Senate Standing Committee on Energy, Utilities and Communications

Senate Committee on Energy Utilities Communications will come to order. Good morning. Welcome. It's been five years since California experienced unexpected rotating outages. In August of 2020, heat waves across the area affected the amount of electricity supply, but also increased demand, primarily because of air conditioning.

At the time, our state's largest electric grid operator, Cal-ISO, implemented rotating outages in order to prevent cascading blackouts on the system. Well, outages range from eight minutes to 90 minutes.

They raised concerns from many, including the Legislature, about the need to reduce the risk of future outages due to supply constraints and high demand, especially during extreme weather events.

Additionally, three years ago, based on continued concerns about near term reliability, the Legislature approved SB 846 which authorized a five year extension of the state's last operating nuclear plant, Diablo Canyon power plant, whose two generating units were scheduled to be decommissioned in 2024 and 2025.

Today's oversight hearings intended to provide Members of the Committee and the public with an update from the state's energy agencies and the state's principal electric grid operator on the efforts to address electricity reliability and an update on the requirements in SB846 related to Diablo Canyon, including the billions of dollars in reliability related programs and policies.

We all know that electricity outages, depending on their scale, duration, frequency, can be life threatening and paralyzing for affected customers. While electricity outages can be caused by many issues.

My son let me know there was an outage at our house last night in Menlo Park, including distribution equipment failures or as a safety measure for like public safet depower shut offs. Today's hearing is focused on managing electric grid supply and demand, particularly given extreme weather events.

This is particularly salient as we transition to a zero carbon energy future with additional variable energy resources including solar and wind on the grid. Affordability is also of paramount concern for the Legislature this year. Our efforts to address affordability and reliability must help do really three things. Number one, grow our energy resources.

But they should also help share energy resources in a larger market and shift demand for resources to maximize the available capacity on the electric grid. So I think we'll hear about all three of those things today. Grow, share and shift.

I think we'll hear some good news from our agencies, including the record amount of clean energy resource procurement. Grateful for everyone who's been working working on that.

Last year, nearly 7,000 megawatts of renewable and zero carbon energy resources, a tremendous accomplishment and the growing role of energy storage in helping to better integrate renewable energy resources on the electrical grid. Since 2020, California has added over 12,000 megawatts of storage, a nameplate capacity, a record and growing amount.

And it was just at the National Caucus of of Environmental Legislators in Boston talking about how the cost of storage has gone down significantly thanks to all the investment and deployment, especially from California. Another sign of good news though we remain cautious this summer there have not been any emergency alerts issued by caiso.

We're still in the midst of summer session. We'd like to hear from Cal-ISO about any anticipated issues the remainder of the summer. We're mindful that in previous years, August and September really have been those the more challenging months due to limited hydropower resources and also reduced solar output during peak demand times.

While the challenges to ensure reliability are several, I think we'll also hear about growing and deepening coordination among the agencies in Cal-ISO and load serving entities to better prepare the electric grid for our clean energy future.

Particularly eager to learn about the continued integration and deployment of clean energy resources to better serve the net peak load as well as load shifting opportunities to reduce demand during peak times. That shifting demand, known as demand flexibility, is a solution that reduces cost by maximizing the use available capacity.

It's about recognizing that we've most we have the power we need about 99% of the time.

In fact what's come up recently is we're really we're only using about 45% of our grid's capacity at most times outside of a small number of hours, anywhere from 20 to probably 50 hours a year where we really have strain on the grid. So demand flexibility can help unlock available capacity to allow for demand growth.

We need to connect new affordable housing, deploy electric vehicles, electrify buildings and new demand growth to support economic development. And the shifting hardly noticed by customers supports our climate progress, lowers energy bills and improves reliability. On the sharing front, love to hear from our panelists as well.

Sharing energy resources in a larger market was the subject of an informational hearing of this Committee on the Pathways Initiative to develop a regional energy market.

And then of course we have legislation this year and many people believe that such sharing of resources helps California ratepayers receive the benefits of a wider regional footprint of available resources to serve lode.

Finally, legislation adopted in 2023 AB 1373 Garcia the Legislature authorized Department of Water Resources, if requested by the PUC to serve as a central procurement entity. Since last year's hearing, the CBC has adopted a decision identifying procurement of long lead time resources including offshore wind, geothermal and eight hour storage. We'd like to learn about next steps there.

We also understand demand for electricity is growing, particularly as we electrify transportation and building. In addition, the growing development artificial intelligence is further increasing electricity demands needed to operate systems. So where are we in our efforts to ensure reliability?

What's our game plan to ensure that reliability remains at the forefront of our efforts along with affordability as we transition to a zero carbon future? Of course, we can't ignore the changed landscape at the federal level and its potential impacts on reliability, so we'd like to hear about that as well.

This includes the impacts from the uncertainty regarding federal tariff policies and the recent federal legislation to roll back clean energy tax credits, particularly for solar and wind and other low carbon resources. To the extent there's any update to share regarding the impacts of federal policies and actions would be helpful to hear them today.

Now let's hear from our energy agencies, the California Energy Commission, California Public Utilities Commission, as well as the Department of Water Resources, and our California Independent System Operator, Cal-ISO.

They will share the overall picture leads to reliability and then pivot to specifically addressing requirements from SBA 46, the legislation authorizing the extension of Diablo and Canyon nuclear power plant. On that note, I want to share.

We're joined today by Senator Laird, whose district is intimately affected by Diablo Canyon power plant, and he's a strong interest in the update of SB846 as he helped negotiate that Bill and expect he'll have many questions to raise related to legislation. Welcome. I welcome our presenters here up to our table. Yes.

Mr. Chair, Would it be possible to make some opening comments? Thank you. While people are being seated, first, I really appreciate the fact that this hearing is being held and I appreciate the ability to participate.

And as you said, I have the Diablo Canyon power plant in my district and I was one of the lead negotiators on Senate Bill 846 in 2022.

And tangentially, I also have battery storage and the major fire that existed in the when we did the proposed extension of the life of Diablo Canyon, the negotiations centered about two things and the first one was does California need the baseline load from Diablo Canyon over the proposed period of extension?

And we actually, as part of the Bill, you know, required the regular reliability reports, in part that we're going to hear a report on today. And I think the big thing is where are we? The chair just mentioned the amount of energy that had been developed.

I believe it's more than was sort of projected at the time the deal was done. It's quite likely less Than is it would displace the Diablo load. But that's the question that I think we all want to get at in this.

And also you mentioned the 12,000 megawatts of battery storage since 2018, which I think is one of the reasons we're doing very well. But there have been real issues with battery storage. I know I'm doing a Bill on safety right now and that's something that might come up.

And it should be noted that Senate Bill 846 was approved on the first day of a 10 day heat wave that tested everything we had just discussed in the debate. And it was only a governor's alert that Cal ISO didn't know about when it was first done. I think that sort of saved the day in that moment.

And so the baseline being issued, the second one is where are we in regard to the different provisions of the Bill and implementing them toward the extension of Diablo Canyon? And I know there are those that are beginning to talk about what happens after 2030.

And there were people that suggested that I might want to ask a lot about that. But I think that in General is a future discussion, although the report we get will start to reflect on that.

And my position when a local Board of Supervisors want to advocate for an extension past 2030 is we should see if the conditions that were set forth in Senate Bill 846 are satisfied for five years before we start talking about anything else. And that, I think is what the second part of the hearing is about.

Because we have a whole issue about the loan being a different level than what's been appropriated and who's going to be on the hook for that. We have the issue of seismic safety and tests that aren't totally done yet.

We have the funding of locals because the unitary tax was amortized over 40 years and now it's been extended. And there's no provision for what happens to the funding of locals during the extension period. We had a firm ending date of five years because we wanted to be ready with the transmission for offshore wind coming on.

That's been delayed a little bit. How does that factor and everything? The waste storage is an issue and it was a provision in the Bill and the disposition of the 12,000 acres of land that surround Diablo Canyon. That is the biggest section of undeveloped land except for maybe Big Sur that is in the region.

And there's been a real goal. The locals voted to try to protect that land. And those were parts of the provision of the Bill as well.

And part of the deal that didn't make the Bill, but was an agreement was that the mitigation fees for once through cooling, if there was an increase, they would be dedicated to the land acquisition.

And now because of our success in transitioning a few of the fossil fuel plants, the revenues from once through cooling are not what they were when it was first negotiated.

And there is still a question about how that commitment is going to be made, made good and how that fits into the overall scheme of those mitigation fees and where they go.

Because ironically, I negotiated when I was resources Secretary the notion that those mitigation fees would go to Fund the state's oceans program and if there were any excess over the oceans program, they would go to land conservation along the coast.

And now that fees are shrinking a little bit, where we wanted to dedicate any extra fees from Diablo Canyon to acquiring the lands, there's a question about whether the oceans program will be adequately funded and if so, a question of how the Administration and Legislature will make good on the commitment to try to have that land preserved and have the money there.

So all those I was going to say, to name a few, because there were other provisions, believe it or not, in the Bill.

But I think when it gets to pge, we want to know where it stands on each of those because before anybody talks about anything else, let's know that we have met the conditions of Senate Bill 846. So thank you for the chance to make introductory comments.

Well, thank you for that, Senator Laird, and it's great to have your expertise and your presence because of your involvement in 846. And I'm sure we'll get into it and we'll get into it with PG&E as well.

But in the loan, I was Chair Budget Sub 2, which Senator Allen now chairs, and raised concerns at that time about the loan and whether the loan would get paid back because if it does not get paid back, it's going to fall on taxpayers. So that is of paramount concern for me as well.

With that, let's go ahead and we'll start with Vice Chair. Well, actually, we'll share with. Okay, excellent. We'll have CPUC President Alice Reynolds. Welcome, President Reynolds.

Thank you very much. And good morning, everyone. Good morning. Chair, Vice Chair, Members of the Committee. I'm really pleased to be here today. These are important issues we're going to be talking about. Just in the interest of time, I'm going to introduce the panel.

I have my colleagues, Siva Gunda, Vice Chair of the California Energy Commission, Elliot Mainser, President and CEO of the California Independent Center System Operator and Delphine Ho, Deputy Director for statewide energy at the California Department of Water Resources. So we have a joint presentation. We'll be shifting back and forth.

So I wanted to start with a very brief introduction of the various agencies involved in the electric sector regulation and market operation. You can see on the first slide there are five prime. Let's see if I get there. Oops. There we go.

Five primary energy related agencies, those represented in the panel today as well as the California Air Resources Board. We've listed some of the main functions in the overall energy supply planning process. So we have CARB setting the requirements for economy wide GHG reduction, including the targets for the electricity sector.

We have CEC doing load forecasting so we're ready for variations in load and playing a role in overseeing the renewables portfolio standard. CPUC conducts electricity supply and reliability planning so we're ready for future conditions and so we can cost effectively supply California with clean energy. And then the CPUC also has a role in RPS oversight.

CAISO is our transmission operator running the wholesale. They run the wholesale electricity market and they conduct transmission planning. DWR has electricity supply backstop responsibilities including the electricity Strategic Reliability Reserve Program and managing the Diablo Canyon Extension Fund. That's an oversimplification, but that gives you a high level picture of what the various agencies to. I'm now going to shift to the Vice Chair.

Thank you, President Reynolds. Good morning, Chair, Vice Chair and Members of the Committee, thank you so much for having us today for this hearing.

So I, I'm going to go through a brief history on the greater liability events that we've seen in 2020 and 2022, the actions that the Legislature has taken and the work that the agencies have collectively been incorporating to address grid reliability on an ongoing basis.

So just to kind of go back to 2020, Chair has mentioned this at the top of the in his opening comments about the outages we had in 2020. We are right, right there. It was August 14th and 15th of 2020 when we had the rolling outages.

And you know, just to remind ourselves August 16th was okay, but 17th, 18th, 19th, the three days were extremely tight and there was collective actions taken to bring about 2 to 4,000 megawatts to get through that week. And much of those we used to call dialing for megawatts.

We called a lot of people, including defense departments to unplug ships from the coast. So there's a lot of activities that were done the following week to keep the lights on and ensure that the supply was there. So between those two events, I want to point out a couple of pieces.

