Assembly Budget Subcommittee No. 3 on Climate Crisis, Resources, Energy, and Transportation

Good morning. Welcome to the Assembly Budget Subcommitee three hearing. Today we'll hear from the state's energy agencies with an update on the funds that were appropriated last year, reliability challenges that we have faced due to the impacts of climate change, and the new proposals to address these concerns by the Governor. We'll also vote on 19 items that were heard at our march eigth hearing. We have four items that are planned to be heard for each presentation item.

I'll ask each of the witnesses in the agenda to introduce themselves before they begin their testimony at the end of the presentation items. Members of this Subcommitee may ask questions or make comments on any of the 22 non presentation items. After all the items are heard, we'll take public comment in regards to the departments before us today, first in the room, followed by phone testimony. Each Member of the public will have 1 minute to speak.

The phone number is on the Committee website and should also be on the screen if you're watching over the Internet. That number is 877-692-8957 the access code is 131-5447 if you encounter any problems, please contact the Assembly Budget Committee at 916-319-2099 and a staff Member will assist you if we please take role.

[Roll Call]

So we have a quorum. So we have some votes. We'll take a number of motions on the vote only calendar. The first vote is to approve as budgeted vote only, issues one through 10, number 14,15,17 through 19. Can I get a motion? Second moved by Assembly Member Rivas and seconded by Assembly Member Connolly. All right, roll call, please.

[Roll Call]

The second vote is to prove as budgeted vote only. Issues 11 through 13 and 16. Could I have a motion, please? Assembly Member Rivas. Motion seconded by Assembly Member Connolly. Again, thank you. We're ready for roll call.

[Roll Call]

All right, we'll hold the roll open on both of those to allow other Committee Members to add on, but we'll start with discussion item one, and I believe Commissioner Gunda is with us. And if you'll come up, and we'll start with the Commissioner and then let the rest of you introduce yourself in whatever order that happens to work.

Good morning, chair, Members of the Committee, for record, I'm Siva Gunda, Vice Chair of the Energy Commission, and I'm happy to begin my presentation.

Welcome, and you're a little hard to hear, so if you'll be as close to your microphone as possible. If everybody will pull their microphones to them, it helps, including me. Right. I've been told by my staff. Right. Welcome.

Thank you. Thank you, Chair. Is this better? Much better. So I have a presentation we shared with you, and I'm going to go over the presentation really quickly and just set the stage for the discussions today on the budget items, which are largely informed by the reliability analysis as required by the SB 846 and 205.

So since 2020, we have been working very closely, the CEC, along with PUC and CAISO, to continue our analysis on reliability and to really frame the problem in a cohesive, consistent fashion for the Legislature and the broad public. So over the last three years, with the information we have and the different analysis we've conducted, we look at the problem statement in broadly, three buckets. It's on slide number two. The first bucket is really improving our planning processes.

As you all might remember and recall, last year going into the summer, reliability. One of the issues was have we authorized enough procurement in the first place, and have we taken into consideration the climate change impacts to enable that procurement levels. So we have been working on ensuring that we bake in the climate change impacts as well as we can. And I will talk about this at the end of the presentation. But we're still relying on projections that might be inaccurate, that might still be conservatives.

We are working on a lot of different modeling assumptions, but I just want to call out as a flag second, the CPUC has taken unprecedented steps in procuring additional resources to give us some cushion in the amount that we need to cover for those climate change impacts. And finally, we have been really talking to the communities to understand what their priorities are in the broad planning. One of the things we focus on in reliability is the system level planning.

But what really is important for the communities is the distribution level planning and the increased demand flexibility. The second problem that we've identified is while we do our planning and ensure our procurement, can we actually build to that rate? But also are we able to prepare and take steps necessary to ensure there is a diversity of resources? For example, offshore wind, long lead time transmission, what are we going to do to make sure those resources come online in time?

And also on the demand side, the diversity, as I mentioned, demand flexibility, whether it's vehicle to grid integration, how do we ensure there's a large amount of DER resources on the grid? And finally, the third challenge, and I think I want to make sure I impress upon you this, even if we plan to the standards that are consistent with the rest of the states as well as the country and globally.

And if we ensured that the resources came online in time, we will still not be able to meet the resource need under an extreme weather condition. And that is where some of the tools that you gave us last year in terms of the strategic reserve are extremely essential. Next slide, please. So just a quick highlight. CPUC, as you all know, has authorized an unprecedented 11.5 gigawatts of new procurement in 2021.

Based on additional resources, new forecasts and such, the CPUC has authorized another 4000 megawatts to come online by 2026. So in terms of the procurement levels, we feel really comfortable today that both in the short term and up to midterm, like 26-27 we have authorized enough resources to meet the planning standards, but also give ourselves some cushion. And finally, just in terms of ensuring the resources come online, as you all know, there is a TED task force.

It's basically a compilation of CAISO, CUPC, CARB under the Gobiz to make sure that some of the resources are being closely tracked and monitored and make sure we problem solve actively. Next slide, please. And this is a lot of charts here, but I want to make sure that I just focus on one slide.

You're talking about. Next slide. Are any slides going to be projected on the PowerPoint? We have a PowerPoint presentation being talked through here.

Okay.

All right, great. All right, so when you say next slide.

Slide, slide number four, how about.

Okay, there you go. Slide number four can follow along. All right, sure. Slide number four, if you happen to have the PowerPoint.

And I'm going to focus on just one of the four charts there and then to set the stage on how to read these slides. So if you look at the solar build rates, which is the top left corner in the C, what you see there are four lines. And I want to go one by one. The green line is the average build rates of solar over the last decade.

The average what rate?

Solar build rates over the last decade.

Build rate.

Okay. Yeah. And then the blue line is looking as a sustained record that we've observed over the last 10 years. Right. So those are like basically deviating, because if you build a net average level, you accomplish certain level of procurement. And if you're doing at the maximum, it's the blue line. That's the cumulative procurement we could achieve. And now what you see in the orange and the brown are. Orange is what CPUC has authorized already.

And the brown is what CPUC's preferred system plan, which is going towards our climate goals. What needs to be added. And the real takeaway point from that is even if we do the maximum level of build rates, we will not be able to build to the level we need to until 2026 in solar. I just want to flag that for you.

And then as you go through the other charts, whether it's batteries, geothermal or wind, as you see there, we not only have to build at what we've built in the past, but double and triple in some cases. And I just wanted to leave that as a big uncertainty in the way we move towards. We've authorized the procurement, we have set up some processes in terms of permitting, streamlining and such.

But being able to build at the trades is something that we haven't done in the past and we have to do it.

If you don't mind, and ask questions. I think that's very appropriate. Assembly Member.

Just so that I understand this. So just to be clear, the green line is the real line of kind of where we really are.

So no, the green line is if you were to build at an average level, what would be the future projection?

And the orange is your procurement. But what is the preferred system plan? What does that refer to?

So it's the integrated resource planning where the CPUC is taking not only the reliability goals, but the policy goals of the state and then developing what build rate we need to achieve. And that's that line. And sometimes CPUC uses that analysis to then inform their procurement.

The last question just on this chart is just there's a lot of goals that are mixed in with, you know. So if you were to give your best guess of what we're actually going to see in the next several years, which of these lines would it be?

I think it'll be slightly, I'm hoping it's the blue line at a minimum and slightly above the blue line, because that's what we're trying to do. I think if you look at the last two years we have built about 4000 megawatts of NQC or 8000 megawatts of new resources collectively in 21 and 22. So that seems feasible, but we have to do it continuously.

And Assembly Members, if we can all keep our red buttons off except when we're speaking, I think we'll have much more clarity from the person that is speaking. Assembly Member.

Just quick, I wanted to understand. So what you're acknowledging, and I appreciate the honesty, is that despite everything we're doing, we're not going to be able to meet our energy needs using reliable or solar or other renewable energy alone, is that what you're saying?

I think that's part of it is that what we're trying to say is that we need to build at a record setting level that we have never done before to achieve our clean energy goals.

And we're not on target to do that.

So the last couple of years we have seen record setting build rates both in storage. I mean, if you look at what we had in 2020, we had 200 megawatts of storage and now we have 4000 megawatts on the system. So we really went 20 fold on battery storage, solar and wind. One of the issues we have is this stop and go procurement cycles.

And what CPUC is trying to do is to ensure a steady build rate so that the workforce is there and our ability to really scale happens. So we don't go this stop cap.

Okay, thank you.

Thank you. So I want to go into the next slide. So, resource adequacy planning standards, and I want to make sure that I really share the next three slides clearly with you. What we've talked to you over the last couple of years is we have a demand that we project. And once you project the demand, you have to make sure that we have the resources. What we just said is we have the resources procured.

But what you're seeing on this chart, slide number five, is four lines. And I want to walk through them one by one, carefully. The first line, the very bottom line, the dark blue, is basically if all the procured resources come online as expected by CPUC. So if you follow the current procurement trajectory, that's how it looks. The next line above that is a 20% delay in the authorized procurement. Above that is a 40% delay.

And when we do these analysis, just note that we not only take into account some outages that currently can happen through fire and heat, we also take into account the NERC standards and all. So these lines are showing you the deficits when you plan for a standard level. What the orange line on the top shows, and I want to make sure that you're tracking this, is if we had a catastrophic fire in California, that's similar to 2021 bootleg fire.

In 2021, April 19 or July 19, we had the bootleg fire which knocked out 4000 megawatts of transmission coming into California in moments. So if you lose those 4000 megawatts, that's what we call a catastrophic fire risk. And that's the delta you would see in California, if you had a catastrophic fire. And this is on the planning standards. Next you will see on slide number six is if you had a 2020 repeat, what happened in 2020 is about a 9% deviation from an average demand forecast.

So if you bake that in those numbers go up further. And finally, in a 2022 equivalent, which.

I'm going to take you back to six.

Yeah.

So from five. What is the difference with six? You said it is if what happens.

