Assembly Standing Committee on Utilities and Energy

Good afternoon. I would like to call to order this hearing of the Assembly Committee on Utilities and Energy. We are here today for an oversight hearing focused on reliability, both near term this upcoming summer, and how we're preparing over the course of the next five years.

Before we begin, I would like to go over a couple of housekeeping items. As is customary, I will maintain decorum throughout the hearing in order to hear as much from the public. Within the limits of our time. We will not permit conduct that disrupts or otherwise impedes the orderly conduct of legislative proceedings.

Any individual who is disruptive may be removed from the room. The Committee is pleased to welcome the participation of our budget Subcommitee for chair Assemblymember Bennett today.

Many of the extraordinary actions taken to shore up electric reliability over the past few years have gone through the budget process, and Mister Bennett's continued oversight of these programs, programs is critical. Welcome, Mister Bennett.

And I also want to thank our panelists for being here this afternoon to hold this very timely conversation leading us into the summer of 2024. Over the past three years, the Legislature and Administration have taken extraordinary measures to shore up electric reliability.

I applaud these efforts, but also we cannot ignore the fact that many were just in time and have occurred outside of our normal procurement processes. Keeping the lights on is obviously absolutely critical when the power goes off, especially during a heat wave, lives are on the line.

Californians health and safety are impacted, and as you know, affordability is also a key focus of my work here as chair of this Committee. Adequate planning is absolutely critical to ensure that we make California's clean energy transition in the most cost effective way.

And so that's why I want this hearing to focus not just on our preparations for the summer, but how we are preparing in the midterm, in the two to five year horizon to ensure reliability. And I think, importantly, to ensure reliability at the lowest cost.

Some of the questions we'll be asking today are the efforts we undertook over the last three years abridge, are they helping us catch up to some of the bumps along the way? Are these efforts needed to ensure reliability into the future?

The tight competition in the RA market, the billions in General Fund resources spent on reliability programs, the just in time procurement, these cost drivers should cause us to pause and reflect on how best to face and resolve reliability challenges in the midterm.

So again, I want to begin by thanking you for your tireless efforts over these past few summers. Really look forward to hearing your perspectives and appreciate the balance that we are all seeking as we transition to a green grid in a way that is sustainable, reliable and affordable.

So with that, I'll open it up to my colleagues to see if anyone has opening remarks before we jump in. Vice Chair Patterson?

Yeah, I'm going to have two questions for the PUC, two questions for the DWR, and one question for CAISO. Those questions will form the areas of my concern and will essentially be my comments. I will hold off on those until I question the appropriate presenters. Thank you.

Thank you. And assemblymember Bennett, pleased to have you join us for today's hearing.

Thank you very much. Am I on? Yeah.

Great. I'd really like to thank the chair for the invitation to be here. I'd also like to thank the panelists for coming today. We have some of the best minds in California on policy here from the Energy Commission, the ISO, CPUC and DWR. I'm really genuinely looking forward to what you have to say today. As many of those listening know, over the past few years the budget has played a crucial role in funding some of these reliability programs that are out there.

And the previous year surpluses have allowed a commitment of $9 billion to those efforts, including creating the strategic reliability Reserve, expanding demand response to the demand side grid support funding power plant efficiency upgrades and distributed energy, subsidizing energy storage through the residential, solar, and the storage program and the long duration storage program, forgiving past due bills, as well as advancing hydrogen production and investing in crucial transmission projects.

The budgets also adopted significant policy proposals, including increasing the planning Reserve margin for publicly owned utilities, allowing renewable energy projects to seek permitting authority from the Energy Commission. And as the states General Fund now is facing this deficit, we're going to be forced to pull back on some of these programs.

So we have to ensure that we invest in the most effective programs with the limited dollars that we have. We'll also need to adopt policy reforms that ensure that our state agencies and utilities are able to provide reliable, affordable electricity for all customers, even through the energy transitions and challenges that come with climate change.

So I really look forward to this, and I do want to emphasize one other thing, and that is that we're not a command economy. In a command economy, it's really easy for somebody at the top to insist and hold everybody accountable and force everybody to coordinate. We are a democracy that by intention divides power up and divides responsibility up.

And so when you face a major challenge like this, switching from a carbon economy to a carbon less economy, you really have to work especially hard, diligently smart, to try to make sure you can pull all of these various agencies legislative bodies, Executive branch, all together to try to coordinate properly.

So that's the challenge for all of us to engage in all of those appropriate behaviors and policies that encourage the right collaboration and cooperation and avoid all of those things that traditionally bureaucracies are pretty good at, that keep us from being able to be coordinated and accept accountability and responsibility.

So I look forward to this being the start of a big push for us to have increased accountability and religious reliability and feedback. Thank you very much, Madam Chair.

Thank you, Assemblymember Bennett. With that, we'll go ahead and welcome our panelists.

So our panelists for today's hearing include Siva Gunda, the Vice Chair of the California Energy Commission, Alice Reynolds the President of the California Public Utilities Commission, Delphine Hou the Deputy Director of Electricity Supply and Strategic Reserves Office at the California Department of Water Resources, and Elliot Mainzer the Chief Executive Officer of the California Independent System Operator.

And we have asked Vice Chair Gunda to go first in order to provide all of us with an overview and a bit of a primer on reliability, planning and forecast methodology before we hear from our other panelists.

Just in terms of the format for our hearing, I think I anticipate that after people present, Members may have questions, but we'd ask that everyone stay up on the Dais so that we can ask questions and engage in conversation with the full panel. So with that, over to you, Commissioner.

Thank you. Thank you so much, Chair and Members of the Committee, thank you for this opportunity to be in front of you today and to provide the updates on the summer reliability for 2024. But also, as the chair pointed out, high-level planning that we all do here and answer any questions that you might have.

And thank you, Chair, for setting up the conversation on the importance between reliability, affordability and ensuring that we do both that in the near term, but also mid and long term. So thank you for setting the stage for that. So with that, I'll go into the first, next slide, please.

So just at a 30,000 foot level, just starting off with our broad clean energy agenda. I think as we think through planning for the state, it's good to start with the overarching climate agenda and how electricity industry and the, and overall building electrification kind of plays into that.

So at 30,000 foot level, when we talk about the cleanest pathways, the most affordable pathways to move forward in decarbonizing our economy and reaching our 2045 goals, there is a consensus that we need to electrify large spots of our economy and then underpin that with a clean and reliable grid.

Really happy to report that as of 2022, the latest data we have today, we are 61% zero carbon in California, and the progress continues to move forward. Also a high level reminder on what the Legislature has set the goals for.

So we're looking at continuing that advancement of clean electricity in California to 90% by 2035, 95% by 2040, and 100% retail sales by 2045. So as we continue this path on both electrification and deploying clean energy, it is important to know that we have unprecedented weather events that are driven by climate change.

It's important to make sure while we advance quick and fast here on clean energy, that reliability becomes a centerpiece for us. Going to the next slide, please. I apologize. This is actually when we do it, it's an animated slide, but we just have it as a single slide.

But just want to set this up at a 30,000-foot level on how we do a layered approach in planning as we think about it, in the 2045 timeframe, looking 25 years ahead, more in the planning regime of 10 year ahead, and really one year ahead and then operational timeframe of a given summer.

So what you see at the top line here, when we look at climate goals 10 to 25 year ahead timeframe, we really rely on the scoping plan to provide us a blueprint for the economy. And that gives us both the expected electrification demand directionally and the clean energy resources required.

And then we use the specific venue as SB 100 as directed by you in our regular updates every four years to really study a little bit more on an hourly basis all the way through 2045 timeframe. As you may expect, given the timeframe of 10 to 15, 20 years ahead, it's really hard to have a good demand projection.

So we typically rely on what are called demand scenarios, and we look at different demand scenarios and supply scenarios to construct a directional story of what we need to be building in California. And then comes the 10-year timeframe where things become a little bit more real. This is where we use a demand forecast and these demand forecasts, which are a lot more in line of what's most reasonable to occur, and you begin to do more stochastic analysis.

And this is where we, as the Energy Commission developed the demand forecast again in coordination with all other agencies that are represented here, and the demand forecast goes over to CPUC for their integrated resource planning studies. And CPUC then uses that analysis for pegging the procurement.

But once we do that in the 10 year timeframe, the next question is how are we actually reserving those specific procurement and authorization and steel in the ground for the purposes of supporting a grid. And that's where resource adequacy comes into place.

And this is where PUC and other lras are directing and taking action to ensure that we have enough resources reserved to meet the demand. That's in the era head timeframe. And finally comes CAISO in the actual operational timeframe. Again, CAISO does analysis in all these timeframes, and we do this in a coordinated fashion.

But really, as we approach a summer, CAISO is looking at it from a very operational timeframe. So how does that change every hour? The uncertainties of hydro, they use the latest information to give us a heads up on how it's looking operationally. So again, as we go along this process from a 10 to 15 year timeframe to a real time timeframe, the assumptions become better and better, and we have a better picture. Next slide, please.

So before we go into the more details in the presentation, just at the top level, the top lines for 2024, we have released jointly, the agencies have worked on this. We have looked at the 2024 analysis, and the latest information we have is in January.

As of January, based on the incredible progress we've made in adding resources to the grid over the last four years, we don't anticipate any supply shortfalls this year under standard conditions. In the previous years. Sitting in front of you, we were stressing about extreme weather events and how could we do it in extreme weather events.

Given, again, how much resources we have been able to add this year, even if a 2020 or 2022 events, those kind of heat events, show up, we still feel really well prepared. Again, there is some room for optimism, but also some caution, which we can explore here in the next slides.

But even under those extreme events, given the steel in the ground we have today, we have little to no shortfalls. But the caution there is, all these resources cannot be utilized in a minute, right. Some of those resources have to be turned on a few days ahead. And those require you to have the line of sight of, okay, the heat wave is coming up in the next week, so we can start preparing.

So if there is a sudden onset event or if there are coincidental events, like a huge heat wave is going through the west and coincidental with a huge fire happening that's disrupting a transmission line, those kind of coincidental extreme events could still pose a grid emergency. And we want to just lay that out as a caution.

And finally, as of last year, we have retired about 4000. Once through cooling power plants, they came off as scheduled. But again, thanks to your action with the funding that you provided, the state agencies, about 3000 of them, have moved into the state strategic Reserve. Those 3000 MW are not in the market.

They're not used every day, only under these extreme events. If the state were to green light it, they come online. And so those 3000 mw give us a lot of cushion under those extreme events. Next slide, please.

So with that, I'm going to go into a little bit of a snapshot on the progress to celebrate the successes that we have, but also as we contextualize within the caution of what we've learned. Next slide, please.

So this is our summary of the evolving things, both in terms of our planning and the circumstances we've experienced since 202020. We were completely caught off guard and we had a lot of climate models suggesting that the heat waves and climate change is coming. But that was about 10 years ahead of when it showed up.

We were expecting those changes to come in 2030 timeframe and it showed up in 2020. So one of the biggest challenges in 2020 was much of our planning was based on historical data. We were not projecting climate change impacts based on climate models that are taking into account climate change.

So those planning assumptions then met with extreme heat events that were so outside the bound of what our planning was. We had outages. So coming into 2021, we took a lot of actions to begin to both put climate change information in. But PUC has done some unprecedented procurement to greenlight our progress there.

