Senate Standing Committee on Energy, Utilities and Communications

Alright. We're gonna call this committee to order and we wanna 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, Calabres County And of course, the heat wave around the state. This is very salient to some of our current conditions. You know, this course was six years ago where California's electric grid experienced unexpected rotating outages during August as I recall.

August 2020, when we had, you know, these high heat events around the state around the West and and that then created a whole slew of electricity challenges, supply increased demand. Particularly of course driven by air conditioning. At the time, the the called for controlled rotating outages in order to prevent cascading blackouts on the electric grid.

And while the outages ranged from eight minutes to ninety minutes, they raised concerns from 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 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 and of course, they'll learn wind resource output and declines. So today's hearing is about the balance of power, which is what Nittiest 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 from from and the headwinds that we're we're 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 well, you know, 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 the public utilities commission, the PC. The energy commission, as well as our state's largest electric grid operator, the the Kaiso and the Department of Water Resources, which has been more recently tasked through budget and policy actions with specific energy related duties.

So we've been asked to to get we've asked them to provide updates on several things. First of all, the near term 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 once through cooling regulations and 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 the DWR to procure long long lead time resources if the PC 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 the committee also requested the Kaiso 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 Kaiso and electrical corporations to participate in an independent voluntary energy market no sooner than 01/01/2028, 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, you know, some of these programs are less welcome at the federal level now.

So we'd like to certainly, you know, have an update from from the folks who are gonna present to us on some of the efforts to address procurement for resources that may have have sunsetting tax credits, other changes in federal policies and actions and awareness of the risks posed by the recent US 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 of complicated and and meaty topics for us to to discuss. I just want to welcome to the stage, our our presenters.

So the the CEC vice Chair, Siva Vinda, our CPUC 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 Joseph Vito, who's Chair of board of governors at CAISO. And, we will start with you, Mister vice Chair Gunda. I appreciate everyone being do we have chairs for everyone? Oh. Yeah.

I think we got yeah. We should have enough. And we really look forward to what I what I I know will be a robust and and meaningful discussion. You may proceed when when ready.

Good afternoon, Chair. Alan and the members of the committee. Thank you so much for holding this oversight hearing and giving us the opportunity to provide you updates on the topics that the Chair just mentioned. I'm Siva Gunda, currently serve as the vice Chair of the California Energy Commission for the record. With me, I have colleagues from PUC, DWR and Kaiso who will introduce themselves.

Well.

Leuwam Tesfai, Executive Director, California Public Utilities Commission.

Good afternoon. Delphine Hou, Department of Water Resources.

Good afternoon. Elliot Mainzer, President and CEO of California ISO.

Good afternoon. I'm Joe Edo. I'm the chairman of the board for the California ISO.

Yes, please.

Thank you. I'm Chair. So we'll we'll start with with providing a quick overview of the rules of everybody who's here. I'll pass it to Luam to go over that. Thank you.

Okay.

Good afternoon Chair, vice Chair, and members of the committee. I'm pleased to be here today along with my colleagues from the Energy Commission, the California Independent System Operator, and the Department of Water Resources. I wanted to start with a very brief orientation to the various agencies and organizations involved in electric sector regulation and market operation in California, And then we'll continue with the joint presentation. So going to this first slide, we have listed here the five primary entities.

Those represented on the panel today as well as the California Air Resources Board.

We've listed some of the main functions in overall energy supply planning. So with the California Air Resources Board, setting requirements for the economy wide greenhouse gas emission reductions, including those targets for the electricity sector. The California Energy Commission, conducting the forecasts for the future load. So we're ready for any variations in load and overseeing the renewable portfolio standard. We have the California Public Utilities Commission, which is conducting the electric supply and reliability planning.

So we're ready for future conditions. And so we cost effectively supply California with clean energy. We also have a role in renewable portfolio standard oversight. The slide also includes the California independent system operator or the CAISO, which is our primary transmission operator. They run the wholesale electricity market and conduct the transmission planning and partnership with the CPUC.

And then we have the Department of Water Resources or DWR, which has that electricity supply back stop responsibility, including the electric strategic reliability reserve program, as you mentioned earlier, Chair, and managing the Diablo Canyon extension fund. So with that, I'm happy to turn the next slide over to vice Chair Gunda.

Great. So I'm gonna just provide a quick update on what the state agencies have been doing since 2020. A Chair, as you mentioned, on August 2020, we had rolling outages in California. And one of the main things that, you know, 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. I mean, all the work that I described here is done by everybody here While NOC 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's 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, you know, a new issue presented itself and we really had to think about a holistic transition pathway. An important part of, you know, 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, you know, help ensure that we are 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 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 our, huge update to our transmission permitting process. That's general order one thirty one. I called it a once in a generation update. It was thirty 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, you know, 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 transmission, 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 a 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 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 provide 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 repairs.

In addition to that, I did wanna highlight that those procurement orders that are shown on the slide, you know, 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 and that these procurement orders, you know, 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 and E, but also this 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 with this slide. Thank you. 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 the 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, you know, the CPC 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 of 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 four and a half 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 dark our 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 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. We can move forward.

There we go.

So I'm gonna go through just a quick snapshot of the 2026 summer outlook, and then we're gonna 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. And 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. So but what we want to make sure we leave it 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 Leuwam just noted, we have been really served well with the incredible amount of megawatts that came on the system in a more than 36,000 megawatts in the since 2020. We also have 16,000 megawatts of that 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 825 and the work that Kaiser 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 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 and, you know, just over a few hundred megawatts. But as you see the total resources line, which is the second line in there in terms of numericals, 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 6PM 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 fitting in 2022 in terms of the standing planning, 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 that in the program at DWR.

We have other general fund in a 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 zero is it's because it's actually building of 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 payer 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 capacity of co-gen 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 our neighboring balancing areas, including LADWP and bank. 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 CAISO colleagues. Yeah. I'll do that.

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 I talk a little bit about the launch of the extended day ahead market. And then Chair Eto and I will provide, he'll provide some additional comments on the early value proposition of EDAM and report out on the AB 825 activities.

So lots to report. Of course, if you go to the next the first slide here. You know, for 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 one in 10 loss of load expectation.

That is our standard planning metric. The one in 10 metrics refers to no more than one event every ten 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 are 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, you know, five to six years. 36,000 megawatts of 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 control center are deeply appreciative of those resources. Being able to dispatch into the evening peak just as the sun is setting is really positioned us with a tremendous progress on resource adequacy which I think is very important for the state. A couple other just numbers that I think are relevant. You know, last year's one and two 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 15, which was at the peak for the summer at 43,625.

Interesting the the western interconnection of which we participate actually set a new record on July 24 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 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 at 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, you know, 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 this. But this has been a very warm water year. And something that's also worth noting if we go to the next slide.

As we look out to the balance 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 about 10 degrees warmer than usual. Right. 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 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 Ahead Market has been very beneficial. Just a couple comments on EDAM before I pass it over to Chair Eto.

We were fortunate back on May 1 after several years of preparation to go live with the Extended Day Ahead Market. As you recall over the last twelve 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 five, ten, fifteen minutes. Oh yeah. Sorry. We can change the slide.

Apologies for that. There you go. 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 cost for consumers. We've now extended that real time market into the day ahead time frame to the Extended Day Ahead Market.

And we went live May 1 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 back power back and forth between California and PacifiCorp's 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 to 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 the market on October 1.

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 in the amount of transmission connectivity increases in the resource diversity footprint, that's just going to allow us continue to strengthen reliability and improve economic efficiency. We've just come out with our most recent, our first quarterly EDAM benefits report. I wanted to turn it over to Chair Eto to talk just a little bit more about how those, what those benefits are looking like and how this market's going to play a role in the reliability equation and of course AB 825. So Chair Eto, over to you.

Thank you, Elliot. Good afternoon, Chair Allen and Committee Members. I'm gonna turn to the numbers in a minute. There's a lot of them. But I wanna make a point in particularly in view of the purpose of today's hearing, which is these two markets, the energy imbalance market and the extended day ahead market, are critical tools for reliability.

In the past before we had these markets across the west, if people were tight, the operators were on the phones calling their neighbors saying, what have you got? What can you send me? How soon? Uncoordinated calls amongst, you know, people who know each other through the phone have been replaced by a machine that optimizes resources across the footprint of the west. And the reliability benefits are huge.

So in the real time market we're doing that with the generators that have already been dispatched and who has margin and who can most inexpensively meet that extra increment of load. With the day ahead market, we're actually deciding which generators to turn on. So if you can pre position the entire fleet anticipating what you're going to see the next day, your ability to manage through these sort of unexpected contingencies is greatly enhanced.

And I think a lot of times, I'm going to go to the numbers next, I promise you. But these reliability benefits are enormous and they're going to grow as these markets grow. So let me talk about the numbers. Elliot just mentioned we've only gotten, it's gone off without a hitch. The numbers are right on track. We've got $11 million in savings just with two participants. And the first two participants, two months of operation, seamless, right on target.