Yeah. So the demand significantly deviates from the average forecast. Got it. Okay, so if I just kind of take a moment there. When we plan for our reliability standards, the typical planning is about a 5% deviation from the average demand forecast. In 2020, we observed about a 9% increase from that. Our deviation in 2022, we saw a 12% deviation for just a week. So those are the different bookends we are planning for.

So the 2022 scenario, which is slide number seven, is planning for that level of departure from the demand for a week or so. So, as you see, if a 2022 equivalent summer event were to repeat along with a coincidental catastrophic fire, you're looking at an 8000 megawatt shortfall, potential shortfall this year. And I just want to make sure that we are very clear on that one. And then what are we doing about that?

You gave us a number of tools, the tools that we are going to talk about today, the demand side grid support program, the DEBA program, the ELRP program. So collectively we have about 3000 MW that we can pull pretty well from that. But under an extreme condition like that, we have to show up additional resources and that's what the staff are going to be working on.

I think it's best for us to ask the questions along the way because this PowerPoint just came in late last night and there's more labeling that I'm sure you would like to have done if you had had more time with it.

Absolutely right.

So go ahead.

Thank you. I'm just asking because it'll help me understand what happens next. So can you explain why, with midterm reliability being such a high concern, the system resource adequacy requirements are only looking one year forward. That's a misunderstanding.

So the RA program currently takes one year, and then there is a three year element to it. Luam, if you want to comment. Leuwam is a colleague from PUC.

Good morning. Leuwam Tesfai, the Deputy Executive Director for energy and climate policy at the Public Utilities Commission. So we do have a year ahead showing, but the load serving entities are procuring for three years in advance for different types of resource adequacy. So we have system wide resource adequacy requirements. We also have local capacity requirements. And so it's no longer just a one year ahead procurement for resource adequacy.

Okay. So you have a projection that you can show us that's multi year as well?

We do have multi year.

Taking into account the increasing strain on the grid from things like EVs.

Yes.

Okay, thank you.

Absolutely.

Thank you. We're speaking at a very high level here and I kind of want to not dumb it down, but just simplify it so we understand what you're talking about here. You're talking about in 2022, if we have high demand, we're not going to be able to meet our electricity needs. Is that what you're telling us?

It's a legitimate concern that I think one of our core priorities since 2020 has been to ensure that you are really well informed on the risks to the grid. What we are not baked into this right now is the really good hydro conditions we've seen this year. Right now, the hydro assumptions in this are drought conditions. So that gives you a lot of leeway. It could give you approximately 2000 MW additional resources and we already have about 3000 to 4000 MW strategic Reserve.

So we have tools that can get us through it. But an extreme weather.

Lucky this year.

What was that?

We might get lucky this year with the extra hydro, but we can't count on that in future years. And I guess what I'm trying to get to here is what we're talking about are blackouts. If we don't have sufficient power, people's lights, they're not going to have power in their homes, which is significant risk that could be life threatening. I mean, it's a lot of issues. So I just want to be very clear.

What we're talking about here is we do not project to have enough power for high demand potentially. And you're talking about, I guess we're going to get into what the plans are to deal with that. But I hope one thing we can start discussing is how do we meet our energy needs, because we continue to push people to electrify. We don't even want people to use gas anymore, which I don't agree with.

But as we put all our eggs in one basket, electricity, and we don't even have enough electricity, that's a recipe for disaster. So at some point I'd love to also get into the discussion of where nuclear fits in the portfolio, because right now it's about 10%. A lot of other states, it's much larger. Other countries are primarily nuclear. And I just think there's such an easy solution right in front of our face.

It's not fossil fuel and it's reliable and it's cheap and we can solve all our electricity problems while we do the other things too. So if you can comment on where that fits in your plans, and I'd love to hear about that

Assembly Member if I could, since we're sort of interrupting the presentation with specific questions on the PowerPoint when appropriate. If I could also point out that a year ago the Assembly had significant conversations about things like nuclear and what are we going to do if all of the worst case scenarios happen. So we will obviously have some philosophical differences about what the solutions are. But I don't think we want to have staff try to say that.

Staff is saying we don't have enough electricity to meet our needs. They're saying we do have projected enough electricity to meet our needs, and they're trying to project if in the worst case scenario, what do we do? And last year the Governor came with a solution for the worst case scenario and it has now been implemented. The question is, this is sort of a report, how are we doing implementing the corrective action for the worst case scenario?

So it's a little bit different than just saying it's obvious we don't have enough and we have to do something different. We actually have come up with a game plan. The question is how well is it being implemented? And that's sort of an oversight role that we have on this Committee in terms of trying to do that.

I appreciate that. I want to make sure I understand the graph though. But the red is worst case, but the blue line is regular demand, right?

No, just wanted to make sure, Assembly Member, that chart is a 2022 equivalent. So the 2022 equivalent weather event is a significant departure from an average weather. So we are talking about a departure that's one in 17 year event or a one in 30 year event. So the very first slide, slide number five that we showed you is what we have.

Under a traditional planning situation where we have average weather, we have some contingencies to cover, about 5% departure of demand, and that takes into account high electrification scenarios. So both transportation as well as buildings. So what we are showing there is just the worst case scenario. And if the General traditional planning situation were to come together, we can cover those deltas even under a catastrophic fire, what number seven shows is worst of the worst of the worst that can possibly happen.

Got it. Thank you.

Assembly Member Ting.

Commissioner, thanks for being here. I just want to understand again, chart number five, what it has on there and what it doesn't have on there. So does it factor in the strategic Reserve? So the strategic Reserve is in there?

No. So the three blue lines that show underneath are basically what we have authorized in terms of procurement. Doesn't include Diablo Canyon. Does not include strategic Reserve.

Does not include our colleague from Orange County to hear that. So it doesn't include Diablo Canyon, Mr. Essayli. So it doesn't include Diablo Canyon, which is about 10% of energy. That chart doesn't include. What else?

It does not include the OTC power plants, which are expected to retire, which is about 4000 more megawatts.

Doesn't include the retirement. But that retirement is not happening till. We postponed it. Till when?

22-26. And our hope is to bring those 4000 MW roughly into a strategic reserve.

Doesn't include strategic reserve.

No.

Which is how many megawatts?

So it varies, but we expect it to be about 1500 this year.

Okay. And also doesn't include, I believe, demand response?

No, they're not the ELRP program. So the emergency load reduction program that.

CPUC has and then demand responses for. I don't know why we're not including demand responses, because again, demand response is what really saved us, not last year, but 2021. And more and more people are responding and joining demand response. That's something that I think, again, and frankly, that's the fastest thing we can do.

Absolutely.

It doesn't cost, frankly, anything.

So no Assembly Member Ting to your point, one of the requirements of the 846 was to develop a demand flexibility goal.

So if you're going to redo this chart with the strategic Reserve and Diablo Canyon, we could debate demand response, but that would be a much bigger surplus.

Yeah. So if you're looking. So sorry, the way the slides were structured was we were going to go through the shortfalls and then talk about the magics we have in our pocket. But to your point, given the strategic reserve, we have the Diablo Canyon, the OTC power plants. So that Delta is kind of essentially vanished if it's an average planning situation.

Yeah, but you're saying. I guess your labels are difficult to understand. So when you say a 2020 equivalent event, I think it's better if you actually describe what that event is or 2022. So what event is that?

Yeah. Let me take a moment here. So when we say standard planning, we take the demand, the average demand that we expect in the year, and then we add about 16% on the top of that as a buffer to cover 5% deviation of demand, 6% of NERC standards, and about 6% of outages, thermal outages, or any other outages. So that's what we plan for. Take the demand, cover 16% on the top of that. That is what a traditional planning scenario looks like.

That's for 2020.

No, that's slide number five. That's traditional planning standards. Okay. And then you go to 2020 event, and our demand departure was 9%. So you would go all the way to a 20% PRM planning, 20% margin on the top of the demand is what you're planning for.

So what you're saying is this is if you needed a bigger buffer, now you're looking for a 20% buffer.

Yeah, 20% buffer. And then if you go to the 2022 event, then you're adding another 3% deviation. So you're looking at 23-24% buffer.

Buffer. Right. Just so we all understand. So we're talking apples and apples. I think the closest we got was we had some challenges last year, we had some challenges in 2021. Give the Committee a sense of how much above what's normal.

Yeah, absolutely. So, last year, on September 6, 2022 the forecasted average demand forecast would be about 45,000, and we were at 52,000 MW. So we were a 7000 megawatt deviation. And the extraordinary things that you provided, as in terms of tools and the real time markets and the imports we had.

But relative to your chart, were we 20%, 24%?

Yeah, we were 24% off.

Okay. So we were 24%. So last September, we needed 24% more than we normally.

Yeah. Above the demand. So it would be from 16% to 24. You needed another 8% above what we typically carry.

Got it.

And then we were able to do it because of the tools that were given to us.

Right. But we were able to do it without strategic reserve.

No, sir. On September 6, we pulled everything that we had in our pockets.

So we did use strategic reserve. We did use demand response. Obviously, Diablo is still running, so we use Diablo.

And the OTC power plants were running.

The four peaker plants that were retiring were also in use as well.

So I think the biggest difference, the way I would contextualize last year to this year, is we have everything we had last year in our pockets for this year, plus we are bringing in additional resources.

But let me ask you, why would you project a shortfall, given the fact that we had the resources to hit that number in that 2022 equivalent of slide? Wouldn't that be a flat? Wouldn't that be flat?

No. So, just kind of making sure. In 2022, we pulled all the resources we had, some of the resources that came in to support us that day. For example, demand response. A lot of people were turning on their backup generators. We don't even know who turned them on yet, completely. And also if we did not have the 2000 MW relief we got from the text alert, we would not have been able to keep the lights on.

The 2000 MW relief from where? I'm sorry?

From the text alert that everybody got around 05:00. The Amber alert. Yeah, the wireless embrace.