PUC also changed the PRM requirements for RA. This is the Planning Reserve margin, the amount of resources we plan above the expected demand. And we were going into 21 and we still had extreme heat. But what happened was a coincidental extreme drought. The first time you had audible not having any megawatts.

But also we had wildfire on July 19, 2021. That's when we had the bootleg fire up in Oregon. And we suddenly had 4000 transmission coming into California lost in a minute. And we had to make that up in real-time.

And that's the beginning of the supply chain issues that we started to see because of COVID but also some of the federal tariffs that were levied. And so we thought, okay, we had two years under our belt, we are beginning to feel a little better in how we can plan.

We went into 2022, we continue to reassess the PRM, continue to take into account some of the supply disruptions, identified the need for a strategic Reserve, and we're working with the Legislature. And then hits another landmark historical climate event in 2022.

Just to give a scale of this in 2022, in September, the expected load and the Caisa system is about 45,000. We were hitting 53,000 mw on September 62022 and that didn't last more than 10 days. Right? So, and then even that peak didn't happen more than one day. But that is adding two ladwps on the top of Caiso just for a few days. And that's the extreme nature that we have to plan for moving forward and 2023.

Thanks to the Legislature for the number of tools that you've provided us in 2022, the funding for strategic Reserve and the continued work that we've all taken in, both improving our analysis but also directing procurement. With that coming into 2024, we look much better. Next slide. So, in summary, what did we do over the last four years?

It's really around improving grid planning, essentially making sure that we augment our historical weather patterns with more climate change studies, improvements to resource adequacy processes at PUC, and a large and diverse procurement that happened on the supply side.

There's a number of bills that gives us permitting authority and such to streamline and moving forward along with CAISOs work on interconnection, upgrade reform and deliverability reforms. And finally, while we are doing everything we can do to accelerate the clean energy procurement and stealing the ground, it is essential that we feel comfortable and confident that we can get through an extreme heat event in the short term.

And thanks again for the legislatures blessing, for lack of better words and giving us tools to get through that. So with that, I will pass to President Reynolds to just give a higher level of procurement strategy by PUC.

Thank you, Vice Chair Gunda, and good afternoon Chair Petrie Norris, Vice Chair Patterson, Members of the Committee, and Assemblymember Bennett. And just to outline our presentation, I'm going to go through a couple of slides and I'll turn it back to Vice Chair Gunda. And then we have additional slides.

So I wanted to provide a little bit of additional detail about one piece of the framework that was outlined by Vice Chair Gunda. And that is the piece of our planning process that relates to the 40 plus load serving entities, the retail sellers that are within the PUC's jurisdictional planning process.

And those are the investor owned utilities, PG&E, Southern California Edison, San Diego Gas and Electric, as well as the community choice aggregators that serve a significant portion of California's load and direct access providers. So in total, it's about 75% of the load in California served by these entities. And they're part of the PUC's planning process.

And so the slide before you shows the way we think ahead about what procurement needs to happen. So new resources that are brought onto line online. Our process is geared towards the CARB scoping plan. So we look at a greenhouse gas emission reduction target for the electric sector.

We take the portion of that that applies to the entities in our process, those load serving entities, and then we calculate what's needed over time to reach the ultimate target of carbon neutrality by 2045. And we also look, this is based on the CEC's demand forecast.

So each year we update, are planning in relation to that forecast as it gets updated by the CEC to make sure that we're tracking changing demand over time. And as you know, we are seeing demand change because of climate change. We talked about some extreme events. This planning process really is normal planning ranges.

And so that is, are we prepared for the worst days of every month throughout the year and then moving forward? Are we planning ahead and getting resources under contract and built so that they're there when we need them for the system, for reliability, and to meet greenhouse gas emission targets?

So over the past five years, so the slide shows, starting in 2021, we started in 2019 making orders and also reacting to the heat waves of 2020 with unprecedented procurement orders. The total on this chart is cumulative. At the bottom, it's 18,800 mw that have been ordered from 2021 to 2028.

And that really is, it's a record for us. And it reflects the need to deal with changing conditions, increased demand, as well as the greenhouse gas emission targets. And so the, and the order also importantly includes, the orders that we've issued, includes 1000 long duration storage and 1000 long leave time resources to reflect the needs of the system.

And Chair Petrie-Norris alluded to this at the beginning, is that we need planning to determine the best way to meet the needs of the system in the most cost-effective way. And so that's part of what our modeling does.

With our modeling, all of the individual load serving entities, the 40 plus entities also prepare their own plans. How are they going to meet their customers needs? All of those are compiled through our process and then monitored for reliability and procurement orders. From that, I'll turn now to the next slide.

So the next slide shows the resources that have come online. So this is pursuant to those procurement orders and then have been contracted to come online. So on the left side of the vertical line, these are actual new projects that are here that have been built to serve California loads.

And so you can see the great increase in projects starting in 2020 and going up to 2024. We saw that resource development has nearly doubled over the past four years. And in 2023 alone, we had a record of procurement, excuse me, record build of new projects at 5700 mw that came online.

And we expect that pace to continue. So, as you can see from the chart, the projects will be growing. And these are, I think, really importantly, these are projects that are under contract. So all of the load serving entities have done competitive solicitations, received bids, and entered into contracts with developers for these projects to come online.

So we've compiled that information and depicted it here in the chart, really just to show the acceleration and what we see as predicted. It's also, the other point that I wanted to note is that we'll talk about a couple of numbers here. So when you see the 18,500 resources added, that's a NQC number, meaning that's a number.

Okay. That's a nameplate number. Sorry. That is expected to. That's the. The project and the maximum capacity. So if you're talking about a solar project, that's how much maximum capacity that solar project can produce. That would be during the middle of the day for a battery project we have. But the solar project also has a different value.

And that value is what is the value that is needed at the time when the grid is most constricted. And for California at this point, it is at the end of the day, as solar resources are going offline. And so solar projects will have a different value that we call the net qualifying capacity value.

And the procurement orders that we issue are geared toward that number. We want to make sure that we have the capacity online when we need it. So the numbers look a little bit different from the nameplate capacity of the projects that are shown here. For batteries, it's about the same.

You can use batteries at the time the system needs them. So I wanted to make that distinction. But overall, we're seeing a rapid increase in deployment of projects. We also have stood up and are continuing to work on growing the tracking energy development task force, TED task force that helps to manage barriers that come up with various projects.

So really it's to expedite projects, make sure that if a problem comes up, we have a coordinated team of, it's an inter agency team that are ready to work through problems with those projects.

And sometimes it means getting the developer to talk to the utility to make sure that studies have been done on time and connecting people to make sure that online dates are met, and we've seen a lot of success through that process, and that's going to continue. All right, I'll turn it back to.

I'm going to pick up here for a moment. So thank you. So, Chair Petrie-Norris, pleasure to see you. Members of the Committee. Assemblymember Bennett, thank you so much for having me.

I wanted, as the independent system operator, I think you're certainly well familiar that our primary role, of course, is to maintain the real time load resource balance in California, keep the lights on in real time for about 80% of the state.

And as Vice Chair Gunda and President Reynolds have described, with this incredible amount of new resources that has come online in the last several years, our role has been to effectively integrate that into the system, to bring it online, to incorporate it into the energy market, and to make sure that it's dispatched efficiently.

Of course, I remarked just the incredible supply of four hour lithium ion batteries that have come on now about 8000 mw operating in our system very effectively. As you've also heard, we need to sustain this pace of onboarding of new resources for many years to come to stay on track.

And one of the other essential elements that we also have an important responsibility is to ensure that there's enough transmission capacity available to bring this next generation of resources on board. This is another area that has required exquisite cooperation and coordination between the ISO and the Energy Commission, the Public Utilities Commission, other local regulatory authorities, stakeholders across California.

And we've tried to really lean in here these last several years to develop a much more sort of forward looking, long term approach to transmission planning, including a 20 year outlook that we produced back in 2022, and to make sure that those core inputs around load forecasting and resource planning and reliability are incorporated into our transmission plans.

And so we've also attempted to use transmission planning as a forward looking variable that shapes the pattern of resource development and interconnection, queuing, and procurement rather than reacting to it. Transmission, as you all know, is a very long-dated resource. It takes a tremendous amount of commitment of time, dollars, and investment, permitting, citing.

And so you really need to stay ahead of the curve on transmission to make sure that you're able to deliver the next generation of resources. And of course, we all know that interconnection queuing with literally hundreds of thousands of resources lined up to have an opportunity to get on the grid is another area where we need to make much more significant progress in onboarding.

And we have a very ambitious stakeholder initiative underway right now, which again has involved cooperation coordination with our partners at the state to really try to make sure that queuing is no longer a barrier, that we're right, sizing the studies, coming out with studies that provide meaningful results for the ISO, for the utilities, and ultimately take some of the friction out of the system so that we can continue to onboard resources as efficiently and cost-effectively as possible for many years to come.

So we'll come back to some of the other issues, but wanted to add that dimension of transmission because it really is a critical variable in the reliability and affordability equation.

Thank you, President Mainzer. So just kind of summarizing. So we just went through the different planning processes and what PUC has been able to do in terms of procurement and then that Caiso has been able to do to help with connecting those procurement.

So for the overall history, I just want to end with the next slide, if you want to go to the next slide. So what does that translate to? What you're seeing here are the grid stress events over the last four years, including 2024, some of the results we have as of today.

And I would like to direct your attention to the bottom two rows, which calls the total emergency alerts in CAISO area. And then the next one is the total emergency alerts across the western RC footprint, RC west footprint that CAISO is a reliability coordinator for.

As you can see there on the road that looks at Caiso balancing area, we had 24 of those emergency alerts in 2020, dropped down to five because of, you know, we didn't have that bad of a summer in 2021, except for the fire. 2022, we went up to 22 of those.

And 23, we were only at three because we had really good weather, complemented with the enormous amount of build out we've had over the last few years. But if you look at the west as a whole, those continue to be pretty high.

So if you look at RC west as a whole, that was 47 in 2020, and in 2023, it was still 29. So while we are adopting to the climate change impacts, the rest of the west is still catching up. And even in 2024, given some of the northwest issues we've had, we've already had eight emergency alerts in the west without Caiso. So thank you. I just wanted to close the history with that as we go into the 2024.

And I think, and then we'll just pause a moment before we jump into the 2024 outlook to see if Members have questions on the materials we've covered so far. All right, we'll start with Vice Chair Patterson.

Appreciate that Madam Chair, this is a question to the PUC. I noticed last week the San Francisco Chronicle reported that California's electricity rates are the second highest in the 50 states. I have sat on this Committee for the Last 11. I'm going on 12 years now.

And the term affordability has been thrown around over and over and over again. I don't know how you can define this pathway as affordable, as affordable compared to what our constituents are having. I mean, they're literally almost in rebellion.

We know that the resource adequacy rules require the utilities to buy enough energy so they have this margin, this cushion. But if these utilities, large or small, if they have to pay astronomical prices for these new resources that come online, who's going to absorb those costs? Have you done a serious, trustworthy analysis that this rush to this additional supply will have on rates?

Because my constituents in Central California are sitting in front of their television sets and they're seeing a very disingenuous pg and e advertising where the President comes on and basically talks about how they're undergrounding the power lines and how they're making all of these decisions and choices to make it a more reliable and more affordable grid that's insulting to our constituents.