The energy imbalance market that I've just spoken about, we've had that in place since 2014. That's now charted $9 billion in savings. And those savings are growing. We have 22 entities across the west, across 11 western states. The last quarter, those benefits were almost half a billion dollars. The Energy Commission did a study for us looking at what we can expect from EDAM.

EDAM is expected to bring to California an additional billion dollars a year in savings. Key, let's go on to the to the AB 825. Key to, just go back one please. Key to unlocking these additional savings with EDAM has been this, the AB 825 legislation, which enables us to partner with an independent regional organization that will govern and operate this extended day ahead market and the energy imbalance market.

In particular, as the Chair mentioned, no earlier than January 1, 2028, we're gonna implement tariff changes that have been filed at FERC that allows to operate this market on a west wide basis, provided that we certify certain conditions are met. Foremost among those conditions are that we...

Mr. Chair, just a quick quick question. Clarifying.

It's a clarification. When you talk about energy savings, is that dirty energy not turned on? Is that, what is the savings reference? So that we have an understanding. They're big numbers and they're fantastic.

They're very big numbers. And so prior to the market, prior to these markets, operators would sort of dispatch the resources they had at hand or the ones that they could get from their neighbors. And they would do that as all operators do in merit order of the least cost to the most expensive. So what you have happening when you enlarge that market is you have a much larger pool of low cost and high cost resources.

And so in many cases, the lower cost resources from your neighbors can displace the high cost resources in your footprint. And so the savings result from essentially avoiding having to pay more for electricity than if you didn't have access to this broader market of resources that you could draw from.

Got it. Thank you very much. Thank you, Mr. Chair. That's really helpful.

Yeah. I apologize for not being clear.

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 have you're using that which is not as clean. And so that's the reason I...

I couple of good news stories, but I also don't want to be misleading. The good news story is that we've brought on so many clean resources that we're often exporting them at times of need. And the reason why that's the case is because they're cheaper than the dirtier resources. When things get tight of course you use what you have, but if you can minimize that by sharing the lower cost resources that are available from your neighbors and do that in a more or less automated way, you both have the market benefits and these incredible reliability benefits.

Reliability is very difficult to quantify because we only know about the reliability disbenefit when things don't go well. But you talk to the operators across the west, and these markets, the power moves almost automatically. And so like these hot temperatures across the west, we were all exploring to support our neighbors and it was to the benefit for the entire community in that regard.

Sure. Let's talk about the legislation. There are some very specific protections that we as a board will need to certify before we're gonna file these tariff changes to allow this independent government to take forward. Foremost of them are consumer protections, transparent and open stakeholder processes, and extremely importantly, respect for state authorities, in particular our clean energy policies. We will not, those are deal breakers if those conditions are not met and we understand that very, very seriously.

Let me talk now to what we are doing in implementing AB. Our first responsibility is to report to you annually on how the markets are performing. And so we've just filed our first report in February. Talks about five key activities. The first one is the changes to the federal tariffs by which we operate the market.

We submitted 40 filings to FERC last year. Large number of them are directly tied to the elements of the EDAM design that we're trying to roll out. I'm very pleased to report that as a result of robust stakeholder processes run, these filings have been approved by and large unchanged. We have not had a FERC filing rejected for several years now. And that really is a testament to the strength of those stakeholder processes that we've been running.

We also are reporting on the initiatives which lead to many of these tariff filings. We've got 14 processes currently in this process. These will ultimately to tariff changes to improve our markets that the stakeholders have asked for and that we're working on currently. Importantly, we have a independent Department of Market Monitoring that reports directly to the board. This is sort of one of the aftermath of the 2000-2001 energy crisis.

They both are looking out for bad actors in the markets, ones who are not following the rules, but they're also doing an independent assessment of the function of the market. So their annual report just came out. It reported that the WEIM, the energy imbalance prices are slightly lower than last year and that's principally because of natural gas costs. On the next activity we report are the actions that we've taken as a board. Reports on the 25 actions that we have voted on.

One of the most significant, which is the 2024-2025 transmission plan which we approved back in May. That last activity is actually the transmission planning processes. We approved over 30 projects, about $5 billion worth of transmission last year. Cumulative total is close to 30 billion now over the last five years. So we're building transmission, we're playing the transmission in lockstep with the procurement portfolios that are being handed to us by the Public Utilities Commission.

Okay, let's talk specifically about the implementation of AB 825. That's the last slide I have. This is a complicated slide. There are a lot of work streams going on simultaneously. The top row has the work streams that are being undertaken by the what's called the formation committee, which is seeding the regional entity.

The bottom row is our activities internally. So I'm gonna start from the bottom and work up. I've just spoken to you about the annual report that we've just filed. We're also on track to deliver a jobs report as called for by the legislation. I think we have a public workshop scheduled for this in September and we're certainly on track to deliver that by the end of the year.

We're gonna, we're aligning the processes internally by which we'll certify that the conditions of the AB 825 legislation have been met. That is a joint activity with our partners at the California Public Utilities Commission. According on that to make sure that we can get everything to the finish line at the appropriate time. Probably the most important thing that's going on outside of our domain is within the formation committee. And they're in the midst of seating a board.

They incorporated back in January and they're in the midst now of seating a board, an independent board of five governors at least initially and ultimately seven board members. They're in a selection process. I think they've got a, they have an executive search firm. I think they're doing interviews. I've heard 25 candidates.

They're gonna narrow that down to five. They hope to be able to announce that in September. That will be the counter party with whom we will negotiate this contract to operate this market, provide that we can, that we do successfully certify the conditions that are in the legislation. I think that's all my report on the 825. Let me turn it back to Vice Chair Gunda.

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 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 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, you know, planning and procuring to meet the one 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 late 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 Tesfai mentioned, there are a number of these events that happened in 2020-2021, 22, and 23 that are extraordinary enough that they fall outside the one in ten 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, when 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, you know, as as we discussed, we have, you 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 SB 100 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 is the most likely scenario as we do our analysis today. As Director Tesfai mentioned, we continually update these numbers. And as we move forward year after year, there'll be new procurement that will be added to the system. So I wanted to just bring it back into the summary of the presentation that we provided you today before we open up the Q and A.

So in summary, I think one of the most important things is there has been significant progress in planning and procurement, and we're in a structurally better position. We were structurally short in 2022, and we're 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 you know, 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.

And 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.

Well, thank you. Thank you very much for this thoughtful and comprehensive presentation. Let's go first to Senator McNerney.

Well, thank you, Chair. So I wanna thank the panel. I mean, this sounds like really good news. I have some concerns. First of all, I just wanna make a note that I saw that data centers are projected less energy consumption growth than electric vehicles. And people are all excited about data centers.

But 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're getting at. But you also mentioned the word machine controlling this. And that makes me nervous because AI hallucinates. What are our risks here?

By machine, I meant an optimization machine. A machine that looks at all the generators across the footprint. Looks where they're loaded at, how much they still have to go and what they would cost. And then stacks them up in rank order from the cheapest to the most expensive and dispatches them in that order. And so that's the mechanic, I should have said a mechanical process.

It's certainly not an AI driven process. Let me reassure you about that. Does that speak to the concern that you're

Well well, it does. You know, I have a 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 one 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 gonna affect rate payers cost? I mean, we pay some maybe the most expensive and maybe it's, you know, looking ahead that in future years, you know, when when fossil fuels become less and less available or whatever happens to them, California is gonna be ahead because we've made all these investments and all that.

So what do does all this transmission build out help reduce repair costs?

Thank you, Senator McNerney. I can start on that and perhaps Kaisa will have something they wanna add as well. You know, something that we were really trying to emphasize in our presentations was really the collaboration between all three, entities, the energy commission, public utilities commission, and the Kaisa. And one of the main benefits of that coordination are lower rate payer cost.

So to go into more detail, you know, as I said, we leverage the demand forecast that the CEC puts together to integrate into, integrated resources planning so that we're requiring the right amount of resources at the right times.

And then that also feeds into what new transmission that we need. So the new transmission that is being planned for and permitted isn't just new transmission in case it is specifically connected to what we call bus bar mapping in our integrated resources planning process. So we're looking at all the different substations across the state and the different points that they connect to. And trying to understand what new amount of resources they can take in those locations.

And so we're very cognizant of making sure that resources are build being built in diverse locations across the state and optimizing those locations so we're not just building new transmission.

And so we're very careful about not triggering new transmission without leveraging all of the existing transmission on the system as much as possible. And then the CAISO is taking that information into their transmission planning process to identify what new transmission is needed. Maybe, Elliot would like to

come over. Absolutely. So first and foremost, as you stated, trying to make the best use of our existing infrastructure is always starting point number 1. And we're constantly doing that through our market dispatch and just grid utilization. But at the Kaisa 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 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 rate payer.

Well, as I've I've said often, people want people want lower rates. You know, they don't really care about all these details. They just want lower rates. So we we needed to look at how we're doing this and and how that's gonna impact our constituents and how we're gonna explain that to them, you know, if they're not seeing lower rates next week instead of, like, five years from now. So that's that's an important consideration for us on this dais.

What about Diablo Canyon? I think somebody mentioned Diablo Canyon. Is that is that a rate payer expense or is it rate payer savings operating that that nuclear plant?

