Senate Energy Utilities And Communications Committee

Thank you. Thank you. All right, we're going to call this committee to order, and we want to just welcome you all to this wonderful hot day summertime hearing, which is appropriate, you know, given all that's happening right now with the fires in Spokane, Calaveras County, and, of course, the heat wave around the state. This is very salient to some of our current conditions. You know, of course, it was six years ago where California's electric grid experienced unexpected rotating outages. It was during August, as I recall, August 2020, when we had these high heat events around the state, around the west, and that then created a whole slew of electricity challenges, supply challenges, increased demand, particularly, of course, driven by air conditioning. At the time, the CAISO called for controlled rotating outages in order to prevent cascading blackouts on the electric grid. And while the outages ranged from 8 minutes to 90 minutes, they raised concerns for many, including here in the legislature, about the need to reduce the risks of future outages due to supply constraints. due to high demand, especially during extreme weather events. And the greatest risk has largely existed during the evening hours, while demand for electricity remains really high, particularly due to air conditioning needs as people get home. And, of course, solar and wind resource output then declines. So today's hearing is about the balance of power, which was Nydia's pithy title, including both the literal physics of electricity on the electric grid and the need to balance supply and demand but also the political balance of power to achieve the state's reliability, affordability and clean energy goals given some of the hurdles that we face and headwinds that we're facing with regards to our federal partners. So I think we're going to be hearing some cautious optimism for this summer given the numerous policies and resources that are available. I think with this breathing room in mind We also want to pivot to focus a little bit on the midterm to better understand some of the potential challenges on the longer horizon. So before us today, we've got representatives from the Public Utilities Commission, the PC, the Energy Commission, as well as our state's largest electric grid operator, the CAISO, and the Department of Water Resources, which has been more recently tasked through budget and policy actions with specific energy duties So we been asked to get we asked them to provide updates on several things First of all the near reliability concerns for this summer including the continued role of the Electricity Supply Strategic Reliability Reserve, funded by the state budget, including the continued capacity of natural gas power plants that are scheduled to retire due to the ones through cooling regulations and the demand programs that have been implemented at the CEC. Looking beyond this summer, the committee has requested an update on the midterm outlook for reliability and clean energy procurement and build-out needs to address the state's energy load while working to achieve our state's clean energy goals. So this should include the status of the central procurement function authorized by AB 1373, which authorized the DWR to procure long lead time resources if the PEC makes a request to do so. Relatedly, the committee will want to hear how the state's clean energy planning is affected by the pending end dates by which the Diablo Canyon nuclear power plant is authorized to operate. So the committee also requested the CAISO provide us with an update on the recent launch of the extended day ahead market and a report on significant tariff or developments as required by AB 825, which also authorized the CAISO and electrical corporations to participate in an independent voluntary energy market no sooner than January 1, 2028, if certain determinations and conditions are met. Lastly, the balance of power title that we came up with reflects the changes at the federal level under the Trump administration, including impacts to federal tax credits, policies for clean energy resources that California is pursuing to achieve its carbon reduction goals. And now there's less of some of these programs are less welcome at the federal level now. So we'd like to certainly have an update from the folks who are going to present to us on some of the efforts to address procurement for resources that may have sunsetting tax credits, other changes in federal policies and actions, and awareness of the risks posed by the recent U.S. Supreme Court decision regarding the ability of a president to remove members of the dependent commissions and boards, potentially affecting decisions by energy-related commissions such as FERC and who oversees energy markets and transmission. So lots of complicated and meaty topics for us to discuss. I just want to welcome to the stage our presenter, so the CEC Vice Chair, Sivagunda, our CPC Executive Director, Luan Tesfai, Department of Water Resources Deputy Director of the Statewide Energy Office, Delphine Hu, Elliot Mainzer, who's the President and CEO of the California Independent System Operator, along with Josephito, who's Chair of Governors at CAISO. And we will start with you, Mr. Vice Chair Gunda.

And we really look forward to what I know will be a robust and meaningful discussion. You may proceed when ready.

Good afternoon. Delphine Ho, Department of Water Resources. Good afternoon. Elliot Mainzer, President and CEO, California ISO.

I'll pass it to Luam to go over that.

I'm going to just provide a quick update on what the state agencies have been doing since 2020. Chair, as you mentioned, on August 14th and 15th of 2020, we had rolling outages in California. And one of the main things that we came back to you on the root cause analysis is the importance of improving our planning processes and procurement and coordination. Those are the three elements that we came back to the legislature with. And as it pertains to improving our planning, we've done a lot of work. All the work that I describe here is done by everybody here. While CEC takes lead on the forecasting, it's always a collective effort in all aspects of this. So one of the most important things that the CEC had to focus on is to ensure we put climate change impacts into the forecast because much of our forecasting before 2020 was reliant on historical trends. So we worked on thinking through how best to incorporate climate change impacts as well as electrification uncertainty Another element that we had to think through in the planning process is to really figure out the procurement Thanks to CPUC work on an historic amount of procurement that has been done since 2020 that Luam is going to discuss in a bit. And finally, one of the core elements was to continue to improve the resource adequacy requirements. An important part of the journey from 2020 to 2026 also included the impacts of COVID and what came with that in terms of supply chain. We had tariff issues with solar panels coming from China. It's the ability to build out. And then we had a fire in Oregon, the bootleg fire in 2021 that knocked out transmission. So each year as we continue to prepare ourselves, a new issue presented itself and we really had to think about a holistic transition pathway. An important part of the work is then once you improve these processes, do the planning and procurement, are we able to build the resources adequately? And part of the process was to track the procurement and figure out how best to solve for any project-by-project issues. Obviously, the legislature has provided opt-in permitting authority to the California Energy Commission, which has been significant, as well as looking at demand-side resources. A final component of that was while we do the procurement and planning and help ensure that we're building at a fast pace, are we still prepared for extreme events? And again, thanks to the legislature, you have given us a number of different tools over the last five years that we could use as a cushion as we continue to improve our processes. Along with that is also transmission work that we have done, which Luang is going to discuss. So still on this slide, I wanted to highlight under the Scaling Supply and Demand Side Clean Energy Resources, the bullet there that says Transmission Permitting Pilot Program and Dashboard. So part of our update this year, we wanted to share that, you know, last year we did do a huge update to our transmission permitting process. That's General Order 131. I called it a once-in-a-generation update. It was 30 years ago the last time we made an update there. And so this is already showing benefits. of streamlining our permitting process for transmission. And in addition to that, really being able to provide more clarity to transmission applicants about what that permitting process is. And so we've already started to see the benefits of that, hearing about that from the participating transmission owners. In addition to that, in May of this year, we did also launch a transmission permitting pilot program where we are further able to look for additional improvements to the permitting process. So as part of that, we launched an online dashboard so that all of these different data points showing the permitting process and where we're able to find further speed and optimization in that process is very visible to stakeholders. And so very proud to be able to get that big update done last year as well as this year launching the permitting dashboard. Thank you. I was trying to get to the next slide. Great. Perfect. So this slide is illustrating an update here about the procurement orders that have been ordered through the California Public Utilities Commission, in particular in the integrated resources planning proceeding. So as mentioned by the vice chair, the CEC's integrated energy policy report, or the IPER forecast feeds directly into the California public Utilities Commission's Reliability Needs Assessment, and the overall generation, procurement, and transmission planning. And so that forecast really informs both the longer-term integrated resources planning proceeding, which guides our load-serving entities across the state to meet reliability and greenhouse gas emission reduction goals, as well as our shorter-term resource adequacy program, which requires resources to be under contract and show up and provide energy to that California independent system operator region. So both informs the long term and the short term. Over the past six years, the CPUC has issued several procurement orders, and those are listed right here on that slide, within our integrated resources planning proceeding to increase the amount of capacity available in the CAISO area. And so this is totaling over 24.8 gigawatts of new capacity to be delivered through cost competitive solicitations, bringing those best prices to California customers and rate payers. In addition to that, I did want to highlight that those procurement orders that are shown on the slide, we're starting back in 2019 with the most recent procurement additional order happening in February of this year for an additional 6,000 megawatts coming online between 2030 and 2032. And this is really important because this additional 6,000 megawatts, it followed an analysis of system need within this near-term time frame. And we are always reassessing things to promote future electric system reliability in light of changing circumstances. Just very important to note here in that these procurement orders are also flowing from the fact that there was an expectation for Diablo Canyon to be retired. And so we are continuing to keep the foot on the accelerator with our procurement process as directed in SB 846. And then in addition to that, you know, these load serving entities are signing these contracts and also splitting that among all 40 load serving entities across the state. So it's a shared responsibility with many entities that we are steering that ship. And so in addition to that, that includes investor owned utilities like PG&E, but also the community choice aggregators and the electric service providers. And these new resources are going to expand that total amount of electricity capacity that's available on the system to meet peak demand during the summer months in particular. And so these procurement orders are for clean energy and battery storage in particular. And so our no new fossil fuel procurement is listed as part of this slide. Thank you. Thanks for the help of the slide.