All they got to do is open up a pg and e Bill. So how do you test the price tag of these new resources coming online? It seems to me that the more we are aspirational about the climate, the more our residents have to pay high costs. Can somebody address this?

Thank you for the question. And it is a really important question to think about how this work that is geared toward climate change targets is done and is done in the most cost effective way.

You're going to hear a little bit in the next part of the presentation about how the agencies have worked together on measures to address contingencies in the extreme climate events that we are seeing with an effort to minimize impact on ratepayers. And so we'll talk about different elements of those measures that are extraordinary.

And as you heard Vice Chair Gunda talk about, some of which are only needed for 10 days of the year or zero days of the year if we have a mild summer. And so we have to be really careful about investing, especially ratepayer funds, for capacity that's not actually needed and resources that aren't actually needed.

And so that's part of the reason we think about this in two ways. One is the normal planning standards, and we look to the load serving entities to do competitive bidding to make sure they're getting the lowest cost resources.

And then for extreme events, we look at other sources of funding, given that this is a statewide benefit, to make sure we're ready to handle extreme events. So to the extent we can, we've been working together, we, meaning the state agencies, together with our partner Caiso, on what tools do we have?

What are the most cost effective tools and how can we deploy them precisely and line them up precisely so that we're not overpaying for capacity that we don't need or energy that we don't need to meet our needs? And I'll also note that we are getting hit by climate change events.

We knew that this was going to be expensive when we envisioned what's happening with climate change and studies showing how our state is changing and how we're adapting to climate change. So this is a very hard issue.

I appreciate the continuing conversation on ways to reduce impacts on ratepayers because we have seen a lot of adaptation efforts to climate change, such as wildfire expenditures and other new expenses go into rates recently, and it is a huge issue. So thank you for highlighting it.

Yeah, well, look, when I first showed up here, we talked about affordable rates and affordable rates were here. 10 years later, you're here talking about substantial costs of new procurement which will affect ratepayers, and yet you're going to still use the term affordable when the rates are up here. So I don't know what you're doing to try to moderate rates, but I can't convince my ratepayers back home that it's moderating rates.

Thank you. Assemblymember. Assemblymember Bennett.

Thank you. Point out a couple of things. One, electricity is going to cost more in California. There's just no way we're going to. The lights on. Am I on?

Put the microphone closer.

Work the microphone. All right. Great. Electricity is going to cost more in California. The question isn't how are we going to get electricity costs less than it costs today? The question is, can we do all the things that we have to do to expand the grid, make it more reliable, make it more resilient, allow us to transfer costs that we have been spending for things like gasoline? They'll all be reflected in our electricity bill, but we have to do it as cost-effectively as possible.

And I think that's what I'm hearing the agencies referring to. But I think we fool ourselves and we fool the public if we don't say electricity rates will cost more, water will cost more in California as it becomes more precious. Electricity will cost more in California as it becomes more precious.

But there will be offsetting aspects to that. Like I mentioned, the gasoline. There's also something we have to be aware of. When you're switching from one kind of market, a carbon-based market, to a carbon-less market, there's going to be significant dislocations, and those will cause cost to go up also.

Again, we need to do the best job we can. So, I just want to respond to this, to that question, because it's going to keep coming up. And the question is, are we doing the best job that we possibly can? But the four quick questions that I have. First of all, could one of you or all of you jointly just summarize who's responsible for grid expansion from planning to actual implementation? How does that work through the authority process?

It really is all of us. Yeah. And so maybe I'll start and then others can jump in. When you think about a timeline starting from demand forecast, the Energy Commission, they do the demand forecast. They have experts working on that. They're looking at changes because of climate change events. That demand forecast comes to the CEC, CPUC.

We use it to do our planning process with the load-serving entities who are responsible for the procurement and deciding what sources of energy they're going to use to generate the electricity to serve all of their customers. So, we look at the procurement orders. Integrated resource planning is what we call it.

And all of the load-serving entities have a plan with particular types of resources. We use that to put together a transmission plan, and that's our transmission planning process. We call it the TPP. And that goes to the CAISO. And maybe President Mainzer, you want to talk about your process.

So, our plan that is based on the load serving entities, integrated resource plans, or IRPs tiers into, you know, exactly what do you need to serve your load, then what is needed in terms of transmission to make sure that generation can get where it needs to go throughout the system every day of the year, every hour of the day. And then that goes to CAISO for transmission planning.

Just, if I could. I just want to be clear. You identify how much load is needed?

Yeah.

You identify how much load is needed. And then.

And then the procurement and the resource adequacy obligations happen at the PUC.

The procurement of the energy, but not the grid procurement aspect.

The procurement of energy drives what's needed for the grid. So when we look at cost effectiveness, we include what's needed for the grid to make that generation work for the needs of the system.

The actual grid implementation goes to CAISO.

That's right.

We take the core inputs from the Energy Commission, the integrated resource planning from the PUC, and then our transmission planners in Folsom conduct a very exhaustive analysis to figure out which combination of transmission lines and also non-transmission solutions, including grid-enhancing technologies, will best meet the needs of the state, married together with our, with the reliability standards and an economic analysis to see if there's any.

I want to be respectful time wise. So just one other question. You talked about the queuing.

Yes.

And it's probably the number one thing that I'm hearing is the queuing problem and the problem getting connected and the problems, the lack of flexibility in terms of being able to connect. People are willing to pay for it themselves and do it themselves. Can you address that briefly? Where are you going and what do think the solution is?

It's a critical issue. The first thing we're trying to do is we've focused so much on really having an actionable, solid transmission plan. As we're saying, folks need to queue up in areas where there's either existing transmission capacity or whether we're planning to build it.

And projects that are lined up with the plan are going to have a better chance of getting studied, getting through the process. We're also making sure that our load-serving entities are also expressing some level of interest in these projects, projects so that we can say these are ones that have some potential commercial viability as well.

So, we're using more sorting criteria to define a smaller subset that we'll study and eventually pass on for procurement to the utilities. So again, it's about coordination, but cutting down the total number of projects to a manageable size that doesn't have the planners and the folks that have to construct paralyzed with an oversupply of resources.

Literally just decreasing the queue by prioritizing it.

Basically. Yeah. I mean, at the end of the day.

Wow. Okay. Thank you.

Yeah. The queue is meant. People can come into the queue, but we're going to say we're going to use a more stringent set of sorting criteria than we have in the past.

Thank you very much.

Assemblymember Bauer-Kahan.

Well, that was perfect, Assemblymember Bennett. You set me right up for my question. So, I'll start with just one quick remark on what our Vice Chair said about affordability. I know this is a reliability hearing, not an affordability hearing, but we can't talk about one without the other, as the President so aptly said. And I do think it's really important that we highlight that the IOUs come in wanting to build infrastructure because they want a rate of return.

And that it is our role as the state to make sure that we are putting first our constituents who need reliable energy at an affordable cost, and that we not prioritize the return of the investment of the IOUs, but instead our constituents. And so, I think this process is really important that we're talking about this.

And one of the things that I think came out really clearly in Mr. Bennett's question was the silos. I've always been fascinated by this sort of system that each of you has, but all comes together to create this system and it really is the most efficient way to be doing this.

And so one of the things I wanted to understand a little bit better is in order to make these decisions. And Vice Chair, you actually did a good job of highlighting this. There's so much science and prediction, I imagine that goes into what is the future going to look like. Right?

And you have resource adequacy determinations coming out of both of your shops and it's. And are all of those done separately? Do each of you have different departments that are doing these forecasts separately or is it all happening together? Just curious because it seems inefficient if everybody's doing their own.

Yeah. Thank you, Assemblymember. Just kind of taking a cue from Assemblymember Bennett's comments at the very top. I think the, the specific role that each of our agencies have are very different. So, CEC has the role of around planning, PUC has more regulatory. So, the commission actually votes on stuff that is very different from CEC.

So, I think in developing these state agencies, I think the Legislature saw need for that separation of role. But as Assemblymember Bennett mentioned, given the extraordinary situation we are in right now, and you pointed out, we really need to de-silo and make it really efficient.

So, since 2015, there has been processes on the demand forecast called the JASC, Joint Agency Steering Committee. The staff meet every week. The joint agency staff, we all kind of help each other on different elements. CEC is largely develops the employment necessary personnel necessary for the statistical analysis of the forecasting.

But PUC staff and CAISO staff attend those meetings every week where CEC is sharing. This is what we're doing. Is this correct? Not, are your back-of-the-envelope calculations in place? So, we do that, and that then goes to what we call a principal-level meeting. So where President Reynolds, myself, and President Mainzer. We all meet quarterly once and make sure that we're all on the same place. But when it comes to, let's say, IRP and resource planning, the expertise lies with PUC.

And so we hand off the demand forecasting to the extent we can support that with, for example, PUC staff might say, you know what, the forecasting, we would like to incorporate these additional variables. Can you do that? And then we do that and share it with them. And they have the expertise to specifically run the resource planning models.

And I'll add, I mean, first of all, reflect on the fact that it is complicated, but we also have different areas of specialty. And so, as the Vice Chair noted, the PUC is the regulator, meaning that we issue prescriptive orders, enforceable orders to the IOUs in particular, but also do the planning process for all of the load-serving entities, including CCAs, who are more and more serving customers in California, even if they're using the distribution system and transmission system of the IOU.

So, they're making the decisions about what sources of generation serve their customers within IOU territory. And we need to make sure the planning is done so that all of the 43 plus load-serving entities have their share of the load forecasts that CEC does, but then also is coordinated among all 40 plus of them, and that they know what they need to do to make the system reliable as a whole in of course, a cost-effective way.

And then we're iterating on that. So, we look at each year, and then we do 10-year planning, and we're starting to even look ahead to 2045. And so, in that way, it's the load-serving entities that are driving the generation we expect the utilities who run the distribution and transmission system to support that.

We also have private transmission developers as well now. And so those developers need to support the generation decisions that are made by the load-serving entities. And we need to make sure that we're building ahead of time so that we're ready, but also not overbuilding because that's very expensive. We don't want transmission we don't need. We don't want generation we don't need, but we want to be ready and we want to be ready for any condition. So, it's a little bit about the why as well as the how.

Yeah, I mean, I think that what I'm trying to get at is that I think that as we do demand forecasting resource adequately, it all is being informed by forecasting and predictions of the future. And you have different roles within that. But I guess what, I think the efficiency would come, and it sounds like maybe this is happening from what the Vice Chair said through those meetings you mentioned, of everyone working off of the same set of data rather than having three different entities that are deciding the forecasts are all over the map as scientists.

So, it allows us to develop specialties but also coordinate with each other.

Right. Okay. Thank you.

Member Friedman.

Thank you. Just a couple of questions and along the same lines. So, I just, I am still trying to understand how is it that you had, the CUP had said that all of the load-serving entities had met their resource adequacy requirements, and yet PUC still ordered this additional procurement.

So how does that happen and how do we make sure then that we are not sort of over worrying, over forecasting, spending a lot of ratepayer money, ordering this extra procurement that we then don't need? So, what are those checks and balances in that?