A lot to that question. Good question, though. So just kind of with the start, you know, the reference I made in my presentation was that when the Senate when the legislature passed Senate bill 84 d six, there was a requirement for us to continue, to have our foot on the accelerator. I have to remind myself not to say put on the gas anymore, put 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, you know, the offset that you would have for additional procurement, end up seeing potentially what those savings are. And so again, we did just a very preliminary analysis last September. And stakeholders that's public document stakeholders have access to it. But that would be the potential savings for customers. Right now, the cost 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, it was those costs were focused on the PG and E footprint, but now they're spread out statewide.

Okay. That was not a simple answer. And I'm not gonna ask about GGRF decisions today. Okay. That's something that's on our minds, I believe.

Maybe somebody else here will. But my last question is when we have a power safety power public power public safety power shutdowns or other power failures, is there a metric as to how much that's costing the economy per hour or per event? I mean, because we see these things happen and we wanna know, we need to know basically how much is that costing, you know, and who should pay for the for the cost when that happens.

So on public safety power shutoffs that you don't as you all know, they are a tool to prevent potential wildfire ignition. So Right. There has been public safety power shut offs have existed for many years, but we have been routinely improving them. The standards for them and the utilities and 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, of the 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.

Not answering the question. Is there a metric to decide how much those are costing of the customers in the state and the economy? Yes. You know?

I I can speak to that Senator. Before I joined the ISI, I had a forty 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 value, 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 risk as part of it. And I know it's a standard part of the analysis that's done in those activities.

Okay. Mister chairman, I'm gonna yield back.

Alright. We're gonna go to Laura Richey Sadden next.

Thank you. Let me start off by, thanking the chairman for, arranging this overview. It builds on a previous session that briefing that we had. So thank you. Thank you very much.

Some of your requests actually.

I noticed. I did notice that. I have a couple questions to make sure I'm understanding this. I appreciate the data of, you know, where we are now. My questions are more surrounded on where we're going forward.

So, with that in mind, am I correct in understanding that our current use is approximately the forty six thousand five hundred and forty six? Is that correct? Am I reading that correctly?

Yes.

Okay. And then, you're saying that our future need state forecasting significant load growth is gonna be approximately 20,000. Am I reading that correctly? Correct. Okay.

So then that means we're going to need an increase of a little less than 50% of where we are now?

Yes. Okay. And just wanted to make sure the 46,000 that we just shared with you is only for the CAISO jurisdiction or the footprint. So when you look at the entire state today, it's close to 55, 60,000 depending on the year. So and and you're correct that, you know, moving forward, that could go up 50% to 70% depending on which loads might manifest the amount of data centers, the uncertainty around that, and the amount of electrification.

Okay. So then that's leading to my next question which is how confident and I think, Mister McNerney was getting at that. How confident are we that, the data center would only really be 4,700 and electrical vehicles 8,200? How, how are these numbers derived?

Yep. Thank you. So I'll go one by one. On the data center, again, to your point, just 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, you know, in terms of the applications they see. So if you count all of that today, it's over 25 gigs and not 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 higher amount than what they actually build. It's typically about 65% to 66%. So we bake that into that. Second, how much of 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, you know, coming in with an application, they typically have a two to five year ramp time of bringing that load on. So we're 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 Kaisai planning, and the higher forecast is for local reliability planning. So we will continue to to your point, there's a lot of uncertainty.

We'll continue to update those numbers and then, you know, make sure that every cycle we do the procurement and planning, we'll update them.

One of the other elements around the planning is the Westway 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 Support 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 you know, lose some of these tax credits from the Federal Government or higher electricity price.

That will change the forecast and we update that every year.

Okay. So you typically give us this type of report annually?

Yeah.

Okay. And so if I understood correctly what you just said, this slide is basically, I would describe a conservative estimate of what you think our need will be. But it could potentially be higher. It could potentially be lower.

But you've taken things into account. Okay. So, might I suggest a couple things, through the chairman. One, if you could give us, a little more detail of when you say these data centers and approximately needing 4,700, how many data centers are that? So as some of us were in different meetings in different locations and if we're hearing, for example, you say, oh, well we're only estimating, you know, three data centers we're gonna need between now and the next five years.

And then we go to another meeting and someone's saying, oh, we're gonna need 20 data centers. It would just help us to equate, the need numbers with to quantify them with what we're talking about. And the same thing with electric vehicles. How many, electric vehicles, for example, are you anticipating that we're gonna be utilizing versus where we are today? Because that helps us because then, when I'm in a meeting in transportation and they say, oh, well actually, the electrical vehicles are down.

Then it it just helps us to better understand where we are. So if you could, quantify where these numbers come from. And then, I would also suggest through the Chair that maybe you give us a best case and worst case going forward. So we understand best case. This is conservative where we think we're gonna be.

But worst case scenario, if these following things happen, where could we be? And because I think we have to find our way probably someplace in the middle from a planning perspective. And then my last question would be in I don't know if I missed it with what you're saying. But, if we are going to need approximately, you know, 50% more than what we have, How are we, planning on generating that? So I missed that in the discussion of how does that happen?

How much is that going to cost? How long would it take us to put it in? More of the details of it. And I realize I'm new on the committee, so I I get it. But I'm working to come up to speed with, you know, with the needs of of how we can provide oversight.

But it would be helpful to understand what does a a 50% increase, mean and what would it take for us to get there. Just so again, we can begin to properly plan. And then the last thing I didn't see here and maybe it's here and I'm I'm just missing it. You have fuel substitution. The question having to do with the ports and the refineries and all of that.

So for example, I've heard, you discussed in the past that I believe currently we're importing 20%, of our fuel. If we were to increase that and continue to transition, which I'm not necessarily a proponent of. I'm a proponent of keeping what we have and then growing new technologies. That's my personal position. But if we were to fall in the realm of we're importing 20% and we're gonna increase that by 20%.

And if we're expecting the ports to be electrified, how much is that that we're gonna need? So I would just say if we could delve a little bit further more on some of, maybe, those other needs that are being discussed, but maybe not necessarily reflected in the anticipated growth. Just to make sure we're all on the same page of of what the expectation is gonna be.

But in summary, I just want to say based upon the last meeting that we have, I do thank you for, actually taking that into account and working to provide more information of what I was asking. So thank you.

Yeah. Senator Richardson, if I may, just a quick response on that. I think all the points that you raise 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 SP100 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 as as 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, you know, 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 really appreciate those questions, and we are really trying to work together, as a as a state agency team to integrate, petroleum, electricity, and natural gas as well as we can and look forward to reporting to you.

Okay. Thank you. I won't name, names due to the fact that there's very, volatile negotiations going on as we speak that, Mister Gunda is aware of.

But, I would just stress, to the Chair how important this is of understanding that piece as well because we have, municipal locations who are now in the process of taxing with this whole refining process which, and now, you have lawyers going from one city to the other city to the other city trying to replicate and can, make this even worse and faster than what we expect. So it's really critical that we're understanding, what are the potential impacts because we may find that we don't have enough.

And if we don't, we need to be helping you by coming up with some sort of legislation to protect, the state's position and your role as an agency to kind of go time out. No, we can't we can't approve this or we can't support this because that's gonna throw off our whole plan of this.

And so that's what I'm getting out of trying to understand the bigger picture and where we're going so that we don't wake up two years from now, three years from now, and go, oh my gosh. Now we we have a worse problem than we expect. So I'll look forward to that information through the Chair, and to the committee, the additional details requested.

But thank you. Thank you very much.

Senator Rubio.

Thank you, Mister Chair. And I appreciate all the information that you always provide us. It's a lot and I really have to say I appreciate the confidence in your delivery and everything that you have to share. But there's always, concerns that I have to grapple with. And, so I just wanna start by saying I don't think any of us here disagree and that we all need a reliable grid and that, we are also, need to continue to move towards our goals of clean energy.

But as we as I say that, I also know that simultaneously, we're continuing to electrify transportation, homes, and we have to grapple with the growing energy demand from data centers and artificial intelligence. And what I state every time I'm in these committees is that, I I know. I know based on our conversations with our constituents, our families, that a lot of our low income families end up paying the price.

And again, as I share with you, I too appreciate your confidence in how you foresee the future. But I just wanted to ask, you know, as you sit here, how confident are you that at this point that there are not unforeseen circumstances that may basically, that could be detrimental to to the infrastructure that we are not seeing right now.

And and I know it's a broad statement that I'm making. But, you know, we cannot account for what we cannot see. And Aye, for example, I remember we saw Texas that all of a sudden their their system failed and everyone there's people dying. People didn't have heat. And I mean, anything could go wrong.

But, when you stated the calculation and how you're collecting data, it is my assessment based on your statement that it's very preliminary in terms of how we gather the data, what we have before us. I think you talked about accounting for, you know, projections and collecting every so often data that comes your way. But, do you have concerns? And I hope you can be honest about this. Are we not seeing something?

I know data centers right now in my community are one of the biggest issues. And the biggest fear I would say collectively is Californians. What is this gonna do to the future? But is there something that we need to be aware of that perhaps we're not seeing, perhaps that you believe is coming our way, and that maybe we need to tackle in advance to help you prepare for that future?