So that was demand response. We employed demand response. Absolutely right. Okay, I got that. But I guess what I'm saying is we were able to. I'm not sure if I totally agree with your chart. I mean, obviously I can't disagree with the future part, but from a resource point of view, we were able to meet the resources last year and then in the coming years we anticipate even more resources coming online. Yes. I don't understand why this shortfall.

So one important point, Assembly Member Ting, that you are honing on is some of the assumptions that are in this chart. One of the biggest assumptions that differs from what happened in September was the amount of imports we got. So typically in this analysis we bake in imports about 5000 MW. So that's what we have under the resource adequacy program is about 5000 MW. Last year we were getting 78000 MW during that time and we could not have gotten through without those real time imports.

Can I just respond real quick? First of all, I actually want to commend you because I appreciate the honesty and the frankness. And believe it or not, I'm going to commend the Governor for fighting hard to keep Diablo on because I think he recognized how important that is for reliability. I know he was under a lot of pressure, but when we say things like strategic reserves, we're talking about diesel generated power, right?

Not entirely. So under the strategic reserve we have three components. So one is the DWR program. So the DWR program is primarily around retaining the OTC power plants that are due to be retired. So you have that. So those are natural gas power plants to keep on. Second, we have what is called the DSGS program, the demand side grid support, which has been primarily the backup generators. But we are hoping to bring in more and more clean demand response into it.

And the third one that was authorized last year was called DEBA distributed energy resources program, which is for improving the amount of demand side new generation, whether it's storage, fuel cells and such, which are also working on.

But a big part of that is still natural gas and diesel. I mean, I just want to be honest with people. We're using fossil fuels to make up for the difference. And then demand response. I appreciate, but that's basically scarcity. We're telling people, turn off your power, turn off your air conditioner, don't charge your car. Again, I think we can have abundant power and cheap power if we diversify a little bit.

But I just think it's important to be clear about what we're doing to keep the lights on. And we're all for meeting this clean energy goals, but let's just do it in a smart.

So, yes. All right.

So if you'll continue.

Yeah, thank you again.

We could certainly have a full day conversation about energy here.

Yeah, absolutely. So again, just kind of making sure to Assembly Member Ting's point, I want to make sure that we understand the three slides of short walls that we showed. Those have assumptions under supply that are conservative in terms of imports, in terms of Diablo, in terms of OTC power plants. So we are looking at a situation where the imports are constrained and we lose our Diablo Canyon and we lose OTC power plants. And then we set up that.

And then what we're going to do next on slide number eight is talk about the strategies that are being implemented. Okay, so then the strategy is coming to. I mean, those numbers are big numbers. Again, we are trying to ensure that we give a clear picture to the Legislature going into these summer events, that some of these are extraordinary events that we need to plan for. So one, we are tracking the energy development. It's called Ted taskforce. It's an important element of the work.

It's looking at project by project in the pipeline right now and actively solving this, a permitting issue, supply chain issue, and so on. Second, we have the strategic reserve, which is the DWR portion. Last year they had approximately 1600 MW, depending on how you count it, supporting the overall grid reliability event. On the top of that, DWR also was able to change their pumping load to further support the grid. CEC has two programs, the demand side grid support program and the distributed backup generators.

And between that DSGs we were able to add 300 MW in about 10 days time frame. And then, as you all know, you also gave us some authority on the opt in permitting to streamline that and give CEC as an option for some of these sightings. And finally, CEC just adopted a decision that we support. Based on all the analysis, we see an extension for Diablo. So that's what the Commission voted on.

Finally, in summary, I just want to make sure on slide number nine, so the current authorized procurement meets what we need for the state to meet our traditional planning standards and a little bit more. The real uncertainty is around being able to build quickly enough, whether it's interconnection, supply chain issues and so on.

Three, we have some tools in our pocket today through the strategic Reserve and such, that we think will get us through most of the harsh events, unless it's a coincidental event that is so extreme that we currently haven't dealt with. And finally, one of the questions that the Assembly Member asked on the demand flexibility. There is a specific statute in the 846 asking us to look at a demand flexibility goal.

We are working with PUC and CAISO on developing a framework for bringing in several thousand megawatts of demand flexibility by the end of the year, just to kind of close it. Electric vehicles we just talked about is a two way street, once if you do a managed charging, it is not a load at critical times. And on the top of that today we have about 10 gigs of storage on the wheels, which we expect to grow to 60 gigs of storage on the wheels by 2030.

And that's an incredible opportunity for grid resiliency if we unlock that. Thank you.

Thank you. We have a number of questions. Now that your PowerPoint is over, I just want to very briefly, if Assembly Members don't mind, is there anybody else that had something to add to this before we go to the questions? Assembly Member Friedman.

Thank you. And thank you, Commissioner, for a very clear and helpful presentation. Very much appreciate your expertise and your time that you put in this. My question has to do with SB 846, which I voted for reluctantly last year, and that Bill contained a five year extension of Diablo. So why now is PG&E applying for a 20 year extension, given that they were authorized for a five year extension.

I would defer that question to Leuwam, if that's okay, CPC.

Thank you for that question. And so at the Nuclear Regulatory Commission, they do have.

Excuse me, could you pull your mic closer, please?

Thank you. Is that better? So when an entity goes to the Nuclear Regulatory Commission for an extension of a facility, there are set amounts of time for those applications. And so though PG&E went with the set amount of time, the 20 year period, we're not expecting them to use that entire period of time. But the application process at the Nuclear Regulatory Commission is for that set period of time.

So for my constituents, who are very concerned about the extension of Diablo, when it was their understanding that Diablo was going to be decommissioned, should they rest assured that we're not going to be going beyond the five year extension?

So I think there, I would point to in SB 846, there was specific language that directed the Public Utilities Commission to continue with the integrated resources planning as if Diablo was retiring. And so we are keeping our foot on the pedal in relation to procuring additional clean resources in order to replace Diablo. We're not allowing Diablo to crowd out any of these more desirable resources.

So it's CEC and the administration's intent to allow for Diablo to retire in five years?

Yes, that's our goal.

Okay. And why is there a need to release another 800 million to PG&E when they've only drawn down 350,000,000 and they have another 250,000,000 in reserves? And my understanding is they haven't asked for that allocation.

You're right, yes.

So what's the thinking behind that?

So we're just working through the stakeholder process at the Commission in order to get all of the numbers on the table. Those dollars have not been fully committed to that process. And PG&E is also having to provide invoices for the operations of the facility in order to be able to recoup those costs. And so we're helping to review those invoices along with collaboration from DWR.

So there may not be this release of funds based on the invoicing?

Yes, they need to produce the invoices and have those reviewed before those funds are distributed.

My last question is, why did DWR place the Legislature in this September 30 bind with regard to allowing grant proceeds to pass directly to PG&1E, bypassing first recovery from the state's General Fund?

I don't want to speak for DWR. I know that we do have a representative here, so I'm not sure if we could.

We could bring in Delphine from the Department of Water Resources.

And that's my last question. So thank you.

Good morning. My name is Delphine Hou. I'm the Deputy Director for statewide water and energy. I appreciate that. Is that close enough? Hope so. One more time. Delphine Hou, Deputy Director of statewide water and energy at the Department of Water Resources. Appreciate the question. The way we've structured the loan agreement is to ensure that the monies provided to PG&E are available to them for their relicensing.

But we also do want to make sure that by putting the monies in an escrow Fund that we're able to coordinate with PG&E and what they're doing, as well as the application they have with the Department of Energy.

Thank you very much.

Other members'questions, Assembly Member Ting. Great. So, Assembly Member Ting, I am holding off on two questions because I understand you're interested in those, just so that you know, and that's the state's plan to meet the renewable energy goals and the demand response questions. So I will be deferring on those. But could you give us a status update on the interconnection challenges and the delays that were forecast last year? Have they improved? How much electric generation has come online since then? And I have a follow up question to that.

So this is really a question for the system operator, if we're talking about generator interconnection. But I can also answer questions related to customer interconnection. So I just wanted to check which.

I want both, so why don't you give us the customer interconnections and then we'll talk about generator. But I'm much more interested in the customer interconnections.

Great. That is something that I can answer. So we have heard concerns from a number of members as well as.

Closer to the mic, please.

So we have heard concerns from a number of members as well as communities related to challenges interconnecting new customer load. And so the commission has taken action in order to address these issues. And we really have a three pronged approach, short term, medium term and long term. So looking at the short term approach, we have assembled an internal task force of staff who are working directly with these customers and helping them interface with the utilities.

Often it has been PG&E. And so in order to conduct this work, we work directly with customers. These might be a new development that's trying to connect or we've been prioritizing housing and public safety largely and helping them identify exactly how much electricity do they need to serve their load.

Did they have an initial projection that is slightly off, helping them what we call right size the project, and then we also interface with them with PG&E to come up with short term engineering solutions in order to get those customers connected. And we've had a high success rate there. Our medium term is in relation to, for PG&E, their general rate case, which is their large case that comes forward every four years for their revenue requirements or their budgets.

And so we're expecting a decision on PG&E's rate case in Q3 of this year. And so we have staff from our distributed planning branch, the ones that are helping with this task force, helping to advise decision makers in that proceeding, to make sure that the budgets that we will be approving are able to address this need. So that's the medium term.

And then I do want to speak to the long term first in relation to a proceeding that we have open called our high distributed energy resources proceeding. And so this is the proceeding where we are looking at the changes that are needed to our distribution system planning in order to address a high transportation electrification future, building electrification as well. And so changing the way that the utilities do that planning.

This is looking at a number of different issues, including changing the data sets that we are using to inform that work, looking at how the utilities are interacting with local governments and planning agencies, and then also working with our sister agencies like the CEC on how can the demand forecast that we rely on from them help to better support this work? And then I do want to highlight one additional piece, which is focused on medium duty and heavy duty vehicle charging.