So, procurement, the procurement orders are driving the build the projects. And so, looking ahead at what projects we're going to need for the future, for reliability, and for greenhouse gas emission reduction. So, reducing the use of gas and really targeted toward reducing the use of gas on the system.

Those orders tell the load-serving agencies, here's what you need to build in the future, and they contract for that. In the near term, though, we have resource adequacy requirements, which is essentially, is that energy. Do we have the available capacity? So, is the energy going to show up when we need it to serve load?

And so, we require all of the load-serving entities to look at the worst day of each month and contract for firm capacity for those months so that we know that the resources will be bid into the market they'll be available when we need them.

So, it's almost like a layer on top, a reliability layer, capacity layer on top of the procurement orders that really are for the projects. And when the procurement orders are met with projects that come online, then we do have more available resource adequacy because those projects are there to provide capacity when we need it.

So, if I read the report correctly, there was about a gigawatt extra procurement that wasn't necessary. Did I read that correctly or?

Yeah, I think so, in terms of the authorization of the procurement currently. So just to add to what President Reynolds mentioned, one of the common thing that all three agencies do in understanding how many resources we might need is this stochastic analysis called the one in 10 loss of load expectation.

So, this is taking into account the variability of generation and the variability of demand, and trying to do an analysis, statistical analysis, saying for us to not have more than one outage in 10 years, how much do we have to build?

So, that is a common platform we all use to kind of guess what level of resources we need. PUC, given that the variability in the extreme weather events currently has authorized procurement that is in addition to that one in 10 levels to future proof, some of that, but not all of those resources will be contracted for RA today.

Okay, let me switch gears. So, Assemblymember Bennett and Assemblymember Ting and myself had been involved in some budget discussions in the last few years on distributed energy funding appropriations to address reliability. But I understood from my own AB 2891 this year that not all state-funded, and ratepayer-funded programs are able to help lower our RA needs and avoid expensive wholesale power purchases.

It would be really unfortunate for, I think you would agree, for the state to fund these incentive programs, but we don't actually harness the resources to help reduce the costs that are associated with our reliability needs. So I'm wondering if you can elaborate on and explain how we can better align our DER program to reduce customer cost impacts from those increasing RA prices.

Yeah, absolutely. I'll start and then pass to President Reynolds. I think, Assemblymember, if we go back to 2020 and coming out of 2020 and really looking at 2021 in these oversight hearings, and when we discussed where are the reliability problems coming from, the reliability problems were not just coming from extreme events.

We were also talking about the delays in potential procurement, coming from the lack of updates from the forecasting standpoint in incorporating those climate change events. And then we also talked about the supply disruptions and inability to build. So all those issues were stacking up. So if you look at the last three years versus where we are and where we are going forward the last three years, we were digging ourselves out of a lot of different holes. So we needed all of RA. We needed every resource we need and we needed to build.

But moving forward, what you will see from the rest of the presentation is we're coming to a good equilibrium, new equilibrium, where we will be able to optimize the resource build to meet the planning standards. And the non-ratepayer funded projects that you gave us will be really utilized to augment the resource planning.

And I guess I'll also add that we think about different types of tools. So resource adequacy is for normal planning standards. We also, especially from 2022, have learned that we need to plan for extreme events. We need to be ready. And so we've developed contingency measures which are not as, which are available for emergencies. They're not supposed to be available on regular days. We don't pay for them to be available throughout the year, every month, but they're available for emergencies. Some of these are even pay for performance. So we only pay if we use them.

Others are, we pay in advance, but we know they're there and we only use them for emergencies. And that's a way of not overpaying, I guess, to have resources sitting around. So kind of, we think about some of the state resources were in that latter category of the contingency resources. And we'll be talking a little bit more about that later in the presentation.

I'm wondering just briefly, and if you're going to be talking about this later in the presentation, you can just tell me that and we'll move on. But I'm, of course, very gratified to hear about the long term IRP procurement activities to bring on more renewables. And we're really thrilled with the progress on that.

And I'm wondering how that stacks up to the long-term RP's procurement activities and whether there's a target date plan for CPUCs to integrate the two plans together, the IRP and the RPS. And, you know, so that we sort of coordinate them for our long-term decarbonization goals.

Yeah, that's a great question. That's absolutely how we think about it, as coordinated. So the load serving entities have their IRP requirements, which have certain eligible resources, and, and then we apply the GHD standard. So it's a larger group of resources that would qualify for the IRP compliance, but they're integrated.

So the LSEs, at the same time they're meeting IRP procurement requirements, they're also meeting RPS, so they just have to make sure that they're doing both. And we're checking both as they go, but they complement each other, and there are two different state policies that we're implementing together.

Okay. Thank you. And so is there a target date to kind of? I mean, is it?

Well, the target. The latest target on RPS is 60% by 2030. And so once we get to 2030, RPS, the final target will be reached, and we have IRP that's going beyond out to 2045 concurrently with the scoping plan. Thank you.

Assemblymember Wood.

Thank you. Chair. A couple questions. I heard, Mister. So, Gunda, you talked about as we get into these extreme weather events and predicting them, you sometimes need a couple of days to bring up certain cuts. What kind of power are you talking about that you need a couple of days to bring online?

Yes. So when we talk about the different resources we have in our stack today, that once-through cooling power plants, for example, that the natural gas power plants that have been moved into the strategic Reserve, that would require us to have at least a couple of heads up, a couple of days of heads up that the heat wave is coming so it can be warmed up to help with the event.

Like peaker plants, that kind of thing.

This is not a peaker plant. This is larger than a peaker plant that would need some warm-up time. And I would request Director Hou to just add on to that.

Sure. I also want to add, in addition to those plants, just representing my state water project colleagues and maybe other water agencies, is that water? It's an integral part and touches upon electricity a lot. But obviously, for the water agencies, it serves a different purpose.

But there are times during an emergency on the electricity side that the water agencies have some capability to help with electricity, for example, reducing pumping load if they can. However, because water moves and has to be moved physically from one place to another, it actually does require multiple days to let the operators know that the pumping needs to be reduced in x number of days down the road. So those are some of the reasons why, for a slower moving event, we do need those extra days to coordinate with the appropriate entities for response, if they have it.

Yeah. Assemblymember, we're just kind of in contrast to that. Like an event on July 19, 2021, we had the fire knockout the transmission lines. It's almost impossible to get an OTC power plant react in that moment.

Yeah. Okay. So. And following up on your process for obviously you have the demand forecast and the IRP, and then CAISO does their planning as well. I've noticed in some of the situations where the CEC forecasts something, the PUC comes up with another number and then you come up with a third number, Mr. Mainzer.

And that's sometimes that's lower and that creates concern among some entities out there that are looking to invest in green energy. So how often does that happen where the forecast and the IRP then lead to Caiso downgrading, so to speak, how we're going to build out for that capacity?

I think one thing just. It's always important to understand that sometimes, particularly the Energy Commission will be looking at the entire State of California. And because we only represent 80% of the state, there will be sometimes just an inherent difference there.

But usually I would say when we're looking at the common footprint, we're working pretty hard, and I think fairly successfully, to have common assumptions and common standards.

You'll hear when we turn to 2024, we are using that industry standard one in 10 loss of load expectation, and we work very closely with the Commission and with the PC to, to harmonize those numbers.

So honestly, maybe if you have any other specific examples, but I think generally there's pretty good consistency between our reliability assessments at this point.

Well, I think recently there was some related to offshore wind planning, some numbers that came out and then your numbers downgraded. What would be built out?

So just if it's a. I would say that, you know, we are, there are some very. The longest dated sort of aspirational numbers for offshore wind are large numbers north of 20,000. Think for this particular round of transmission planning, based off the PUC's assessment, we've elected, looked at a smaller slice for starters. So that's the 4000 mw.

But it's not really a disconnect or a downgrading. It's just that's what we've been asked to study at this point in the planning cycle.

So. And that kind of takes me to the. And thank you for that. That kind of takes me to the concerns that we have as you look at our goals. CPUC called between 21 and 23, procurement of 3.3 gigawatts, 23 to 26, we're looking at 11.5. Then recently CPUC called for an additional four gigawatts to come online.

So that's about seven gigawatts per per year. And does the grid have capacity for adding at this level? Because when you look further out to 2030, I think it's 2035. We're looking at 56 gigawatts. Where is the capacity for that?

Yeah, this really gets back to my previous point, which is that at this point we are still largely, we've awarded quite a bit of transmission capacity going forward that we should be able to serve for the next several years.

But we really do need to be able to get after the next round of transmission construction with considerable alacrity. So it's breaking down those barriers, getting the planning right, getting the permitting, getting the siting, getting the capitalization, getting the construction so that the next major tranche of transmission capacity will be available. And that's a really urgent issue here in California.

Well, it is an urgent issue, and I keep asking questions about that over time because we hear from, certainly from industry, I've seen some charts that say from beginning to end to construction, we're looking at up to 12 years. This is 2024. And if we're looking at 56 gigabyte gigawatts, excuse me, gigawatts by 2036, that's 12 years.

And our goal is 2030 is in that timeframe. You talked about that. It's an exquisite exercise to come up with the planning. I've been asking these kinds of questions for a couple of years now as to how we are going to get there. Transmission.

I think we even heard a couple of years ago that there are green energy resources that cannot be onboarded because of our challenges with our grid. And so we've also heard somebody, I think it was you, sir, said that we're concerned about potential oversupply of resources, or maybe it was President Reynolds, an oversupply of resources.

When has that ever happened? And have we ever overbuilt transmission anywhere in our world? Because if we have, I'm not aware of it. Go ahead.

Well, in the past we have, the PUC has been criticized in past years for allowing too much, too much generation, too much transmission being.

But if we have these goals, if we have these goals that we're supposed to be moving toward as per legislative mandates. Right. How do we get there with the timeframes is what I'm getting at.

Yeah. And given the conditions that we've seen in the past few years, we've realized that, that we do need to build and that what we have now is not going to be sufficient for where we expect to be in 2045 and where we hope to be given transportation, electrification and building electrification and the need for electricity supply.

One thing I want to note is that first, the total procurement numbers are big numbers, and you kind of think big projects, but it's actually a combination of many smaller projects. So there are hundreds of projects that we expect to make up those numbers. And some of them might require a substation upgrade.

Some of them might require some enhanced grid technologies, and then some, like offshore wind in the north coast, likely requires new transmission. And so one element that we haven't talked about is in the transmission planning process. The PUC sends over a base case for transmission planning and a sensitivity case.

The base case has the numbers that are actionable based on load serving entity IRP plans that need to be studied by Caiso, and transmission needs to be ready and in motion. Sensitivity case allows studies to happen, costs to be more accurately defined, and then it can feed back into our IRP process to go through the next cycle. So it allows us to look ahead.

The sensitivity case usually includes a pretty big number, and it allows Caiso to be creative about what might happen, what we might need, and study that with more detail and send it back to the PUC for us then to incorporate those costs and see what pops up in terms of cost effectiveness.

So noting that this hearing is really about reliability, and I'm going to bring it back to that as we continue to add resources to the grid, and noting that I don't know where we are in the queue as far as what transmission is coming up, and maybe that's something that could be offered as information from you guys so we can know how much transmission capacity is coming forward, what those projects are, where those projects are.

That would be helpful. But as you continue adding resources, at some point, is the whole thing just going to go poof? I mean. I mean, or do we actually have the grid reliability to sustain the continual addition of resources?