When we plan, we plan for what Is called a 1 in 2 demand forecast. So we look at a distribution of forecasts for any given year and then we look at the median. And we start with the median.

And with the median we kind of create a little bit of a cushion on the top of that for demand deviation and outages. That's how we plan. In 2020, the deviation of demand from what we were planning for was approximately 8%. It was between 8 and 9%. So it was significantly higher than what we would have expected.

And in 2022, that was almost 12% percent at 52,000 megawatts. So just want to make sure that I flag that when we were looking at the forecast itself, the cushion we were planning was not sufficient to absorb those events because they were so outside in the, in the tails of the distribution.

Second, in 2020, obviously we had the rolling outages. 800,000 customers were affected. It was a few hours, but still they were affected. And those an important aspect for us to consider as we move forward in 2022.

Because of the Amber Alert that was sent and the subsequent 2,400 megawatt instantaneous drop, we did not have to go into that, but we were very close in 2022. On September 6, in terms of key lessons in 2020, just to have you focus on the charts, the top chart, it's really around net peak.

So this is when the solar would go down. So you lose all the solar production on the grid, but the air conditioning load is still continuing into the late evening. And we did not have enough supply to make sure that we're substituting for solar.

And that was the main issue that we had to resolve and that was their focus on net peak. So the definition of net peak is you take the total load on the system, remove solar and wind and say, what else do you have to meet with the rest of the demand?

So we recognize those evening hours, the net peak hours, as the most important for us to think through. So to the points that were made by the chair and President Mainzer is going to talk about this, we have had significant battery storage capacity that's come online which has been instrumental in dealing with that evening peaks.

And on September 6, you know, the slide, the chart below, you know, it was a historic amount of load on the system. And that load we were inching towards a 53,000 megawatt load.

And if not for the actions on the demand side, that were taken and the Amber Alert, it would have been a very tough day to move forward. Before I move into the next slide, I just want to make sure that I give this context to the Members.

Just a year later, on September 62023 the peak load on the system was 33,000. So we're talking about a 20,000 megawatt shift. And that oscillation and that volatility is what makes this great planning very hard. And you can definitely plan all the way to 53,60,000, but it comes at an expense to the ratepayers.

So the importance is, how do you solve for this in a way that we can make sure we have safety, reliability, and affordability.

So then kind of taking a step on just building out what happened in 2020 after we came out of that event, one of the most important things we realized was much of our planning has been based on historical projections and history, and that was not sufficient.

As climate change is accelerating, we needed to really think about how do we take the climate impacts and plan into it. So taking the lessons from 2020 of the extreme heat event, we started baking in how to plan under such conditions. We went into 2021 feeling a little better.

But as we all know, one of the core things that happened in 2021 is bootleg fire in the transmission line coming from Oregon into California was stopped for a little while. It was 4,000 megawatts. And as a state, we rely significantly on imports.

And knocking out that line was this 4,000 megawatts that Caiso had to make up instantaneously. So we looked at the fire risk. So we started with heat. And then the other piece that we also observed in 2021 and 2022 was the historically low hydro conditions. And for the first time, we have oral not producing in those events.

And so we needed to really think about the coincidence of heat fire and catastrophic fire. So we needed to think about all those things as important elements.

The other part that we were dealing with in 2021, coming off of COVID or going into Covid, really is about supply chain delays and also some of the tariffs that were introduced in 2020.

So taking all those pieces, you know, many of the hearings we've had at the time was really how do we acknowledge and understand the impacts of these uncertainties and how do we plan the grid in a cost effective manner?

So thanks to the Legislature, a number of tools were given to us, including the passage of 205 and 846. So the main pieces that we have been working on since 2022 collectively. And I want to just not only acknowledge our collective work here, but just the staff.

There's hundreds of staff that work collectively between CAL-ISO, PUC, CARB and CEC. And there has been incredible amount of work on this and a lot of times it's beyond the 40 hour job that they have.

So I just wanted to acknowledge the staff and their hard work and our sister agencies, whether it's the fire Department and their ability to support us. It's been a statewide effort and I want to just acknowledge that. So in terms of the actions, there were three primary buckets of actions we've taken. Looking at the legislation and all the support that the Legislature has given us.

It's really improving our grid processes, planning processes, processes that included how do we best make sure that we reflect climate change uncertainties around electrification into our forecasting processes and make sure those follow through into the subsequent downstream processes, which are integrated resource planning, resource adequacy, transmission planning and the distribution planning.

And just want to acknowledge there that based on all the work, PUC has made some incredible amount of procurement which President Reynolds is going to talk about. Second part of that is planning and procurement, but making sure those are actually built and energized.

And this is where CAL-ISO has taken a tremendous amount of work in thinking through how do we energize these resources, interconnect them, but also collectively as agencies we have the TED Task force are tracking, Energy Development Task Force and also a transmission forum where we're actively tracking the development and making sure we are addressing the bottlenecks and finally really thinking through where we plan, we build, but understanding there are uncertainties and curveballs that we may have to deal with, really thinking about how do we characterize the extreme events and how do we plan for them.

And demand flexibility has been an important part of that strategy. So as we go into that then just we've touched upon the Diablo Canyon power plant and we can definitely take some questions on this. A part of the CEC task on this was twofold.

One was to establish the prudency of whether Diablo Canyon power plant extension through 2030 would be beneficial for grid reliability. And based on the analysis, the core pieces that we've taken there are what is the forecast looking like and what sort of uncertainty do we have to bake on the demand forecast?

And under those conditions, do the supply that's anticipated through the procurement orders and baked in the supply delays, construction delays, can we actually get by without Diablo and the Commission staff. And then finally Commission adopted this determination that it's prudent to absorb those uncertainties, that we continue the operation of Diablo through 2030.

And the second aspect that we were asked to look at as the CEC is whether we can have clean energy alternatives in a cost effective manner substituting Diablo Canyon. And the specific ask from the Legislature was can we bring in alternate resources before Diablo actually retires? And the determination was we could not. We could not do that.

Given the problem statement that a part of the reason why we need Diablo Canyon is the delay in construction. We did not want to go out and compete with other LSCs who are also procuring the same resources.

So that was the determination and those two were passed on to the CPUC for further implementation of the Diablo Canyon extension. So taking all that, how are we doing? And the answer is in the data is we have made some significant progress and the results are really showing.

What I would like to kind of bring your attention to are the bottom two rows on this and those are Caiso wide emergency alerts compared to the rest of the west or the RC West. And what you see there between 2020 and 2022 is essentially the Caisos emergency alerts were almost half of the rest of the West.

But as you move forward to 202324 and 25, the number of emergency events that we are having in Caiso have significantly dropped. And I want to note this, that this is a West wide balance. There are times when we lean on our colleagues and neighbors in the west to support the grid in California and vice versa.

There are times that we have in the last couple of years supported the rest of the west in ensuring that the lights stay on for all of us collectively. So with that I will pass to President Mainzer for 2020.

Oh, sorry. Apologies. I was trying to hand off the responsibility sooner than I should. So I'll start on the 2025 and I'll pass it to Mr Mainzer for his slides. So 2025, just an outlook going into the summer.

We're already in August and the next 10 weeks, you know, going into, we think about going all the way through October would be kind of the most important time for us. The agencies have adopted the word cautiously optimistic.

So we are cautiously optimistic about the summer based on where we are in the build outs under current planning standards, meaning the 17% PRM that we currently adopt. And also there are additional provisions for higher RA procurement which President Reynolds will touch on in her remarks.

We are looking really good even under the conditions that we've experienced in 2020 and 2022. We don't expect any shortfalls on the grid. This is because of the storage capacity that has come online. And also the market and supply chain uncertainties continue to remain elevated.

So we solve for one problem and another problem comes in now that the federal Administration with the tariffs, kind of the nature of those supply chain issues have morphed slightly into a different frame. And still a long lasting west wide heat wave coincident with potential fire could still put us on the edge.

And that's something we want to watch out carefully. And in terms of what do we do under those extreme events, thanks to the Legislature we have about 4,000 megawatts of contingencies in our pocket. Significant part of that is the ones through cooling power plants, about 3,000 megawatts of that which is managed by DWR.

And the rest of it is both non ratepayer programs and ratepayer programs fundamentally demand flexibility. So this is the tabular form of the same analysis. A couple of points I want to showcase here. The first row in the table which says the total demand.

Want to observe that the total demand on the system, on the CAL-ISO system has not significantly or meaningfully increased over the last five years. That is really because of the uncertainty around COVID.

We've lost, you know, significant amount of demand during COVID There has been a lot of migration out of California from an econ demographic point of view. But we're seeing those trends slowly reversing.

So overall this is the flat period of our of the decade and we expect the demand to start going up as we move into the rest of the decade.

But what I want to focus on is the next line on there for practically the same amount of demand on the system the overall available net qualifying capacity of resources have gone from 53,000 to 63,000. Right. So that's net qualifying capacity, that's not actual nameplate. Nameplate is almost double.

So we are looking at that 10,000 megawatts really supporting the system. But want to go down all the way to the last line, you know, and looking at the 2020 and 2022 events, we're still looking good even under those conditions.

The one thing that would put us under tightness again is a westwide heat wave coincident with a catastrophic fire. And that's an event that we cannot currently plan for. That will be a scramble in real time. So this is the list of all the contingencies we have on the system which I just mentioned.

And we can answer more about this in the Q and A with that, it is time to actually give it to Mr. Mainzer.

Thank you. Thank you, Vice Chair. Well, I'd also like to thank the Chair and the Vice Chair and the Members of the Committee the opportunity to be here today. I'm just going to offer a few more points just to emphasize some of the elements that have already been spoken about.

But certainly the summer of 2025 so far has been in many ways sort of remarkably stable and moderate. We've really been quite fortunate with the weather going so far this summer. About 2/3 of the way, 28 out of the 31 days in July were actually below normal forecast.

And August so far is also trending below normal so far. Vice Chair Gunda mentioned our all time peak load, 52,000 megawatts back in September of 2022. So far this summer we only hit 40,000 megawatts for the first time on August 6th. And so far to date this year our peak load is 41,868 megawatts.

So it's been fairly modest as well mentioned, we certainly haven't. We have another month of summer and as we know, August and September can be very hot. So we're going to stay vigilant. But it's been remarkably stable on the grid so far. And then certainly the variables we've discussed have been contributors.

One thing I do want to point out however, it has been very active fire season. I'm sure many of you are aware of that. This year We've had over 5,300 fires so far in 2025. That's above last year in the five year average.

Fortunately, through I think very close collaboration coordination with the utilities of fire agencies have done a fabulous job. They've really helped us to respond, I think very effectively to these fires. Just giving us being able to have the heads up and the state awareness that the fires are either forecast or during, during the occurrence.

We're able to redispatch generation, reconfigure the transmission system and do some contingency planning. So so far, even with a very, very active fire season, the bulk grid has remained stable. But we do need to stay ever vigilant on that. And as Vice Chair Gunda mentioned, so far this year, no flex alerts and no energy emergency alerts.

And again, a real deep appreciation to yourselves and all of our partners and the level of coordination across the caiso footprint and of course across the west has been.

We do have another four weeks officially of summer as we know, looking out, looking at the latest forecast, as you can see here, we do see the potential for some above normal temperatures again in both Northern California and Southern California. Oh, I'm sorry, excuse me. Thanks. There we go. Yep. In both Northern California and Southern California.

So we'll see how that plays out. But in short, when we so far, when we look at a couple other notable things, Chair Becker mentioned this. The remarkable amount of clean energy generation that have been coming onto the system here in recent years. Back in July, California hit its new all time solar peak of 21,774 megawatts.

And we are now sitting on a battery storage portfolio of over 13,500 megawatts within the Cal-ISO footprint. Did that switch over? Yeah.

So we in the batteries really, it's an amazing resource, performing very well, particularly in evening hours when demand is still high and solar energy is ramping off the system, the battery storage fleet has become an essential part of the reliability equation in California.

We've also been fortunate again this summer to see significant geographic diversity in the weather patterns. And of course by virtue of the fact that we have significant transmission, connectivity and resource diversity across the west that's allowed the western energy imbalance market and our reliability coordinator function to again play a critical role in maintaining reliability across the West.