So this slide should be familiar to you all. We have been updating it in this hearing on a regular basis. And so this slide is really showing the remarkable progress that we have been able to show as a state for getting new resources online. The vertical gray line on this slide is representing the point of the last data update in late May with new capacity that came online since 2020 to the left of that gray line. And the future new capacity under contract is also listed on this slide. So it's really showing over 36,000 megawatts of new resources coming online and over 21,000 megawatts of new resources contracted and in development between now and 2030. So this isn't just hypothetical resources that we would like to have. These resources are being built right now, and they are under contract. In addition to that, the CPUC procurement orders on the previous slide show what we call net qualifying capacity, and so that's what we're looking at these numbers for. Really important metric for us to be understanding not just new resources that are coming online but how they help us with addressing reliability concerns at the subject of this hearing So solar shown in yellow and battery storage shown in purple represent the majority of that new capacity so far and we expect that trend to continue into the future. In fact, over 4.5 gigawatts of battery storage alone came online in 2025, and there are now many gigawatts, over 16 gigawatts of battery storage online in California. And that's up from only under one gigawatt just six years ago, so really remarkable progress that we're able to share with you today. Battery storage really is a key asset for us to be able to capture that affordable intermittent wind and midday solar and be able to leverage that during our evening hours when solar is dropping off of the system. Of course, the slide shows other resources as well, including wind, hybrid solar, storage systems, small amounts of natural gas as well as geothermal, hydropower, biomass, and biogas. And then natural gas resources represent increases in the available capacity at the already existing natural resource generators that are operating as efficiently as possible. So with that, I wanted to turn the slide over to my next colleague.

So I'm going to go through just a quick snapshot of the 2026 summer outlook, and then we're going to give you a longer view after that. So this slide captures the summary of where we are. This is a slide that you are familiar with. We try to update the same format. Based on the current conditions, the 2026, we try to stay cautiously optimistic. We are well into the summer. there are three things that we present. One, how are we doing under traditional planning standards? We do not see any shortfalls under traditional planning conditions. We also look at 2020 and 2022 conditions, which have been extreme points beyond the traditional planning, and we also currently see surplus under those conditions. But what we want to make sure we leave with the little caution that we always carry is an extraordinary compounding event. While it might be extremely unlikely, we still want to be prepared for that. As Luam just noted, we have been really served well with the incredible amount of megawatts that came on the system, more than 36,000 megawatts since 2020. We also have 16,000 megawatts of that as storage. This number is almost a year old now, the 16,000. We are currently looking at updating that number and will be presenting to the legislature in short order. And also, along with those developments, it's about efficient usage of those resources, both in California and the West, and much of, you know, thanks to the legislature for the work on A25 and the work that CAISO does to make sure that we are coordinating across the West. So, with that, I will go to the next slide. So now taking that into a numerical stance, what this table is trying to show you is year after year, a comparison of how we are doing in different conditions. The top row is the demand. As you see, the demand has not gone up significantly since 2023. The demand more or less has been flat with a little addition, just over a few hundred megawatts. But as you see the total resources line which is the second line in there in terms of numeric numeric goals that has been a significant improvement year after year One of the things that you will see as a difference between what is being presented here and for those of you who might have reviewed the quarterly report at table five this number that we list here is the total megawatts, nameplate megawatts that have been installed. But table five in the joint report shows specifically the amount of resources available at 6 p.m. in the evening. It's important to do the analysis based on that. And what you see here in terms of surpluses is based on that hour 18. So then kind of moving that into a little bit of a visual cue on what you've just seen there. Here we go from 2022 to 2026. What we're trying to show here is how are we fading in 2022 in terms of the standard planning efforts all the way to 2020-2022 equivalent event. But finally, the extraordinary unlikely event of a coincidental catastrophic fire. So when you look at those four columns, anything above zero is a positive where we see surplus. And as you see visually there, year after year, we have been better and better situated. We do note that there is approximately 1,000 megawatt of potential shortfall under an extreme catastrophic unlikely event. But that's precisely why we plan for contingencies resources, which are shown here on slide number 10. So the contingency resources are beyond the resources we are planning for grid reliability. Thanks again to the legislature for the creation of the strategic reliability reserve, which DWR manages. We have almost 3,000 megawatts in the program at DWR. We have other general fund funded programs, which are DSGS and DEBA. The DSGS program is the demand side grid support program, which we have enrollment about 650 megawatts for the summer. The reason why we have DEBA is zero is because it's actually building off new resources. Those grants have been made, and those resources will be coming online through 2030. In terms of CPUC, you have a number of other rate paid programs, including the ELRP program. You have about 100 megawatts. We have historically used imports as a way to stack this. We do not have that anymore for this year. But also CPUC coordinates a capacity of cogen beyond their resource adequacy levels, which we can talk about. And finally, the non-programmatic is what CAISO really takes point on. This includes balancing area transfers and coordination with the neighboring balancing areas, including LADWP and BUNC. And also, if we were to reach out to the federal government for a 202C waiver to run the power plants beyond their permit levels, that's another one. So when you add all of them, we have nearly 4,500 megawatts of contingency resources that are available. in the moment we might need for a catastrophic event. With that, I'll pass it to Kaiser colleagues.