And so we have been working on a staff level framework to coordinate with Air Resources Board and the vehicle rollouts. California Transportation Commission, California Energy Commission, of course, to make sure that the work that we're doing is coordinated, particularly around medium duty and heavy duty vehicle charging, to coordinate with the goals from the Air Resources Board, as well as addressing equity issues that we know of, communities where this charging is going to be occurring, near the ports, distribution centers, all of that.

So I think those are our short term, medium term, and long term strategies for customer interconnection.

I appreciate that. Sure.

Now, the Department of Finance Commissioner Gunnar was here really for the reliability update. He has a very busy schedule today, so I'd like to excuse him if possible. And we have several other experts from the CEC here in order to answer your questions. If you have any final questions for the commissioner.

Does anybody have, Assemblymember Ting.

Thank you, Commissioner. Appreciate you being here. I think just going back to our chair's interconnection question, one of the major challenges we had heard with getting a number of the clean energy resources online was really around interconnection. So what are we doing to really close the gap there?

Yeah. Thank you, Assembly Member Ting. So just to elevate a couple of points, thank you for your hearing in November, where you pressed us very clearly on essentially having a Gantt chart of what's happening. So as a part of the integrated energy policy report this year, we are hoping to develop those charts for the legislature. We've already asked the IOUS to provide us information, and depending on what we get, we might develop a formal ask on the data.

So that's one, in terms of just providing you situational awareness. Two, we have been meeting with the industry in seeing if there are opportunities from the $1 billion reliability funds to further some of those, if we can. So, including process improvements, support for state agencies or other local agencies, but also looking at is there a way for us to think about covering some of the network upgrades using the setup money? So those are two things that we're doing in terms of moving the ball and providing both information and recommendations to the committee here.

And then I think going back to the strategic reserve two years ago, I said the same thing. I was just very disappointed that the strategic reserve didn't make up more clean energy, that there wasn't wind, there wasn't solar, there wasn't battery. I mean, we are at a point now, with lithium being cheaper and cheaper, that there was really no excuse not to have had some foresight to purchase those items to be part of our strategic reserves. Can you give us a sense of what progress you're making in that area?

Yeah, absolutely. So I just want to flag the premise of the strategic reserve being out of market resources. So what we're hoping to do is those resources that are required under the RA program and such have the full advantage of the supply chain right now. So if once we get those resources in the RA program, we will be really moving towards cleaning up the strategic reserve.

Having said that, there are some technologies which are not cost effective for RA program, like the fuel cells and such, which we are going to put in. And finally, you mentioned this several times, both in briefings with you and other forums. We are absolutely recognized the sentiment on the demand response, and we want to grow it. So as I mentioned, we are currently in the framework of how do you take the entirety of the demand flexibility opportunity and unlock that in broadly three buckets?

What can rates do in really getting our demand flexibility going, and what amount of demand flexibility could be on the supply side, like a four hour product, and what can be done for the emergency load reduction programs, really leaning on the electric vehicles. So we'll continue to work on that.

Well, I think that's what's absolutely critical. I think we've underutilized demand response, educating consumers. Now we have a number of technology companies who are really in that space, but educating consumers, letting them manage that. So really, I would urge you to, at the very least, figure out some specific plans and to figure out really how much energy we could save by moving into more aggressively into demand response, especially on the residential side, because obviously that's where you're going to get your bigger benefit.

But I really do think it's inherent. I know a number of us, our colleague Ms. Friedman already left, but Ms. Friedman, Mr. Garcia and I, we were in those discussions last year around energy. And I think for me, it's absolutely clear what we need is we need a plan. So that goes back to Mr. Essayli's points. We have a plan so that we actually are planning to have enough energy in the long run. But in my opinion, I think there's enough technology out there to make sure it's clean. So again, when are you going to be updating, I think, your plan.

So in June, we have a deadline to submit to you under the 846 a demand flexibility goals. And we are hoping to one frame it, frame the opportunity, but also provide some operational recommendations. And to your point, given that the extreme weather events are 10-20-30 hours a year, being able to really lean on the large amount of storage behind the mirror would be exceptional. We're absolutely working on that.

Well, hopefully even before your plan comes out, maybe we can get a briefing to get a sense of where this is going. I think it's really important because I think we're all committed up here to make sure we have enough energy for not just every household, but every single business. When the energy goes down, our economy stops. And I think it's really important that we traditionally, one thing we don't worry about, when you plug in something, you assume it's working.

And we know that we can't predict wildfires, we can't predict some of these rains, but again, as much as possible, what we can predict, I think we need to really make sure we have a plan today and tomorrow.

Chair. With that, if I could step off, I have another commitment. Thank you again for this incredible opportunity to be here and answer your questions. We take this very seriously to keep you informed and all the information that we provide. Happy to do further briefings for your offices if need be. So thank you, sir, for the opportunity.

Really appreciate it. Assemblymember Garcia does have a question for you if you have another moment, just quickly.

Regarding reliability, the CPUC in January pushed back its firm renewable resource efforts that they had put out for procurement. Concern about reliability, the timing of it, just some thoughts perspective on that. Because if we're talking about the grid instability and we put out procurement for some firm renewables and now we're pushing that back, I would imagine that that would cost some.

I mean, I have a colleague from CPUC who could answer, but I think in the presentation we also touched upon, CPUC authorized an additional 4000 MW for 2026. So maybe Luam could thank you for that opportunity.

Assembly Member Garcia. Leuwam Tesfai, deputy executive director for energy and climate at CPUC. And so what I think you might be referring to is that in that February 23 decision where we did authorize an additional 4000 MW, there had been a long lead time resource requirement that had been for 2026 of 2000. We did push that to 2028.

And the reason for that is that we had set this requirement in 2021 and we've been monitoring the situation and some of the early indicators are showing that load serving entities are struggling to procure some of these long lead time, diverse resources. And so that's why we push that forward and then also how the central procurement entity will fit in.

Thank you very much for your time.

Thank you so much.

Really appreciate. We still have the other presentations and I would like to make sure that the Department of Finance actually goes through and publicly lists the cuts that are being made and. Go ahead.

My apologies, Mr. Chair, I have to get going and I do have one question for DWR before I head out. Apologies. We know that there is a proposal around central procurement that you would be in charge of. Can you give us a sense of how you would procure, whether you would be procuring, whether you're asking IOUS or utilities to procure, and then what impact on the General Fund would that have? Or are you planning to float a bond? Where are you getting the resources to potentially be this procurement entity?

Great.

Appreciate the question. Again, this is Delphine Hou, Deputy Director of statewide water and energy from the Department of Water Resources. Sorry, a lot of acronyms. Appreciate the question. So first, I do want to clarify that we're here to support the CPUC in their process. So the PUC would, through their integrated resource plan proceeding, designate and request that DWR perform that central procurement function.

In thinking about what comes, we've outlined sort of two broad pathways that could occur, and again, it would depend largely on the type of resource, the scope and the scale. But the two broad pathways are first and foremost the DWR could, like any other load serving entity, issue a power purchase agreement. So that's sort of the sort of very known pathway. In addition to that, the idea would be to understand the resource that DWR would need to procure.

But the benefit there could be that DWR could undertake a power purchase agreement that is slightly longer in timeframe and thereby decrease the cost. On the other hand, also, again, it depends on the resource, the timing, the scope and the scale. If the developer is unable to secure financing, that's where DWR could step in with our bonding authority to assist with that. That would be a more complicated pathway. But from what we understand, these clean, large, diverse resources are very unique and complex builds.

And so if we had to go down that pathway, we'd have to balance the needs in terms of understanding what is required under bond financing to support the program. Again, there the benefit could be that DWR could look at bond issuance along a longer timeframe, again saving overall money. But also we would need to make sure that in terms of the bond issuance, we are clear in reducing as much risk as possible.

So under both pathways, either a power purchase agreement or bonding, we would seek to go back to the CPUC, work through the PUC process to ensure that we could get a non bypassable charge either to support the PPA or bonding. Now that's when we get to the actual project phase. In terms of your question, Assembly Member Ting about general funding that largely from what we understand, is to start the program before there is an actual designation or before there is an actual project on the horizon. But in order for us to be a viable option for the CPUC to consider, we do need to actually have that functionality within DWR.

So the power purchase agreement, you said you could be funded with a non bypassable charge. So that would be like a non bypassable charge from different utilities, or from the IOUs in particular, or from all the utilities, including the POU's. Well, when you say non bypassable, I assume it means it's not going to be passed to the customers.

If I may. So the non bypassable charge is paid for by the customers, and the term non bypassable means that you can't get around not paying it. And so the purpose of having a non bypassable charge for a resource like this is to create a steady stream of funding to pay for resources. And as a reminder, these are resources that we already know we need to have. So it's not something, in addition, it's something we already know that we need to have. But that steady stream of funding is what is able to reduce the risk and help reduce the financing cost for a project like this.

And why wouldn't currently IOUs, POUs, they're all procuring energy as we speak. Why would this need to be centralized?

So for some of the reasons that Director Hou outlined. So the economy of Central. Can I answer that? Okay, sorry, I don't want to jump in. That Director Hou identified, if we identified DWR as a central procurement entity, well, one we know they have a track record of procurement. They do it for the state water project. They did it during the energy crisis. They are a tax exempt entity. And so that also provides additional cost savings for customers. And then also the economy of scale. If they're going to be procuring these resources on behalf of customers from several load serving entities, that's another potential cost savings through this program.

I guess I would respectfully disagree that they have the competency to do this because this is not like a one off emergency. This is something that is potentially ongoing. So I guess I'm not aware of the competency or the skill set that they have in this particular area.

So I do want to let directer Hou speak to that. But the reference I was making is that the state water project is one of the largest procuring entities of electricity in the State of California and they've been doing it for many years. And so that's what I was referencing of competence, but I would like to let Director Hou speak to the competence of her team.