And if not, or if we do, then can you show us a bigger plan on how that's going to work, please?

I appreciate the line of questioning, and I'd like to just give you a couple of really tangible examples that I do think reflective, because all of us, we spend a lot of time on this specific issue.

So, first of all, in 2022, after taking, after significant effort with the Energy Commission and the PUC and other entities in California, we produced a 20 year roadmap of the California transmission plan. If you don't have a copy of that, make sure you've got a copy of that. Right.

That was our opportunity to sort of step back and take a look at the big architecture of California onshore, offshore, into out of state. What's the sort of master plan. Right.

We then last year had about 45 transmission projects approved by our Board of Governors, about $7 billion worth of transmission investment, which, which was again a function of a 10 year planning process with the state agencies and the utilities and the other stakeholders in the state.

And that plan, we're now in the process of beginning to award contracts to build some of that infrastructure, and it's now working its way through the capitalization and financing, permitting, siting structure.

And those are the next generation of transmission projects which need to get built so that the next generation of procurement can be successfully commercially consummated and then brought online onto the system.

And my emphasis on getting ahead of the curve in making sure that the transmission is planned and then built, constructed and energized and that the queuing processes and the procurement processes are aligned with the transmission plan is an essential part of our shared strategy. And happy to discuss that with you in greater detail, offline if necessary.

But the plan, we're just in this month, just in two weeks, we'll be taking the next tranche of tenure transmission planning to our Board of Governors for another round of approval, and that will be a subsequent round of investment to further make sure, as you question implicates that the grid has the transmission capacity to onboard resources for years to come.

And then the final kind of the final, I mean, I'd heard have we ever overbuilt transmission? I mean, considering how we are pushing everyone towards electrification. But I hear concern that we're worried about overbuilding or over procuring. Have we ever overbuilt transmission?

In the 1930s, we built a lot of transmission. Okay, we are not in the 1930s. So there was a period of time when we built a lot of transmission. We're still living off of the transmission our predecessors built. That's why everybody is today saying it's so important to build transmission. You want to right size it.

I want to emphasize, and I know the affordability questions. We understand that we're acutely sensitive to that. And we do everything we can when we do our transmission plan to try to reflect back to the state a transmission plan that really is the least cost infrastructure plan.

And we do embed grade enhancing technologies and non wire solutions into that. But at the end of the day, we are going to need a lot of transmission, and so we're ready to get going. And I think everybody's motivated to see it get energized.

I would bet in the 1930s it was easy, cheap, and fast.

Yeah. I don't want to be glib about it. It's time to invest is the bottom line.

Thank you. All right. Before we jump into the summer outlook, I do have a couple of follow up questions. So Mister Mainzer, picking up on the conversation around transmission, and I think you heard from a couple of other Members' questions.

I think there's a lot of concern, and I shared this with you yesterday when we met, about the fact that it's taking 8, 10, 12 years to build these projects. I think it would be super helpful if you could. Well, two things, I think one will certainly distribute that 20 year transmission plan to Committee Members as a follow up here.

I think it would also be super helpful for Members as well as folks listening to understand the key reforms that you have planned and the upcoming milestones associated with that and when we can start to see some of that move more swiftly.

Certainly. Well, I think, as you're all aware, this issue of queue reform is a topic that is of major concern across the country.

And the Federal Energy Regulatory Commission, which, of course, has promulgated these rules for many years, has also, I think, come to that conclusion. It's why last year they actually put out a set of reforms to interconnection queuing, which established sort of a next baseline of study efficiencies and some milestones which all of us that are jurisdictional are now obligated to comply with.

As a matter of fact, we'll be submitting compliance filing to that in the next week or so. We have elected to go above and beyond the sort of baseline reforms that are embedded in what's known as Order 2023, because we think even greater coordination and greater sort of sifting of the queue is responsible.

And again, I want to emphasize that our theory of interconnection queue reform is indexed to a rational coordination of load forecasting, power planning, and transmission planning, and having a transmission plan which again, does not react to a lot of commercial activity, but actually shapes the pattern of resource procurement and interconnection queuing. And what we've been doing, we've had a very, very comprehensive effort with stakeholders from across California, very intensive here in the last year.

It's known as our Interconnection Process Enhancements reform docket, in which we've said, we've asked ourselves how can we really separate out and study a rational number of requests, a rational amount of capacity that bears a greater resemblance to the actual demand for power here in California in the next 5, 10, 15 years, and provides study results that come up with an infrastructure plan that are actually sensible and rational and allow the planners and the folks that have to capitalize and construct the system to prioritize the right projects so that they're not paralyzed with several 100,000 megawatts of requests that are several multiples greater than the actual demand for electricity.

So looking at commercial readiness criteria, looking at alignment with the plan, looking at local impacts on the system, and providing a set of scoring criteria that determine which projects will then be eligible to be studied.

And if we even then have an excess of study requests, go even further to effectively ration, to sort of auction off the right to get studied. These are the reforms that we're looking at. I want to be clear that we are still finalizing this process. As you can imagine, there's a lot of opinions on this.

We will be taking this issue to our Board of Governors the week of the 21st of May. We'll allow stakeholders to sort of express their general positions on this, and then we'll be taking it back for a decision process on the 12th of June and then with the intention then of getting a filing ready to go to the Commission.

And so, and so by next year, we want to be in the position to start applying these new decision criteria to sort out the queue more rationally. So our goal at the end of the day is we want there to be a good competitive supply of projects to help support cost effectiveness for the utilities.

We want to give everybody a chance to get on the grid, but we also need to make sure that there's a rational set of sorting criteria and the planning and the studying bears some resemblance to the actual demand for electricity so that we can get projects built, constructed, and onboard resources and support reliability. Thanks.

Thank you. And then, President Reynolds, I want to follow up on Assemblymember Friedman's question about distributed energy resources, because I didn't understand in your answer. So how are we incorporating these distributed energy resources into our forecasting such that we're not effectively double procuring or having to double count?

So most behind the meter distributed energy resources are taken into account in the load forecast. So the load forecast will go down, and then that in turn, since we translate that into an RA requirements, the RA requirements go down.

Okay. And so you have sufficient visibility into those DERs in order to incorporate it as part of your forecast?

Yes. So we have data requirements that we currently collect information on everything that's over 1 megawatt. And then we have a lot of data sources. So what happens is in the forecasting, we start with the total number of electrons that are needed, so we call consumption, and then we remove all the things like energy efficiency behind the meter generation from it, and then send it over to PUC for procurement planning.

Got it. Okay. And then I do have one last question about forecast methodology. So, obviously, forecasts are based on data analysis, usually of historical data. The advent of artificial intelligence and just the huge explosion of AI is truly extraordinary and expected to create a, I don't know, it's like seven x increase in electricity demand or something. Truly astronomical. How are we taking that into account as we are forecasting for the future? Ensuring reliability.

Yeah, great question on that one. So, as a part of the demand forecasting process, every year we have a workshop that talks about emerging loads. So the last few years we have been starting to hear about the AI load.

So we have a dedicated workshop coming up this month, later this month, to just talk about how do we project that. And a part of that is once we hear stakeholder input on what their expected load growth in California is, we have to collect data.

So a part of that, and then we interage joint agencies, talk through how best to incorporate that into the forecast. But that is happening. One of the pieces, to use an example, was cannabis load. A few years ago, the cannabis load was exploding, and we were not really capturing that in the forecast.

And the steps were have a workshop, gather the information required, and then bake it in. And for those things like electrification that we are not clear about, especially industrial growth, we do what is called additional achievable scenarios. And we all agree that those are reasonable to bake in and we bake those things in.

Okay, understood. Great. I have a bunch more questions, but we'll go ahead and hear from Member Reyes and then we'll jump into the 2024 outlook.

I know I arrived late, but I don't believe you talked about the Diablo Canyon Power Plant. Or was that discussed? In the papers, the analysis that was provided, there was talk about page 12.

The background paper does mention the two reports that were required by statute when the Legislature extended the authorization of the Diablo Canyon Power Plant two years ago.

One of those reports was meant to, and I quote, present a cost comparison of whether extended operations at the Diablo Canyon Power Plant compared to a portfolio of other feasible resources available for calendar years 24 and 25 is consistent with energy sector GHG emission reductions.

The Committee notes that the CEC only looked at resources that could be online by 2025 and that were not competitive with resources load serving entities that were procuring. It seems odd that that was the way it was written, even on its own.

But what gave me great pause was the line at page 12, again of the background paper, which says, and I quote, it is unclear to Committee why the CEC analysis ignored statute and provided a cost comparison to a procurement that bears no resemblance to the actual procurement ordered by the CPUC to replace DCPP, Diablo Canyon. Can you explain why the CEC would ignore legislative statute when conducting this analysis?

Thank you, Assemblymember. I apologize. I'm tracking the question, but if I miss something, I would love to kind of come back to that.

It's page 12, the first full paragraph. But the most important part is at the second full paragraph.

Yes. I'll just kind of go from the CEC's thinking in kind of just doing what the statute asked us to do. The statute was asking us to look at resources that could be alternatives that could do what Diablo Canyon does. So when we explored that, we looked at three different elements.

One is, when we think about Diablo, it's a baseload 24/7, so we wanted a combination of resources that could actually provide 24/7 ability. So that's one. Two, it asked us to be able to replace Diablo.

So we looked at, given that the deadlines for decommissioning Diablo were in 24 and 25, we looked at the opportunities for resources to be able to do that. And third, we looked at whether the resources can have the greenhouse gas emission requirements as the statute calls for.

So when we looked at all those three things, and the stated one that you mentioned about, given the delays in procurement and the supply chain issues, we did not want the alternative analysis to compete with what is actually needed today to replace Diaglo Canyon down the lane. So when we took all of them in totality, our ability to bring in new resources that could fulfill those things did not exist.

Should we be expecting another report?

Yeah. While the statute, most of the 846 and 205 requirements asked us to continuously study. So as a part of our reliability analysis, every year we'll study some of these opportunities. But specific to that report, there aren't any plans now to redo another one.

There are plans?

There aren't. There aren't any plans.

All right. Thank you.

All right. We'll go ahead and move on to the summer 2024 outlook. Thank you.

Thank you, Chair. I think we are going to go. So we are going to go into the summer analysis, but I'm going to hand off to President Mainzer for that. But just before I hand it off to President Mainzer, I just want to point to what you have seen on the layered approach we talked about.

Now that we are in this really close to the summer, we are in this operational timeframe. At this point, the best analysis we have is coming from Cal ISO. So looking at this summer, I want to hand it off to President Mainzer for that analysis.

Thank you, Vice Chair and Committee Members. Later today we'll be actually releasing our, what's known as our 2024 summer readiness report. So I wanted to give you a preview here today. All of this procurement that we've described earlier today has definitely made a major difference.

Our analysis at this point does show a reasonable supply margin to meet forecasted demand and reserve margins for 2024. This is certainly a much better position. You could look at just some of the numbers. Nearly 6300 megawatts of new capacity added in 2023. Another 1200 megawatts of capacity brought on board just this year through April.

And as we mentioned earlier, we deploy, at the California ISO, a standard loss of load expectation model, which is sort of the industry standard used also by the other, the ISOs, which looks at a 1in 10 forecast.