Well, thank you very much, Chair Allen and members of the committee. It's a pleasure to be here with you today. I'm going to be providing some additional comments on short-term reliability conditions here in California, and then talk a little bit about the launch of the extended day ahead market, And then Chair Edo and I will provide some additional comments on the early value proposition of EDM and report on the AB 825 activity So lots to report Of course if have to go to the next the first slide here You know from the perspective of the ISO of course we get to watch this grid in California operate in real time and we do conduct additional analysis, and certainly our evaluation also has revealed that the grid has sufficient resources available to meet demand during normal conditions. As a matter of fact, our analysis indicated a 2,547 megawatt surplus, of installed capacity relative to what is needed to meet the 1 in 10 loss of load expectation. That is our standard planning metric. The 1 in 10 metrics refers to no more than one event every 10 years where insufficient generation needed to meet demand requires operators to actually deploy emergency measures to keep the system balanced. And, you know, just four years ago, our analysis indicated that we were going into summer with a shortfall of 1,700 megawatts. So very, very great progress. And again, thanks so much to the state agencies for all of the procurement orders and the coordination. We've heard already just the sheer magnitude of new resources that have come on this grid in the last five to six years. 36,000 megawatts a new generation, 16 gigawatts of batteries, really the largest battery storage fleet in North America. And those resources have made just a tremendous impact on system reliability for our grid. I can tell you the folks on the control center are deeply appreciative of those resources. Being able to dispatch into the evening peak, just as the sun is setting, has really positioned us with tremendous progress on resource addictions, which I think is very important for the state. A couple other just numbers that I think are relevant. You know, last year's 1 and 2 load forecast was 46,094 megawatts. As you recall, actual demand was actually a little bit less because it was a relatively modest summer last year. The forecast for this year is 46,844 megawatts, a fairly modest year-over-year increase of about 1.6%. These last few days, as was noted by Chair Allen, we've been having some warm conditions here in California. Yesterday, our peak load in California was 43,536 megawatts. That's a little bit less than what we saw a couple weeks ago on July 15th, which was at the peak for the summer at 43625. Interesting, the Western interconnection of which we participate actually set a new record on July 24th of just under 170,000 megawatts. So on that day, California actually had relatively modest loads. We were only at about 41,000 megawatts. But that shows the kind of growth that we're seeing when you hear about electrification, we hear about data centers, we hear about load growth going on across the West. It is happening, and we're seeing it show up in real time. If we go to the next slide, I wanted to talk just a little bit about the water conditions because this has really been a very unique year in some ways. You know, despite the above normal rainfall that we had earlier this year, many of the storms were actually warmer than usual, which left mountain snowpack well before normal. As a matter of fact, some locations in California are rivaling the lowest snow water content on record for this time of year. Hopefully our reservoirs, many of the major reservoirs in California, and certainly Delphine can speak to this, are right around average. So we're actually, in terms of water content, we're in pretty good shape, but we're not going to get the recharge from snow melt. So we're going to have to be using that water very diligently across the course of the summer. And as we get into late August and September, there could be some more strain on the system. Obviously the batteries and the solar energy are compensating for some of that. But this has been a very warm water year. And something that's also worth noting if we go to the next slide is we look out to the balances of the summer, we are still predicting, right, we're still just here at the beginning of August, above normal temperatures are likely statewide. And the strongest indications of being in Northern California and the Pacific Northwest. Something I wanted to note, which I think is worth paying attention to for the next couple years, is, you know, we are headed into an increasingly strong El Nino, right? And coastal ocean conditions are a critical driver this year. As a matter of fact, I wanted to note it. The sea surface temperatures that are happening off the coast are well above normal, really limiting the typical marine cooling. The Pacific Ocean, this statistic we're checking in with our team today, the Pacific Ocean is running in some ways about 10 degrees warmer than usual. And that could certainly negatively impact the marine layer and heat up the coast, which, of course, is where a large portion of California's electricity demand. And these are now the warmest coastal sea surface temperatures since 2015, which is, of course, a notable departure from recent summers. And those sea surface temperatures can translate into warmer overnight temperatures and really basically the potential for more frequent coastal heat events. So obviously all the new capacity that's been placed on the system going into the summer with the surplus, having the outstanding coordination, and then, of course, being able to participate in a grid that is bigger than the weather across the western United States. through the Western Energy Imbalance Market, and the extended day-to-day market has been very beneficial. I have just a couple of comments on you, Dan, before I pass it over to Chair Edo. We were fortunate back on May 1st, after several years of preparation, to go live with the extended day-to-day market. As you recall, over the last 12 years, we built out, with many of the other utilities across the Western United States, the Western Energy Imbalance Market, which allows us to move power across a big portion of the Western United States to provide the lowest cost energy every 5, 10, 15 minutes. Sorry, we can change the slide. Apologies for that. There you go. Thank you. To be able to move power across a wide area to take advantage of the diversity of load and transmission connectivity to help keep the lights on and lower costs for consumers. We've now extended that real-time market into the day-ahead timeframe, to the extended day-ahead market. And we went live May 1st, and so far things have been really working quite well. The very early returns are showing us that the market is functioning well. We're moving power back and forth between California and Pacific Corps' eastern service territory and their western service territory. The prices are rational. The new products that we developed are working well. And I think so far, as market participants gain experience and the enhancements ensure, I think the full benefits of EDAM, including improved efficiency, enhanced reliability, and broader market integration, are expected to become more pronounced. Later this year, in October, Portland General Electric is scheduled to go live with a market on October 1st. And going into next year, we've got several of the other major entities here in California, including the Balancing Authority of Northern California, the Turlock Irrigation District, and the Los Angeles Department of Water and Power will also be joining the market. and then the following year we're expecting to get NV Energy. And so as we scale up the number of participants and the amount of transmission connectivity increases in the resource diversity footprint, that's just going to allow us to continue to strengthen reliability and improve economic efficiency. We've just come out with our most recent, our first quarterly EDAM benefits report, and I wanted to turn it over to Chair Edo to talk just a little bit more about what those benefits are looking like and how this market's gonna play a role in the reliability equation and of course, ABA 25.

Let's go back one, please.

Mr. Chair, just a quick question. Just a real quick question. I'm sorry. Sure. Clarify. It's a clarification. When you talk about energy savings, is that dirty energy not turned on? What is the savings reference so that we have an understanding?

I apologize for not being called. No, no, it's all good. I'm just, you know, we've always thought of energy in terms of having to turn on the dirty energy when we don't want it, right? At the time, it's the hottest, and then you're using that which is not as clean. And so that's the reason I was trying to get my hand right. A couple of good news stories, but I also don't want to be misleading.

Sure. Thank you to you.

Thank you, Chair. So I'll just kind of provide a quick summary on the long run planning before we open up for questions. So I just wanted to kind of take us back to 2020 and the discussions we've had and the reason behind the development of the Strategic Reserve and the context that we were working with in 2020 through 2022. So one of the issues as we mentioned earlier was the first question that we needed to ask ourselves as a team together on the state and with CAISO is are we planning and procuring to meet the 1 in 10 loss of load expectation as President Mainzer mentioned. And one of the things we were not doing well, including the forecasting, is to really take into account the climate change impacts. So much of the work was to ensure that we have the planning in place to be able to procure to meet the standard. Then comes the question, if we plan and procure, are we able to build at the rate that is required to build?