Thank you, Senator Rubio. And I I just wanna make sure that Aye, share. I think the, what I would say from 2020 to now is the processes have gotten much better. I think I have a 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, you know, 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 ten years, especially beyond ten 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 wanna, like, 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, ten, fifteen, twenty years, we we really rely on our ability to continually do that analysis every year. And 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. If I may add to that, I know I've been sitting here for eight years listening to every single informational hearing. And back in 2019, I was also part of, SB, sorry, AB 1054 when we almost had a catastrophe on our hands. And all the time, I keep putting rate pairs front and center. How is this gonna impact our lowest income families?

And going back to 2020, yes, you know, I absolutely agree. We've done, you know, we've done a lot of work in trying to ensure that we do right by our constituents and Californians. But nonetheless, you know, as families open their electric bills these days, it's a it's a challenge. They continue to struggle with affordability. And and I stated every year, and I'm always assured that things are being done to make sure that it's fair and affordable across the state.

But it always happens that I don't see it. And I continue to worry about those low income families. Earlier today, I'm not sure who stated this, but you talked about working on something called sectional lysine, I believe you said, which impacts fewer customers. And then we get into, well, what does that mean? Who are these customers?

Are we talking about affluent communities that could afford it, that wouldn't even think twice about it? Or are we talking about those that cannot afford to keep the lights on? Right? And so, I'd like to go deeper into that. What does that mean?

And how do we balance it and make it fair and equitable? And more importantly, how do we focus on the low income families who right now can't even afford the electricity bill? There some of them are actually without electricity because they can't afford it. So help me understand how we help the low income families.

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, you know, when PG &E was doing public safety power shutoffs, I would say about over five years ago at this point, there were customers who are very far away from the area where the potential wildfire risk was that were also having

their lights shut off because, 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 shut off 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 and 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 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 VERA 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 q four of last year and then in q one of this year as well. And so really trying to find that equity that you're talking about in terms of how customers are built for their electricity.

And thank you for that clarification. Just one last thing, if I may. And I know that we have these programs that we've been implementing to ensure that, we support those low income families. But my argument in past times has been that not every family knows about these programs. And I believe at some point I asked for a comprehensive study of these programs.

And just trying to understand if we can do better by making sure that those that need it know about it. I don't think we're there yet. Because when we hear about our constituents and they're constantly sharing with us their distress and and how they can't afford it. And if you talk about these programs, they they still don't know about it. But if A, you don't have to tell me now.

But if you can get a something to me where we have some kind of study or comprehensive review of these programs so we know where the money's going, where the support is going, or or how are we reaching these individuals. Because I think at the end of the day is also that education piece. If they don't know it exists, we may not be able to help them. But if there's something that you can share, I would love to read it.

But I do think we have to have a very particular focus on not leaving people behind because year after year, like I said, I've been hearing you're sitting in the same committee.

And the narrative narrative keeps getting worse. The distress keeps getting worse and the electricity bills keep getting higher. So anything that you can share with me that can help my constituents understand all the programs that are out there and how do we make sure that they take advantage of it. I would greatly appreciate it. But thank you for for that.

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 the lienus of this next lienus study.

Appreciate the information. Thank you.

I will yield, Mister Chair. Thank you.

Sure. Yeah. Go first. I understand.

Yep. Oh, oh, sorry. You okay?

Alright. I will not be long winded so appreciate it. I really appreciate the update and the fact that you're all working together is a long overdue. I'm really happy to see it and whatever it took to get us to this point is really good. I I 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 Sigma and the regulatory framework we've created, we're gonna lose between a million to 3,000,000 acres of ag land. The way the valleys historically developed is 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 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 I'm I'm a trombolodite, you know, trying to keep solar from coming into the valley. What I'm really looking for and have spent 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't surprised when it was pulled back once the administration changed.

So we lost that opportunity to really jump start what I think has the potential for a solution. I think the air board has identified it as well. We have 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 the opportunity with biogas. And we've invest made major investments in dairy digesters that that get us moving and that has that has had some real successes in the heavy trucking industry.

And so I I'm I'm wondering if if that's part of a planning that you're and and and why that's important is we have waste in our forests and waste, ag waste that we've we've obligated it to to the open air burning now is is not permitted unless there's no solution and we've created no solution.

So I thought ag burning was gonna end and it's not. It's still happening because we have no solution.

So I I'm wondering in terms of, all all alternatives and I'm I'm all for battery storage and I'm I'm I'm all for for for solar but, but I do think in an area that is prone to blowing dust with belly fever as a very serious lung disease that we risk 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 spend and when I visit the COP conferences, in the past, other countries are moving in this direction.

We're gonna lose our edge in the technology sector if we, if we don't at least consider some of these possibilities. And I wonder in terms of your your advanced planning whether that fits into anything.

Yes. Senator, thank you for the question. And I think I also want to just uplift and note something that you just said in the conversation, which is the intersection of the energy planning, you know, decarbonization of the grid goal

the land use planning, but also with the industrial transition planning. Yes. So I I think the, you know, what we have today within the state context is to create the foundations for the discussion. And the way we're trying to do that is in the SB100 analysis, we do have multiple pathways that we look at multiple sensitivities, both on the demand side, but also different types of technology combinations.

with

And sometimes we force a solution if it's not cost effective, like let's say CCS or hydrogen might not be cost effective on the merits of where it is today.

Right. But we run those scenarios to look at its implications on other non energy areas. So for example, land, for example, air quality and so on. So we do have that in the SP100 study. And similarly, every integrated resource planning also considers a variety of those scenarios.

So as you pointed out in terms of land, depending on what technology portfolio we pick, even if it's more expensive, the land use for just energy could be anywhere from 1,000,000 to 3,500,000 acres moving forward to 2045. If you have high density resources, including CCS, geothermal and others, you might have lower land impact. But if you are going to depend solely on solar, it could kind of grow the overall land use. So I think we have the foundations of that conversation today amongst the agencies.

And we would love to have that conversation because I think I also heard you ask a similar question when we were discussing the petroleum issues is how are we going to layer this together in a way that we create not just the energy planning, but the overall economic transition planning Right.

And would love to have that continued conversation.

I appreciate that. And some of the technologies are moving in the direction of taking weight 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 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 waste water and what they would return to the community is potable water which is it it has a value in and of itself. And they were interested in working with, some of the ag companies that that have industrial waste water 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 if you if you, develop it in a sequence, it becomes more, 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 fairly quickly. So Yeah. I'm that's it's that's my interest.

And if there's a way and you I just found out today at our agriculture hearing that that UC Merced has a project where they're they've put the solar panels up high and they're they're producing a product below. So you're not stopping agricultural production. You're just doing two things on the on the land at the same time. Which 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, there's shade underneath.

So that's very exciting. But how do we craft solutions that require different inputs from different from the CDFA and then obviously maybe cap and trader or general fund money so that we are sponsoring innovation.

No. I I I totally agree with you, Senator. I think we have over time, I know during these different resource planning exercises, we have included more and more agencies to get their perspective. I think one, you know, point that I would like to put it for discussion as we continue this is what parts of those, let's say, a more expensive resource that have co benefits should be borne by the ratepayers versus their funding comes from somewhere else.

So I think that's an important part to think through.

How do we continue to put downward pressure on the rates? But at the same time, if we see a co benefit in a certain technology, how do we fund that, you know, open so I I would love to continue that conversation.

Great. Thank you so much. Appreciate it. Thank you, Mister Chair. Oh, if I

may so the Public Utilities Commission is actually implementing that program now from Senate Bill 1383. So for biomethane to be procured by the gas utilities. And so we have done the relevant approvals for the first tranches of that. And we are looking very closely at through this being able to study what those above market costs are, because those above market costs are paid for by customers. And so we'll continue to do that work and and share that information.

But we found great partners in, of course, the Air Resources Board, but in CDFA and CalRecycle as part of that effort as well.

Senator Stern.

Thank you, Mister Chair. Appreciate you all being here today and all the collaboration and coordination. You know, when we're we're in the bubble of California, I think things can seem grim. And I know as somebody pays the utility bills in my own house, I get 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 I I did wanna offer the opportunity for you all to put us in a little bit of context here. You know, California is often pointed to is the they they love to out in DC love to say how expensive everything is in California. I was doing some some rough math just looking at our our situation comparatively. Say between ourselves, the Northwest, PJM, and even France and Spain, just to give a general sense.

We're we're our wholesale prices, the twelve month average that I've been able to find is a third of what it is in in the Northeast, in the PJM, where prices have jumped about 75 percent. I've seen, even in the BPA region, we're seeing average, average cost over, $30 a megawatt hour on average. And right now, I think 40,000 people are in the dark in the this awful fire that's going on up there.

And then when you look at say France or Spain, they're up in the more than double our wholesale prices. Have I done my math right here?

Are we is our wholesale power market more efficient than any of these comparative markets at the moment? Maybe you president Mazer.

