passed in the California legislature this last year sponsored by Senator Josh Becker who's our local state senator. We worked very closely with him. We worked closely with him in the writing of this legislation. And that is going to require that every load serving entity start looking at what their hourly emissions are starting in 2026 or 2027. So we're starting to move the whole system in that direction, which is great. We'll be probably the first to be showing how that's done. But as we get to more, everyone thinking more about hourly tracking, hourly matching of their supply and their load, then there'll be hopefully the infrastructure there to properly account. So I think that's all I have for today. You know, if things change and the market conditions allow it, we'll try to go to a hundred percent. But right now our 99% target is what we're going to do and we're excited about moving forward on it. I think that's good. And I'm happy to answer more questions that people might have. So we will go to the first round of questions to the students. If any of you have a questions because I know some of you need to leave early or at the class, you need to on time not to leave early actually whether or not you can. Any questions from students? You said you contract the generation and capacity. Do you also contract the storage or do you have storage capacity? We can't do that as well. So in the past, the storage that we've contracted for so far has been co-located with solar, so that solar plus storage with the new inflation reduction F that now allows standalone storage receive the investment tax credit. So we can now contract for that as well. The price for that will go down. We will only, you know, we'll charge that standalone storage only during those hours where we have excess renewable so that it's renewable energy going into that storage. Story five. Who's the rest and what is this technology that we're contracting for? Right now the only storage that we have contracted for is lithium ion batteries. And that's pretty much the prevalent technology out there. And most of what we have is four hour storage. We do have one contract that we're doing with a number of other CCAs for long duration storage, eight hour storage, but it's also lithium ion. We're hoping to have other technologies to be able to contract for in the future because it would be good to diversify that like low batteries, we're interested in those. There's gravity storage is just pretty interesting technology. There's some compressed air energy storage. It's actually a project we're looking at. Press there. There's pumped hydro that's in short supply for companies like us to get them. Thinking like you guys like come to life cycle so lithium batteries like carbon emissions feel like that's the lifestyle that the lithium batteries really love. I feel like that's just like, I see there's a difference, but I really do see a difference. I think if I hear you correctly, you're asking, do we consider the life cycle environmental impacts of the different technologies? Absolutely. So lithium battery. Lithium battery. Yeah, yeah. We don't like that. Which is why we're interested in finding other technologies that have less environmental impact. And actually we've been working with Senator Beth or others legislature to have California enact some legislation about recycling, looking at recycling of batteries and also solar panels, too, that that whole life cycle impact be considered when all that's going out there. Very good. Then we go to the guests here for them. Yeah, so what does PGAD like and not like about your model? And then set savings. Does that PGAD say they could replicate that or are those unique to what you're able to do here? Yeah, okay. So does PGAD like or not like what we're doing? We actually haven't done a battle. So I think that some of the people within PGAD might be interested in it. Corporation as a whole, maybe. I wasn't so excited about CCAs in general, but we're here to stay. And then the 5% discount of our rates, that's a policy that we set as an organization and that our board has set that we be less expensive than any so that that's not a reason for someone to opt out. So the way the CCAs work, everyone in a jurisdiction that was, that voted to be a part of us is automatically our customer. They have the option to opt out and you need customer for generation services if they so choose. We want to make it so that why would you do that? Why would you want an inferior product? A more for us. So. So the modeling exercise increase the liability to this. For example, I'm thinking about early summer or late summer with generation opportunities at the peak. We are really hot summer days combined with like really high wind error. Most type of situation when it is not even there. But the explicitly model the liability. That's right. But in the exercise that you've done. Yeah. The way it is to get out of the liability this is that. Thank you, questions. Did we model in the liability? Yeah. I think that's part of the stochastic modeling that we do that what if a generator is out? Like what if it's cloudy days for multiple days and there's no wind or what's the impact? So that's what we look at in that stochastic modeling. The probability that's happening is probably pretty low because we contract for different resources in different locations so that if it's cloudy in Northern California and we have solar up here, but it's sunny and local. We're still getting the sun from there. The wind resources are in different places. We're contracting to some California, some in the Alcomod and then the Tahatchki. We're also looking at some out-of-state wind. And also we do get some out-of-state wind in the Northwest right now. Then we'll be looking at onshore wind which has a more constant generation so far. So we try to diversify our portfolio to make sure that we're not subject to that a weather event isn't going to affect the whole portfolio. We have more than 10 questions from online participants. Let me suggest this way. Why not let one of them? One or two, yeah. We would like you to answer this one. And the rest of them, if it's your option, you can feel free to, we will send this to you and then you can, yeah, we are overdue. So not a good question. It's a really good question. Good, yeah, that's the same stuff. Okay, let's just. So there's a lot of questions there about storage and the technologies. So I think we talked about that a little bit. We are interested in different storage technologies. How much cost increase are consumers willing to bear? That's actually an interesting question because right now we do have a 100% renewable product. Why not you repeat the question? Then you can answer it, how's that? Okay, this one here, Brian Kaiser. How much cost increase are consumers willing to bear in order to have 100% renewable portfolio? So right now, we do offer a product that is an off-depth product that is 100% renewable and we charge one cent per kilowatt hour more for that product, but slightly more than PG&E's product. We have maybe 2% of our customers who have opted up them. So I think it's interesting, the market research, when you do market research and you ask someone, would you be willing to pay more for 100% renewable and you'll say, yes. So then when it actually comes up to signing up for it and writing the check, maybe not. So 30 or 40% will say yes, but when it comes right down to it, only about two or 3% will do it. So what we're doing when we roll out 100% renewable to everyone, it's not gonna be more expensive. It's not gonna be our premium product. We're gonna have a marketing challenge here to figure out how to communicate that we're transitioning to 100% renewable for everyone at a lower price, but then we'll get through that because the research shows and the empirical data shows that people really don't want to pay more or they won't pay more for excess or for 100% renewable, they'd like it. So we're gonna give it to them or we're gonna give it to them at a lower cost. So there's a number of questions here about energy storage technology. We're looking for other resources. What portion comes from long-term contracts? So we do have a policy within our organization that 50% of our contracts will be long-term contracts which are 15 years or more, then a certain percent will be less than that, will be like medium-term contracts and certain percent will be shorter-term contracts. We also have a goal that at least 50% of our contracts will be for new resources that we're making those resources come online because of what we're doing that we're not only contracting for existing projects but for new projects, these still in the ground. So it's all part of the portfolio diversification to make sure that we aren't kind of stuck and that as prices go up and down that we're not ending up contracting for everything at the high price and then if prices go way down then we have a lot of spam and tax that we're pricing ourselves out of the market. So yeah. With that. Thank you, Jen. Thank you. Thank you all for your great attention and for your great questions. It's so fun to be here at Stanford. I love it. Thank you.