And early on, coming out of the 2020 COVID pandemic, and then early times during the leading Trump administration, previous Trump administration, but also in President Biden's administration, there was the tariffs with China and a number of other supply chain issues that we had to continue to work through. And we were not able to realize the levels at which we needed to build. Early on, the delta between the levels we were procuring and building were almost 40% below. Then we need to think about, given that we are not able to build fast enough, how do we cushion with some additional resources? On the top of that, as President Mainzer and Executive Director Tussfi mentioned, there are a number of these events that happened in 2020, 2021, 2 and 3, that are extraordinary enough that they fall outside the 1 in 10 planning regime. So we needed to think through if those extraordinary events are happening, how do we create cushion? That was the second additional cushion we needed. And finally, what if you had a coincidental catastrophic event that also included fire? So when we looked at all of that together and when we testified in 2022 in front of this body, was really thinking through how do we create the cushion to help with those four elements. And one of the charts we showed earlier is that now, compared to 2022, when we were structurally short, we are structurally long now. Based on all planning scenarios, we see a surplus, except for the very unlikely, extraordinary situation of having a coincidental catastrophic fire. So then looking at the load growth, as we discussed, we have almost 36,000 megawatts of resources that were added. But as we look forward from here, this is the standard planning forecast. Obviously, we do a lot of different scenarios collectively, including in our analysis of SB100 that we do, along with CARB, is looking at what is the baseline forecast that we expect to grow. And what you're seeing here is a waterfall chart. So between 2025 and 2045, we expect another 20 gigs of load to be added to the system. And each of those components are shown here as what's adding and what's subtracting from that overall load. One of the main pieces when you see consumption there as the first column, that is just looking at the long-run forecasts of GDP growth, demographic growth in California, and seeing how much would that add to the system. Second is the climate change impact. This is the incremental temperature and weather change that we need to bake in that adds another 2,000 megawatts of load between now and 2045. But the three big components that you see there are data centers. We currently have almost 5,000 megawatts of data centers being added to the baseline forecast. Both the electric vehicles and the fuel substitution, which is the electrification of buildings, adds a significant amount, almost 13,000 megawatts. So when you add all of those things, we are looking at 20,000 megawatts. Again, this is what we think of as the most likely scenario as we do our analysis today. As Director Tesfai mentioned, we continually update these members, and as we move forward year after year, there will be new procurement that will be added to the system. I WANTED TO BRING IT BACK INTO THE SUMMARY OF THE PRESENTATION WE PROVIDED YOU TODAY BEFORE WE OPEN UP THE Q IN SUMMARY I THINK ONE OF THE MOST IMPORTANT THINGS IS THERE HAS BEEN SIGNIFICANT PROGRESS IN PLANNING AND PROCUREMENT AND WE IN A STRUCTURALLY BETTER POSITION So in summary I think one of the most important things is there has been significant progress in planning and procurement and we in a structurally better position We were structurally short in 2022 and we structurally long today except for those extraordinary conditions The forecast has significantly improved, and we have done some historical procurement, and CPUC closely monitors that. And the second plank of work is really looking at the ongoing coordination. One of the things that came out of the root cause analysis, again, was called for better coordination, given that we have to build in a lot more resources. So we continually discuss these things, both in terms of thinking through the electrification loads, but also federal policy and how it impacts. And finally, building on those two solid steps of planning and procurement, and coordinating around the build-outs is really looking at the emerging market and the significant opportunity we see there. And obviously, we continue to have contingency resources that will continue to backstop under extraordinary conditions. So with that, we will close the presentation and look forward to any questions that the committee might have.

Thank you, Chair. I want to thank the panel. I mean, this sounds like really good news. I have some concerns. First of all, I just want to make a note that I saw that data centers are projected less energy consumption growth than electric vehicles. People are all excited about data centers. so there's other issues that we need to think about with regard to load growth. My first question is the regionalization impact. That was a big controversy last year, and it sounds like it was a good decision. Is that your assessment? I mean, it sounded like that was what you were getting at, but you also mentioned the word machine controlling this, and that makes me nervous because AI hallucinates. What are our risks here?

Well, it does. You know, I have a piece of legislation that requires human, you know, involvement in these kind of decisions, and so I'm glad to hear that. Thank you. So the next question would be, Luan, a transmission build-out. Does that reduce? Well, I mean, what I'm trying to get out here is, you know, this is all good news, but how is that going to affect ratepayers' costs? I mean, we pay some maybe the most expensive, and maybe it's, you know, looking ahead that in future years, you know, when fossil fuels become less and less available or whatever happens to them, California is going to be ahead because we've made all these investments and all that. So does all this transmission build help reduce repair costs Thank you Senator Birknerney I can start all that and perhaps CAISO will have something they want to add as well

Absolutely. So first and foremost, as you stated, trying to make the best use of our existing infrastructure is always starting point number one, and we're constantly doing that through our market dispatch and just grid utilization. But at the CAISO also, our motivation is when we receive the information from the state agencies around the load forecast and the preferred resource portfolios, our goal is to come back with the least cost transmission plan, and that's trying to find the most efficient lines and also looking for opportunities to deploy advanced grid technologies, grid-enhancing services, flow control devices, dynamic ratings. So we're constantly looking for the least-cost portfolio to try to have the smallest potential impact on the ratepayer.

A lot to that question. Good question, though. So just kind of with the start, the reference I made in my presentation was that when the legislature passed Senate Bill 846, there was a requirement for us to continue to have our foot on the accelerator. I have to remind myself not to say foot on the gas anymore, foot on the accelerator, to continue to do procurement with the expectation of potential retirement. We did do an analysis last September looking at potential affordability savings around Diablo Canyon. That would specifically be if there was an extension, the offset that you would have for additional procurement we wouldn't need to do. And that's how you end up seeing potentially what those savings are. And so again we did just a very preliminary analysis last September and stakeholders public documents stakeholders have access to it But that would be the potential savings for customers Right now, the costs for Diablo Canyon are spread out across all three utility footprints, PG&E, Edison, and SDG&E. That was a shift that was created by Senate Bill 846. Previously, those costs were focused on the PG&E footprint. But now they're spread out statewide.

So on public safety power shutoffs, as you all know, they are a tool to prevent potential wildfire ignition. So there has been – public safety power shutoffs have existed for many years, but we have been routinely improving them, the standards for them and the utilities in their operationalizing of that tool over the last, I would say, decade, five years, and have seen particular improvements there. So those improvements in order to reduce the potential impact to more customers. So we've seen sectionalizing of the existing electricity system so that fewer customers are impacted. Very specific protocols for informing customers in advance of potential public safety power shutoffs. But I think it's hard to quantify.

Yes.