Our wholesale market is very efficient relative to a lot of other locations. And I think the key reason is that we just have a very effective, paradigm for resource adequacy here in California. You know, we have clarity of roles and responsibilities. We have clear load forecast and responsibilities by the Energy Commission. The procurement responsibilities of the PUC and the utilities, the publics are obviously participating and we're able to get generation on the system.

Resource adequacy program provides some compensation to provide long term incentives in the wholesale market both here in California. And now increasingly to the Western Energy imbalance market and the extended data market is very efficiently dispatched. So we are very fortunate as many of you have talked about in the affordability concerns are are paramount for all of us. We need to continue making that progress. We need to continue getting transmission infrastructure energized.

We need to continue the onboarding of new resources. And I think the points made about diversifying the resource portfolio both on the generation and transmission side make a lot of sense. I appreciate the comment and we are pleased with where the market is performing and we think that's gonna continue to be a feature in the years ahead.

Can you zoom zoom ahead into the not so distant future? I know we talked a little bit, Mister Eto, about the the current savings that we're generating in e dam and and the EIM. But what what could we see with the as the implementation of 08/25 goes forward? I guess I'll I'll just say why why isn't this enough? Why why shouldn't we be sort of satisfied with how things are right now?

And what what more could we save, I guess, for for rate payers in California as we charge ahead?

What I what I was quoting was a study that the California Energy Commission put out. I think it was two summers ago looking at the potential benefits to California from a wider West ride footprint for this extended day ahead market. And at that time based on who they thought would be in and who they thought would not be in, those were they came up with the benefits of a billion dollars a year of additional benefits to California.

Key to our getting to that of course now is this independence governance structure. We've got a number of folks that are going to join in EDM.

Elliot went through the list of the ones that are already signed up and there's a number of them that are on the fence and they've been asking the question we'd like to see this independent governance structure put in place so that we can be sure that our state along with California's interest will be equally well represented through a regional governance framework.

So we see that as critical to be able a secure both those benefits as well as to onboard those that were not anticipated in that CEC study a couple of years ago.

And so could the savings even be greater than what they were projected back in the CEC study? Yes, sir. And so, from whatever the benefits we've seen from the efficiency of our of our current market and the RA market as president Mazer articulated, you think that, expanding into this, into this, sort of multi state governance structure, we could actually see direct pass down to rate payers actual savings in the very near future?

Yes. And that's the promise and and the and the purpose for moving forward into this regional governance framework.

And that's both from avoided costs of our generation but also the ability to sell over gen and move things efficiently between our Both directions.

Both what we don't need and they can use and pay for Yeah. As well as for us to bring in imports when it's when it's a better deal for us than we could do locally.

I just to analogize, I I just stole my, my colleague's power. At least I said, sorry for stealing your power. I stole his charger here. But I think we actually have a seam agreement between us where, when I don't need it, I think I'm fully charged enough. You can just hand him the charger and and it would go to to his system.

To that point, are you encouraged or or discouraged? Do you do you see despite all the, you know, there's a lot of politics at play, obviously, across the country, but just at 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?

I think we've seen a remarkably stable environment. As a matter of fact, I just returned from a quick trip to Washington and meet with a number of the FERC commissioners. They've been very supportive of the work that California is doing. There's a deep appreciation for the progress that the state has made on resource adequacy and transmission planning and interconnection queue reform. There's a reasonable, I think, very positive spirit of bipartisanship and they're watching what's happening in the West.

I think they are paying attention to your point about seams. I think they're very excited to see that we've now got the physics and economics of a wider market paired with the independent governance that the legislature so, you know, presently was able to approve last year. And I think we're now going to see how the topology of the Western market shakes out. And I think our focus at the CAISO is to try to run the market as effectively as possible.

And we're excited to see the regional organization Western Energy get stood up and provide that that that that independent governance footing.

So for everyone who's wary and scared, we there are a lot of saber adding last year, like, we don't wanna become PJM. And we've seen the price spikes over the past year and all the governance challenges and lawsuits and announcements and then think why why why do you all believe that our our case can be different?

What is it about the structure of our market now and and as contemplated under 08/25 going in 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 and governor Erika. You know, I I started with, you know, first and foremost, you know our our energy markets are built on a foundation of resource adequacy. Right? The adequate supply of resource the fact that we're sitting here today six years later with another 36,000 megawatts of generation on this grid and a 16 gigawatt battery fleet that can just work perfectly and absorb extra energy in the day and re inject that in the grid. That's just transformational.

So the resource adequacy situation is really is really foundational. We're also fortunate that we're able as as California in the West to learn from the experience of others. And I think what we've seen is that in you know obviously in in PJM that RTO has that has taken on that risk that resource adequacy responsibility. The load serving entities aren't doing it. It's a fundamental change.

We have we are literally the mirror image of that here in California. Our load serving entities, our regulatory bodies have assumed that responsibility for resource adequacy. And those of us at the ISO are able bring the physics and economics of a wide area dispatch and connectivity to optimize those resources. But we're not the entities substituting their judgment and their responsibility. The second thing is what we've learned is and what I think we're bringing in with with the governance changes.

We're already doing some of this here with with Western Asia markets governing bodies. We've recognized that you want to have strong independent governance and decision making authority. You want to have an outstanding participatory stakeholder process where the stakeholders have their voice but the decision makers are allowed to still make decisions.

And then you want to make sure that the states have a strong voice at the table and that you have a policy mechanism to make sure that the market design is not interfering with the state's ability to maintain their jurisdiction over retail making and retail and and and integrated resource planning. That is the structure that's being contemplated for the regional organization.

Western Energy and Governor Edo and his his fellow governors at the at the California ISO will now have the responsibility over the course of the next eighteen months to make sure that that organization meets those attributes as stipulated in AB 825. The PC will subsequently certify. And and I think that we're gonna be establishing organization that hopefully will have the ability to continue evolving as we've done over the last twelve years and deliver value and enhance our liability and bend the cost curve.

Really exciting. I I am 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 may your work continue and may others join us. Can I just shift real quickly, Mister Chair? Two other quick questions.

One about the strategic liability reserve and one about about Diablo real quick, if you don't mind. On the SRR, it's maybe to DWR, popular topic. We've gone over this many, many years. And, I know we're ending, we're we're nearing the end of the the term of those contracts. They don't expire at the end of this year.

They expire at the end of '27 or

Actually, Senator, you're correct the first time they do expire at the end of this End

of this year. And so the so so far have not used them. To my understanding, at least the peekers, they've not been switched on in any is is that still the case? We haven't actually had to utilize those resources?

For the ones through cooling resources Yep. This year, we have not used them. They were used last time in actually 2024 during the emergencies that were declared. Sure. And then last year was a fairly nice year, so we did not use those resources as per the CAISO.

They weren't called at all.

And my understanding is some of the water permits MPDS and maybe others have not been this extensions have not been sought. I know for Alamitos but potentially also for for Ormond as well. Is that the case?

It it's only for Alamitos. That's the only one that's been impacted. So there is nothing for Ormond Beach to secure. So you're absolutely correct for the Alameda's unit. Their time schedule order has expired.

So because of that, they are limited in terms of the temperature that the water inlet can get to. And because of that, they have to monitor the plant fairly carefully and make sure that they stay within their current limits without that TSO coverage.

Understood. And so but for the other for for the one in Oxnard, they have they they do have that permit That's correct. Timeline extended. So they can, in theory, operate should they should they be needed.

That is correct.

I guess that brings me to my next question on the reliability reserve. I I don't believe we took action on any extension of those contracts in this year's budget. From a operational perspective, maybe I'll turn to you Mister Gunda or perhaps Mister Mains or 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. And we heard from Mister Mainzer, you know, 36,000 megawatts and lots of generation and storage coming online. Do you have a is there an official view or an unofficial view at this point about the the need for those resources going forward?

Yeah. Yeah. Senator, so we have a body, the SACWIS, which is the joint state agency body and director Tesfaye is a part of that. And then there has been an official hearing, if I may just ask her

Yeah, please. That'd be great.

So in July, we did appear before the State Water Resources Control Board to do a presentation of the SACWIS. And in that presentation, we did not request any recommendation to extend the once they're cooling facility extension dates that are in place at this point.

And is there anything left in the life of those contracts to at least be, you know, whatever money we still I think the last time we checked in there was 600,000,000 or so left. I don't know what we sort of spent down. I know there was a it was tricky to exit those contractually. But is there anything we can do to get value out of the remaining portions of those contracts?

I know, for example, at Ormond, there's a 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 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 get a squeeze a little bit more, squeeze something productive out of those investments?

Yeah. I appreciate your thoughts on that. Unfortunately, under our, two things. Under our contract, also under our authority, that is not going to be possible. And also as, executive director testified mentioned, per the, SACWIS decision up to the water board, we do have that binding OTC policy.

So if we were looking at additional, storage or, you know, other options there, we, a, probably don't have enough time to do that before between now and the end of the year. We'd also have to think about in regulatory impacts across the board of what that would look like. So I think there is a lot of binding constraints on the current contract that wouldn't, be flexible enough to kind of have sort of those additional considerations between now and the end of the year.