So the energy imbalance market and of course we are actively in the process of developing and getting ready to go live with the extended day ahead market next spring. So both of those mechanisms have been very helpful this summer.

And I think in short, you know, the new resources that have come on the grid, just the tremendous push and resource adequacy by the state agencies has been remarkable.

The enhanced communication and coordination across the caiso footprint and I think a well functioning electricity market have allowed us to proceed to this summer so far I think in very good shape. And as we mentioned, hefa's position is, I think hardly optimistic for the balance of the summer.

So thank you very much and we'll look forward to some additional comments as we move on.

So the last section we have for you here is just forward planning. So when I set this conversation before we go into the Q and A for grid reliability from the demand forecasting perspective, want to make sure that we uplift a few things for the Committee.

So what this chart is showing here is the delta between 2020 and 2024 and 2040. So over the next 16 years, what do we expect the forecast to be? So what we're looking at is a waterfall chart that adds and deletes as we go step by step.

So just on consumption, and the consumption is primarily driven by economics, economic and demographic variables of the state. This includes household income, gdp, the number of households and so on. Just from that we expect almost six gigs of new load to be added. So that's the first one.

And then as you go down there are different variables that add to this. So climate change adds about a gig of additional load from the normal weather patterns that we take in. But one of the key elements, the next three variables in terms of additions are data centers.

EVs and building electrification are what we call fuel substitution in the forecasting, substituting natural gas with electrification. So as you see there, right now we are baking in about 3.4 gigs of data centers over the next 16 years. That was the first time we put in data centers based on input from the utilities.

That is a significantly smaller number. We've created a number of different scenarios and we decided to go with a mid case scenario for the first iteration. But I want to thank CPUC and the IOUS to providing us what they call known loads as they have applications coming in for data center development.

Those are being passed on to the forecasting team and those are baked in at the earliest part based on the next iteration of the forecast, we expect that number to at least double.

So just wanted to flag that data centers is a significant variable on the demand forecasting in terms of EVs that continues to grow the electric while we have the EV sales at about 25% of all new sales and that continues to be a strong demand variable. So about 8 gigs of new load coming from EVs.

And finally the fuel substitution, this is around space heating and, and water heating both. Moving from natural gas to electricity adds about six gigs. And then you kind of see you know, from that, are there anything we can reduce based on behind the meter variables?

So this and behind the meter, PV storage and efficiency, remove some of that load that we have to meet on the grid. But overall, between now and 202040 we are looking at adding almost 21 gigs of new load.

So that adds to, for example, today we're at about 44 projecting, so that puts us over 65 gigs. So that is the load you have to meet with. So the second important element that we wanted to make sure we flagged to the Committee is the rapid growth in winter peak.

What you're seeing here is the continued growth in summer peak in red and the blue is the winter peak. This is looking at February in blue and September in red.

So as you see there, the current forecast suggests that the summer peak will continue to grow based on all the variables that we've shown in the previous slide, exceeding over 66 gigs.

But as you look at the winter peak, and this is the February load, we begin to see the fuel, the electrification load increasing the winter peak as well, and Moving into the 2040 time frame, we'll be looking at two peaks that we have to contend with during the year, both in winter and summer.

All right, so the Integrated Energy Policy Report, the IPR forecast that the Vice Chair was just discussing, feed directly into the CPUC's reliability needs assessments and overall generation, procurement and transmission planning.

So this is really about looking, taking the forecast, looking at the existing system and figuring out the best way to meet the needs of the system for reliability and climate change goals in the most cost effective way. Because of course, we're protecting ratepayers as we go.

And so what the CPUC does is uses the IPER forecast to inform both our longer term Integrated Resource planning proceeding, or iper, and the Shorter term Resource Adequacy Program, or ra, which provides resources, requires them to be under contract and show up when needed.

So over the past six years, the CPC has issued several procurement orders and these go out to all of the load serving entities. About 40 entities are retail providers in California and we have increased the overall total capacity available. The orders total 18.8 gigawatts of new capacity.

And the procurement orders, the various ones are shown on the slide. One in 2019, one after the 2020 heat wave, and then 12 years ago in 2023.

One important thing to note about these procurement orders is that the analysis that was done to support them assumed that Diablo Canyon retired when its operation operating licenses were originally set to expire in 2024 and 2025.

But as you know, as required by SB846, we have now been planning, although the extension has been granted, we're now planning for the system without that asset.

So assuming that Diablo Canyon is not online, we're doing our planning to make sure that resources are online and built with the idea that we'll be letting Diablo Canyon go at some point. So that's how the planning is structured according to the requirements of the Bill.

So the responsibility to sign the contracts to meet this 18.8 gigawatt procurement order, as I said, is met by the 40 load serving entities. This includes the investor owned utilities, the community choice aggregators and the electricity electric service providers. And these 40 entities serve about 75% of the load in California.

So the resources that are built are then available for the resource adequacy program, which means that the load serving entities provide enter into contracts to make sure those resources show up into the market when we need them.

And the procurement planning process really does require close coordination with both the CEC as the Vice Chairman, but also with caiso. And the demand forecasts in the IPR and the GHG reduction targets then are also aligned with the CARP scoping plan. So that's the metric we are targeting.

And then also note that the procurement orders are for clean energy and battery storage only. So we don't have procurement of fossil fuels going forward. All right, this slide tracks the progress. You've heard a little bit about it so far. Really remarkable progress in getting new resources online.

You can see the vertical gray line is the current moment with the new capacity that came online since 2020 to the left of the line and then the future capacity to the right. And note that to the right of the line, that future capacity, those are resources that are already under contract.

So all of our retail providers have negotiated and entered into contract through competitive solicitations with resources to total the resources that you see depicted on the right. So it's showing that since 2020 the total number of new resources connected to the grid has surpassed 25 gigawatts in just five years.

And then also I will note that this is nameplate capacity. You heard earlier about NQC or net qualifying capacity. This, this is nameplate. So it includes total amounts for all the solar in particular.

And then the other thing to note is that in 2024, just last year, we set an all time high record of build approximately 7 gigawatts coming on last year alone. So really extraordinary accomplishment. And then we have nearly 3 gigawatts that have come online in 2025 so far.

You'll also note that solar and battery storage, the solar is in yellow, battery storage in purple. That represents the majority of the capacity so far. And then the trend continues out into the future and we'll hear a little bit more about energy storage.

We've talked about it already, but this really has been a key asset in capturing that intermittent solar and wind in the middle of the day and shifting it to the evening hours when the solar drop drops off.

So we expect to continue to see that resource needed as we look for the types of assets that can be dispatchable and flexible to complement our intermittent resources. I also want to note that looking at making sure we get the projects online. So how do we do it?

How do we make sure we're continuing to do it in the future? One thing that all of the agencies have been focused focusing on is getting together as energy agencies. The caiso, the GO biz, DWR, Puc, Cec. Our staff has all been working together to address project specific bottlenecks. So they are actually going project by project.

The ones we know that have contracts are ready to come online, focusing on those and breaking down barriers. And it's been very successful. We expect this to be an important tool that will be used as in the future. And then I'll also note that more resources does mean more costs.

So as we're adding resources to our existing portfolio that is cost that ratepayers bear and we're talking about the ratepayers within the territories of the investor owned utilities here. So that's why it's really important to make sure that we are using cost effective resources, that we're using the competitive solutions, solicitations.

I'll note that our procurement orders really focus on attributes. They don't order specific resources. So we get that competition among the various types of resources that can provide the attributes that the system needs. We also of course really focus on demand response programs.

As the chair mentioned, these are so important to shift and shape the load and manage contingencies. We have a number of programs at the PUC both for supplies demand side that are incorporated into the forecast. So avoid new resources being built and then supply side.

And then we have emergency programs that are called and show up during emergency conditions. So full portfolio of demand response and including importantly time of use rates, really important way to shift demand. And so we're looking forward to, to continuing to build those.

All right, a little bit on Diablo Canyon, on the extension, this slide provides an overview and summarizes the roles of the various agencies. We're going to be going through these in more detail later in the presentation, but just this list.

It gives you kind of a laundry list of all of the activities and responsibilities of the agency agencies. I'll go to a little bit on specificity because this slide shows the requirements and then the actions taken.

So since the passage of SB846, energy agencies have been implementing the Bill and moving forward with what the Legislature has directed on Diablo Canyon. I'll focus on a few of these actions.

One of the CPUC's first actions in 2022 was to adopt a decision that authorized PGE to move forward with what it needed to do to continue operations. So we essentially said you have the authority to move forward with past your original dates, which they had not been planning for previously.

And then In January of 2023, PUC opened a proceeding to implement other directions, including the requirement to authorize extension. The Legislature set the target dates and we needed to revise existing decision that we had which previously had set the expiration dates. We needed to authorize recovery of reasonable operation costs of the extension.

We authorized collection of a volumetric rate in lieu of a rate based return on investment. And that was pursuant to specific provisions of the statute. And we developed a process to annually Review PG&E's plan for using these compensation dollars, again pursuant to statutory direction.

I also wanted to note another tool that was put into place through legislative authority, the center central procurement function. The Commission PUC adopted a decision regarding central procurement last year in August.

And what we did is created a process to allow a central entity to help secure diverse clean energy resources, the ones that require long lead times and defined as over five years to come online, such as geothermal, longer term energy storage and offshore wind.

So again, this is a complement to our normal process of retail providers going through the procurement of resources through contracts they enter into. So it gives us another tool to reach our clean energy goals. The decision allows the Department of Water Resources to hold competitive solicitations for these types of resources.

And it includes a megawatt cap for each category as well as the planned online date. So DWR can plan its process towards those online dates and that matches the needs that we see in our modeling and analysis.

The decision seeks to contain costs by establishing these broad resource categories to encourage competition and then allows for a series of solicitations so that we can really capture declining costs as these resources are developed and brought to scale.

And these orders I Just want to mention all of this was the orders were issued before the current federal administration's imposition of tariffs before the termination investment tax credit. So all of the activities that are happening now in D.C. are we're tracking and following and may provide some headwinds. Headwinds for us.

But the orders were all developed before that. So it's something that we will need to watch very carefully and we can talk about that more. All right.

I did want to move to Research Adequacy to talk a little bit about our resource adequacy program because it's a complement to the resource procurement that I was just discussing through the IRP process. Resource Adequacy assigns capacity requirements to each of those loads of serving entities.

The load serving entities have to show that they have enough capacity under contract to serve their load. So they are the ones responsible for meeting reliability targets for their own load. But we do the planning for them and we establish the amounts that they need to cover.

So the generators imports demand response programs that are under contract for we Resource Adequacy then have an obligation to participate in the Caiso market.

And I want to note what's noted on this slide that until recently we had a program that looked at the peak hour of each month and that's how we did the assignment for this is the load that you need to cover for each retail provider. We recently developed what we're calling the slice of day framework.

And it is, you know, really what it says that for each slice of the day, each hour you have to make sure you're low is covered. And this really helps with things like battery deployment. So if you, you can't just look at the stack of resources.

You have to consider maybe the batteries started discharging at 6pm you can't consider that full stack then at 78 9pm and so by looking at each hour we make sure that the system is reliable throughout the day. It does require more granularity to the program.

And so we are still watching it carefully, but we've seen high levels of compliance so far. So the adjustment has been iterative and gradual with lots of input from our load serving entities. And we've seen a lot of success in it. All right. Oops. There we go.

Just a little bit on what we have done the recent work on transmission permanent planning. In January of 2025 we implemented SB 529 which adopt and adopted a new General order. It's called 131e governs the way we do permitting for transmission projects. And so it makes it faster and easier to upgrade and build transmission projects. In California.

We're really looking forward to accelerating transmission permitting moving forward. And this amendment to our rule will help us with that. I'm going to just go through a couple of points in the rule, the changes that were made to accelerate transmission planning or transmission permitting.

One is that the new order allows the applications to use a more expedited level of review, so not the full scope of review for upgrades and modifications to a existing transmission facilities.

So the idea is if you're upgrading something you already have, you don't have to necessarily go through every step that you would apply to a larger new project.

Then it allows applicants to submit their own documents, which helps with the processing their draft CEQA documents, which helps to expedite our environmental review and really trying to minimize duplication of processes. We also are not reevaluating the need determination that CISO makes.