I can speak to that, Senator. Sure. Before I joined the ISO, I had a 40-year career at the Lawrence Berkeley National Laboratory, and one of the tools I developed was something called the Interruption Cost Estimate Calculator. And what it does is it synthesizes what are called value of loss load surveys that utilities have conducted across the country, where they ask their customers if they lost power for one hour or three hours, nighttime, daytime, what would it cost them in terms of either inconvenience, principally for residential customers, or loss of revenue that couldn't be recovered or damages to equipment in the case of commercial industrial customers. This is a publicly available online tool. It's being used around the country by utilities to justify reliability spends where they balance the cost of improving reliability against the cost they can save customers in terms of avoiding power interruptions. We did a lot of work with the Public Utilities Commission several years ago and have actually surveyed California's customers, the three IOUs, to put those data into the tool, And it was done in support of some of the risk analysis proceedings that the Public Utilities Commission has managed, of which they consider the wildfire risks as part of it. And I know it's a standard part of the analysis that's done in those activities. Okay.

All right. We're going to go to Laura Richardson next.

Yes.

Okay.

Thank you, Senator. I'll go one by one. On the data center, again, to your point, we haven't had a lot of visibility on data centers for a very long time. We had about 1.2 gigs today of the load on the system. So what we have done together as a state team in planning is to work with PUC and other local jurisdictions on getting the application data. So what we're getting is by utility by utility how much they're expecting in terms of the applications they see. So if you count all of that today, it's over 25 gigs and not five gigs as we baked in today. But when we got that information, collectively we've done some workshops, talked to colleagues in the industry to figure out how best to bake that into the forecast. And the way we've done it is looked at the characterization of three elements. One, oftentimes when the application comes into you, the application is a higher amount than what they actually build. It's typically about 65% to 66%. So we bake that into that. Second, how many of these projects actually translate? There we still have a little bit of a visibility issue, but largely talking to LSEs, we were able to convert into a confidence level on how many of those projects show up. And finally, even though a particular data center might say I'm coming in with an application, they typically have a two- to five-year ramp time of bringing that load on. So we taking those three elements together and we have a lower forecast and a higher forecast The lower forecast is what we have for the system level for CAISO planning and the higher forecast is for local reliability planning So we will continue to to your point there a lot of uncertainty We'll continue to update those numbers and then make sure that every cycle we do the procurement and planning will update them. One of the other elements around the planning is the west-wide coordination. We've heard from colleagues in other states that some of the applicants might be the same. So the west-wide, there is a coordinated effort to create a database to figure out if we can remove the duplication. In terms of transportation and building electrification, the transportation is based on work between California Resource Board and CEC on doing a consumer preference survey. We survey consumers every three years. And based on that, we have their preferences, and based on the preferences is how the forecast is developed. Currently, we see that the forecast and the actual numbers that we see in the market are pretty closely aligned. But I think to your point, there is a huge dependence on the survey of the forecast and the cost to the consumer. as we lose some of these tax credits from the federal government or higher electricity price, that will change the forecast,

So you typically give us this type of report annually?

Senator Richardson, if I may, just a quick response on that. I think all the points that you raise are super, super important, and I think part of the state processes look at different time frames of planning. So we have obviously the scoping plan that provides kind of the blueprint, but really once the scoping plan is done, we collectively develop the SB100 analysis, which kind of lays out multiple scenarios, to your point, on what are the different supply scenarios that we need to be able to create and how does the different resource combination look like. So we do that, and then it becomes more real when it comes into the integrated resource planning process at the PUC and other LRAs. And I think so what I want to share with you is there is kind of a process on creating a diversity of pathways and figuring out how to plan for both the extreme and potentially the conservative scenario. But we would welcome and love the opportunity to provide more information to the committee. And to your points on the intersection of the electricity planning as well as the petroleum planning, I think some of the questions that you've asked us is like when you take the economy as a whole, how are you going from point A to point B? So I really appreciate those questions, and we are really trying to work together as a state agency team to integrate petroleum, electricity, and natural gas as well as we can and look forward to reporting to you.

Senator Rubio.

And I just want to make sure that I share. I think what I would say from 2020 to now is the processes have gotten much better. I think I have kind of definitely a strong confidence in our ability to work together. But I think to your point, there are a lot of unknowns and uncertainties. Things that we are not able to track right now are really big in. So in terms of what would be the uncertainty around electrification, how fast, how slow it might come, what might be the future of hydrogen in California, hydrogen would add, especially if we did electrolytic electrolysis, then that would add a significant amount of load. So I think you're absolutely right that there are a lot of uncertainties. What we have as a process is our ability to continually improve them. So when we talk about the confidence, the way we have structured our overall analytical framework is, as we look through the summer, very near term, four, five, six months at a time, is where we have the most confidence in our numbers. But as you go out 10 years, especially beyond 10 years, the only thing we do at this moment is scenario analysis. And what we try to do is if we see a lead time, so for example, let's say a geothermal, and geothermal project takes a significant amount of time to build out, those lead times is when you try to look at and reassess those different aspects. So by no means we want to provide a confidence that we can see the future. The near term is the most confidence we have in terms of the surplus we have and the ability to navigate a significant event. But you're absolutely right. Long run, 10, 15, 20 years, we really rely on our ability to continually do that analysis every year. So as we get closer to that, we reassess. And, you know, more often than not, we take, you know, the scenario of development that creates the best cushion for the state. And thank you for that.

Thank you, Senator Rubio. So I was the one that made the comment about sectionalizing the system, and what I was referring to there was when PG&E was doing public safety power shutoffs, I would say about over five years ago at this point, there were customers who were very far away from the area where the potential wildfire risk was that were also having their lights shut off because they were completely connected to those very distant locations. And so there have been upgrades made to the grid in order to be able to be more precise about how public safety power shutoffs are operationalized. And so that means, you know, if there is a family that lives in Richmond, California, and there's a wildfire risk that is, you know, three or four counties away, they won't have their power shutoff anymore. And so that's been something that all three utilities have been working on, but we saw in particular a big problem with that in PG&E's territory about five or six years ago. And so there have been work done on the grid, not based on where wealthy communities live or otherwise, but making sure that the customer power outage impact is closer to where the actual risk exists. Now, focusing on how do we help protect low-income customers in particular, absolutely a huge focus for the Public Utilities Commission. We have specifically two low-income programs, the California Alternative Rates for Energy Program, CARE, as well as FARA program, which is the Family Electric Rate Assistance Program. That is targeting our most vulnerable customers and making sure that they have discounts on the customer bill. In addition to that, when we implemented the income graduated fixed charge in order to have more equity in how customers pay their electricity bills, we implemented a discount on that income graduated fixed charge in particular for care customers and fair customers. And that started being implemented in Q4 of last year and then in Q1 of this year as well. And so really trying to find that equity that you're talking about in terms of how customers are billed for their electricity.

And if I may, so we're actually embarking this year on a new LENA study. LENA stands for Low Income Needs Assessment Study. So it's embarking on that this year. It has been done in the past, but we do it every few years because there's constantly opportunities for improvement. So we'll make sure to keep your office up to date on the progress of this next LENA study.