And we believe at this point, our numbers are indicating that we have about a 2550 megawatt surplus going into this summer, which is certainly just an enormous improvement over the past several years. I wanted to point out just one other slide.

We're also at the point of the year when we start trying to start getting some reasonable fidelity on the weather forecast for the summer. We all spent a lot of time looking at the weather. At this particular point, looking in the summer, we're seeing an increased chance of above normal temperatures across the interior of California, but lower chance of above normal temperatures for the coastal area. This is actually fairly similar to what we saw last year.

So we're across June through August. We're likely to see significantly elevated temperatures across the desert southwest and potentially up into the northwest, but again, lower chance of above normal temperatures in those coastal locations where we have so many people living, particularly in Southern California.

As we get further into the summer, we do see a higher probability of things heating up in California. But that heat appears to be, at this stage, concentrated in the interior of the state, so not as extreme. I will note, hydro conditions are always an important part of the supply-demand balance.

As you recall, back in 2022, when we were still very much mired in the drought, we were able to import a significant amount of electricity from the Pacific Northwest. Between 22 and 23, those conditions really flipped on their head. We've had two very, very good water years here in California.

This year, we're in good shape hydroelectrically, but the drought conditions have really hit the Pacific Northwest, particularly up in the Canadian basin. And so as we get further and further in the summer, our ability, our sort of our net imports from a particular hydro from out of state are likely to be somewhat strained.

So that's a variable that we'll keep a close eye on, and just in general, the weather patterns both within California and from our other supply basins in the west. Back to you, Vice Chair.

Thank you, President Mainzer. Going to the next slide, slide number 15, to give preview the expected new resources to be added this year. As we mentioned, we added over 6300 megawatts last year. And recently there has been some press on the unprecedented storage we have in California.

So just over the last four years, as President Reynolds mentioned, we've added over 18,000 megawatts, but 10,000 of that can support us in the evening, which is really, really good news. So this year we're expecting to add another 7500 megawatts on the grid.

And just to kind of note that we are now at our first quarter mark, we had about 1200 megawatts in this year. Also, one thing we observed over the last four years, the build rates in January and February are the lowest because of the winter conditions.

And we start picking up as we go into the summer and really have high November and December rates. That's what we observe. Next slide. So just to kind of give then some precise numbers going in based on President Mainzer's kind of work. So if you're looking at the Dex table, I want to slowly walk through.

Each of this column represents a different year as we were walking in summer 2022, when we were doing the analysis ahead of summer 2022. I want to direct your attention to the last three rows. We were barely meeting our standard conditions in summer 2022.

If you looked at 2020 and 2022 extreme events, we were going into summer with 7000 megawatt deficit, and that's unfortunately what happened. So we had 7000 megawatt deficit going into that September 6 heat wave. And we had to do extraordinary things, including a text alert to keep the lights on in California.

Coming into 2023, again, this is a progress of having more and more resources on the table. The conditions were much better. So we were having surplus in the standard conditions, and we had some defaults or deltas in the 2020 and 2022 extreme events.

Because we are using the terminology of 2020 and 2022 events, that 2020, we had about 9% deviation in demand from what we expected. In 2022, that was 12.5% difference, divergence. So that's the enormity of heat that we've seen for a few days.

Now going into 2024, given how many resources we were able to add last year, we are in a much better situation. In the market today, we have about 4000 megawatts of additional resources above and beyond what we need to meet for RA. But as you go to those extreme events, the tightness begin to occur.

So one important thing I want to note here, this does not include a coincidental fire risk, a catastrophic fire risk. If we had a catastrophic fire risk, like what happened in Bootleg in 2021, that 4000 megawatts will be added as a deficit to these numbers. So those will be extraordinary situations that we had to deal with.

So going to the next slide, slide number 17. This is to kind of temper the optimism with some caution. We try to structure the kind of events that we see. It's anywhere from loss of imported energy to an earthquake or a cyber attack. Any, many kind of things could impact our grid.

So some of them are slow moving. We can see them coming, and some of them are starting onset. We cannot see them coming. So just want to caution that much of our work today supports those slow moving, visible conditions that we could prepare for.

But if it's a sudden onset cyber attack, sudden onset transmission fire, those are the things that we would not be prepared for, short of a few resources we have in our pockets that can quickly come online, including some demand side response. Next slide.

So then, going all the way back to 2021, this is a slide we showed you regularly in these meetings. When we talk about the need for strategic reserve, why do we need these additional contingency resources? Let me slowly walk that stack. The bottom dark blue is what we would need to procure to just meet our planning standards.

That's the representation, the bottom blue. Then you go to the next light blue. So given that all of these resources might not come online and there might be some developmental delays, you need to cushion that with some additional resources. Next, you add to that these extreme heat conditions and finally the catastrophic conditions.

So the top three buckets are what you're trying to meet with resources outside the standing planning process that might require some support from the General Fund. Next slide.

So going into 2024, we've just given you that we are looking good, but then how are our contingencies looking, those set of resources outside the planning resources, the large infusion of the strategic reserve with the OTC power plants that DWR has contracted for and Director Hou is going to talk about, we are looking pretty good going into the summer with the number of megawatts that we could rely on in emergencies.

So that's what this slide is about. So we will give you for each one of them, there's a top line, which is the strategic reserve is largely state funded. Those are the resources I'm going to discuss in a bit. But first I want to pass to President Reynolds to talk about the CPUC portion of those resources and then go to Director Hou for the resources from DWR.

Thank you, Vice Chair Gunda. So on the PUC side, as I mentioned, after 2020, the PUC opened an emergency summer reliability proceeding. And the intent of that was really, what can we do quickly to have additional megawatts available in emergencies? And those could be additional supply resources as well as demand side resources, meaning demand response.

How can we reduce demand quickly during emergencies and line those up in advance so we're not scrambling when we see an emergency coming on. So one of those, the first one is Emergency Load Reduction Program, and we call it ELRP, as well as the Smart Thermostats Program.

So that is on the demand side, and that program is pay for performance. And all of our load serving entities were ordered to essentially go out and see how much, see if customers, you can get customers to sign up.

There's no penalty if you don't perform, but you get paid if you reduce your demand when called upon in emergencies. And a large part of that program is residential and commercial customers. You might have heard of Power Saver Rewards.

This is just individual households if they're able to reduce demand compared to baseline, they can get paid for that during emergencies. On the commercial side, we have existing programs that pay for demand response during emergencies. That is part of our normal planning. It's part of the RA requirements. And so we have that.

We think about that separately, but we have relied on that program during emergencies. It is called when Cal ISO does an EEA Watch, and you might hear of an EA watch where certain resources are being called.

But we have known resources that we have relied on in the past and so that's kind of the first level of emergency support. We also had the IOUs go out and get additional imports that were to be available during emergencies. And then the third line is as available energy from installed resources.

These are existing generation facilities and where we could get additional capacity out of those, there's a contractual relationship that was set up by the IOUS so that they would be ready when called.

Thank you very much, chair, Vice Chair, Assembly Member Bennett, thank you for having me today. So I'll be presenting the strategic reliability Reserve, overseen by the Department of Water Resources, and that is the electricity supply strategic reliability Reserve portfolio.

So here I've laid out the three here I've laid out the three years that we have been able to provide the portfolio. Thanks to the foresight of the Legislature and improving the authorization, I'll focus on 2023 because that's quite similar to 22. So those two years are fairly similar.

So starting in 2023, we had 147.5 Megawatts these emergency and temporary resources for extreme events. That includes the 120 that was originally built back in 2021 pursuant to the governor's emergency proclamation. But we were able to retain those units and add to it. Moving down the 2023 column last year.

We were also authorized to procure additional firm energy imports and pay for the above market cost of those resources. That was also done in coordination with the CPUC to make sure that those procurements were above and beyond the resource adequacy requirements. So there's no double counting there.

We're still at the tail end of validating all the information and the assessments, but from what we can see at this point was coming in about 3400 mw, so very similar to what we had in 2022. And you'll notice at the very last row for temporary diesel generators.

Our authorization for that ended July 12023 but DWR opted to close that program early in favor of less emitting resources. So again, 22 and 23 fairly similar, and resources were available for any extreme events moving into 2024. This is where things are quite different. So we are adding to our emergency and temporary natural gas generators.

So we're going to be up to 291 mw for this summer. But the big change that we've talked about is starting in January 1 of this year, we now have three ones through cooling natural gas resources.

Those would have retired at the end of 2023, but for the joint recommendation from the CEC, PUC and CAiSo to the State Water Resources Control Board to extend their OTC compliance date so that these units can be put into the Reserve.

And that is really kind of bringing together a lot of the different themes that we've been talking about earlier today. So first and foremost, it touches upon reliability because these resources would be there to help with extreme events, but it also touches upon affordability as well because otherwise these resources would have retired.

But using the state funds and paying for them takes them out from ratepayer burden. But at the same time, I'm very happy to say that DWR was able to negotiate prices with these generators that were on average $10 per kilowatt month.

And just as an idea of what that compares to, we don't have the most publicly available numbers for resource adequacy for 2023. For 2024.

But I was doing a little sleuthing on the Internet and the ccas actually have on their website that they've been encountering some RA prices in 2023 that are as high as $60 per kilowatt month in the summertime. So again, could be very different resources.

We don't have any details or information, but that does show you that being able to sign these contracts early, being able to negotiate resources that would have otherwise retired, was a good move to populate the strategic Reserve. And lastly, also for emissions, this also creates a balance in terms of offsetting emissions to the extent possible.

So in the resource adequacy program, there is something called a must offer obligation. Resources must offer themselves so that the grid operator can see them, and then they are visible and usable.

And that is part and parcel of the resource adequacy program, which means that these OTC resources as of last year, had to be available 24 hours a day, seven days a week, so that they are visible to the grid operator as resource adequacy capacity. Now, with the Reserve, that is the opposite.

They are actually going to be default, turned off unless and until the CaiSo decides that as a grid operator, these resources could be needed to address either some projected or occurring extreme event.

So that is a sea change in the operational characteristics of these resources, of having them default off on the system versus on to be prepared all the time. However, those resources are still in the Reserve. They're being maintained.

We're working collaboratively with the resource owners as well as with Caiso to make sure that they're going to be available and ready to perform in summer. And then moving down past that, you'll notice that for firm energy imports that is also blanked out. We no longer have the authorizations flagging that that ended October 31,2023.

Thank you. Thank you, Madam Chair. Could I have a specific question about what she just went over? Can I just add. Sure. Very quick. And I really appreciate that the OTCs are now not on standby, but they're in Reserve. They're in our most disadvantaged communities, and so I hope we don't have to turn them on.

And I appreciate that Caiso won't do that unless they absolutely need to. But do you, given that we have an optimistic scenario. Do you think it's reasonable for us to say that in 2024 the OTC plants won't get turned on at all? You don't think that's reasonable? That'd be a great headline.

I don't think we can provide that assurance. I think.

I don't mean assurance. Is it possible that's different? Well, if things stay good.

I think. The reality of the situation is that we are still facing the risk of very extreme weather or fire or transmission contingencies. And we're going to be ever watchful. We'll reiterate the point that these will be a resource that we will only turn on in last resort, but I think there still is.

Thank you.

Yes.