And this is something the Legislature directed as well, that we shouldn't be duplicating efforts of the CISO and reopening a need determination that's already been done. And then we also are requiring a pre filing consultation with developers to minimize application deficiencies. So we don't want to wait and then have the application be deficient.

We have our staff working up front with the developer to get a really fulsome application before the Commission when it comes in. All right.

Well, I just wanted to. Well, first of all, at the caiso, we really appreciate the transmission enhancements that President Reynolds just described. They've been very helpful.

Of course, one of our principal responsibilities at the ISO is to make sure that we can actually interconnect the thousand thousands of megawatts of new resources that are coming on board to keep the state on track with SB100. And so managing the interconnection queue process is a key responsibility.

And back in 202223 and even before that, we received a record breaking number of grid interconnection requests. It was really clogging the queue. It was making very difficult to conduct meaningful studies.

And so we worked extensively with stakeholders for over a year and came up with a package of significant reforms to our interconnection Q process that established a much clearer set of sorting criteria that would determine which projects were most ripe, most ready, most qualified, most relevant to be included in that study process.

We took those reforms back to the Federal Energy Regulatory Commission and they were approved in September of 2024. And we immediately put them into production for what was known as our Cluster study cluster for.

And after several months, we had already removed about 73% of those requests from the queue to try to find the projects that were really best suited to be studied, that really lined up with the state's integrated resource planning and our transmission plan.

And even then we still had a very healthy number of requests to study so that the state could still have a good, strong competitive supply curve. About 68,000 megawatts of resources still being studied. So that is underway. We still have a large volume of requests in our interconnection queue.

We're going to continue working to sort of perfect this process and make it as efficient as possible, take as much friction out of the system. But one other number I just wanted to leave you with.

It is very important for us at the CAISO to make sure that transmission and interconnection and transmission capacity does not become a bottleneck to the development and the onboarding of new resources.

And we actually have about 60,000 megawatts of available transmission inventory right now that's available to be used for procurement over the course of the next 35710 years for the utilities. But we know that the total volume of new resources that are going to come on board in California is very, very significant.

So we need to continue doing the coordinated planning and continue onboarding and energizing not only the transmission facilities, but also the other innovative grid enhancing technologies and other sources of transmission capacity to be able to deliver resources to load. So you have our commitment to continue working on those processes. With that, I'll pass it back to President Reynolds.

Great. All right, that was our last slide. Just in closing, I just wanted to reiterate a couple of points. As you've heard, planning for electric reliability and greenhouse gas emissions is very detailed and requires close coordination. And we also have a long history that we're building on at all of our agencies. The Vice Chair mentioned the staff.

We have so many dedicated staff who are working together. They know each other very well and they're making all of these pieces fit and then making sure that we're nimble as we go and making changes, especially because of the degree of uncertainty that we've seen.

We've talked a little bit about both in the projection of data center load, transportation, electrification. There's quite a bit of uncertainty that we haven't seen in the past. And then we've also seen just that volatility in the demand.

So you could have a day in the summer in one year that is 20 gigawatts higher or lower than the same day of the year in the next year.

So dealing with that type of system and doing it in the least cost way, while we're also taking greenhouse gas emissions out of the system, is something that we're laser focused on and working to pull all the pieces together.

The other thing I want to highlight is that we are working with an existing infrastructure system, an existing distribution system, an existing transmission system.

And so we're trying to shift the Ga greenhouse Gas emissions out of supply, serve the load, and do all of this in a way that minimizes costs to ratepayers, which essentially means not triggering a lot of extra work from the utilities that then goes on to ratepayer bills.

So really looking at how all of this can be done in the most cost effective way possible. We always appreciate your engagement and work as we, we've noted bills that have been implemented. And so we very carefully pay attention to direction from the Legislature and look forward to continued engagement with all of you. Thank you very much.

Well, thank you all. And there's a lot we covered there and a lot to cover. I know my colleagues have a lot of questions. I'll just start with two and then we'll turn it over to my colleagues, as you say, first year, proud of the collaboration between this Committee and our colleagues in the Assembly and all of our agencies for all the work I started in December of 2020, so not, you know, shortly after that event.

I remember those very first hearings where we looked at a lot of these load projections, looked at what happened was, you know, obviously here for the Diablo Canyon debate, you know, did we need to extend it?

And I think on the three parts that I mentioned at the beginning around the growing resources, the grow, share, you know, share and shift, all of those really dramatic improvements over where we were.

And you talked about the massive amount of new load we've added, the battery storage, had that one Bill 887 that was planning between the PUC in Caiso and so really happy to see obviously that growth and in, in new generation capacity.

The decision to keep Diablo Canyon open, which I think was an important one in terms of all the reliability that we've laid out here today, the sharing that we've had with the western energy imbalance market and now the plan for the Edam and hopefully the larger sharing across the west, the important role of that and then the shifting.

So just for my two questions, I'll start with the shift because that really started with 846. And I appreciate that the CEC established a goal as per 846 of 7,000 megawatts of load shifting. You know, I have a Bill 841. I think that's going to help take us and help the roadmap to that.

But what can you tell us about planning towards that 2030 low flexibility load shifting goal?

Yeah, thank you, Chair, thank you first of all for, for your continued engagement and advocacy on just kind of making sure it's 541. Yeah, two bills in that space share and shift. Thank you. Demand side resources are an important part of the solution.

I think the, the common wisdom is we used to be able to forecast demand and we had a very good handle on dispatching generation when we need them. So that used to be the paradigm before renewables have become a significant part of our grid planning.

So with the intermittency of the renewables, it's just as important to forecast the supply side and make sure we have the optimization of matching the demand to that supply side on an ongoing basis. So as we think through that, collectively, the joint agencies have framed the demand flexibility as an opportunity between three buckets.

So the 7,000 megawatt goal broadly hits three pieces. So first, just as a good practice, again, the filter for all of them would be cost effectiveness. So if it is cost effective through the ToU or rate design to make sure the demand has a certain shape, that's the first bucket of work we would like to do.

And so this is what is called in the forecasting lingo as a demand modifier. So you have the rates a certain way to overall transform the demand side in a profiles into a certain pattern. And so that we believe could be almost 3,000 megawatts of opportunity.

We are not that far off today between when you take the statewide, we are pretty close to that number. Then comes the opportunity of given that we have these resources, could we cost effectively put them in our resource adequacy planning? So as a supply side resource.

And the third bucket would be those operational resources when you have demand flexibility used like a day in a 2020 to September 6th for emergencies.

So between those three things, whether it's demand modifier primarily driven by rate design, resource adequacy or emergencies, we collectively believe that there is an opportunity for about 7,000 megawatts, especially as you look statewide.

So the progress towards that, currently the CEC in coordination with PUC and CAISO are working on furthering that 7,000 Microwatt goal and the strategies to continue to look towards.

Great, thank you for that. Because as you mentioned, our alternatives, as you say, every new generation comes also at a cost. And you know, we say it's like the, it's like the parking lot, the retail parking lot, you know, building for Christmas. Right.

You have to prepare for that rush and you have to build for that maximum capacity even though they're not using it most of those times a year. So obviously we can embrace that load flexibility that we really started with 846 and have that roadmap. It's going to be, I think a massive savings for us.

I did want to ask about the loan and I know my colleagues will have lots of follow up on this, I'm sure, but as a piece of that we're supposed to get an update on the electricity supply strategic liability reserve. I think we haven't gotten that. So that might be good to hear. Number one.

And as I mentioned, my Chair, sub two raised those concerns about whether that loan would be fully paid back because if not, it's going to pass on taxpayers. I don't want taxpayers to have to bear that burden. But what can you tell us about the electricity supply strategic reserve?

Absolutely. Thank you very much, Chair Delphine from Delphine Hou from Department of Water Resources. So in terms of the Reserve itself, we have a little over 3,000 megawatts today in the Reserve, the vast majority of which as we talked about, are the ones through cooling resources. And our contract for those are up through the end of 2026.

So for example, last summer it was a lot of wildfire and heat and those were activated by the CAISO three times over the summer period in preparation for any adverse event. So those were used in useful resources last year.

And the remaining assets are what we call short start resources so that if there is an emergency in the real time, they can start very quickly to respond to that.

So in the Reserve itself, the vast majority of the payments and expenditures were approximately halfway through, which tracks fairly closely with the time frame of the largest expenditures, which are the ones through cooling resources.

Okay, well I'm sure we'll go into this with, I know my colleagues will have questions on this as well. But as we also discussed a lot in sub 2 when I was chairing, we have to keep those one through cooling plants open at a tremendous expense to taxpayers.

And we are continuing to look at what can we do to replace that with clean energy resources. Especially as now we've seen the efficacy of battery storage and those costs continue to come down dramatically. The success is also of the DSGS program. And I'd love to hear about that as well as we go on.

Maybe you can comment on that quickly because that's a program that I think has had a great success. We're starting to see also we had a great virtual power plant success recently and we need to make sure that those are funded. Quick comment on that before I turn over to my colleagues.

Yeah, thank you, Chair. Yes, the DSGS program was one of the many tools that the Legislature provided us. I think the premise for the strategic Reserve was we knew we were in a crisis and we needed to have a bridge over some time to first get through the next couple of years.

And that's where the OTC power plants really came in. And then the opportunity was through the end of the decade creating these programs like DSGS and making sure they become a substantial part of the grid. And you're accurate, we have under the DSGS today over a gigawatt of subscription. Majority of that is demand flexibility resources.

But again, until we do a test event, we don't know how much of that gig shows up. But the most recent event showed about 650 megawatts of response and it's a useful tool. While we do DSGS, PUC also runs programs similarly through ratepayer monies. And I don't know if you want to comment on that.

I just want to say that this is an area we're very interested in pursuing, but we also have to be very careful about ratepayer impacts and make sure that we're seeing that our demand response program to provide incremental reductions and are not double-dipping. So, for instance, with the net billing tariff, customers receive compensation.

We don't want to then take money from ratepayers and then add additional either ratepayer money or taxpayer money on top of that. So we just need to be very careful about the costs of what we're getting.

We're doing that by experimenting in a lot of ways and working closely with CEC to make sure that we're aligning kind of, you know, what are we getting and what is the cost of that and really looking under the couch cushions for every kind of demand response that we can get.

Okay, well, I have some more thoughts. Let me turn it over. Let me just start with Senator Stern and then we'll keep going to our colleagues.

Yeah. Thank you, Mr. Chair, and thank you to all our principals here for your progress over the last few years. Encouraging and rather harrowing times. I mean, we're sitting here at the verge of a scorching heat wave about to occur in Southern California starting tomorrow, I believe through the weekend. The largest we've seen in a few years.

So we have, I think, three active wildfires still in the region, although pretty high containment. So the stakes are certainly high, I guess. I wanted to follow up on the Chair's line of discussion with you all. Madam President, you mentioned concern about sort of ratepayer versus taxpayer pressure from demand response. I think they're two different things.

We know your charge is to worry about ratepayers. We're paying billions from taxpayers not on the rate base to keep these OTC plants open. And we haven't used them yet. Right. To my knowledge. Ms. Hou, is that right? It's been sitting there as capacity but not utilized during any of these events thus far.

Last summer, the CAISO did order them on. On three separate occasions in preparation for.

Preparation, but not actually.

Yes. We did not get into an emergency event. Correct.

Right. So they're a standby or whatever. I forget, how exactly are you. So I think that's over. I think it's a $2.3 billion contract that you guys are about halfway through expending. I think it goes through the end of 26, if I'm not mistaken. Is that right, Michelle?

The contracts in total for just the ones through cooling resources, about 1.2 billion. And we are approximately halfway through that amount.

And those are monthly payments, right?

Divided into. Divided into monthly payments.

Right. So we've spent down about 600 million of that 1.2. Is that fair?

I think that's a fair approximation. Thank you.

Yeah. So, I mean, I guess there's going to be taxpayer dollars expended one way or another on this capacity that we need. My concern is that we're paying for resources that are just sitting there and not being utilized.

And that if we were actually investing on the demand side and actually utilizing what Vice Chair Gunda noted are useful tools, it wouldn't just sit there. We would actually use those tax dollars live and be able to utilize them not just in the emergency events, but consistently.