I will not be long-winded, so I appreciate it. I really appreciate the update. And the fact that you're all working together is long overdue. I'm really happy to see it. And whatever it took to get us to this point is really good. I've expressed my concerns about the electrification of California in times past, mostly because for the past at least eight years, maybe closer to ten years, the discussion has been that all eyes have been on the Central Valley for the development of huge solar arrays. It's hot. I mean, walk outside, it's 105. It's producing a lot of energy. But that also correlates with our water issues such that with SGMA and the regulatory framework we've created, we're going to lose between a million to three million acres of ag land. And the way the valley's historically developed, it's a bunch of small little farm worker communities that rely on water and on agriculture for the businesses to succeed. The small businesses that are truck drivers, that are box makers, that are mechanics, that are welders. And that's what keeps the ag industry moving. And so if you take out a million acres, you've got devastation in the valley, apart from blowing dust and environmental issues that I don't think have been studied significantly. And when I tried to do a bill on it, of course, it didn't get out of the legislature because it looks like I'm a tronglodyte, you know, trying to keep solar from coming into the valley. What I'm really looking for and have spent a significant amount of time working on are alternative ways to develop energy, alternative technologies. You mentioned hydrogen and I was so excited that California got the Hydrogen Hub grant from the federal government but I wasn surprised when it was pulled back once the administration changed So we lost that opportunity to really jumpstart what I think has the potential for a solution I think the Air Board has identified it as well. We had investors come to California that were interested in joining the project, and it was disappointing to me to see that, and these are investors that spend billions of dollars in the state already. I think we can get there, but it's going to be on a slow track, which has me worried because then we ignore the probability. What I like about hydrogen is it's a different technology. It's an industrial product, and it's the transition away from oil and natural gas production that we need to have in order to get good jobs. But there's also the opportunity with biogas, and we've made major investments in dairy digesters that get us moving, and that has had some real successes in the heavy trucking industry. And so I'm wondering if that's part of a planning that you're – and why that's important is we have waste in our forests and waste, ag waste, that we've obligated it to – the open air burning now is not permitted unless there's no solution. And we've created no solution. So I thought ag burning was going to end, and it's not. It's still happening because we have no solution. So I'm wondering in terms of alternatives, and I'm all for battery storage, and I'm all for solar, but I do think in an area that is prone to blowing dust with valley fever as a very serious lung disease, that we risk ending up with a dust bowl right in our own state that we have spent no time analyzing and trying to figure out what's an alternative and how do we bring those businesses to California. And when I visit the COP conferences in the past, other countries are moving in this direction. We're going to lose our edge in the technology sector if we don't at least consider some of these possibilities. And I wonder in terms of your advanced planning whether that fits into anything.

I appreciate that. And some of the technologies are moving in the direction of taking a waste product, solving for the waste product, and returning something to the community. And so some of the models, and I don't remember whether it was a CCUS or a hydrogen. I need to get back. If you don't talk to some of these companies two years later, it's an entirely different opportunity. But one of them was taking wastewater. And I think it was hydrogen. It was taking wastewater. and what they would return to the community is potable water, which has a value in and of itself. And they were interested in working with some of the ag companies that have industrial wastewater that they are obligated to clean and taking it off their hands and then returning to them potable water again, which, again, you're absolutely right. Right now, the hydrogen production is not cost effective. But if you develop it in a sequence, it becomes cheaper, if you will. And if you can use it in aviation and maritime and heavy-duty trucking, then all of a sudden you've got a market that is robust enough for you to be able to turn it around very quickly. So that's my interest. And if there's a way, and I just found out today at our agriculture hearing that UC Merced has a project where they put the solar panels up high and they're producing a product below. So you're not stopping agricultural production. You're just doing two things on the land at the same time, which I think is excellent. It maintains the agricultural production for local communities, but it also then takes the energy and actually cools down the plants because there's shade underneath. So that's very exciting. But how do we craft solutions that require different inputs from the CDFA and then obviously maybe cap and trade or general fund money so that we are sponsoring innovation I totally agree with you Senator I think we have over time during these different resource planning exercises

That's great. Thank you so much. I appreciate it. Thank you, Mr. Chair.

Senator Stern. Thank you, Mr. Chair. Appreciate you all being here today and all the collaboration and coordination. You know, when we're in the bubble of California, I think things can seem grim. And I know as somebody who pays the utility bills in my own house, I get severe pain every month. And I think that pain is shared from a lot more people than just me who, you know, make a decent salary. But everyone else out there is struggling. But I did want to offer the opportunity for you all to put us in a little bit of context here. California is often pointed to as the, you know, they love to, out in D.C., love to say how expensive everything is in California. I was doing some rough math just looking at our situation comparatively, say between ourselves, the Northwest, PJM, and even France and Spain, just to give a general sense. Our wholesale price is the 12-month average that I've been able to find is a third of what it is in the northeast, in the PJM, where prices have jumped about 75%. I've seen even in the BPA region, we're seeing average costs over $30 a megawatt hour on average. And right now, I think 40,000 people are in the dark in this awful fire that's going on up And then when you look at, say, France or Spain, they're up in more than double our wholesale prices. Have I done my math right here? Is our wholesale power market more efficient than any of these comparative markets at the moment? Maybe you, President Mainzer?

Can you zoom ahead into the not-so-distant future? I know we talked a little bit, Mr. Eto'o, about the current savings that we're generating in EDAM and the EIM, but what could we see as the implementation of 825 goes forward? I guess I'll just say, why isn't this enough? Why shouldn't we be sort of satisfied with how things are right now, What more could we save, I guess, for ratepayers in California as we charge ahead? What I was quoting was a study that the California Energy Commission put out, I think it was two summers ago,

And so could the savings even be greater than what they were projected back in the CEC study? Yes, sir.

you think that expanding into this sort of multi-state governance structure, we could actually see direct pass-down to ratepayers actual savings in the very near future?

Just to analogize, I just stole my colleague's power. At least I said sorry for stealing your power. I stole his charger here. But we actually have a seam agreement between us where when I don't need it, I think I'm fully charged enough. You could just hand him the charger and it would go to his system. To that point are you encouraged or discouraged Do you see despite all the you know there a lot of politics at play obviously across the country but just at the current moment, a fairly stable climate when it comes to FERC governance in this arena? Have you seen any warning signs or generally a relatively depoliticized and stable environment?

What is it about the structure of our market now and as contemplated under 825 going into the future that we can sort of avoid the pitfalls, say, that we've seen in PGM? I'll offer a couple of initial thoughts, Governor Etta.

I think that we're going to be establishing an organization that hopefully will have the ability to continue evolving as we've done over the last 12 years and deliver value and enhance reliability and bend the cost curve. Really exciting. I am glad, you know, we always like to be first movers in California, but to see some of the pitfalls out there for others and be able to avoid those and be able to deliver benefits, very encouraging. So really appreciate the progress and may your work continue and may others join us. Can I just shift real quickly, Mr. Chair, two other quick questions, one about the Strategic Reliability Reserve and one about Diablo, real quick, if you don't mind. On the SRR, maybe to DWR, popular topic, we've gone over this many, many years, and I know we're ending, we're nearing the end of the term of those contracts. They don't expire at the end of this year.

My understanding is some of the water permits, MPDS and maybe others, extensions have not been sought. I know for Alamitos, but potentially also for Ormond as well. Is that the case? It's only for Alamitos.

So you're absolutely correct. For the Alamitos unit, their time schedule order has expired.

But for the one in Oxnard, they do have that permit timeline extended, so they can, in theory, operate should they be needed.