But nothing foreclosed the possibility of potentially utilizing those transmission resources going forward. Say, you know, not not under the in the context of the SRR or

Correct. Right. That would be out of the DWR's jurisdiction authority.

And it shifts over and and to either into the PUC or you know Like Kaizo and transmission. Right. Kaizo and transmission. But it would just be something that we'll we'll see what the the generators wanna do down there. But I do think there's a lot of interest in the community.

And I would just note that Prop four does also have 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'll be a subject to negotiation here down the home stretch, but there may be this may be the most sort of the a category of one for jump starting that and getting it moving.

Because we do know that's that sub area in the Moore Park sub area is soft. And and I I we've 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 it is on our mind between myself and the Pro Tem's area in the Goleta Substation and then ours in Moore Park. I I know we are gonna need some capacity. That's where we get hit with a lot of PSPS. There's a lot of fire risks. So hopefully, something coming some some new storage or clean generation coming soon to a community near near me.

Lastly, just on the Diablo piece, update on the loan payback, loan repayment. I don't know whose world that falls into. Yep.

Under the year as well.

So I I had heard that the current anticipation is that the the loan is not gonna be repaid in full under the projected timeline that we only get about halfway there from the what did we what did we lend? Do we lend a billion 5?

1,400,000,000.

$1.4?

1.4 was lent out.

So just an update on that?

Yes. Absolutely. PG and E qualified for the civil nuclear credit program under the Department of Energy. So the maximum allowed under that is 1,100,000,000, which we didn't find out about until after SBA 46 had completely passed and, PG and E had applied for. And since then, PG and E has provided some information to Department of Energy.

The initial assessment came back that, they're eligible for 741,000,000 in cost recovery, but that's the latest information that we had from a few years ago. Since then, PG and E is actually that was an estimate. So since then, PG and E has been providing actual data to the Department of Energy for their assessment. So the timeline is a bit long.

The earliest that we could, get funding back through that program is 2027, but it really is dependent on DOE and their processes for kind of validating and auditing the materials that PG and E has provided to them.

I just wanted to note that DWR doesn't have any involvement or oversight to that, but we are obviously tracking this very closely.

Because you're the you're the lender in.

For the state.

For the state. For the state on the 01/04. Right. And and so you're saying that 2027 is the earliest we'd get the July back from the feds on that?

Portions of that current.

And then and but any hope to get even more than that back? That's where you're saying supplemental information has been provided by PG and E to the Federal Government on that front.

Correct. So DOE program could pay out up to 1,100,000,000 but that's up to

But hasn't been that has not been approved yet. Only the seven forty one has been approved.

Those are the preliminary numbers that we have is the seven forty one.

Okay. So so say that that's it. They don't they don't approve any further be you know, beyond the $7.41. We do we eat the rest?

In addition to that, SB 846 provided two additional pathways for cost recovery of the loan. So the second pathway is revenues at the last year of operations. That would be 2029 and 2030 for each of the units and as well as any other federal programs that come along the way they could be used to support paying back the loan.

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

I would just hope for more information in terms of how to get our rate payers the best deal.

I think Mister McNerney might have asked earlier, is this gonna be a benefit or cost? Right now, it feels more like a cost in the near term. But is there 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 is there a hypothetical structure that that in theory wouldn't just, you know, that would actually deliver savings and and meet some of this load growth going forward?

Because you're not just to be clear, you're not projecting that that resource beyond the the the current term in in the projections in your stack? Diablo included in the projection?

So I'll answer part of the question and pass it on

to my colleague. So Yeah. For for DWR, I just want to make sure that we're clear that our visibility into this is only pursuant to the loan. And so our funding obviously came from general funds. And so we don't have a direct rate payer impact, but understanding that many rate payers are also taxpayers.

So I do wanted to Sorry.

Yes. Those Good clarification. Tax payer impact. Right?

Exactly. Yep. So DWR's charge is to obviously be aware of those impacts and to get as much money back to pay repay the state. But in terms of your additional questions, maybe I can turn that over to my colleagues.

Yeah. And an uneasy question and a bit of a hypothetical. No.

It's okay. I mean, I'll only answer the question to the extent I'm able, which is, as I said in September of last year, we did put out some preliminary information, in our integrated resources planning proceeding that looked at, if there was a further extension of Diablo, how could that help support customer affordability? And that would require not doing some amounts of procurement for resources like solar or batteries in order for customers to see those savings.

Now in terms of the structure of what a a potential extension for Diablo would look would look like, I know that is a conversation going on in the legislature Yeah. But Aye, you know, I don't feel comfortable.

No. No. I I I don't expect that. I guess I Okay. I do wanna get clear though.

You're not in in your projections for how we're gonna meet forecasted load growth. Diablo is baked into that or not baked into?

It's not pursuant to SB 846. We assume that Diablo would be closing and continued When?

What's the date? Do we what do we assume under August?

By 2030.

That was the extension. Yeah.

Okay.

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

I can get back to you. We do have that information that was provided publicly and it specifically was showing that there would be components of solar, for example, and batteries that would need to not be procured in order for rate payers to realize the savings of keeping Diablo online.

Understood. Avoided cost, things like that. Okay. Yeah. Mister Chair, Senator Becker had to leave, but he did have two additional questions.

Do you wanna give me that? Would you

Of course.

Okay.

So, CAISO recently published a blog, titled powering the West Future with Demand Flexibility. So this is the demand flexibility question. This is our favorite topic, in absentia, former Chair, Becker. So LBNL projects that by 2,050, California could realize 21 gigawatts of shed potential and 30, gigawatts of shift potential. Can you tell me how, how we're approaching this potential and maybe, more pointedly for the PUC, how do we how are we incorporating, that potential and ongoing reliability proceedings?

So I don't know. Maybe maybe between ISO and do you see on that front? We're a big fan of getting more out of this existing grid and using that demand flex.

And just I would just state, obviously, the core policy decisions about demand response and and load flexibility are being made inside the 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 day hit 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 resource 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 Yeah.

A couple of different things. So, you know, earlier I was mentioning all the new resource generation that has been coming online. But, you know, in addition to that, we have energy efficiency and real time demand response programs also contributing. And so we have those occurring across the state. They include our air conditioning cycling program, capacity bidding program, of course, the base interruptible program that we see in particular from industrial facilities.

In addition to that, the CPUC has two other rule makings that are open at this time. One is, our demand response rule making in order to further expand opportunities for demand response use in the state. And then the second is our advanced rate design, rule making, which is focused more on the demand flexibility side of that.

In order to be able to, for example, you know, we have time of use resource, time of use rates, but being able to get more out of that and be able to send those signals, we're also leveraging that rulemaking, to do our analysis for the SB 57 report which was looking at ways to reduce the impact of large loads like data centers and how can we get demand flexibility out of those resources in order to reduce impacts to rate payers.

I think there's a very exciting opportunity there and a and a different way to think about data centers not so much as a liability but as a potential asset. But I would just say, you know, we we were a big fan of what CEC has done with DSGS and I wanted to know if the PUC's position was still one of skepticism about DSGS sort of I think the official position is that there's opposition to continuing that market beyond the current term.

I think we have an extension through the end of this year under the current budget agreement. But do you have a is there an official position from the Public Utilities Commission on the while you're getting those some of those longer term proceedings going, sort of keeping this what is no longer an incubated market. It's a maturing market growing and sort of ready for the hand off into the market oriented space still official position there?

Yeah. I'm happy to share. So in the demand response proceeding, we did issue a ruling earlier this year that included information about another program as well. The emergency load reduction program, questions for on ELRP as well as the demand side grid support program in order for us to find the best of all of these programs and create products that customers are able to participate in.

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

Leveraging a stakeholder process. So we're able to get all of the different perspectives in play in order to create a product that works for everyone.

Okay. I'm gonna take that as a openness to continuing DSGS. I'm just gonna 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 I I wanted unless you wanna correct me, I'm gonna say you're you're gonna leverage the stakeholder process and stay open minded to to that in the at least the near term.

And I I do I do see the potential for a transition there but I 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 the spot, Mister vice Chair, on that front but you have you have every opportunity to correct me if you want and you're welcome to jump in, Mr. Vice Chair, if

you'd like. But I I think there's a few points there. I'm sorry. I think really appreciate kind of the conversation. Just as the demand side programs as a whole, I think it's a very valuable resource.

I think every study whether it's LBNL, others have shown that there is significant technical potential for reducing the demand and aligning our supply better. I think the question is how do you do it cost effectively has been a significant question. And two, to the extent that there are different programs, how do you harmonize the programs in a way that different programs don't conflict?

I think the question that we have in front of us is given that there is a significant potential, how do we harmonize, you know, the totality of demand response framework, whether it's coming from dynamic rates all the way to emergency programs and building a construct that allows and the agencies are working collectively with the long term proceeding that PUC has to continue to think about the future of demand response that could be operationalized in a way that we provide certainty to the market.

I think it's important that the market recognizes as long as we have private players coming in, but it has to benefit the cost and the rate payers.

And I think the real data gaps that we have is how do we construct a strategy right now.