I'll ask it one other way and then I'll stop. If we have the summer that we had last summer, would we be able to keep them off?

All right. With the caveat that they still need to be tested in order to be operationally ready.

Correct.

Okay. Thank you. So, chair, we have a few more slides. We'll try to get through this quickly. So just kind of closing off with another part of the strategic Reserve, which is state funded. So you got. The Legislature gave us money to have this two programs called the DSGS and DEBA.

I'm going to just move to slide number 22. In interest of time, go to the next slide. So at a high level, the nature of the DSGS, the demand set grid support, is very similar to what PUC is doing, which is these demand reduction resources that are operationalized through a few different pathways, but all of them are pinpointed to performance based payments. So in 2022, we had very little time.

In about two weeks, we were able to bring in about 315. TABLE but the reason we got 315 mw was all of them were diesel backup generators. And we want to be able to be in a situation where we supplement them with actual clean resources like demand response and virtual power plants.

So in 2023, we tested some new guidelines on how we can operationalize them moving forward. We have a very optimistic view, given the strong stakeholder process we've been able to do, that we can bring in a number of demand side resources that can actually support the grid during emergencies.

The DEBA, which is the distributed energy backup assets, is a slightly different beast. It has two different aspects to it. A part of the money, we were directed to invest in bulk side resources. So the bulk side resource solicitation of about 30 million has already been completed.

And that is going to get us about 300 mw by 2027. So that's in place and we're working on that.

One of the reasons why you see a lot of zeros on DEBA was we were taking the necessary time to go through a broad stakeholder process to really invest in resources that can come right after the OTC power plants, but we can have the time to do them thoughtfully.

And given that these are new resource development, it'll take some lead time. So that's the reason why you see zeros right now. But they're anticipated to come along. And one of the most important aspects of DEBA and DSGS, along with what DWR is doing is these are not ratepayer funded.

These are resources that are state funded and essential to go through the extreme events without rate payer burden. So then kind of going to the next two slides very quickly. Slide number 24 quickly that.

So given that we are looking at different operational timeframes, we are looking good this summer, but we also look at the next 10 years. The important part, I will actually go to 25. So to give you a high level.

The biggest part is the climate change is going to continue to show up in very different ways, both in terms of the heat, the levels of heat we'll see, but the frequency of that heat and how long those heat waves are going to be.

So what you're seeing on this slide is each bar constitutes to how many days you will have consecutive, over 100 days, for example, in Sacramento. So if you go all the way down to 1980s, you know, that was under five days on an average over 100 degree days.

But as we are going into the 2023 timeframe, it's already extended past that five into 6-7 days. And by the end of this decade, you'll be having 10-20 consecutive days that we have to have those additional resources for. And that brings us to 26. Okay. When you put all those numbers, what does that look like?

So what you're seeing here on this slide is basically a compounded worst case situation all the way to 2034. The reason why 2034 has extremely high negative numbers is one, extreme weather, but also two, we don't have procurement that far out. So as PUC brings in more procurement orders, those numbers will go down.

But I do want to emphasize to this Committee that this problem is not going to go away. It is. We are going to do everything we can to procure resources through resource adequacy and IRP that meets the standard level. And that standard level is about making sure we don't exceed more than one outage every 10 years.

Based on the stochastics. But as you move forward, given the weather variability, we will have these extreme events and we will need to have a path for that moving forward. So that brings us to the last slide I want to bring to you on 28. How are we preparing for that?

As we just showed you in 2023, if you look at the contribution of the strategic Reserve, it was broadly DWR resources, some DSGS resources, which was largely bugs, and some clean. 2024 to 2026, that stack has increased significantly because of the OTC power plant's presence.

Moving forward to 26 and 2030, if some of the resources you gave us in the budget continues to remain as we implement them, a significant portion of that will be made up with Deba and DHGs resources.

But I just want to make sure that you realize that we cannot bring in the levels of extreme weather resources we need with the current appropriated numbers. And we do not have a plan beyond 2030. Current levels of appropriation we have, and beyond 2030, we do not have any plans to continue that Strategic Reserve.

So the last slide, key takeaways again, just reminding, I think our analysis is looking much better going into 24. I have to say, I came here for a briefing right after the August 14 and 15th events. It was not fun to be in front of you and taking the questions of why the lights went off.

And I think to the point that was raised by all of you today, some of the tension continues to be between affordability and how many resources we really can build and how do we optimize that. I think the best case is if resources are cheap and we can build it, we should build a lot.

But as long as we have the constraint of cost and GHG, we'll have to always cap how many resources we build under an RA program and how many are we going to support through General Fund.

Overall, we will have to continue to build at the same levels that we have seen the last year, which is about 6000 mw. We need to continue to build that year after year through 2045. With that, a big stat for you.

If we are going to realize our resources, we need another 2 million acres of development in California. So with that, we'll leave that to you. Thank you.

With that. All right, we'll open it up for questions from Committee Members, Assembly Members.

Thank you all for being here today. You probably won't be surprised that my first. I have two questions. My first question is about offshore wind. As you know, I'm very concerned about the fact that we're projecting having around five gigawatts of offshore wind energy by 2030 or 31, I guess.

What is your current assessment about whether or not all the things that have to happen to meet that are on track and how important is it that we actually take steps now to start securing the financing for the port infrastructure?

Yeah. Thank you, Member Zabar. I'll begin by broadly the CEC's portion of the work and then pass to President Reynolds for any additional comments. I think from a strategic plan perspective, I think we have the central procurement function in place as PUC takes decisions on that. I think it's an important element.

So we have the tool in terms of ports and planning. I think we are moving forward with the 30 odd agencies that are invested in it and some of the money you have given us for planning purposes. So overall, from a planning perspective, I think we have good handle.

Now starts the implementation process, and I think that starts with some of the strong signals we got from IRP on some authorized procurement. So I think overall, I think the planning is there and then the implementation is beginning to take place and there's a bunch of work to do.

So I've always just looking at large infrastructure entitlement processes, I've seldom seen them occur in periods that are less than 5678 years.

We have significant amount of work to both make the final selections on the ports that will be the main staging ports, but also moving through the entitlement of that and frankly finding the financing to put it in, the financing in place to assure that the development of these improvements of these ports can take place?

To me, it seems like when I look at the entitlement period alone, plus the construction of the ports we're taking, we're moving all the, you know, I don't see how we get there by 2030 and 2031.

And it would seem to me, I mean, do you think that it's a fair concern of mine that we need to move this year to start putting the financing in place to make sure that offshore wind becomes a reality and is a reality and is meeting the objectives that we, that are embedded in basically our forecast?

Yes, I would absolutely agree with you that some of these long lead time projects, the time is of a sense, and I think from the perspective of all the elements that you raised, and I just want to thank you for your leadership in this.

I think the sooner we take those implementation steps, including the financing in place, the better chance we have at hitting our targets.

One other question, I think, and also, if any of you can answer, would you say that it is a fair characterization to say that offshore wind is a key and essential element in meeting the electricity that we are going to need to meet our scoping plan obligations.

I mean, I think it's a crucial element and that's why I've been pushing forward for us to make steps to include $1.0 billion in the bond, which obviously isn't anything close to what we need for these things.

But when I look at the timeframe that we have, which is entitling financing, constructing the ports and that all having to happen between 2030, I just don't see how it happens unless we take sort of immediate steps.

And then if that doesn't happen, is it fair for me to have a significant concern about whether the state can meet our scoping plan obligations, which all the things that require electrification in the scoping plan. Is that a fair concern that I have?

I think it is a concern. How are we going to meet the scoping plan targets in General and how are we going to put together the right combination of resources that work in the right way? We know we have amazing wind resources off the coast of California, in particular in central coast and North Coast.

And they work those resources, according to the studies that we've seen, work very well with our solar, that we already have in place, large capacity of solar in California. And so in that sense. With a. Portfolio looking forward to how these resources are going to work together with the build that's going on, offshore wind looks very positive for our future. I think the question for me is how do we think about repair cost always in doing that, in looking forward to what we need and the right combination of resources.

And you're right that offshore wind is going to take advanced planning. We need to start soon, and we are, we're starting to look at the transmission, where that might go, what that might cost, how we might design it, what the procurement might look like, as well as the port planning.

And thankfully, we have some federal assistance there and so, and we have, the 524 process has really brought all of the agencies together because as Vice Chair Gunda noted, the permitting process is going to be challenging, but also will benefit from coordinated interagency work together.

So I think all that is going to be really necessary in order to make sure that we're not missing any opportunities here.

And I'm not criticizing anyone, I want to really thank you all for really moving that ahead. I think it's a crucial part of really meeting our scoping plan obligations.

You know, if I had to look at like the one thing we could do this year to basically make sure that, that we're able to sort of, you know, have the electricity we need, the kind of electricity at the time that we want it, it would be to sort of make, take the urgent step to send the signal to the market now that we are serious about offshore wind and it moving forward.

And I'm nervous if we wait another year that we're going to be sending pretty negative signals to the market. So that's just a comment. I have one more question, and then I want to give others time. So this is actually for Mister Mainzer.

SB 350 passed in 2015 that increased the RP's to 60, required that prevailing wages be paid on all transmission projects built in California. What procedures does Cal ISO employees to ensure that bidders on transmission projects are aware of the requirement and to ensure that labor costs and their bids are actually factoring in prevailing wages?

And what steps are you taking to assure prevailing wages are actually being paid? And then the last question is, are prevailing wages part of the cost that you are anticipating? Are they being worked into the cost related to projected costs for the transmission?

Yeah, certainly. We see, you know, I think across the, across our enterprise, I think we see the important role of labor in playing just a huge role in building out the infrastructure across transmission generation, you name it.

So we certainly, this is one of our evaluation criteria, looking at costs and making sure that we are accurately reflecting total investment costs and labor costs in our bids. So certainly something we're very sensitized to. We're also pleasured this last year or two to have had the IBW 1245 now operating our control center.

So we're very acutely sensitive to these issues. So thank you.

Thank you, Madam Chair. Thank you.

Thank you, Assemblymember Wood.

Thank you. So, kind of thinking about some part of an earlier conversation when we are looking at transmission and planning. I think when we talked about, we talked, it could be any industry, but the forecasting, the planning, and then Cal ISO makes it decides how much we should actually be building in the process.

We don't need to go back to the 1930s here, but in that process, are we looking at future capacity for what is being built?

So that, in other words, if we're building towers and wires and are we thinking about the future capacity, or are we just building for what we need now because it's such an onerous process to go through, and five years from now, if we need that, we got to make people go through a whole new song and dance to get there.

So can you describe how that is done?

Yeah. Thank you for the question. One of the reasons we decided to develop a 20 year transmission outlook was exactly for that reason. You can't just be thinking about transmission just for the next two to three years.

You really do need to step back and think about a whole bunch of different scenarios, growth scenarios, technology scenarios, resource development scenarios, and make sure that you've got a plan that's robust and honestly is scalable as well.

So when we're thinking about the major corridors that we're building out both within California and as we offshore and as we look to other parts of the western United States to meet some of California's resource planning requirements, we're definitely thinking about growth and scalability and expansion capability and interconnectivity, because as you've mentioned a couple times, I really appreciate the sensitivity.

Our transmission system is really the fundamental undergirder of reliability and ultimately affordability and our ability to move power around to where it's needed, particularly under acute events. So we are definitely sensitive to that issue.