I appreciate that, Leuwam, and appreciate the comment as well. Assembly Member Ting, I agree with you. This is a new function. This is something that we would have to establish within the office that does not exist today. But as mentioned, we do have other similar experiences where we have stepped up on behalf of the state, especially for electric reliability. So we would be leveraging all of those experiences as well as bonding experience if we needed to accomplish the task at hand, if we are selected.

So with the power purchase agreement, the idea would be you would purchase, but that we would be reimbursed or the utilities would pay us to buy that energy.

Through the non bypassable charge. That's what we would be seeking.

So there would be no General Fund or special fund money needed.

Once we get to an actual project selection, we would go back to the CPUC, coordinate with them, and if that's acceptable and we move forward, that is correct. Any journal of funds would really be to support the office before there is any actual project selection because we would need to already have the staffing and the right expertise available to actually do the work. I just wanted to clarify the two different timescales.

And what about the bonding authority? How would that work?

Again, it would depend on the actual project and whether the counterparty or the developer could actually secure financing. So we think about it in terms of as a backstop option. If the developer is unable to secure traditional financing to support a power purchase agreement, that's where the bonding authority could come into play.

Got it. I know we're going to be hearing more about this in utilities committee too. While I do believe it would be helpful to have an agency like DWR be a central clearinghouse to make sure that they can play a coordination role, I do have concerns whether or not they should be the ones actually doing the purchasing.

I think that there are ways to leverage either the IOUs or the POU's and their expertise, because that really is what they do all day long and still maintain DWR's role as a central procurement authority or really watching the procurement occur throughout the state. But it seems like that having a new team hired to go do this, I don't even know how we would train them to go do this. Maybe a little bit out of our skill set. Thank you.

Appreciate the comment.

Senate Member Ting, I know that you have a hard stop and we'll have to leave. I would like to point out for the benefit of everybody, but especially Assembly Member, that this issue of central procurement, it has many policy questions and ramifications. As you started to hear from him, we will move this as a policy bill in the Assembly is my understanding, but that doesn't mean we're not going to fully vet it as much as possible here.

Also, because it's such an important and complicated issue that I want to make sure that we have both options sort of out there for us to both gather the information and have a healthy conversation with the administration as we move forward.

So I wanted to be clear about that when we get to issue number two, I have a number of questions about how this affects risk for the ratepayers and everything else when we get to item two, but we jump to that so that Assembly Member Ting could meet his hard stop. So, Assembly Member Garcia.

Yes, thank you. And along the same lines of my prior question regarding reliability, how do you see the central procurement proposal in front of us? Maybe moving more aggressively on the firm renewables that have been pushed out to 2028. Now, I recognize that at 1.0 the procurement call was for about 1000 MW. Now, we've increased that significantly, but pushed it out significantly. Does the central procurement concept, in your mind, allow us to move far more aggressively on ensuring grid reliability with firm renewables?

Assembly Member Garcia, that is issue two coming up for us. We only jumped to it just for the benefit of Assembly Member Ting. So if you could hold that, I think it'll be more appropriate because that's my question. We still have an issue one. We still have Department of Finance that we need to hear the cuts and we want the LAO. So that way we can finish up with issue one unless you have a hard stop.

Great. Ok. All righty. So if we can move back and appreciate DWR, time to change seats here. So how about Department of Finance? We want to make sure we read into the record what all the cuts are and then we'll take any other questions or comments from Administration side before we go to LAO.

Okay, sure. Amin Albin, Department of Finance. So the budget retains key funding for important investments to support clean, reliable and affordable energy and maintains about 7 billion of state funding for the clean energy transition from the energy package of 2022, preserving all 3.4 billion of funding for the critical reliability budget included in the 2022 budget, given the commissioner's presentation. Overall, the 2023 Governor's Budget proposes $897,000,000 of General Fund reductions and $370 million of General Fund delays into future years.

The reductions in the budget are largely where programs were still in the development phase, where there are available funds, followed program expenditures, and where there's potential federal support to supplement the reductions and or shifts. We strove largely to maintain critical investments to achieve the state's energy and climate goals and prioritize equity, reliability and safety as the state continues to encourage efforts to decarbonize the grids. The specific reductions that were included in the budget are for the California Rearrange payment program.

The budget reverted $400 million in California Emergency relief funds in 22-23 to the General Fund from savings from the California Rear Payment program. Based on actual applications received and approved for the funding for the residential solar and storage program at the CPUC, a reduction of 270,000,000 in 23-24 is contemplated. This maintains approximately $630,000,000, about 70% of original funding for solar than storage incentives for low income utility customers.

For the long duration energy Storage program at the CEC, a reduction of $50 million in 2324 is proposed. This maintains about $330,000,000 of about 80% of original funding for support of long duration energy storage projects that will help with the state's clean energy transition. For the carbon removal program at the California Energy Commission, a reduction of $25 million is proposed in 23-24. This maintains approximately 75,000,000 or 75% for projects that support the removal of carbon.

For the transmission financing program at the California Infrastructure Bank, a reduction of $25 million is proposed in 23-24 maintaining approximately 225,000,000 or 90% of original funding for the financing support of new energy transmission projects. For the accelerating adoption of low global warming pollutant refrigerants at the California Air Resources Board, a reduction of $20 million and 23-24 is proposed.

This program helps accelerate the adoption of low global warming pollutant refrigerants and will maintain still and the reduction will still maintain $20 million or 50% of program funding for supported businesses adopting those technologies. For the Food Production Investment program at the California Energy Commission, a reduction of $10 million in 23-24 is proposed, maintaining approximately $65 million or 87% of original funding for support of projects that help with decarbonization of the food production process in the industrial grid.

Support and decarbonization program at the California Energy Commission, a reduction of $10 million is proposed in 22-23 maintaining approximately 90 million or 90% of original funding for projects that support the decarbonization of the industrial sector and provide grid support for the equitable building decarbonization program. At the California Energy Commission, a delay of $370,000,000 of funds in the current year and the budget year to future years is proposed, as well as a reduction of $87 million in 25-26. This maintains approximately $835,000,000 in the program.

About 91% of original funding for support of projects reducing GHG emissions in homes and advancing energy equity. Lastly, not part of the Energy package, but equally important program at the California Energy Commission, the Climate Innovation Program. A delay of $150,000,000 is proposed in the current year and the budget year to 2026. These reductions, while not ideal, are necessary because of the fiscal environment we find ourselves in. And with me here today are representatives from the Energy Commission and the Public Utilities Commission to speak to specific programs. Thank you.

Thank you very much. For the benefit of everybody. We're an hour and a half into this Committee hearing. We're still on issue one. We have done some spillover into issue two. So I think if everybody will try to be as sensitive in terms of the time as possible as we move forward. Does the Administration have anything else, representative of CEC or CPUC have any other comments that you wish to add?

I had prepared comments, but it's not essential. I think Vice Chair Gunda did a great job of giving the overview.

Great. Thank you very much. We'll turn to the LAO. Same thing in terms of. You have extensive comments. I know on both issues 1 and 2, we have had a chance to review those, but we'd like to have what you think is important to read into the record.

Thank you. Sarah Cornett with the Legislative Analyst Office. So the governor is proposing about 900 million in reductions, as we just heard. We find these to be mostly reasonable. The reductions are occurring across programs and are really targeting newer programs or ones that are early in their implementation. The largest reductions are occurring in the residential arrearage payment program, the residential solar and storage program, and the equitable building Decarbonization program, which is proposed for a delay.

We find these to be reasonable and benefits for low income communities are prioritized. So, for example, in the residential solar and storage program. The retained funding would specifically support residents in low income and disadvantaged communities. The administration has also provided evidence that this new proposed amount for the arrearage payment program would be enough to fully cover all existing need under the program's current eligibility requirements. The governor is not proposing reductions to the reliability programs.

We think these could be worth considering, as it's not clear if all of this funding is needed now. So, for example, there has been no spending in the distributed electricity backup assets program or DEBA. That program received 700 million in the budget last year. There's also more funding proposed for these programs in the Clean Energy Reliability Investment plan, which is intended to provide 100 million this year. We think additional solutions may be needed given the budget situation, so we provide two examples in our report.

First, the climate innovation program. So this program has not really gotten off the ground and could be a good candidate for reduction. The Oroville pump storage project is still early in its planning. We think the legislature could provide funding for the planning and permitting process now so the project can make some progress, but wait until a more accurate cost estimate has been provided before giving the full amount committed last year. Thank you.

Thank you very much. I want to compliment LAO traditionally comes in with good recommendations, but particularly in on issues 1 and 2. As complicated as they are, it struck me as being very thoughtful with very many good sort of suggested options for us to consider, and options are nice to have on the table when you have something as challenging and difficult as this. Do we have other questions on issue one from any of the committee members?

It seems that there's an appropriate balance out there, but I am not able to capture what the administration's view is on that particular balance, and I'd like to get started on trying to capture that. And I would offer these comments as we go forward.

Just like demand response, but the same people that will be hollering at us that rates are too high will also say demand response isn't something that we should do because we need to have all the electricity you want, anytime you want, whenever you want it.

And there is a balance there also in that if you want to keep rates down if you can flex demand to where it doesn't cause a hardship, but it just becomes people choose to help for a variety of reasons, maybe because they're going to be reimbursed, maybe because they're going to get lower rates. Some people may say, I'm willing to do that because I actually want lower rates. So, it seems that there is an appropriate role here.

I'm not capturing the administration's position on that appropriate role, and I don't know how we can make sure, from a legislative standpoint, we can weigh in on something that we're all trying to get our hands on and stuff. So, can you offer from CEC and CPUC your thoughts about that?

I'd be happy to go for it.

Great. All right.

And so I did appreciate this question. I have prepared a couple of bullets and happy to discuss as well. So, the CPUC has taken several actions to support the commercialization of microgrids. So, in addition to the policy direction and funding we've directed with the CEC's research and development programs through EPIC, which I'm sure CEC will cover, we have also supported microgrids to accomplish a number of objectives in the CPUC's microgrids and resiliency rulemaking.