So my question is really about, you know, reassessing the most cost-effective use of those taxpayer dollars as we move forward in meeting these new grid reliability challenges. And why the decision to defund DSGS. And I don't know where that decision lies, but maybe amongst this panel you guys could comment.

My sense is that there's been a decision somewhere in the Administration to not fund DSGS going forward. So I just wanted to get a sense of that logic and whether that's sort of a fixed decision or if there's openness to.

Is that just about the ratepayer expenditure on DSGS or is there openness to sort of utilizing this kind of SRR contracting post OTC to lean harder on the demand side? So I don't know who wants to comment on that.

I don't know that we want to comment on DSGS funding. That. That's more for the Administration Department of Finance. That was not from us. Right. And yeah, but we can talk about kind of demand response options and programs and how to think about it. So let me start and then we can, we can all weigh in.

But I'm sorry I missed it. I was over here. But.

Oh, just. I don't think we're going to. It wasn't our. I don't think we have the right people to talk about the budget, I guess. We're not prepared to talk about the budget.

Got it. So it was a budget. It wasn't a PUC order. It was about.

It was not a PUC order. No.

It's been General Fund funded. Is that right? At this point?

Yes.

Got it. Okay. So not really a ratepayer question, in other words, not before the Puc, but a General Fund question. And in the current budget is not funding.

There is Prop 4 funding potential, there's some other resource potential, but as of right now, no, no current funding in the DSGs.

Right. So let me talk a little bit more about tomorrow demand response so we can all just think about how it works. And so one thing to think about is the CEC incorporates assumptions about solar systems and battery storage behind the meter into the demand forecast.

And so in that way we avoid the build because that demand forecast is what triggers the build. And so if you don't reduce that demand forecast, you're going to be building to meet that demand forecast. So we so CEC does a lot of work to really accurately figure out how are the demand behind the meter systems performing.

What is the projected uptake of batteries which we have seen go from in Sunrun alone 10% to 70% in their installations with battery storage. So that gets incorporated into the demand forecast, which is really important. So that means we don't build, we don't assign resource adequacy to load serving entities. So we're saving money in that way.

And I'm sorry to interrupt you if I'm following you though.

This is on that chart, I guess it's on slide 20, the energy resource growth where you're saying new and expected so when you're looking at projected demand, because I think the Chair and I were trying to figure out where that demand reduction or response piece was in that breakdown. Or is that not the right way to.

I would kind of. Yeah, the slide number 17 would be a good one, Senator. So the, that kind of provides three negative bars in the waterfall chart that says behind the meter PV storage inefficiency. Those are what we call the load modifiers.

Basically saying that is essentially removing the load off of the bulk grid. And so this, this load which nets out that will then be sent to PUC for their resource planning.

So that's a demand reduction, but not necessarily demand response. Right, that's an overall. Yeah, I think for storage.

So part of the. So just want to make sure those three negative numbers do take into account the incorporation of the impact of rate design. So by those rate design, part of our demand flexibility. 7,000 megawatt call is that element. So those numbers inherently take into account some demand flexibility.

Including the 3,000 megawatts that one of you cited about time and use rates coming in?

Yeah, so that's roughly 3,000 megawatts is what we call the demand modification side. So those are those elements. So we are looking at the rate design and we're saying between the investments on energy efficiency, those are energy efficiency programs.

And the load change to a counterfactual based on those rate designs, what can we remove off of the forecast? And so that is roughly 3000 megawatts.

604 plus 993 plus 1900. Yeah, this is how you get 3000. So you don't need new legal authority to approach those time of use rates, in other words, to capture that.

Yeah, so that is from a forecasting standpoint, we are looking to PUC and other LRAs, local regulatory authorities like SMUD and others and what they are doing. And then we directly incorporate data analysis into our work.

But if we're going then pop forward to slide 20, that whole projected new and expected resource growth, it doesn't necessarily. So it reflects that's not about the overall demand. But I don't see where demand response is within that set of resources. I get what you're saying about the projected load, but what about the supply side?

Is that buried in hybrid? Is that what the. Is that?

Where does that live? So like, so just kind of framing that again in terms of when we look at the demand, the first part is remove as much demand as you can. And so as you just noted, that's the first part.

And once we go into the IRP process, process, the IRP process is saying how much more of that incremental load can we get through demand site resources? So what you're seeing here is just the bulk grid build out. But when you look at the resource adequacy within the resource adequacy you also have something called the PDR resources.

So those PDR demand flexibility. But what happens is those demand side resources have to have similar attributes as generations we can depend on them.

So typically those resources are a few hundred megawatts, so 3,000 on the demand modification and about 4 to 500 megawatts across the state on resource adequacy site resources and the rest of it really serves the emergency programs today.

And when you think about this, really good to focus on what we have. So think about the batteries behind the BPP potential. Those resources can qualify for resource adequacy.

So there are things that we have, we say if they show up, all of the CCAs, IOUS should be able to, should procure those as part of or contract with them for resource adequacy. And that's a competitive process.

And so having that be part of the portfolio of resources that can provide resource adequacy is a really important thing to grow and expand. The complication is, you know, we don't want, and Vice Chair mentioned this previously, we have to be careful about competition for that supply of resource adequacy. Right.

We don't prices have come down for resource adequacy. We want to keep those prices controlled, but absolutely want to develop demand response as a resource adequacy tool. We also then have emergency programs. And so demand response can be used for emergency. In particular, resources like ag use and industrial facilities get a capacity payment.

They show up when called in emergencies, it's better to stop the emergency because you know what happens when prices are going up and we get into emergency conditions. Market prices, prices are very high and all of the ratepayers are paying those high prices. The entire market settles at those high prices.

So if we use the resources first, the VPPs, if they come in early, it helps to prevent that market price spike.

So it's a complicated system that we're working on developing, but getting those resources as part of resource adequacy and used in advance either through rate design and then it goes into the forecast or resource adequacy and then there's some potential for emergencies. But getting to the avoiding the emergency is really important to keep costs down.

And is it fair to say that if we were to expand into say EDAM and looking at this Pathways Initiative, that we'd further take pressure off that RA market and even those emergency circumstances, just from a price perspective, that in some ways expanding our markets abroad would give us more flexibility to pursue these kind of newer, more flexible, clean resources.

Absolutely. I mean, that's the goal, right? You have shared resources for reliability. So avoid getting into emergency situations and then so everybody can have a little bit of a lower buffer. Although we have to be very careful about our buffer. But that's the concept. We share our resources. Resources as well as keeping costs down in the market.

Mr. Mainzer, have you seen, would you corroborate what Ms. Reynolds just testified to in terms of overall? I mean, I know you're not on the price side so much and you're on reliability, but.

No, absolutely. The work that I think that you're advocating for and that the PC and the Energy Commission are working to advance is extremely important. We're seeing real progress there.

And so we're wanting to make sure that the Cairo, we're able to have a clean interface for those resources to participate in the energy market to the extent that it makes sense and also for other utilities outside of California to participate in EDAM with their demand response resources and to take advantage of that wide area diversity to take overall pressure off the system.

So completely corroborated

And just last question, I guess. Yeah, I'll manage myself since the Xhair's gone. You've got to reign me in and. Thank you.

You can count on my colleague. The possibility of having say, an EDAM or expanded possibilities for say, not just curtailing solar power during peak times, but ability to sell it to, you know, other states that might need it. Also to, you know, our own industrial users who might need it.

But you know, if we're looking ahead, say beyond the current stage of these contracts, we've got Diablo and we've got the OTCs here. Ms. Hoenodes, I've been frustrated on the OTC front and we've been really trying to kick the tires.

I appreciate, by the way, your transparency with us and the follow up from the last year hearing and the trust about sharing contracting information.

And I hope that, you know, we've sort of showed a two way street to say, you know, you're going to give us, you can show us behind the tires so we can kick them, that we're not going to just go push that out to the public and respect the confidential nature of your negotiations.

But if we're trying to think of a future where we don't have to just lean on these OTCs and these gas peakers, does the pathways and. Does pathways give us an opportunity to not have to rely on gas peakers for that sort of backstop going forward? I don't mean this year, I'm saying in the coming years.

I just want to get your sense of that.

Thank you Senator. Thanks for the question. I think CEC has contracted with Brattle to do an independent study and I want to thank PUC and CAISO for helping consult on that study.

The core pieces that come out of that study is as the footprint of a day ahead market grows and we capture a large footprint, you have impacts on both reliability, GHG emissions as well as cost.

So in terms of cost based on the footprint we are able to capture, we see over $1.0 billion of savings for the consumers in California annually in terms of reliability to what President Mainzer had already mentioned.

If you think about the west as the load coming, you know, the coincidental load coming up and down at different times of the day and the resources coming at different times, you have several tens of gigawatts of additional capacity available in the system to help each other on those events, especially if you don't have those seams and then you're really operating that in a cohesive marketplace like what CAISO would do under the EDEM.

And finally on the GHG emissions, it's approximately 30% reduction over the next decade or so in terms of the emissions in California. And the savings for ratepayers primarily comes from reduced curtailment of the resources today and those can be used in the West. And so I think those benefits are pretty well established.

And again there are always risks to anything we do, you know, any good thing we do and the part of planning is to ensure that we manage and mitigate those risks.

So just to put a fine point, summarize it, maybe flipping the projected $1.0 billion savings annually, in other words, over the next decade, if we don't pursue this, we're going to have $10 billion more in ratepayer costs and less utilization of renewable energy. Should we not pursue that path? Is that a fair.

It's a very fair way. And also just wanted to note much of these analysis are done. If you look at historical analysis that have been done whether when the energy imbalance market it was being set up, the early analysis is usually significantly lower than actual benefits in real time.

And I think that's something that we watch historically as we look back.

Senator Laird. And I have Senator Grove next.

Thank you very much. I want to follow up on sort of the discussion with the Chair because we've had this great discussion of your processes and the statistics in the high ;evel.

But I think most of the people that are listening in relation to Diablo Canyon want to know what our progress is against what that load is. And there was even a provision in Senate Bill 846 that said if we develop enough renewable energy before the five year extension, then we don't have to do the five year extension.

And so it means that we have to have a way of looking at that and measuring. And what I'm trying to understand from all this is where are we, did we make? Because what I heard at the high level was we've made progress, but we're not there in displacement.

But I didn't get where that was in numbers or where that was in a piece of how we've made it to that how. And I don't know if other people want to.

We're both looking at each other, so maybe the Vice Chair can take a stab at that and if anybody else and I might have a follow-up question or two.

Yeah, thank you, Senator. Just in answering that question, I would just want to frame the assumptions that went into the study. Obviously, the first step of looking at implementing an extension of Diablo was to establishing the need for it. So the pieces that went into it are four pieces, right? So the first one is demand forecast.

Second is the kind of what level of reserve margin do we need to get through an event such as 2020 or 2022? And the third variable is have we, have we been procuring them, procuring enough resources. And finally, are we able to bring them online? Those are the four fundamental variables that we've taken into account.

So if you look at the demand forecast that we have used for the previous analysis to today, in the near term, it's essentially the same, right? So the demand forecast has shown uncertainties, some pieces, again, the demand forecast has several pieces underneath that.

But those changes up and down, whether you have higher EV or lower behind the meter penetration, those all in the aggregate as we have continued our forecasting process, haven't really changed through 2030. So I just want to start with that. So that assumption has not changed. In terms of PRM, our need to get.

And I'm sorry, I'm not Senator Stern, I'm going to make you define every acronym?

Yes. PRM, Planning Reserve Margin. So the planning Reserve margin is the first step of saying, okay, I know the demand in order to get those resources. So how many resources do we have to have on the grid to support the demand?

We basically say, If I have 100 megawatt load on the system, I want to add about 17% on the top of that. Right. So to make sure one, if the demand comes up higher or if the resources that are, I'm planning for vent and an outage, unplanned outage, and some NERC standards.

So between federal standards, between those three things, we need about 17% over demand. Right. So that PRM, what we believe is for an extreme event. And again, I want to make sure that this is laid out, in an extreme event.

We are talking about tail, you know, in the distribution and the tail event, we need that PRM to be able to absorb a heat such as 2022.