And even though we're doing, we're on a two year planning cycle and we're building on a transmission plan that has some broad architecture already built into it. So we're sensitive to those issues.

So as a follow up to that and just thinking, we often, the Legislature often comes, things come forward from the Administration or the Legislature that change what's going to happen out there. And I don't think any, I certainly wasn't on my radar. The fact that, as the chair talked about, AI is a huge consumer of energy.

We don't know what the next thing is out there. How nimble are you going to be able to be for when that next thing comes along?

Because we hear from industries like as we move towards an all electric car fleet, just the infrastructure needs and the energy needs for that is pretty significant and putting a lot of pressure on utilities and others to build that out. So we don't know what the next thing is.

But how are you, you have a 20 year forecast, but is there a buffer somewhere?

Yes. Thank you, Assembly Member. I really appreciate the questioning on the need for longer term planning. And I think the crux of one of the things that you've identified goes to how we used to do things versus how we are doing things now in terms of enhancements.

Much of our planning used to be kind of near term with little to no scenario development and largely focused on single point estimates because we had a very kind of stable demand growth and stable supply conditions. But over the last four years, especially the amount of work that gets done.

When we say we do a forecast, it's not a single point estimate anymore. What we're doing is we are doing a forecast for each sector, and for each sector we are doing many different variations on different scenarios that could occur.

So we have these menu of forecasts by sector and by variability, and then together, jointly, we say, what combination of those forecasts should we plan for IRP in the near term, and what forecast should we do a long term study on, and which forecast should we use or scenario should we use for sensitivity understanding?

So all that is currently being done, and those sensitivities are studied across different processes. And when we talk about these products, those products are not really one single set of data anymore. They really do take into account a large variability.

And specific to your second element of the question, how do we take into account these new load growth issues? So starting around 2019, what the agencies have started doing was we developed these scenarios of additional growth. We might not bake them in for procurement, let's say, but we do put them out for stakeholder input.

And as we begin to see that those kind of growths are going to be real, we start baking them into the forecast. So part of it is, do we have visibility? Yes. Are we deciding to use a certain level of load growth for procurement? Yes. It depends on the process, the public process.

We go through a stakeholder process and bring that to the Commission for adoption.

I just have one follow up question related to the strategic Reserve, so understand that it's incredibly important. But I think that the multi year cost for the strategic reliability Reserve is, I think, like 2.1 billion, which seems like a lot of money for something that we use, hopefully zero days, maybe two.

You did talk a little bit about comparing that to other options, but can you speak a little bit about what we're doing to identify other more cost effective ways to maintain a strategic Reserve?

Absolutely. So I did talk about the OTC contracts, and that was to retain assets that would have retired. There's also a combination of new asset builds. And so that was going to be a bit more expensive, but that's also limited in terms of how much we are able to advance that sector.

So in broadening that out, one of the things that DWR has been looking at, are there other options that we can pursue, especially cleaner options? And we did put forward an RFI earlier this year to look at some various options.

And we did find is first and foremost, there is so much build out happening on the normal planning side for resource adequacy, one of the core tenets that we have per legislation and throughout DWR for the energy side is that we don't want to compete with the procurement that is already happening for the load serving entities or the publicly owned utilities.

So that does take out quite a large swath of resources, especially clean resources. So kind of usual suspects like battery storage, very popular. But we also don't want to add any more pressure to load survey entities that are trying to obtain those resources for their planning needs.

So unfortunately that does push DWR if it's not sort of the tried and true traditional gas fired, if it's not the newer cleaner technologies like storage or even clean generation.

Unfortunately, I think what we found is that that does push us out into sort of more, let's say less commercial resources, those that don't have the proven track record, that tend to be a little bit more expensive.

But even within the portfolio, we've stepped out a little bit in some of the smaller gas fired resources that we've recently constructed and own.

Those are still natural gas fired, but we specifically sought out that technology because it is much lower emitting and it also has Low emissions to the point that a similar technology was actually approved by carburetor for the distributed generation program certification.

And in doing so, that had allowed us, as we go through the local permitting process, to really get through some of the local air districts very, very quickly. But again, that's newer technology that's been constructed in California for the first time. And so we're excited about that and having that online for the summer.

But again, we still haven't broken out of necessarily that natural gas fired space. So it's been, it's been a challenge. We are looking through as many options as we can, including contracting partnerships and any creative mechanisms that we can think of and cost sharing and things like that.

Well, actually on the topic of creative solutions, there seems to be a ton of potential, and I guess this is sort of in the context of strategic reserves, but actually just more broadly in the context of more reliability at a cheaper cost. There does seem to be a ton of opportunity in banned response programs, virtual power plants.

Can you, and maybe this is best directed at President Reynolds. Can you speak a little bit about what we're doing to unlock that potential?

Yeah, I'm happy to talk about it, and it is a really exciting but also challenging area. And I think one way to think about it is the cost of resources that are certain in times of scarcity is high and that's what we're talking about with the strategic Reserve.

But it also means that we need to look at alternatives. We need to look at our whole suite of potential solutions. And the demand side is something that we've been exploring a lot and is also complex, but has a lot of potential.

And so PuC has been working really closely with CEC on all types of ways to harness demand response.

So every flavor, whether it's through rates, and we have some exploratory rate designs, the calf use rates that we're working on at CEC and testing those, seeing if we can get those to result in modified demand shapes, load shapes that are relatively certain, and we'll lock that down more over time, as well as the emergency programs we talked about.

Of course, in multi day heat waves, your ability to shift people away from air conditioning when it gets hot in the afternoon gets lower and lower or worse, or worse as the heat wave moves on. And so we have to think about that as well.

What types of consumer behaviors are we going to see in the future, and can we expect and can we get to work the ability to shift load with heat pumps, with electric vehicles, all of the electrification efforts that we are working on also provide huge opportunities. So that's something to think about in the future.

We'll have more and more of those opportunities in the future, and we'll continue to look at ways to use those in emergencies versus just incorporating them into the normal planning, which we also want to do.

Thank you so much for that question. Just to add to the conversation, the CEC, along with PUC and Caiso, we were able to adopt a 7000 megawatt demand flexibility goal by 2030. And we are required to report to you on a regular cadence about the progress of that.

And the next step would be on how best to operationalize those 7000 mw moving forward. And you were kind of getting to the question around how are you looking at the costs of these different resources? It is a good metric for us to think about how much does a kilowatt cost you to Reserve for a year?

So as Director Hou mentioned, the OTC power plants, given the $10 per month, is looking at about $120 per kilowatt per year. So that translates to if that is the cost, 120 million for 1000 mw. So that's kind of how much you need to pay. Most resources in the demand response frame is around the same cost.

So if you look at the BIP program that PUC administers with the large users, that's about $170 a kilowatt year versus the DWR resource at about 120. And we could definitely do better with these different resources. What CEC is exploring through the DSGs construct are around $120 to $140 for these demand response resources.

And one of the core elements in what we are looking at is how do you ensure that those resources actually show up.

And one experiential data point we have is that when they're backed with some resource, like as you mentioned, virtual power plants, if there's a behind the meter storage or it's that there's a vehicle battery, so you suddenly get a lot more performance from them rather than it's just purely behavior driven.

And so again, behavior driven programs doesn't mean that they don't produce. It's just that if you're thinking about 1000 mw, maybe 200300 shows up regularly and the rest might not show up, and how do you take that variability in your pricing strategy?

So we are carefully looking at that and we'll come back to report on the progress.

Great Assembly Member Bennett.

Thank you very much. And I'll try to quickly go a few things.

Number one, to the extent that the demand response is close to the same price as reserving it with the OTC plants, certainly we have the great advantage of you only have to pay for the demand response if we have the bad events, whereas if we Reserve, we're paying that cost up.

So I'm certain you guys are sharp enough to calculate that in, but it would be an advantage for the State of California the sooner we can deal with the OTC plants in those disadvantaged communities.

One, two, have you, and I would encourage you, if you haven't, if you could do any kind of cost calculation of what will be the impact to Californians, cost wise, of having blackouts, of having, there's significant cost involved there.

And so when people talk about, well, you're raising rates because you're putting on the strategic Reserve, you know how much your rates will go up. If we have another one of those 2022 outages, what is the hidden cost that almost people don't see?

The third thing that I'd like to just ask you to consider is that whenever you create organizations, when you ever create differences, the Senate versus the Assembly, there's always tension. That just is, it's normal. It's just absolutely out there. To the extent that we all professionally find ways to work with each other, it's just better for everybody.

And I would offer that a lot of times at the legislative side, we feel like it's difficult to get information from the Executive branch agencies, etcetera. At the budget hearings, we've endeavored to try to not create a hostile environment where we're going after anybody or play catch you, etcetera.

And at the same time, it can lower the temperature. If everybody knows, hey, we are going to get the information, maybe it's not available right now. So I would just point out that at our last budget hearing that we had on this topic, the information wasn't ready.

And if it could become sort of an unwritten policy, that we will get written responses to the questions that we have. And it's fine to say that question is so hard and would take us so long. We can't do it. That's legitimate.

But at least everything else, if we knew it was going to come, I think in General it would lower, in General, legislative frustration. And hopefully our treating you guys professionally always also helps increase everybody's ability to deal with the normal friction that's always going to exist there. So that would be my request. Thank you very much.

Just as Member Bennett, thank you for those three points.

Just on the first one, just wanted to quickly note that the capacity payments that we're talking for demand response, the industry is asking us to do these contracts over a time period, whether we are using them or not, similar to what we would do, because that would help them to think about how best to structure those.

But I think you do allude to an important point, that these resources do not have long lead time. So it doesn't take two days for us to warm them up. So if we can come to a place of good performance and demand response, the spontaneity at which we can deploy them is a huge benefit.

And two, most of these are stranded assets. So if we are using stranded assets to reduce, I think it goes a long way in creating that sustainable and clean pathway. So 100% agree. I just wanted to add that additional point.

Thank you very much.

Well, I think that seeing and hearing no further questions from our Members, that concludes our panels. I just want to say thank you so much to our panelists for being here. As we've all noted, we've got some incredibly ambitious and incredibly important climate targets for the State of California.

We have a monumental challenge on our hands to deliver on that. And I really appreciated the conversation as we focus on the work to ensure that we do that in a way that's reliable.

And I do also want to note, because I think it's important for us to pause and recognize what we have accomplished and what we have achieved.

And as you noted at the beginning of the presentation, annual new resources installed by the state have nearly doubled over the course of the last four years, including 10,000 solar over the last five from what was essentially a standing start. And so certainly we have a lot of work ahead of us and some major challenges ahead.

And I just want to thank you all for joining us today and sharing your perspective, your testimony, and look forward to continuing to partner with you as we tackle these challenges for the State of California. Thank you very much.

Thank you so much here. Thank you. Thank you, Members.

And with that, we'll go ahead and open it up for public comment. Public testimony. If anyone would like to provide public comment comment, you can go ahead and approach the microphone. At this point, please state your name and organization, and you'll have two minutes. Let's see. Anyone? All right, well. zero, there we go. Anyone? Okay.

While seeing and hearing no one in the room wishing to provide public testimony, that concludes today's agenda, and today's hearing of the Assembly Committee on utilities and energy is adjourned.