And so that was opened in September of 2019 in response to Senate Bill 1339. And I'm happy to provide a few updates from that proceeding. So first, in June of 2019, the CPC adopted a decision approving short-term actions to accelerate microgrid deployment, including topics like single line diagrams to smooth out interconnection data access portals so that communities can access data and understand: is a microgrid the right option for them?

And that includes distribution and transmission data that can go to local governments as well as to tribes to invest in micro grids. Then, in January of 2021, the Commission voted to approve another decision that adopted rates, tariffs, and rules for facilitating the commercialization of microgrids, including a framework for what we're calling the microgrid Incentive program, which is a $200 million program-focused on equity targeting customers most vulnerable to outages to commercialize clean microgrid technologies.

The program rules for that program have been in development, and the rules for the program will be voted out at the Commission next month. And then also in July of 2021, the Commission approved a decision that adopted the suspension of what we're calling the capacity reservation component of standby charges. And so the point of this was for eligible microgrid technologies to be able to reduce some of their costs and support third-party microgrid development for customers as well with these technologies.

I also wanted to focus on the summer reliability component, so we put together a last-minute track at the end of December 2021. So, that was three decisions in one year, but that was focused on summer reliability. And so in that decision, not only did we include the approval of temporary microgrids, leveraging substations to support communities, but then also four circuit-level microgrids that are focused on providing peak and net peak grid reliability.

And then the second piece that you talked about, DERs kind of in general, not just microgrids, just taking a step back. We're also looking at opportunities for distributed energy resources in our high DER proceeding, and so that's really looking at also supporting investments in transportation, electrification and building electrification, and that's also the venue for some of those distribution planning topics as well.

Great. CEC?

I'd answer your first question, Chair; thank you. Drew Bohan, Executive Director for the California Energy Commission, the first question regarding distributed or central, I think our answer would be we need both. It's not an either-or question, and we think through diversity, through all manner of diversity, but in that respect as well, it brings better security to the system.

With regard to DR, we are working on the report, as Vice Chair Gunda talked about earlier, that we were directed to put together pursuant to SB 846, and that is due to you on June 1. We were on track to meet that. And we think there is tremendous opportunity in the state; some of the questions Assemblymember Essayli mentioned something with regard to DR potential: there is tremendous potential with additional electrification.

And I want to just repeat what the Vice Chair had referred to, which is electric vehicles are not a threat to the system. They're a tremendous opportunity. You can't decide when you want to have your lights on. If it's dark, you have to have your lights on, obviously, but you don't have to charge your vehicle during five to nine at night when that's the critical time, 2030 days out of the year, where it's absolutely critical.

Some people will, and they can, but if we get it right, we'll design rates in such a way that would encourage folks to charge during the midday while power is abundant and cheap versus in the evening when it's not. So that's one thing we're doing. We've got a proceeding right now pursuant to bill that passed a few years ago, and we're looking at appliances so we can bake this into certain appliances.

The one we're working on now, and we'll have a regulation we're going to adopt a little bit later this year, is for pool pumps. So today when you buy a pool pump, you set it up however you want. The default will be we will require manufacturers to have the default be during the hours when, again, power is cheap. And for most customers, they won't care. As long as their pool is kept clean, they won't care, and it will run during those times.

They can change it if they wish and they would want a different duty cycle. So we're looking to do that on a lot of different appliances. Your refrigerator and freezer can defrost at one time or another. It happens randomly based on how engineers designed it. So there's a number of programs, and I don't want to go into all of them, but just to give you a flavor of them.

Thank you very much. I have some more questions on that, but because of where we are in terms of the timing of this, any other questions on issue one before we go to issue two? Assembly Member.

Yeah, not so much a question at this point because I think you raised the issue, and I just wanted to reiterate that this legislator is also very interested in microgrids as we tie into the issues of interconnection and distributed energy. I guess one question it sounds like, and I'm aware of it, is there is planning around microgrids at the CPUC and otherwise. Do we have examples of successful microgrids in terms of being implemented in California, and what impacts on energy costs are we seeing from that?

We have a number of examples. The Energy Commission is funded. I lost track of the number, but it's in the 30 or 40 range of microgrids that we funded in the State of California. One example we like to point to is up at Blue Lake Rancheria in Humboldt County, where the PUC commissioners and CEC commissioners just held a joint onbonk forum a couple of weeks ago. That facility has a microgrid, and several times over the last couple of years, the power has gone out.

They're in a part of California where power does go out sometimes they didn't even know about it. They found out later because the microgrid kicked in without anybody noticing until they looked at the diagnostics afterwards. So we're very bullish on them. The knock on microgrids is that they're expensive relative to incumbent technologies. But two things are happening. One, the price of solar, which is typically what fuels them, is going down, as everybody in this room knows. Similarly, the storage is going down, and one of the programs that you directed us to invest in was long-duration storage. Right now, lithium is really the only game in town, and we are looking at other chemistries, other mechanical ways of storing electricity, and even heat technologies. So we're looking to broaden that and diversify. But as lithium comes down and solar continues to come down, microgrids will become increasingly appealing.

And potentially hydrogen as a long-term storage source also -

Absolutely.

As those costs come down, I want to point out that redundancy is a great way for us to improve reliability long term. And I just see the microgrid sort of approach is that you talked about the cars in terms of, one approach would be to make sure that they're charging because of incentives, off peak hours.

The other would be to actually create an incentive to use that car, that battery that's charged, to give back to the grid during peak hours and then charge when the peak hours are over with. And to the extent that we can do that, that's another option there.

I think it's one of the things we're looking at, chair, in the DR report that we're doing for June 1. And just to reiterate the numbers you heard earlier, a million battery electric vehicles in California using Ford's been very bullish on this, and using Ford's discharge rate from the vehicle to the home or business. At that rate, a million battery electric vehicles in California, and we're over halfway to a million, will be able to put into the system 10 gigawatts. Our peak load is 50 gigawatts.

They'll put in 10 gigawatts. If we get to 8 million vehicles, that's 80 gigawatts. Now, we're never going to get every one of those units, but if we get a small fraction, that's a tremendous boost to the system.

Sure. And another way to keep rates down for everybody, which will be the constant tension we'll have. People will complain about the higher rates but also want electricity 24/7 and being creative there would really help. Yes.

The Public Utilities Commission also has an open proceeding on-demand flexibility. And so that's the rates piece that you're talking about. And so being able to create those rates to work with these technological improvements that the CEC is enhancing so that they connect for customers to get these price signals, these incentives. And this is really the future of demand response. Looking at things today, we have over 1500 demand responses in the supply-side stack of resources.

And the Commission also has an open proceeding where we're looking at how to enhance those demand response resources. But in the future, we want it to be seamless and so that customers don't have to think about scarcity. They're thinking about, as you pointed out, shifting their use to a different point in time, or the technology is doing it for them seamlessly.

Thank you very much. We have one more question. Assemblymember

Yeah, thank you. I appreciate it. I'm going to have to take off after. So, you guys touched on a couple of things. I'm having a hard time reconciling it because every time we talk about renewables, I hear the cost is going down. They're becoming more cost-efficient. But our electricity prices continue to go up. We have Californians pay 80% higher electricity prices than the US average. Commercial electricity is 85% higher than the US average industry is 116%. What's the disconnect?

Why are our electricity prices so much higher than the rest of the country when we're being told that renewables will save money?

Yeah, I can speak to that. So, there is a component of the electricity rate that's related to the procurement of electricity. And so that's what we've been talking about. The cost of renewables go down. But there are also a different portion of the electricity rate that's focused on wildfire mitigation. For example, the build-out of the actual physical infrastructure, whether that's the transmission line itself or steel in the ground, is separate from the procurement of the resource itself. And so we are working to mitigate those costs.

But those costs are very present in the rates that you're talking about. So that's a very important point.

I do have a concern, and I hope the PUC is doing proper oversight on this because what I hear is that the utility companies make most of their money now on constructing these power lines, and they're really just in the construction business now. So I just want to make sure that we're being careful watchdogs in how much we're paying out for construction projects and we need to get these prices down. And I don't know what the solution is.

I would love to hear from you, but I think we can have both. We can have abundant power and we can have low prices because we're smart, right? It's 2023. We have lots of technology, very smart, capable people. We can do both, but we have to start showing some results in lower prices. And I think what that will do is build the public's confidence to invest more into these projects.

But when they hear we're going in this direction and all they see are their prices going up, it's hard to sell. It's very hard in my district, too. So I just want to make those comments and then last comment on the item, too. I'd share Assemblymember Ting's comments anytime the government comes and says, create this new agency, we'll do it better and cheaper.

I'm very skeptical, so I'd want to make sure we have some hard, concrete evidence on why they're going to do it better than the folks doing it now. But thank you, Mr. Chair.

Thank you for your comments, Assemblymember. As we move on to issue two, I just would point out to everybody that weighing in on the utility debt relief program and the self-generation incentive program with staff is welcomed if members or anybody have strong feelings on which way to go with those programs. So we're now at issue two, and that is the question of the energy trailer bill. And as I've already mentioned, this issue will be moving in the assembly as a policy bill.

But while we have it here, and it doesn't mean it may not eventually come back here, depending on what happens with the Senate and the governor, we want to make sure that we get the questions answered and help shape the policy conversation that will. So I appreciate Assemblymember Garcia being here so he gets the benefit of both this and there with the hearings. So we will start with the administration and whoever in the administration wants to start off. And if you'd again introduce yourself and kick it off.

I'm prepared to start. So again, my name is Leuwam Tesfai. I'm the deputy Executive Director for energy and climate policy at the California Public Utilities Commission, and I appreciate the opportunity to share some remarks on behalf of the Public Utilities Commission on the central procurement function from the trailer bill. So, through our stakeholder proceeding on integrated resources planning, the commission has determined that clean, diverse, long lead time resources are needed to meet California's 2045 climate and reliability goals within the electric sector.