And when you take into that, and then under high heat, you have thermal resources that go at a higher rates of outage and their overall capacity decreases because of the ambient heat. So when you take those two pieces, you have to plan for an extreme event not at 17%, but like close to 26%.

Because if you want to get through that extreme event solely through the resources that we have available. And finally, procurement, again, PUC has authorized incredible amount of procurement. We've taken all that into account, so that hasn't significantly changed.

And finally, the progress we have is when we looked at the Diablo Canyon Prudency report, we incorporated about 40% delays in building because we're coming out of COVID we were seeing a lot of delays. That 40% number has definitely come down, and it's closer to 25% now. So we are making progress in our ability to interconnect.

But when you continue to take all of them together and add the catastrophic fire, such as a bootleg fire, the Commission continues to believe that it's prudent to have those resources. I think to your point, there are a number of good things happening, but there are also uncertainties that are remaining and inaccurate.

I think the way I'd like to drill down is that still doesn't quite tell us what, what numbers are in what I'm trying to figure out if demand is the same over that period and if our planning horizon for an extreme event is roughly the same, but we're bringing additional power online or electricity online, we are clearly closing the gap.

But the question is, is by how much? that's what I don't get from your comments.

Yeah, absolutely. I think so. The overall, I think the points that you just made are absolutely accurate. Which is from the previous Delta we were looking at. Right. So that we were saying, if I believe the numbers were negative 7,000 megawatts to 2030, I have to refer to the document.

I can send your office the latest numbers, that in a Delta that we were seeing under a catastrophic event has come down to, let's say 5,000 megawatts because of the recent build out. But that's not eliminated. And we will send you the exact numbers.

And then if we move toward the end of the five year period, do we believe we're going to close the gap? Do we believe we're going to get there by 2030?

Yes. So I think that this is where I think we need to have a number of different conversations holistically.

So when we think about what was the reason for Diablo and the OTC power plants coming out of 2022 and 2020, 2021, 2022, we were looking at about immediate, in the immediate next five to six years, a 6,000 megawatt delta. And we were also retiring about 6,000 megawatt of resources.

So the initial, the immediate kind of legislative path was let's retain those 6,000 megawatts and make sure the agencies take every step to build the necessary resources. And that's what our focus has been. So as we come out of this, the question continues to remain, what are our backstops? What are our contingencies?

And given that if we reduce the Delta, are the available contingencies enough to let go of Diablo? Right. I believe like as we showed on our slide, we have contingencies about 4,000 megawatts today between one through cooling power plants. The DSGS program a number of programs and that will also shrink. Right. So your contingencies are shrinking.

Once we leave Diablo, that's gone. But the legislative mandate to us was make sure you're procuring resources as if Diablo is gone. So if we bring the resources and if we have better market function in the west, that Delta will be significantly closed. And I think the contingencies might be enough to get us through.

Okay, that's what I was looking for and I'm happy to get any follow up. Then two related questions. One is that with Diablo Canyon, you put this power on the grid and you put the power on the grid, that's 8.6% of the state's electricity. But you can't modulate it. You put it up for a week.

And you cannot modulate the nuclear thing. And yet wind, solar, everything else is much more volatile. And there have been stories that we have had to offload power to other states or in some cases not take the power on the grid. Is that true? What are we doing? How are we compensating for that?

I'll start at a high level and welcome President Mainzer if he wants to add. I think when. It is true that when we think about firm resources like Diablo, they cannot be modulated. They generally are at the same level. But we do have a lot of dispatchable resources on the system.

Those dispatchable resources include hydro and also thermal. A significant part of getting through a summer day is dispatching those thermal resources. And one of the benefits of having Diablo was being able to modulate the thermal resources down and not having to rely.

And you're absolutely true that even though we can reduce the thermal fleet, the thermal fleet cannot be turned off in order for it to be kept running. You can only bring it to what is called a PMIN or the minimum level.

And once you add all of those pieces, then you have to go into, you know, what resource should I curtail if I'm under oversupply or what I'm trading. But I think on the aggregate, when you look at the system as a whole, the benefits are significantly higher. President Mainzer and I don't know if you want to add.

Yeah, and I'm not arguing with the benefits, I'm just arguing with the problem. And that leads to the last question, which is, is part of that, that we don't.

We're not keeping up with battery storage, that if we had enough battery storage in those moments, we would never be offloading it to another state or, or not bringing it onto the grid. We would have a place to store it. So the real issue is developing enough battery storage.

Yeah, I think, Senator, I always appreciate your questioning. Absolutely true. I think it's a factual statement that the more storage you have, the more ability for us to absorb that energy. But I also want to just note that there are other things on the system that might require us to either export or constrain is local constraints.

So sometimes even though you have potentially storage, you need to have the storage at the right place to be able to absorb that under those conditions. So I think the questions that you raised speaks to the complexity of the moving pieces.

And I think every piece that you just laid out is absolutely important for us to continue to track.

And I know just sort of tangentially, we have a big problem with the public since the Moss Landing fire in January. And I don't think they are grasping that that was the original technology and a technology we might not approve now.

And that 75% of the technology is either outside cement slabs in containers, not in that a similar percentage is new lithium ion and not having the heavy metals that were really bad in the smoke plume and really were an issue with people surrounding Moss Landing and that we have to work on convincing the public that this is the right thing to do completely separate from the fact that it might be for all the external reasons that we are talking about here.

Yeah, I'll lean on President Reynolds on the specific battery side. I think we have a group right now that's working on the battery safety. But I think to your point, Senator, more broadly every resource has pros and cons.

And I think we've seen this in 2021 when the Durazo City in a thermal power plant had a failure, catastrophic failure and explosion that sent shards out to a near community center and made a hole through the roof. Right.

So these are no matter what technology is using, it's really, really important that we proactively think about safe implementation.

Well, the very Moss Landing plant that had the battery storage fire had a huge fossil fuel fire 20 or 25 years ago that threatened the surrounding area in a state similar way. And Chair Reynolds is not used to getting praised very much.

And I would just say that the actions on the battery storage safety that were taken I think in March by the PUC together with when I did the Bill, there was an incident at Moss Landing in 2022 and I did a Bill that required safety plans to be filed with local cities and counties.

And much to our amazement they hadn't been done by either PG&E or the other one at the time of the Moss Landing fire to satisfy that Bill. And it never occurred to me when I was doing the Bill that I should set a deadline or I should do something. I thought it was going to be self executing.

And the PUC as part of it will really monitor whether people are in compliance with that law. And that is another step to us getting toward trying to deal with the issue of competence. Thank you. I wanted to ask those follow up questions. I appreciate the opportunity.

Excellent. Well, thank you. And I know we have a lot of questions. We want to make sure we also. Get to the second part as well as we do have a hard stop at noon. Let me turn over to Senator Grove.

Thank you Mr. Chair, thank you for being here. Vice Chair, you've just been absolutely wonderful in all aspects of energy production and sustainability. So I appreciate your input.

And I have visited the ISO a couple of times, and I can't even imagine the job that you have every day, sir, to make sure that when somebody flips the switch, the lights come on and other things. I'm a pretty simple person, not like my colleagues here that are highly educated.

So I guess. So I guess I have a couple of questions. One, you know, regarding the wholesale energy price differences between peak and net peak. And the reason why I ask that is because I represent Kern County. The former Secretary of Natural Resources mentioned his title three times.

So I have the ability to do that as well with my community, who's the energy capital of this state, producing over 80% of the state's battery storage. Karen Bass was just in our district with a new project that is going to make Los Angeles almost 60% green energy.

I often tell my colleagues when they complain about our other assets that we have on oil and gas, I'd be glad to shift our 6,000 acres of solar panels to Santa Monica Boulevard or up in the Bay Area. I'm sure they'd be able to take that and produce their own green energy.

They're used to me, so it's okay. So I guess my question is that as a net exporter, like my district is a net exporter, is there a way to access cheaper rates? I mean, we produce an abundant solar and wind, and for the state, 58 counties, and we produce almost 60% of the state's renewable energy.

That's because we have Lorelai Ovia, who is just brilliant as a planning Director. And so that's a question that I have for whoever can answer it. And then I have specific questions for the CPUC and the CEC.

Yeah, I mean, I think it's a great question and something that is always on our mind. I think just starting with the need to really stick with the process that requires developers to be least cost to provide the attributes we need for the system at places where the development can happen in the most cost effective way.

And then make sure that energy that's produced and the batteries, the energy and can be deployed are shared throughout the system in a way that makes sure that they can show up where needed versus producing electrons that aren't used at a certain moment, but maybe they're used the next week or the next day at a different place.

So really making sure that we're sharing the use of the electrons as well as the costs and spreading those among the biggest rate base of customers as possible so that we're lowering rates for everyone. Adding megawatts to our system at this point now really helps because we're getting additional. We're spreading our volumetric rates over a bigger base.

So things like electrification of transportation and vehicles to the extent that demand is using the grid, it really helps with costs overall. So thinking about it from a system wide perspective is important from a cost perspective as well as a supply perspective.

I appreciate that. And we do do that. We're probably the only county that has transmission lines, non contiguous counties.

We produce 6,000 megawatts of operating solar and wind and 7,000 battery storage and 7,000 megawatts already in this, in the system for process that we hope to have done by 2028. 21,000 megawatts of wind and solar, 6,000. I mean just go on and on. And there's no other county that does that.

If we were able to produce. We have 80% of the state's battery storage out of 58 counties. And if unleashed, we could produce 70% of oil and gas. That would help reduce cost as well.

So going back to the simplicity of stuff we talked about or it was mentioned that, you know, we have these plants that we fire up or they go on alert just in case we need them. I mean, what would be the reduced cost to our consumers and our ratepayers if we just operated Diablo.

Like, I mean, I guess my question is from a business background because I've had a business in the state for 30 years. Sometimes in spite of this state. If you set a five year timeline on Diablo, if you do or you set a Five year timeline on development of anything.

How does somebody do a capital investment for ROI and plan for that and not create an automatic increase in cost.

I mean how do you, if you have to do a I don't know, five million dollar investment or whatever, that $1.2 billion investment or whatever it is, how do you calculate that over five years if you're going to only let them operate for five years. I mean it's like you're throwing a party and nobody's going to come. Sorry.

I think that. Well, I'll start with that's why the, or what I see in 846 is the Legislature's attempt to deal. We don't want to make a massive investment in Diablo Canyon to upgrade it if it's only going to be lasting for a short period of time.

And so the compensation structure was based on production from the facility versus a capital investment that's collected over time. But it's.

If we allowed them to operate, we could reduce rate payer rates across our state. We'd have grid reliability because they produce so much power. I mean if you look at just the information, and I could be wrong, but like just take data storage.

There's estimates that just from data centers alone, which is where the new technology is going, that will grow by 10 gigawatts by 2035. That's equal to power to right now five Diablo canyons. So if we know that this technology is needed in the future for data centers and those kinds of things, why not just bring.

I mean other countries have nuclear facilities. And so I guess my question is that why even have a five year deadline, why don't we just say produce the power that we need to provide the future needs to meet the needs of data centers and increase power.

I have Tejon Ranch — or not Tejon Ranch, Tejon, the tribal casino up in Tejon. Thousands of jobs in my district, and they're being delayed and delayed and delayed from PG&E. I have a whole community that went almost 20 days without power because Southern California Edison can't keep the power on.

And we're the fourth largest economy in the world. So why not unleash power that we have, including what Diablo Canyon can offer to all of our ratepayers in every one of our districts. Because it goes straight to the grid, right or not.

It does go straight to the grid. That's right. So right now we're operating under legislative direction for the. "So it's our fault?" No, I'm saying we're following the direction it's certainly a great question to examine the most cost effective way to meet our needs. And Diablo Canyon has a cost and the other resources have a cost too.

But that's the way, a great way to think about what we need for the future.

Okay, and so just if somebody could answer this for the benefit of us, how could an extension of Diablo Canyon beyond 2030 affect commodity prices in the State of California.

Like if we said we're extending Diablo Canyon beyond 2030 and we're allowing them to produce the energy that we use every single day and the energy that we need to procure in the future, while we simultaneously build out solar and wind and battery storage until we meet that, then do you actually have to plan for these catastrophic events.