Okay. We'll be looking to you for that. Last question from Mister Becker here. The PUC reported about 3,000 megawatts of customer sighted batteries already installed across the state and a 100 megawatts of new customer side of batteries are installed monthly, give or take. Numbers may have shifted a bit.

These are resources that Californians are paying out of pocket for 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 see foresee customers being able to participate in the market to provide these resource to our grid?

What what will it take?

Yeah. Happy to jump in there. You know, I I do wanna provide a clarification there. These behind the meter batteries are not being paid for out of customer pockets. They are being funded by a net billing tariff for all rate payers, including rate payers that don't have these, resources on their sites are funding the incentive that the customers that that have these batteries, are receiving.

And so I think it's very important as we do that analysis to always make sure that we are calculating in the very large financial incentive that customers are getting with the net billing tariff and making sure that we're calculating that in before we provide even further rate payer dollars to those customers that have it's a battery and typically solar together. So that is not funded just straight out of that customer's pocket.

They are receiving an ongoing discount essentially to their electricity bill that is being paid for by other customers.

So again Upfront may be funded by the customer, but the through the tariff compensated back through the left billing tariff.

Yeah.

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 incentive takes into or 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?

So we had a proceeding that established that net billing tariff for customers. And so we're seeing a huge surge in that attachment rate. Right? So customers including batteries. So that's been very successful.

Yeah.

And then we will have further studies that are done about, you know, what is the future of that incentive and, you know, how do we build on the incentive.

And to our earlier discussion about just the potential for large load customers coming online and different ways to provide demand flexibility. One of the one of the ideas was, if you can actually reduce load by customer sighting batteries, that you may not have such a big demand on the grid. Is that something that, either is being contemplated both in your shop at the PUC or sort of a more to policy level at CEC as a as a real as a real thing?

I mean, I I know there's certain constraints around what is it general order 91, sort of the context of you pay you gotta pay, you know, for for your impact on the grid. But is that kind of tool on the table?

So Senate Bill 57 passed last which was passed just last year required the CPUC to study that. And so in order to get those benefits, we house that study within the demand the advanced rate design proceeding. And so, we'll be putting out a schedule in the next few weeks about when we plan to have that report completed.

I think an additional thing that I want to kind of layer on top of that is the CPUC earlier this year, approved a tariff structure for flexible interconnections. So a way for these types of customers to get connected to the grid more quickly

Okay.

Very excited.

If they are yeah. And, you know, that was something I wanna be clear. The utilities have been offering it for a number of years, but it was not standardized into the tariffs. So one customer might get it, another customer might not get it, and that makes it harder for businesses to have certainty into the state. So that was a very big development earlier this year to have that put in place.

And that's helping us potentially unlock further benefits by making those loads flexible as well as helping make sure the grid stays stable.

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 gonna sort of track the progress out of that flexible interconnection proceeding and sort of try to feed that into it, as well as but but on on this point around the general order, 91, I mean, is that one of the if if a large load customer wanted to come online, could they bring that kind of offering in theory?

It's not general order 91 but it's it's okay. Yeah. There is a rule 30 tariff that was proposed in PG&E's territory in particular. I think you saw from vice Chair Gupta slides. They have the largest potential opportunity there.

Yeah. And so right now, that is pending. Burke did open this order to show cause where the Kaiso is the respondent there. Of course, we're engaged as well. That might have some overlay on these large load issues.

And so that's something that we're engaging in this fall in order to be able to understand what is the difference between what we're kind of pursuing with rule 30 To get these new large loads connect to the grid more quickly versus what FERC would like us to be able to look into. I don't know if you wanna share. Comment on that?

I was just gonna say Appreciate the the the questions. I think this 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 up 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 process on progress on 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 our of your of your collective efforts is is not lost on us. And I and I think to some of the members earlier points, our ability to translate that back to rate payer savings is gonna be everything because the rage is real still despite all this progress.

And just to say like, we're not it's not as bad as France or Spain or Pennsylvania or Washington doesn't make anyone feel good if you're paying a thousand dollars a month on, you know, and you're making $70,000 a year. It's it's still totally unacceptable and so we're going to keep working with you all to bend the curve.

Mister Chair, I defer to you and there goes my long winded there's my long windedness.

Thank you, Senator. I wanted to just follow-up a little bit on the questioning on the Diablo Canyon loan and just get more insight as to as to what what what's happening there. You know, it was taxpayer dollars. I mean, obviously, we're being asked to make various changes involving issues related to the utilities.

Thank you, Senator. I wanted to just follow-up a little bit on the questioning on the Diablo Canyon loan and just get more insight as to as to what what what's happening there. You know, it was taxpayer dollars. I mean, obviously, we're being asked to make various changes involving issues related to the utilities.

I understand we didn't know about the exact amount that we're gonna be getting, you know, they're gonna be getting from the feds but this was a direct loan from, from the General Fund that's—we were told this can be fully paid back.

Can, can you give us a little more insight as to how we should be thinking about that?

I'll take that. Thank you, Senator—or Chair Allen. It is a difficult situation, as you noted, that SB 846 was passed very quickly, sort of under the same emergency auspices as the rest of the strategic reserve. So, there was some urgentness at that time to make this happen for a couple of reasons because the, you know, it was about to retire.

There was going to be a very large federal process with the Nuclear Regulatory Commission, as well as pretty urgent needs if the unit were to be extended to procure fuel and other necessities.

So, understandably, the Legislature, I think, did an incredible job moving it forward, but it was operating under not all of the information was available at that time. So, it was operating under, I think, the best information available at the time. So, what we unfortunately have learned since then is that the qualifications for the DOE program was only up to $1.1 billion.

If there's any silver lining, Diablo Canyon was the first and only power—or the first power plant—to actually qualify for that program that was created by the Department of Energy. So, it was their first foot forward and the audits are still happening.

So, we haven't gotten confirmation on whether 741 is the limit or they're allowed to go up to the 1.1 billion. So, that is still pending.

Why, why wouldn't they be allowed to go up to 1.1 billion?

I'll probably have to defer to PG&E for all of the details. But from the reports that we've seen, the DOE and PG&E had set together to look at what costs were eligible under the Civil Nuclear Credit Program. So, per the DOE determination, they were going to allot $741,000,000 to the cost that PG&E have incurred.

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

Yeah. So, the available—amount available—under the DOE Civil Nuclear Credit Program is up to 1.1 billion n additional costs. So, it was up to PG&E to show those costs to the Department of Energy, which they did. But as the Department of Energy reviews those costs, they're allowed to use their own metrics and per their program to determine what costs are eligible.

So, in the negotiation, the end result of that was a forecast of $741,000,000 eligible out of the $1,100,000,000. Again, PG&E could, if they have other cost they've incurred or if conditions have changed, they can go back to the Department of Energy and resubmit the claims. But DWR isn't privy to that, and it would be up to PG&E to approve that to the...

Was it always anticipated that that this is gonna be fully covered by these federal funds?

I think the expectation under SB 846 is that it would be covered under the federal funds but also the other two repayment pathways, which would be the revenue in the last year of operations, as well as any other federal programs that PG&E would be—I should say Diablo Canyon would be—eligible for.

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

Per the legislation, I think it was—I, I wasn't privy to those discussions, but I think per the legislation, there was 1.1 allocated to cost but then also a $300,000,000 amount that was for performance-based disbursements. And so, that was related to PG&E being able to operate Diablo Canyon reliably. And so, that 300,000,000 with the 1.1 is what created the 1,400,000,000 loan to PG&E.

Okay. Well, I, I'm gonna 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, you know, the process by which DWR assesses whether it will be, you know, whether response to a PUC request for procurement of long lead time resources and, and you know, what sort of considerations DWR uses to inform its decision and may—and maybe some updates you can you can provide us. What's coming out of that letter?

Absolutely. So, DWR is working very closely with CPUC staff. We have very regular, almost weekly, meetings, to understand some of those complicated issues in developing the program guidelines, and we have specifications and specific requirements between both DWR and PUC for its regulatory process. So, DWR, before responding to the letter, we want to make sure that we're able to meet CPUC's request successfully and provide into the PUC's proceeding the information that is needed to move forward.

There's a number of fairly complicated regulatory, legal, programmatic issues that we're discussing at the staff level, but I'll give you maybe two examples. For example, I think the corollary to this is a—we're a sister agency to the CPUC. The procurement that has been done up to this point are from the PUC's low-serving entities. The IOUs are fully regulated by the CPUC.

So, a lot of the precedent and the examples we have of procurement are by regulated entities and how they perform and show up and what they provide to the CPUC.

There's gonna be some adjustments in how we engage with the PUC as a sister agency rather than a regulated entity. Also, in Water Code 8082-O, it does request that the Commission, in consultation with DWR, shall develop and adopt procedures and requirements that govern competitive procurement by an obligations and cost recovery. So, it's a, a way of saying that, yes, more rules need to be developed in order to oversee this procurement and the solicitation and what the program rules and etcetera would be.

So, those are the things that we want to discuss so that we can go into this understanding what all of the obligations are, what we need to provide from DWR to PUC, PUC to DWR, before we fully engage. So, we would like to do that assessment, have a clear idea of what those implications are before jumping in and agreeing.