This need has been confirmed in the CEC's SB 100 report process. There is a need for resource diversity within the state's electric sector portfolio, and long lead time, diverse resources provide reliability and greenhouse gas reduction benefits to the system that would not be procured in the typical procurement activities of our current load-serving entities, which have largely been contracting for solar, photovoltaic, battery, and onshore wind resources.

We've continued to see a disproportionately high amount of procurement of these types of resources, which won't be sufficient to meet our reliability or long-term climate goals, and planned action will likely be needed to happen to support that effort. So why use a central procurement entity? Long lead time resources can be hard to procure. We push for the most competitive and clean resources, so resources like offshore wind, for example, despite its value, will not come to the top of a resource solicitation.

Electric market competition and energy resource development complexities have thus far prevented significant procurement of certain long lead time and diverse clean energy resources. As I stated earlier, most of the new energy resources procured to date have been solar photovoltaic battery storage, onshore wind instate resources, long lead time resources like offshore wind, large scale long-duration energy storage, and geothermal have features that make them likely to require the support from some form of centralized procurement if they are to be procured at all.

These features include a high level of development risk, long development timelines, economies of scale, a need for a significant new transmission to access key resources, federal and state permitting processes and sighting processes, and non-transmission infrastructure buildouts like to our ports and material supply chains that require extensive state-level interagency coordination, which is what we are doing. All electric customers and ratepayers are likely to benefit if all or some of these hard-to-procure energy resources are procured centrally.

More specifically, the CPUC's midterm reliability order requires load-serving entities to procure 11,500 net qualifying capacity, including, as Assemblymember Garcia mentioned, 2000 long lead time resources originally in 2026 in the 2021 order but has now been pushed to 2028 in the order from February.

So, in the meantime, we have been studying the trajectory of these efforts, and early indicators are showing that load-serving entities are struggling to meet these procurement requirements for these long lead time resources, and as such, the commission last month extended the deadline to June 1, 2028. Having the option to leverage an entity like DWR, for example, or another load serving entity as a central procurement entity is going to be a key tool on the table to procuring these long lead time resources.

As you saw in the trailer bill language, the identification of a central procurement entity will occur not just here today but through a CPUC stakeholder proceeding for the integrated resources plan. But in order for us to consider it as a viable option on the table, we need to have the authority in order to be able to do that. DWR, as I mentioned, has procurement experience and, through the trailer bill language, will have the authority and resources to act if identified as the central procurement entity.

DWR is already one of the largest procurement entities in the state through their administration of the energy resource management and procurement for the state water project and the unique role that they played during the California electricity crisis of 2001, and now also their management of the Electricity Supply Strategic Reliability Reserve Program under the leadership of Director Hou.

DWR has demonstrated over the years that it has the knowledge and capability to procure large amounts of needed energy resources, but again, we would leverage the CPUC proceeding in order to determine who would be the central procurement entity. In partnership with the PUC, DWR may be best to lead the issuance of competitive solicitations and establishing and administering revenues and expenditures for energy resource development.

Looking at the issue of timing, as I mentioned previously, early indicators show that load-serving entities may already be struggling to procure some of these resource types, even such as geothermal, and thus could benefit from a central procurement entity right away. So that timing issue is very important.

Other resource types, such as offshore wind, have an even longer development timeline that developers would require a clear procurement signal of a very large number of megawatts of that resource within the next one to two years for sufficient quantities of the resource to be online in time to meet the state goals. Thus, action on the part of the CPUC and the central procurement entity, whether it's DWR or a load-serving entity, may be needed as soon as the 23-24 fiscal year.

So that concludes my prepared remarks.

Thank you very much. Again, we want to try to be as efficient as we can here, given our time. Do we have other comments from the administration?

Eamon Nalband I'll just speak to the second part of our energy trailer bill just to keep it brief and for streamlining it. But to further bolster the state's reliability outlook, the budget also proposes the establishment of capacity payments by load-serving entities that rely disproportionately on the Strategic Liability Reserve due to higher levels of energy resource deficiencies.

This is meant to mitigate potential over-reliance on the Strategic Electricity Reliability Reserve for near-term electricity demand and help ensure that the Strategic Electricity Reliability Reserve will be able to achieve its purpose of providing capacity to support reliability during extreme events. And with us here today are also people who speak to that aspect of the TDL.

Thank you very much. LAO has created for us, I think, one of the best policy analysis. So, for the policy committee going forward, I think it's a great beginning in terms of an overall summary, a good educational beginning in terms of identification of terms and agencies and projects that are out there, and it identifies just how many policy issues are included in this budget trailer bill.

And so I think there's some great benefits of having both a policy hearing on this and the summary here. So, LAO, my compliments. Is there anything I don't want you to go through all of this? Is there anything that you want to particularly highlight that you think is particularly important for us to get into the public record here?

Sure.

I can just briefly go over the four big questions we think that the proposal raises that we do go into detail in in the brief. So, the first question we recommend the legislature consider as it deliberates a proposal is how ratepayers will be affected. So there are kind of three ways in which we think this proposal could affect rates. First, the capacity payment that could be passed to ratepayers should electric utilities experience deficiencies in the months in which the Strategic Reliability Reserve is used.

It's unclear how those payments could affect rates. In addition, the non bypassable charge that would cover DWR's costs, and then finally, the market effects of DWR being in the market. So, it's not really clear to us how energy developers could alter prices of resources and how resources are priced ultimately will affect rates. The second question is, are current processes insufficient?

So, in the brief, we go through the integrated resource planning process and other processes that already exist, and it's not clear to us that these processes are necessarily insufficient to meet future energy needs. The third question is, what are the risks to the state? So, the administration has said this is intended for bigger projects such as offshore wind, long-duration storage, and geothermal energy. These are newer technologies in California and very expensive.

So we recommend the legislature kind of think carefully about ways to kind of assess the trade offs and potentially create some guardrails to reduce the risks to the state. And then, finally, what is the status of recent investments, and is more funding really needed? So, as we said earlier, some of the reliability programs appear to be somewhat slow to spend down their existing funds. So we ask in the brief whether this capacity payment could be redundant. Thank you.

A great setup for this as we move over, and we would have a whole hearing probably just on this issue if we were going to try to do all of the excellent questions and issues that are brought up in the LAO report. So I appreciate that. I do want to idea a few things that I hope are going to be considered, and one is the items about how it affects the ratepayers, et cetera.

I think is really important what we can do to try to decrease risk as we move forward. The other is the intention of the administration is that this be for big projects, but there is no clear definition. There are some examples of that, and so is the administration open, willing to. I guess it's more a rhetorical question, but it seems that we might want to identify, yes, offshore wind is a big project, everybody can agree to that.

But if the administration comes up with other ideas, should there be a check back with the legislature before that gets handled by central procurement? Would be the kind of issue that I would try to raise as we move forward with identifying clean energy projects at central procurement process. If we went forward with that, that they would be associated with. And then I do have for the CPUC the integrated resource plan.

It looks good on paper, but it's all about enforcement with the LEAs and so how do you envision enforcing it? What kind of history do you have so far with enforcing it? Can you help me with just a minute or two in terms of that? So that's my final question on this topic.

I'm happy to start on the topic of integrated resources plan enforcement. So, in the CPUC's IRP process, we have two sets of compliance and enforcement mechanisms for the CPUC jurisdictional load-serving entities, so for timeliness and completeness of the filings that are due to the commission and the information there, and for the procurement compliance related to the procurement orders.

So, for timeliness and completeness of the filing information per the 2021 CPUC resolution, the CPUC can subject noncompliant load-serving entities to penalties should they be late or incomplete in the planning and procurement filings required by the integrated resources planning process. So, for the second piece, which is for procurement compliance related to IRP procurement orders. The CPUC ordered in a decision in 2021, as I said, a lot of new procurement, 11.5 gigawatts of net qualifying capacity. So, this included the opportunity to impose penalties.

So, in that example, a load-serving entity that failed to meet its procurement requirements can be charged what we call the net cost of new entry for buying that new resource for them. And so starting on February 1 of 2023, the IRP procurement compliance filings are now scheduled to be submitted twice yearly for us to be able to use these tools.

Thank you very much. Other committee members, questions on issue number two. I know, Assemblymember Garcia, you had your original question.

Yeah, just again, about the acceleration of being able to bring on our firm renewables under the central procurement concept. Just wondering if that's something that you're deliberating as you propose this policy change in the budget trailer bill.

Happy to take that question. So, just like you were saying and we were discussing earlier, we had been shooting for these resources to come on by 2026; the existing load-serving entities; there are early indicators that they haven't been able to do this procurement.

And so that kind of gets to the timing that I had mentioned in my prepared remarks where we would like to be able to have this opportunity on the table so that we can create a proposal, look at the different central procurement options, DWR, a load-serving entity, et cetera, and use the robust stakeholder process to come to the right decision for us to use this and who the entity would be and be able to continue to move forward.

We mentioned geothermal resources in the closer term, offshore wind further out. But for these types of resources, we need to have a very clear market signal that we're moving ahead with these types of resources.

If I could point out while we're on this because I feel like I'm partially talking to the policy chair that's going to be doing this, I see advantages and disadvantages with central procurement, and I just want to try to identify a few. One is just speed. We have federal tax credits that have to be grabbed by 2030, and the faster we move because 2030 is quick when it comes to planning for a long-term project like this.

And so for the potential project managers and people, the investors that are out there, the sooner they can understand what the process is. So I'd say that falls on a central procurement sort of positive note out there. I think LAO identified a number of potential disadvantages that could come from central procurement as we go forward. So timing is one of those issues, but I think Assemblymember Ting very clearly pointed out the risk of a brand new agency with brand new employees.

And is that agency going to be able to get up to speed fast enough and be the efficient agency that we really need it, particularly if it is part of DWR, which means it's subsumed into another agency and dealing with that. So I see advantages and disadvantages on both sides.

I really welcome the debate we're going to have in the assembly and in the legislature and in the State of California over this proposal because I think we need to have a robust and healthy debate on this. Assembly Member Rivas.