Do you have to. I mean, I'm sure you do in some ways, but it would make your planning a little bit easier if you had this energy that was continuously coming from Diablo and there wasn't a deadline on it. That's my thought process. I guess that would be to the CPUC, I apologize again, or the CEC.

Go ahead, Mr. Vice Chair.

Thank you Senator, very nice to see you.

I think that two pieces I think we need to think through in terms of Diablo again, you know, the closure of Diablo or kind of the nuclear General technology is kind of, you know, through the legislative process, we have a moratorium on new nuclear and I think we are working within the bounds of the mandate of the Legislature being the mandate of the state.

So I think from prudency, prudency part of just, keeping the system as reliable as possible, any asset that we have today retained on the grid would be helpful just because there will be more electrons and especially a resource such as Diablo and any nuclear power plant that has in a firm shape and those electrons are zero carbon, it has a lot of benefits from that end.

But I think that the other parts of the has always been the one, are they cost effective, whether we take about it. And as you point out, you're absolutely right. When we think about a resource planning in five years, the cost metrics for that would be very different from a 10 or 15 year investment cycle.

So absolutely recognize the point. And I think that the points then the other constraints are is it cost effective. But two, especially with Diablo, there has been, you know, prior to the extension, a very strong local agreement to retire those resources.

And I think to Senator Laird's point earlier, I think once when we think about these resources, it's about cost, it's about ability to have reliable supply and it's about community and the statewide support on that particular resource extension.

Thank you. Because the information that I have just as a follow up, it's keeping Diablo Canyon on line reduces about 3% of the cost or and there's a net benefit based on the information I have of about $3.2 billion in cost savings as a result of 846 and making sure that Diablo stays online.

So I guess if we have this great asset that other countries use, why not bring it up to speed but allow an ROI for an investment and don't cut it off in five years.

And I realize that's a legislative issue, but that's why I appreciate the work Vice Chair that you have done across the energy spectrum because you've really looked at, you've really looked at where we have, where we as policymakers have gone in a transition period but realized that demand does not allow us to get there without substantial increased cost to ratepayers.

And so I'm just wondering, I guess if the data I have shows that there is a decreased cost to ratepayers to keep Diablo Canyon online and a decrease costs to all and reliability to the grid, why are we not using that asset.

And I'll just mention, and then we'll let you follow up, then we should probably move on. But maybe you want to comment on that 3.2 billion number because my understanding is that that's driven by RA capacity benefit estimates and the CPC is revising some of the system range market price benchmarks.

So you may want to comment on that.

We'd be happy to follow up with information on that number. I assume we'd want to look at what the alternatives are, but I'm not prepared to comment on the number right now. But I'm happy to follow up. Thank you.

Thank you. Thank you for your latitude, Mr. Chair. Thank you all for being here. Appreciate the hard work that you put in.

I appreciate the line of questioning.

And you know, I will say from my, from my own standpoint, I know there's many in my district that, you know, I was represented in Silicon Valley and a lot of innovators and people are looking at advanced nuclear and, and we're seeing really an embrace for us across the rest of the country and kind of neat look at nuclear and of course we have to do it not just cost but safety, as I'm sure will once we get to the PGD portion as well, of course is the other critical factor there.

But I myself am very open to looking at that in the future as part of our mix. I want to go to Senator McNerney and then Senator Archuleta.

Thank you, Chairman. First of all, I just want to say thank you for the presentation. It was a lot of information and it was well organized. I want to thank your staffs for all the work that went into that. From a 50,000 foot point of view, you don't have to answer. My constituents.

I pay 65 cents a kilowatt hour for power. People want me to do something about that. And so I feel this pressure and I want you to feel the pressure too, and I know that you do.

But nonetheless, it helps to say to voice that and to make sure that that's something we're working on, that we need to have answers. And it's not entirely the IOUs fault. I get that wildfires, environmental concerns, so on have added to that.

But we have to figure this out because businesses leaving the state, people are finding California completely unaffordable. This is something that needs to be addressed. It needs to be our top priority. And first, the last thing I want to say before I start asking questions is when the word delta comes up, I cringe. It's local.

It's a local issue to me. So just a matter of sensitivity there. So my first question is for the President Reynolds, could you comment on regionalization. I know that's an issue that we're going to be dealing with. Is that something that you or anyone on the panel feels empowered to talk about.

Sure, I'll comment on it. And we can turn to other panelists as well. But I think we've done some joint work together with the other energy agencies in looking at the benefits already of the EIM and the EDAM as well as the Brattle study that the Vice Chair mentioned.

And you know, kind of just you start off with 50,000 foot level.

Broadly, having a market footprint that is bigger than any one weather event is helpful so that we can share resources that may be more available in one area and less available in another area if that area is experiencing extreme heat events or other disruptions to supply.

And so kind of the concept in General of having that market that if designed well for benefits of the ratepayer that is able to work without seems could be a very big benefit in terms of keeping costs down.

So affordability benefit as well as reliability benefit, which of course is a affordability benefit as well, because it helps us to meet our reliability needs in a least cost way. And so I think that we need to be careful.

But the iterative process that we're following here really puts us on a path to know what we were in for, right. So we're not just operating in blank slate of we're going to talk about a regional market. We don't know what it is.

We've seen how EIM works, we've seen how EDAM is planned to work the market rules and we know what to expect moving forward to a regional market. I'll also say that we have a lot of cooperation from our regional partners.

California, the CPUC works closely with colleagues throughout the west on working on GHG targets in thinking about affordability as well as reliability for the customers of all of the regulated utilities. And so there's a lot of cooperation and interest in harnessing the resources of the west on behalf of customers.

And utility commissions throughout the west really feel that need for affordability, a need for reliability and thinking about customers as a whole.

Would you comment on potential downside of regionalization.

We have to think about what the market rules are. I think the proposal contemplates CAISO operating the market and having a viewpoint that it is being operated on behalf of the customers.

So we need to make sure that that's retained, make sure that the market operates for customers and doesn't avoids things like price spikes and keeps a market monitor in place so that we really make sure that all of the work that we've done through the years to prevent gaming of the market is prevented.

And you know, there's more detail on each of those things. But there have been a lot of improvements in terms of watching for any kind of gaming, having a market, a very strong market monitor in place, and then also a public process to work on iterative rules.

And so that's something that we would want to see too is that as it moves forward, the public stakeholders are all involved in changes to the market and growth of the market.

Thank you for CAISO. Would you comment a little bit on fire prevention technology and relation to public safety power shutdowns.

Well, as you know Senator, you know, the realm of power safety, public safety, power shutdowns is primarily the realm of the utilities and the transmission owners. What we have seen obviously is that they've invested tremendous in new state awareness technologies and forecasting technologies in sectionalization of their systems.

And they've done, as I described earlier today, an outstanding job from our perspective of providing us with visibility into when they may have to result to public safety power shutoffs.

That has enabled us as the Bulk grid operator to be able to do contingency planning, to react to reconfigure generation and transmission such that those impacts don't cascade onto the broader grid and cause reliability problems. So we continue to coordinate with them around those.

We also, through our reliability coordination function, which looks at a big section of the western United States, are constantly monitoring fire issues and conveying that information to utilities in California and across the West. So we can take preemptive action to prevent broader cascading problems on the grid. So that's our role in that.

We of course, are not the decision maker with respect to PSPs, but certainly that coordination, that collaboration has prevented wider spread reliability issues.

Well, I mean I'd like to see the technology be used in a way that reduces the risk of wildfires so the cost goes down. I mean, we can't continue to see these massive wildfires taking out parts of cities. I mean, that's just completely unexpected. Understood. So Mr. Gunda, again, excellent presentation.

You mentioned the Data centers and EVs are predictable in terms of future implementation. How predictable, how accurate, how granular is that?

Yeah, thank you, Senator. EVs are a lot easier in terms of being able to understand its load. In terms of electrification. As we, you know, went through the early years of EV penetration, now we have a better understanding of their charging profile based on historical data.

So between the historical data and the projected kind of the EV kind of growth over the last several years and the projections, EV demand seems to be pretty, pretty solid as we move forward. Based on history. And then in the future projections, we based that on consumer choice survey.

So between the California Energy Commission and California Resources Board, we collectively do a survey in a consumer survey every three years to understand consumer preferences on which technologies that they're going to incorporate. And we also have working groups with the industry, specifically the OEMs. So between those three data points, being able to forecast EVs has been better.

Obviously, to your point, there's always a little bit of uncertainty. The uncertainty with data centers is significantly higher. It is a massive load that's coming very quickly. And as noted, we are taking collectively some important steps.

These guys have to get permits, right? I mean, you can't just put up a danger center. So it ought to be something that's predictable.

Yeah, I mean, they do have applications. I think the main issue that we have is the forecast is done once a year and the downstream processes sometimes are almost three years cycles. And as you're looking at year to year growth that Real time incorporation of the data is the hard part.

Okay, a couple more questions if Senator Archuleta will indulge me here. I know you're anxious. Chair Reynolds or President Reynolds, the graph that you showed here, energy resource growth, new and expected. I don't know if you can put that up or not again, but you have batteries and solar and wind and all these in one.

But there's overlap. I mean, I think this graph is kind of misleading in the sense that you can't count battery and solar and wind in the same category. I mean, they don't add. They complement each other, but they're not available at the same time.

So I just want to point out that I think that graph could be misleading. So for the future reference. Now, the question I want to.

One thing I might do just in terms, we want to get the PG&E presentation as well. Let's ask all remaining questions, and then I'll just ask the. Among all the remaining Members here, let's just ask all the remaining questions, and then I'll just have you respond to all the questions at once. Is that okay?

Okay, so go ahead. And your questions.

Seems to get in first in a lot. I know. This is kind of a blunt question. Is PG&E using the Diablo Canyon as the cash cow? I mean, that's something that turn says. They point that out. Hey, they're using PG&E, they're using Diablo Canyon as the cash cow.

Would transmission permitting, one-stop-shop permitting, be advantageous in terms of getting things done in transmission. And a very important question to me, and you mentioned it briefly, when you're putting in solar or at a business, have a small business, it takes forever sometimes to get hooked up to the IOU. Can that be improved?

I mean, people complain to me all the time, it took six months. It took a year to get hooked up. What's the problem? Do they need more resources? What do we need to do to get these things to happen?

Great. Let's take that. Let's see. Did you have any questions? You're good. Okay. And then, Senator Archuleta, you're sort of wrapping us up, probably, right?

Yeah, I'd like to wrap that up. You know, if you had the entire auditorium filled up with mom and pop and business owners and kids going to college, just General public, and they're all concerned about their cost of the energy. And you're the experts here, no doubt your expertise is unmatchable.

So the big Question is, is this energy cost going to continue going up or you have a handle on it with your technology and the skills that you have. Do we have a future in reliability, accessibility, but yet cost bringing it down over the next 5, 7 years? I mean it's not overnight. That's my question.

So I'll ask to respond to both of those, both the including the connecting things to the grid, which hopefully SB 410 has helped with but we know we volumetric rates getting things connected to the grid more quickly is important. And then that point around affordability.

And obviously we have some big efforts this year, including with the Senate with SB 254, which I'm carrying as part of our work group. But comments on those two points or anything else.

I'll just start by saying, anything that can be done to take friction out of the system with respect to transmission energization and siting with respect to interconnection key reform, the onboarding of new resources is going to be helpful. Time is money. This goes directly to customer rates.

And certainly I think you've seen the coordination amongst the agencies and the CAISO, our work on interconnection key reform and transmission planning. And I know the utilities are also feeling a lot of pressure to your point to expedite those onboarding timeframes.

So we've got to keep the pressure on and make progress in all of those areas.

Yeah. So Senators, you raised big questions that we could probably talk all afternoon about. I will not do that. I will be brief, I guess just, you know, the cash cow, I think really. I don't know how you define that, but need to look at the numbers of compensation that they're receiving.

There is compensation from the market that helps ratepayers that are paying for the operation of the facility. But it's certainly something we can follow up with you if you're interested in seeing the numbers of compensation they're receiving. The permitting one stop shop that's, you know, like to understand a little bit more about what that is.