I don't believe we took action on any extension of those contracts in this year's budget. From an operational perspective, maybe I'll turn to you, Mr. Gundah, or perhaps Mr. Mainzer, need when you're looking at your stack. You know, we haven't utilized these resources. We paid over a billion dollars, I think, to just keep them around. We heard from Mr. Mainzer, you know, 36,000 megawatts and lots of generation and storage coming online. Is there an official view or an unofficial view at this point about the need for those resources going forward? Yeah.

Yeah, please. That would be great. So in July, we did appear before the State Water Resources Control Board to do a presentation of the SACWIS.

I know, for example, at Ormond, there's some discussion, and I think the city has actually approved the idea of adding battery storage to that site and utilizing, say, the transmission capacity at that facility. I don't think those details have been worked out yet, but is there anything we can do to either amend those contracts, be able to sort of supplement those terms so that we're not just paying for something to sit there and just let it sit through the end of the year and squeeze a little bit more, squeeze something productive out of those investments? Yeah, I appreciate your thoughts on that.

Correct. Right. That would be out of the DWR's jurisdiction authority. Sure. That shifts over and to either into the PUC or, you know, go through the – The KISO and transmission. Right, KISO and transmission. But it would just be something that we'll see what the generators want to do down there. But I do think there's a lot of interest in the community. And I would just note that Prop 4 does also have a chunk of money sitting there that could potentially be used that is specifically for areas that are fossil fuel impact that we still have not spent down. I'm sure it will be a subject in negotiation here down the home stretch. but this may be the most sort of a category of one for jump-starting that and getting it moving because we do know that sub area in the Moorpark sub area is soft. And we've been unable to cite, say, a number of battery plants in the region. It was the furthest stretches of songs back in the day. So it is on our mind between myself and the Pro-Thames area and the Goleta substation and then ours in Moorpark, I know we are going to need some capacity. That's where we get hit with a lot of PSPS. There's a lot of fire risk. So hopefully something coming, some new storage or clean generation coming soon to a community near me. Lastly, just on the Diablo piece, update on the loan payback, loan repayment. I don't know whose world that falls into.

So I had heard that the current anticipation is that the loan is not going to be repaid in full under the projected timeline, that we'll only get about halfway there from the – what did we lend? Did we lend a billion five?

$1.4 was lent out. So just an update on that?

Because you're the lender.

For the state.

Right. And so you're saying that 2027 is the earliest we'd get the 741 back from the feds on that?

But any hope to get even more than that back? That's what you're saying? Supplemental information has been provided by PG&E to the federal government on that?

So DOE program could pay out up to $1.1 billion, but that's up to...

Okay, so say that's it. They don't approve any further beyond the 741. Do we eat the rest?

Understood. I would just say, and I know there's also the management fees that we added on top of that, and I know there's pending legislation on those issues and how those are being utilized and offsetting some of the costs and lost property value and its impact locally. I actually believe that there is a way to make the extension of Diablo a prudent investment, but I would hope for just as...

I would just hope for more information in terms of how to get our rate payers the best deal. I think Mr. McNerney might have asked earlier, is this going to be a benefit or a cost? Right now it feels more like a cost in the near term, but is there a structure of a deal that actually could deliver rate payer benefit in the near term? I don't know who to turn to on that question, but is there a hypothetical structure that, in theory, wouldn't just, you know, that would actually deliver savings and meet some of this load growth going forward? Because you're not, just to be clear, you're not projecting that resource beyond the current term in the projections in your stack? Diablo included in the projection?

Sorry, yes, good clarification. Taxpayer impact, right?

No, no, I don't expect that. I guess I do want to get clear, though. You're not in your projections for how we're going to meet forecasted load growth. Diablo is baked into that or not baked into that?

When? What's the date? What do we assume under 846?

Okay. That was the extension, yeah. Understood. So in other words, that net total then, that almost 20 gigs projected, that stack reduces if you assume a Diablo extension through the date. How much-ish?

Understood. Avoided costs, things like that. Okay. Senator Becker had to leave, but he did have two additional questions. Do you want to give me that? Would you? Of course. Okay. So Kaiso recently published a blog titled Powering the West's Future with Demand Flexibility. so this is a demand flexibility question. This is our favorite topic in absentia, former Chair Becker. So LBNL projects that by 2050, California could realize 21 gigawatts of shed potential and 30 gigawatts of shift potential. Can you tell me how we're approaching this potential? And maybe more pointedly for the PUC, how are we incorporating that potential into ongoing reliability proceedings? So I don't know, maybe between CAISO and PUC on that front, we're a big plan of getting more out of this existing grid and using that demand flex. I would just state, obviously, the core policy decisions about demand response and load flexibility are being made inside the state of California, and we always are deferring to the state agencies. What we are noting as the operator of the Western Energy Imbalance market and the extended the day head market is that there is a lot of interest in this topic across the West, including not only the opportunity to optimize within the distribution system, but also for some entities to participate in the wholesale markets. What we're looking is that for resources that are qualified and are enabled by their program designers and by their utilities to participate in the wholesale market, we want to make sure that we're not a barrier, but we also want to make sure that we're not doing anything to have unintended consequences on state programs. Sure. That's the essence of that. Yeah, yeah. And from the PC perspective, just how are you incorporating this potential into ongoing? Yeah, a couple of different things.

But I would just say, you know, we're a big fan of what the CEC has done with DSGS, and I wanted to know if the PUC's position was still one of skepticism about DSGS sort of,

but is there an official position from the Public Utilities Commission while you're getting some of those longer-term proceedings going, sort of keeping what is no longer an incubated market, it's a maturing market, growing, and sort of ready for the handoff into the market-oriented space, still an official position there?

So maybe not a hard and fast opposition then to us continuing to grow what we've built at the CEC with DSGS in the near term? Is that fair to say?

Okay. I'm going to take that as an openness to continuing DSGS. I'm just going to read that into your remarks. I hope I'm not drawing the wrong conclusion because we're big fans of it here in the Senate. But unless you want to correct me, I'm going to say you're going to leverage the stakeholder process and stay open-minded to that in at least the near term. And I do see the potential for a transition there, but I just don't want to pull the rug out from under a very successful program. I'm not going to put you on the spot, Mr. Vice Chair, on that front, but you have every opportunity to correct me if you want, and you're welcome to jump in, Mr. Vice Chair, if you'd like.

Okay. We'll be looking to you for that. Last question from Mr. Becker here. The PUC reported about 3,000 megawatts of customer-cited batteries already installed across the state, and 100 megawatts of new customer-cited batteries are installed monthly, give or take. The numbers may have shifted a bit. These are resources that Californians are paying out of pocket for and that have large potential to help reduce strain on the grid during peak events. We always talk about optimizing the grid that's already been built and paid for, especially as CEC predicts a period of rapid load growth. This involves the ability to be credited for energy exported past the utility meter. So when do you foresee customers being able to participate in the market to provide these resources to our grid? What will it take?

So, again – Up front may be funded by the customer, but through the tariff compensated back through the net-dilling tariff.

Understood. And it was shifted to be very lucrative for customers that have those batteries a couple of years ago. So, again, there might be a potential for those customers to do even more with those batteries, but we have to make sure that that additional incentive takes into account what those customers are essentially already being paid. Is that something that PUC is currently looking at? Do you have any proceedings on that front investigating that?