But you're correct that it's been a while and we are working with staff closely on all of those questions.

Okay. Do, do you guys want to respond at all to? No? Okay. Okay. Interesting.

I'm interested in some of these jurisdictional issues. Alright. Let me also just ask. I mentioned in the opening comments a little bit about, you know, the, 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...were assessing the, the potential back from the federal tariffs, rollback attacks credits in the recent federal legislation.

Obviously, you know, some, some good, optimistic information you presented in, you know, earlier. But I, I don't know, you know, how, how, does, how do these federal headwinds fit into all the things that you were mentioning, especially with regards to the, the need to potentially, you know, support ensuring an eligibility with the sunsetting federal tax credits?

Yeah. Chair, thank you for the question. I think two kind of part answer. One, we started kind of some analysis collectively on understanding what the reduction of tax credits or elimination of them would do to the resource build. And I think, you know, it's, it's certainly adds more cost to the build out.

So, the Executive Order M3325 really kind of, you know, from the, in the last year, is really kind of putting all of us in high gate to think about every, you know, administrative action we can do to help support, you know, the development. What we hear, you know, from developers is a lot of motivation. A lot of them are really interested in ensuring that they get those, you know, benefits of the tax credits.

I think as a process, we are coordinated to support collectively any request for that comes from the developers and to the extent that we have administrative actions, we are gonna use them in a point by point.

Okay. Yes, sir.

I would just add that obviously, some of those actions are adding financial friction to the system. So, we're doing everything we can to take procedural friction out of the system. The queue reform efforts, the coordination with the state, you know, last year, knowing that we wanted to get as much on the grid as possible as quickly as possible. Just last year in 2025, I think we had over 7,200 megawatts of new resources on the system. This year, another big year.

So, right now, there is a healthy supply curve of resources that are still available. We're working them through the queue, making sure we have transmission deliverability, and then getting them to load. But you're absolutely correct. You know, the back end things will start to get a bit more costly. So, everything we can do within our power to remove friction and to onboard resources and then dispatch them and operate them as efficiently as possible are intended to, you know, just counterweights to some of that pressure.

Yeah. And I just wanted to add, you know, the Governor put out an executive order related to, when these actions were taken related to the federal tax credits. Right? And so, we have had a staff group that includes CEC, CAISO, CPUC, also the Governor's Office of Business and Economic Development, where we have engaged with both developers, as well as the transmission entities that are connecting them to the grid, in order to be able to find opportunities to speed things up.

In addition to that, I mentioned the 6,000-megawatt procurement order that the CPUC put out in February and those are resources that need to come online in the new—near future.

So, you know, by 2030 and 2032. So, helping us to get more of these resources online that, procured under contract, that are able to take advantage of those federal tax credits and then those dollar savings are passed on to customers.

So, couple of different things that we've done to be able to mobilize, understand the challenges that the developers are facing, and leverage our staff coordination through the TED Task Force—Tracking Energy Development Task Force—to really have that hands-on approach with developers to make sure that these resources are coming online in a timely fashion and making the most of the federal tax credits.

Yep. Yep. Okay. That's helpful. Alright. Thank you. I, I really appreciate it. I was gonna go more into Trump fee slaughter but I, I, I wanna talk to you about that later as well. So, appreciate your, your, your great presentation. Thank you for all the thoughtful answers to the members' questions as well and the dialogue, and love to give the public the opportunity to come to the microphone and, and weigh in.

But I appreciate everybody's participation and all the work that, that is reflected in, in your presentation.

Chair and committee, thank you so much for the opportunity.

Thank you. Mr. Smutny.

Thank you. Thank you very much, Mister Chairman and members of the committee. Jan Smutny-Jones with the Independent Energy Producers Association. This is actually a historic day. It's the 50th anniversary of the Private Power Act of 1976, which created the private power producers, which has matured in many, many, many ways over many years to what it is today, which you heard we have a competitive market for resources, which are getting California rate payers the best deals they can, and they're all predicated on contracts.

And so, I am here today just to basically ask we are hearing rumors that there may be something afoot to deal with wildfire liability. The Earthquake Authority did a great job in the study they did, and particularly, Pathway Three. That's there. I am not in the room. It's way above my pay grade.

I have no idea what's gonna be put forward. But our industry, our clean power industry, is based on contracts with, with financially sound counterparties. And having gone through two different bankruptcies over the last twenty-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, is issue that's do—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 the PG&E bill is tied to fire, either hardening the system or paying for fire victims, and I guess, in my understanding, that that is 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 your—to, to keep on the topic on this through the end of session. Thank you.

Yes, sir.

Thank you, Chair Allen, Senators. I just wanted to make a couple comments. Will Abrams from the Utility Wildfire Survivor Coalition, and I just wanted to sort of put this through the lens of some incidents that happened today. So, today, Southern California Edison was found responsible for the Eaton Fire. And so, there are communities that know who burned their house down, who burned their communities down.

And, I just think it's important to think about the things that were discussed in this important committee hearing through that lens. When we're talking about affordability, certainly those folks have additional affordability challenges to recover from these fires. Second of all—and I know, Senator Allen, this is near and dear to your heart, and I understand that.

I, I also wanted to make sure that we're noting that while affordability through a wholesale lens is one thing, as Senator Stern mentioned, affordability through a retail lens is something completely different, and California is the highest energy rates in the Continental US. So, we need to keep that in mind as we're talking about these differences here.

And I would just, as was stated before, as we're thinking about what's coming out of the SB 254 study, and hopefully those are things that are good for the folks, the wildfire survivors who are recovering, but we hope that what that is, is tying the utilities' return on equity to our public interest outcomes. So, as they drive more affordability, they should be getting a higher ROE, but only if they drive more affordability. If they pay their victims fully, fairly, and timely, great.

Let them get some ROE.

As they are driving our public interest outcomes in terms of reliability, let them earn some ROE. There are ways to align incentive structures so we are all moving in the same direction. We do not have that today, and it is my hope because we are running out of the road and we don't have any more room to travel that whatever comes out of this study aligns those incentive structures with our public interest outcomes. There is no other path forward.

So, thank you very much for your time.

Good afternoon, Mister Chair and members. Adam Hatefi, 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. We do not have that in terms of resources that are under RA contracts. The CPVC'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's 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. In 2027, 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.

Good afternoon. Jeff, Jeff Donovan from Glow Strategies, and I'm a former official with the International Atomic Energy Agency. I just have a few comments to make. So, thank you, Mister Chair—Mister Chair and members. What kind of electricity system do we actually want for Californians?

For too long, we've debated one technology at a time. We need to step back and ask a bigger question: is our electricity system delivering affordable, reliable, and resilient power for Californians? Right now, many Californians would say it's not. Regional markets like EDAM can improve coordination, but they can't replace dependable power produced here in California.

We can't assume electricity will always be available from neighboring states when they face the same pressures from electrification, AI, industrial growth, and extreme weather events. California has invested heavily in renewables and storage, yet electricity prices remain among the highest in the nation. That tells us that simply adding more megawatts is not enough. We're not just paying for electricity. Californians are paying for an increasingly complex system to deliver it.

Generation, transmission, distribution, storage, backup capacity, imports, and other reliability services. That's why the cost of the system matters just as much as the cost of generating electricity. And by the way, the CPU—CPUC's—own modeling, which wasn't mentioned in this discussion, found that keeping Diablo Canyon online avoids between 600,000,000 and $3,700,000,000 a year in statewide elect—electricity—system costs. And that's on the low end of various studies. So, if the current approach hasn't delivered affordable electricity or the reliability Californians expect, why would we keep doubling down on it?

Not all megawatts provide the same value. We need to stop optimizing individual technologies and start optimizing the electricity system. The goal should be simple—build the electricity system that delivers the lowest total cost while improving reliability and resilience.

Demand is growing from electrification, AI, advanced manufacturing, and water infrastructure. California will need much more clean, dependable power. That means preserving Diablo Canyon and planning now for the next generation of clean, firm energy, including advanced nuclear technologies designed, engineered, and built here in California. So, the question is no longer simply what technology we should build next. It's what electricity system will deliver lower bills, greater reliability, and long-term resilience for Californians.

Thank you.

Thank you, Mister Chair and members. My name is Adrian Covert, today representing the Bay Area Council. Just wanna make a couple observations about the hearing. One of them was the importance of, 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.

Earlier this year, MIT came out with an independent analysis estimating that keeping Diablo Canyon online beyond 2030 would, would create a value for rate payers up to $1.3 billion annually, which is consistent with the CPUC's findings from last year that it would create a value of rate payers to rate payers of about $990 million. That report was referenced during the, during the testimony, but I didn't 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 gonna see, I think, is, is particularly important to consider. Particularly, the—about 26% of that load growth that's gonna come from electrifying buildings. Now, a lot of that's electrifying heating and the CPUC has estimated that's gonna 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 it 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.

That's a good point. Alright. Thank you. Thank you, everybody. Thank you to our sergeants and our staff for helping to put this together.

Very formative. Lots of—lots to think about. Great public comments as well and, and we'll, we'll hereby adjourn this hearing. Thank you.