Essentially for California transmission projects, they come to the PUC for authorization. As I said, we've done a lot of streamlining work and we're starting a pilot as well to really examine where the bottlenecks are. As President Maenzer mentioned, getting the friction out of the system. Where are those barriers and how can we break them down?

So understanding that a little bit more and then taking action and doing it in a really focused pilot way so we can move quickly to break down those barriers is something we're working on. Solar for small businesses, there are.

We've been working on timelines and in particular energization timelines to get all customers connected more quickly because there have been delays. And so working with processes to make sure we are getting more transparency and accountability for the utilities to connect customers more quickly. And then on the.

I'd like to see some numbers on that.

Okay. Yeah. Happy to follow up with your office. Excellent question on affordability. And I think really you're wondering what's the path, you know, like, what is going to happen in the future?

And we've done some forecast, but essentially, I think what it means is really sticking to the rigor in our evaluation of costs and making sure that we at the PUC are doing everything we can do to reduce costs, which is not always popular because there are lots of financial interests outside of the utilities, where businesses are built based on ratepayer money.

And so we really have to make sure we keep that competitive aspect and be rigorous about the requirements, what we're getting for what we pay for, what all of the customers are paying for, and continuing to make sure wildfire costs in particular are contained as much as possible so that risk reduction metric is met with the lowest cost measures possible.

The net billing tariff is going to continue to increase costs into the future. We were able to fix that to some extent, but not entirely. And so that's something that is going to continue to cause increases in rates, but we're doing everything we can on that.

Okay. I think we want to move on. I just wanted to say, I just want to lastly just refocus again on the loan. What can you tell us about loan repayment?

Thank you, Chair. From DWR’s perspective, in following the SB 846 legislation, the bulk of the loan repayment would be coming from the DOE program. And based on their requirements, what we understand is that the monies should come into an escrow account and then back to DWR.

We're thinking in the timeframe, the earliest timeframe in 2027, but that's again dependent on the DOE program and where they are in that process. Outside of that, there are two other potential buckets for repayment. One would be during the last year of operations of any revenues from the plant.

So we'd have to wait until the last two years there. And then looking at any other either state or federal funding opportunities, one of which we've identified, which is a potential DOE settlement on spent fuel costs that could come back as loan repayment.

Okay. Well, I think we'll get into PG&E as well. I'm still very concerned about us getting that forward payment, and we will continue to push on that. Lots of things we could raise here. I did just want to note here, you know, CCAs have raised petitions around trading of RA applications.

I think that's something we should discuss as follow up a number of other planning points that we could get to. But in the interest of time, we do need to move to the PG&E presentation.

I want to thank all of you, as Senator McNerney said, just tremendous amount of information, tremendous amount of work that's been done since I started here in January 2021, just to see all the work that's been done to prepare for those peaks and to do it.

And I think especially with legislation pending this year, do it as affordable, as affordable as possible. I really appreciate the work of all of you. Thank you.

We'd now like to bring up Maureen, Zalik, the VP of Nuclear Business and Technical Services from PG&E. I will note that we do have a hard stop. I do want to get public comment in.

I know there are Members of the public here and I can certainly, I can stay, but I know we're going to have to have a hard stop a little bit before noon. So we'll get just right into the presentation as soon as you're ready, whatever you want to share with us.

And I know we have a lot of questions, particularly from Senator Laird.

Thank you for joining us.

Thank you. First of all, thank you very much, Chairman and the Committee and Senator Laird, for being here today and for the opportunity to provide an update on Diablo Canyon and what we've been up to since the last time I was here about three years ago in August of 2022.

So, as you mentioned, Chair, my name is Maureen Zawalick, I'm the Vice President of Business and Technical Services at Diablo Canyon. I've been at Diablo Canyon for 30 years. I have a nuclear engine degree and I've been in the energy industry for over 35 years. So again, appreciate the opportunity to be here.

And I'm also here with Tyson Smith, who works with us on our Diablo Canyon SB 846 implementation.

And we do have the presentation. Hopefully have the presentation up. We have it, I know, in front of us, but I'll just ask you to move through that just really as quickly as possible so we can.

We will.

It's pretty detailed, so we can read through it ourselves as well.

Am I supposed to be sharing it or how does it. Just ask our team. Okay, we're up. We're live. Okay. All right. Let's just start with some highlights of where we're at here. Is that being displayed?

Okay, maybe you full screen it. the last line's on there. It's okay. I think we can move along.

All right. You know, most of these statistics already. We've already talked about it a little bit. We serve over 4 million Californians, or 10% of the state or the state's population. Senator Laird mentioned and Senator Grove, about 8.2% of California's total electric generation, Unit 1 and Unit 2's average capacity factor.

We've been talking a lot and hearing about baseload. We are baseload power. And last year's capacity factors were 94% for the units. That's rain or shine, no wind required, available night and day, 24 hours a day. So very reliable. We're also a very well decorated plant.

From perspective of safety and reliability as recorded by the Nuclear Regulatory Commission, our federal safety regulator, we are in the highest performance category for safety Amongst all the 94 units in the United States. Just pivoting to benefits to customers for extended operations.

So for the period that we're in right now on unit one, that was supposed to shut down last November of 2024, and unit two's data shutdown is in a couple weeks or next week, August 26, 2025 it was supposed to prior to Senate Bill 846.

But we estimate that the use for data centers alone will grow 10 gigawatts. I know we've heard some different numbers here today, but that's our analysis and that's equal to nearly five Diablo can.

And that's been mentioned or per the California Energy Commission, what we just heard from Vice Chair Gunda, the peak growing to 22 gigawatts equal to 10 Diablo Canyon. So that's what last that number is, is last year the peak was 45 gigawatts and the projection is 67 gigawatts in 2040.

So the 67 minus the 45 is where the report from CEC shows the the 22 gigawatt difference. So Diablo Canyon being 2.2 gigawatts. That's why we equate it to the 10 Diablo Canyons.

And then just last month in the California Public Utility Commission July staff report shows approximately 1500 megawatt shortfall to replace the clean nuclear energy that Diablo Canyon produces. And then from a societal or environmental benefit.

I just wanted to highlight that the annual greenhouse gas emission reductions, equivalent reductions from keeping Diablo running is equivalent to about 1.6 million cars or for the period of extended operations for the five years from 2025 to 2030, that's approximately 34 to 36 million metric tons of greenhouse gas emissions that will be avoided.

The NRC environmental impact statement that's part of the license renewal process did just state, in June of 2025 a couple months ago that Diablo meets all environmental requirements to operate another 20 years. So pivoting, I'm going to dissect that a bit about the 20 years versus the state current energy policies for five years.

But pivoting to the cost benefit from the operation of Diablo Canyon, the $3.2 billion benefit to customers through 2030 was already mentioned. That's based on CPUC issued energy and resource adequacy market price benchmarks. They issue that every October. Chair Reynolds discussed that that will be updated again this October.

So based on the numbers that are public, that's 3.2 billion customer savings through 2030, but 540 million average net cost benefit to customers. And when you factor in that societal environmental benefit of it being clean and greenhouse gas free, that's another additional 450 million calculated. So close to $1.0 billion annual average benefit for keeping Diablo running.

And it was also mentioned earlier about the net cost to customers statewide is, you know, reducing statewide energy costs by 3 to 4%. I know, cost to customers and rates has been mentioned as well. So I wanted to highlight that.

From a local economic community benefit, in San Luis Obispo County, one of the 58 counties, it's over 1300 head of household jobs for Diablo Canyon coworkers. We're represented by three incredible labor unions, the IBEW, SEIU for our security force and the ESC for our engineers and others. In addition to that, like in this year, we have two planned refueling outages.

And in each of those refueling outages, we bring in 1100 temporary workers to our community. So quite an economic boost to our community. During those refueling outages, we provide hundreds of thousands of dollars in donations and volunteering and so on and so forth.

And then finally, the recent polls that are out there is showing over 80% of residents in the surrounding counties supporting Diablo Canyon operations. So that's a number that's local under those counties of Slo County and Santa Barbara county and Monterey County. But nationwide, those numbers are over 70% now supporting nuclear power, advanced nuclear powers and technologies.

Regarding the extended operations customer relief, Delphine, Ms. Hou went over most of this, but I just want to point out, you know, at the direction of the state, we did apply for the credit award payment agreement under the DOE civil nuclear credits. We signed that contract in January 2024.

Those credits and that funding is to pay back the 1.1 to pay back the state loan over 1 billion from that DWR administers. So that's how that process will work. The first credit will be awarded the end of this year because we'll be in finally the period of extended operations.

And that's how the credit award payment agreement works, is that we have to enter into that period of extended operations to receive those credits to then go into an escrow account to pay back the state loan.

And then the other thing that Ms. Hou said was that the from the final, any excess market revenues from the final year of operations would be another funding source to be used to repay the loan. I wanted to bring this up of an overview of PG&E's statutory requirements from Senate Bill 846.

Senator Laird, you mentioned in the opening remarks that you wanted to talk about this some more. So I'll make sure I get through this presentation so we can open it up for more dialogue. We talked about, you know, seismic and the loan repayment, spent fuel capacity, taxes and land and so forth. From the status that we've completed.

We have completed all the requirements in SB 846, including the updated seismic assessment that was issued to TWR in February of 2024. We've completed other studies like on deferred maintenance, that's in SB 846. But I'll wait for a question so I can dive a little bit deeper into those topics.

And then finally the PG&E filed for a 20 year license renewal application in November 2023 with our federal safety regulator, the Nuclear Regulatory Commission. Because that's the NRC's process. They look at safety and they look at environmental on a 20 year time frame. Even though we've only been asked to operate five years.

That's the process that the Federal Government has. And so we'll be subject to policy direction by the state to go past 2030. But just wanted to highlight that difference because we get those questions.

And as I mentioned, In June of 2025, not only did the NRC issue the environmental impact Statement, the supplemental one confirming that we are safe to operate until 2045, they also issued their final safety evaluation report documenting that.

But as part of being on the Pacific Ocean and on on a body of water, we have two other state requirements that the NRC needs to see and that's the consistency certification from the California Coastal Commission and then also the Regional Water Board for water quality, a 401 certification.

We expect those decisions in first quarter of next year and we've been working with both those agencies discussing their questions and so forth and I think that's the last slide.

I do want to thank you again and I know we're going to get into questions, but I also welcome and invite any of you and your staff to come to Diablo Canyon anytime. Senator Laird has been there and other Members of this Committee that are not here.

But it's an incredible facility and it's amazing to see 10% of California's power and how safe and secure and the commitment by dedicated nuclear professionals working there.

Good. I want to thank you for the presentation. Congratulations, being on the highest safety tier, that's a big accomplishment. And as you said, GSG free energy. So we appreciate that. Do you have questions? I do. And I just want to acknowledge that I did ask the CBC President for some follow up on the estimated benefits.

Turn has disputed some of those benefits, so I look forward to diving into that as well. As noted, we do have a hard stop I do want to turn on. I'll start with my colleague, Senator Laird.

Thank you, and I'm conscious of the hard stop. So I'm going to try to be as quick as possible. On the loan your we heard from the Department of Water Resources. Your statement was any excess market revenues from the final year of operations will, it says, will be used to pay the loan.

How is there certainty that the gap of 300 million will be met without coming back to the, to the taxpayers? I mean, what's on the bottom line to know that that's actually happening?

Well, thank you for the opportunity to answer. The short answer is there's nothing that guarantees that there will be excess revenues, particularly $300 million of excess revenues in that last year of operations. Obviously that's dependent on market prices at the time and the cost to operate the plant. But there's no guarantee of that.

It seems to me that we have to get to a point that there's a guarantee that the gap is going to be met and it's not going to fall back.

And I know that there was even a statement in a Sacramento Bee article in March of 2024 that actually said affirmatively that any excess market revenues in the final year of the extended operating period would be used to do.

And so let me just declare that is still an open question and we have to make sure that gap is closed in a way that there's not liability on the plant safety. While you said it was completed, there is this obscure process of measuring the embrittlement.

And the so called coupon was pulled to get to the process of measuring that embrittlement. But it doesn't appear that the results will be available till April of 2026. Is that the case? Because it seems to me that until there's a determination made about that, it's really hard to say that the safety things have been completed.