I mean, I know there's certain constraints around what is it, General Order 91, sort of the context of you've got to pay for your impact on the grid, but is that kind of tool on the table?

Very excited. Yeah. And, you know, that was something I want to be clear.

So I have the timing right. That's complete, the flexible interconnection decision, and then the advanced rate design decision is pending, but you're going to sort of track the progress out of that flexible interconnection proceeding and sort of try to feed that into it as well as – But on this point around the General Order 91, I mean, is that one of the – if a large load customer wanted to come online, could they bring that kind of offering in theory?

I don't know if you want to share. comment on that? Appreciate the questions. I think this just illustrates that the urgency and the imperative of getting resources onto the system as efficiently as possible, making best use of our existing system, supporting resource adequacy, and then making sure that the activities that happen on the load side of the distribution system can be effectively coordinated with the bulk grid operator so that we can capture the cost savings to the consumer from that demand response. So we're excited to continue working with the PC and the Energy Commission, and we're hopeful. I think that was a little bit of a sense, you know, when we look out the next few years, we know that we're still making fabulous progress on resource adequacy, but there is challenges ahead, and so every tool in the toolbox needs to be leveraged. So we're excited to make progress there. Really appreciate that. I think the creativity of your collective efforts is not lost on us, And I think to some of the members earlier points our ability to translate that back to ratepayer savings is going to be everything because the rage is real still despite all this progress And just to say it not as bad as France or Spain or Pennsylvania or Washington doesn make anyone feel good if you paying a month and you making a year It's still totally unacceptable. And so we're going to keep working with you all to bend the curve. Mr. Chair, I defer to you. And there goes my long-windedness. Thank you, Senator Stern. I want to just follow up a little bit on the questioning on the Diablo Canyon loan and just get more insight as to what's happening there. Taxpayer dollars, I mean, obviously we're being asked to make various changes involving issues relating to the utilities. I understand we didn't know about the exact amount that we were going to be getting from the feds, but this was a direct loan from the general fund that we were told is going to be fully paid back. Can you give us a little bit more insight as to how we should be thinking about that?

Why wouldn't they be allowed to go up to the $1.1 billion?

Say that one more time. Let me just make sure I fully understand what you just said.

Was it always anticipated that this was going to be fully covered by these federal funds?

And the 1.4 was, where do we come up with that number?

Okay. Well, we have some follow-up questions on that. I wanted to just, you know, Commissioner Reynolds had done a letter relating to the central procurement mechanism authorized in AB 1373, and I just wanted to ask a little bit about the process by which DWR assesses whether it will be, you know, whether it responds to a PUC request for procurement of long lead time resources and, you know, what sort of considerations DWR uses to inform decision and maybe some updates you can provide us with coming out of that letter.

But you're correct. That's been a while, and we are working with staff closely on all of those questions. Okay. Do you guys want to respond at all? No? Okay. Okay. Interesting. Great. I'm interested in some of these jurisdictional issues. All right. Let me also just ask, I mentioned in the opening comments a little bit about, you know, some of the federal actions that seek to derail clean energy development, and I just wanted to get a better understanding of how the agencies in CAISO were assessing the potential back from the federal tariffs, rollback of tax credits. in the recent federal legislation. Obviously, some good optimistic information you presented earlier, but I don't know how these federal headwinds fit into all the things that you were mentioning, especially with regards to the need to potentially support ensuring an eligibility with the sunsetting federal tax credits.

Okay. Yes, sir.

Yeah. Okay. That's helpful. All right. Thank you. I really appreciate it. I was going to go more into Trump v. Slaughter, but I want to talk to you about that later as well. So I appreciate your great presentation. Thank you for all the thoughtful answers to the members' questions as well and the dialogue. And I'd love to give the public the opportunity to come to the microphone and weigh in. But I appreciate everybody's participation in all the work that is reflected in your presentation.

Thank you. Mr. Smutny. Thank you. Thank you very much, Mr. Chairman and members of the committee.

That's there. I am not in the room. It's way above my pay grade. I have no idea what's going to be put forward. But our industry, our clean power industry, is based on contracts with financially sound counterparties. And having gone through two different bankruptcies over the last 20-some-odd years, this will throw a monkey wrench into all the great progress we're making. So I would impress upon this committee and your colleagues. I know this is an issue that people are paying close attention to. This is something that does need to be addressed, and I would encourage you for the benefit of your California rate payers. My understanding is 17% of a PG&E bill is tied to fire, either hardening the system or paying for fire victims, and I guess my understanding is that it's about the same. So if we are looking for meaningful change in terms of rates and whatever, this issue needs to be addressed, and I would encourage you to keep on the topic on this through the end of session. Thank you.

Good afternoon, Mr. Chair and members. Adam Hadafi here on behalf of the California Coalition of Large Energy Users, as well as Generac Power Systems. Two things, one concern and one comment. On the concern side, I want to highlight that when you hear the reliability assessment from the agencies, Much of the data that they're using is the same as the data in the CAISO's 2026 Summer Reliability Assessment, which is based on all resources that are eligible for resource adequacy, not resources that are under contract for resource adequacy. The analysis from agencies has showed that for us to have a reliable grid, we need a reserve margin of anywhere between 21 and 23.5%. We have that in terms of total resources that are available in the market. it, we do not have that in terms of resources that are under RA contracts. The CPUC's resource adequacy program locked the planning reserve margin at 18% for 2026 and 2027. Now, in 2026, we have some contingencies. The demand side grid support program will have sufficient funding until the end of this year. There are other contingency resources. You brought up the strategic reserve. Those are all going away at the end of this year. 27, those resources that were put in place in 2022 will not be in place. In 2022, we relied on resources in the market to keep the lights on that were not under our contracts. That cost ratepayers an extra billion dollars over three days. We're headed the same way in 2027, and we're very much concerned about that. So that's the concern. The comment is that it would be nice if DSDS were to stick around in 2027 and in the years moving forward so that we don't find ourselves in the same position in 2022 where you all created DSGS to prevent this from happening again. Thank you for your time.

Thank you, Mr. Chair and members. My name is Adrian Covert, today representing the Bay Area Council. I just wanted to make a couple observations about the hearing. One of them was the importance of taking into account the distinction between the cost of action and the cost of inaction. I think Diablo Canyon raises this point particularly well. Well, earlier this year, MIT came out with an independent analysis estimating that keeping Diablo Canyon online beyond 2030 would create a value for ratepayers up to $1.3 billion annually, which is consistent with the CPUC's findings from last year, that it would create a value to ratepayers of about $990 million. That report was referenced during the testimony but I didn hear the dollar figure The previous speaker just mentioned it But that requires action So without action those costs are going to be shouldered by California rate payers The other observation I wanted to make was we talked a lot about the load growth. But there's also the kind of load growth that we're going to see, I think, is particularly important to consider, particularly about 26 percent of that load growth that's going to come from electrifying buildings. Now, a lot of that's electrifying heating, and the CPUC has estimated that's going to create a new winter peak in demand, analogous to our summer peak, and that's right when solar is at its lowest production point. So that enhances the premium for clean, firm power. So I just wanted to point that out and enter that into the record. Thank you so much.