Thank you, Chair Bennett. I agree with you that there are advantages and disadvantages to a central procurement system, and I'm happy to hear that there is a policy bill led by Assemblymember Garcia moving through the process so that we can discuss this further and not move it this fast. So I think this is major policy and it should be done through policy committees and the legislative process.

Thank you. Any other questions or comments? Assemblymember Connolly?

I'll simply concur with that sentiment and note that I'm very happy I'm on utilities and energy, so we'll appreciate the opportunity to participate in the dialogue. I think the jury is out on the central procurement model, particularly around DWR; although we all recognize the importance the agency played back in the energy crisis days, I kind of had a front-row seat to that. But moving forward, what is the best model? If I can follow up maybe on the capacity payments for the Strategic Reliability Reserve?

It's notable, I think that so far, these activities have included extending the life of gas-fired power plants that were scheduled to retire, procuring temporary diesel power generators, and the like. So, as this program goes forward, number one, can you kind of provide more of a breakdown of where things are at now, but kind of how can we improve on that beyond so-called dirty energy sources?

Appreciate the question. Again, this is Delphine Hou, Deputy Director of Statewide Water and Energy at DWR, and happy to answer that question. We completely understand the evolution that we need to go through. When this was established, when my office was established, obviously, we wanted to expedite and get resources in as soon as possible and completely agreed that under the authorization we had, we did take advantage of securing things like temporary diesel fire generators.

But moving forward, that is not something we are going to pursue, even though we would have the authorization to do that till into 2023. So that's one way we're thinking of trying to move the portfolio so that it is cleaner and cleaner. You're absolutely right that right now, we are still fossil fuel heavy, but as mentioned before, here today, we are also aware that for cleaner resources, such as battery storage, there is a lot of pressure to secure those resources for resource adequacy.

And we are keen also, per the legislation, but also in coordination with our sister agencies, we don't want to be in the market competing with low-serving entities as they try to meet their basic resource adequacy requirements. Now, having said that, we do have for this summer new resources under contract. It's about 143 megawatts, which are ultra low emission natural gas fired resources.

The similar technology under a different model has been certified by the California Air Resources Board for distributed generation to get exemption from local air permits. So those are the types of resources that we would like to pursue and cleaner, if possible, in the future so that we can improve the portfolio.

And we do understand the balance of what we do in terms of being able to contract with resources that would otherwise retire so we can secure that capacity for the state electric reliability, but also doing more so that we can meet those mandates for cleaner and low emission or zero emission resources. Thank you.

You stimulated a few other quick comments, one again with the policy chair here and a committee member here; also, in terms of the energy committee, another advantage that I see of central procurement is since I've arrived here at the assembly, I've struggled with so many different silos to try to find out what's the plan? What's the plan for greenhouse gas emissions, get us there, not just what's the big plan, what are the implementing steps?

And too often I run into, well, you've got to go talk to Cal-ISO about this. You got to talk to CPUC about this, you got to talk to CEC about this. And centralizing something as important as offshore wind energy, which nobody has much experience at and has an advantage. So, I identify that as an advantage that I hope our policy members will be exploring.

The other thing that I want to throw out there is that, particularly if we go with central procurement and the potential, but right now, you have all the LSAs out there competing to try to meet their load requirements, and it seems that at some point in time, we may not be incentivizing the best behavior. We may be incentivizing a race to get something before somebody else driving up, actually driving the rates up that the ratepayer is going to eventually pay.

And if we could create some sense of certainty that because we went to central procurement, we created incentives for LSAs to go beyond their capacity or make sure that they're meeting their capacity needs, et cetera, but we don't put them out there just on an island to do it. There may be some benefits to having this be a more integrated approach to how you meet your capacity needs for each one of these sometimes small and sometimes large load-serving entities that are out there.

And I'm saying LSA, and I mean LSEs that are out there. So it seems that there's some creativity that could blend in there to try to address that. I know the CCAs, in talking to them, they feel like they are at each other's throats and they are driving rates up because of trying to meet this. And I think that's not what our intention is. Our intention is to have reliability.

But if they're good faith players at the table and they're making a good faith effort, we may try to find some other better way for us to address this, making sure they have capacity. So, I just wanted to get those out there. Really appreciate it. I look forward to the conversation that is going to take place in Policy Committee on this, and unless anybody else has any other questions, we're going to move on to issue number three. And we thank everybody that's been here for this.

And we move on to issue three. Would people please. Oh, okay, great. And we're going to stop and very quickly add Mr. Garcia onto the vote. And Assemblymember Rivas, if you would run this transition to issue three. And I'll be right back in just a moment.

Hey, David, how are you? On motion one, Mr. Garcia. Motion two, Mr. Garcia.

Okay, welcome. This is issue three, the California LifeLine CPUC. Go ahead.

Good morning. Thank you. Thank you for the opportunity to be here. My name is Rachel Peterson. I'm the Executive Director of the California Public Utilities Commission. It's nice to see everyone shifting gears a little bit from that deep and thoughtful dive into energy procurement over to the California LifeLine program.

I'd like to start with just an overview of the program, and then I have Director Rob Osborn with me here today from the Communications Division in the event of Member questions about enrollment. So we have proposed two different budget change proposals. First is a fiscal request of 357.3 million for fiscal year 23-24. We make this request each year based on our forecasts of renewals, new entrants, and people exiting from California LifeLine.

And then we have a separate small staffing proposal that proposes to convert three positions from limited term to permanent. And just some information about the program, California LifeLine was established in 1984 by the legislature with the Moore Universal Telephone Service Act. LifeLine provides high quality, basic telephone service at affordable rates to low income Californians. The $17.90 per month subsidy can be used for either wireline or wireless service and may be combined with the Federal Lifeline subsidy of $9.25.

This makes wireline and wireless phone service more affordable for approximately 1.33 million low income Californians. Most participants qualify through programs like CalFresh, but they can also be income qualified if their household income level is at or below 150% of the federal poverty level. And participation by technology is approximately 82% wireless and 18% wireline.

And last, in 2022, we completed a review of the program led by CSU Sacramento, and based on their recommendations, we're presently working on a roadmap to prioritize and determine improvements to the program that we can make in the future. I'm going to stop there and see if Members have any questions about our enrollment forecasts, which are the subject of the fiscal request.

Members, any questions? Just a comment. Oftentimes we'll have some folks come in with these maps looking at the eligibility of folks in our districts versus the actual amount of folks that are enrolled. And so I'm just hopeful that maybe you can share with us the strategies being put forward to try to increase. Because many times those numbers reflective of how many people are eligible and those that are enrolled are very low.

And these happen to be same areas where the issue of broadband accessibility and connectivity are a challenge. And so maybe somewhere in your discussion presentation you can touch a little bit on the strategies to improve those efforts.

Thank you for that, Assembly Member Garcia. We absolutely share both the concern and the strong desire to increase the number of eligible Californians who are enrolled in this program. We went through some unusual program steps, or non-steps, really, during the pandemic where the FCC froze renewals for a while. And so that has contributed to some of the kind of wonkiness in those charts.

But now that the pandemic has lifted and we're going forward, and this was the point of the CSU Sacramento review, we are absolutely taking all of that to heart and really looking at strategies to increase enrollment. And I'll ask Director Osborn to speak a little bit more specifically to some of the strategies.

Yes, thank you. Robert Osborn, Director of the Communications Division at the Public Utilities Commission. So as Executive Director Peterson stated, the CSU's assessment identified a number of areas for program improvement, and one of those is looking at the program's reach and effectiveness. One of the changes that we've made recently to help improve enrollment is on the renewal side. So we've recently signed an agreement with CalFresh where we're able to auto-renewal about 29% of the program participants.

And what this means is people don't have to fill out paperwork. They basically are auto-renewed as long as they're still participating in the CalFresh program. We're exploring other opportunities as well, specifically looking at Medicare, which is a little bit of a harder nut to crack in terms of getting access to the database. But those sorts of approaches, I think, significantly help participants and reduce the burden on them.

Thank you. And I think of the folks that are on reduced lunches. I think of the folks that are on reduced payment plans at the local public utility, the gas company. And so there seems to be a lot of paperwork that folks that would qualify here have to fill out to be able to qualify for a handful of different programs. You mentioned Medicare.

The challenges potentially of getting access to that information. But the folks that I just made reference to are all state somehow state overseen regulated entities. There has to be an easier way to have some integration in our systems to be able to cover everyone in one shot. Perspective on that.

We absolutely would love to do that as well. Oftentimes it's an IT project, and it's also a large agency to agency coordination project. Getting the CalFresh coordination took what, a year, year and a half to do, but is very successful now that that unified application is in place. I don't know if you have anything to add on future possible additional strategies.

Yes. So another area that we've recently in the past couple of years been able to expand the program is an iFoster. So it's a program designed specifically to support foster youth and provide telephones to them. So that's an area where we've grown. Another area is on prison identification. We're now accepting prison IDs for folks who are about to be released so that they're able to get a phone without necessarily having the previously required identification.

Assembly Member Rivas.

Thank you. I also share the concerns of the percentage of my constituents that are eligible versus the percentage that are actually enrolled. And like you mentioned, the CalFresh program. So then when you apply to CalFresh, you're automatically enrolled in LifeLine?

Can you speak to that?

Are there two separate applications?

That's correct, Assembly Member. There are two separate applications. But in the process of renewing, once you're signed up for the LifeLine program, by virtue of being in CalFresh, you don't need to re-enroll, whereas people who are not in CalFresh have to go through the re enrollment process.

Okay, but then how does a CalFresh recipient know about the LifeLine program? Is it when they're applying to CalFresh, or do they get a notice? Because I imagine the majority of CalFresh recipients qualify for LifeLine, so why aren't they just automatically enrolled?

And so there's two areas, and thank you for your question. That is a very good question, which gets to program awareness and how we get the word out to people that they can apply for the program. So two areas that we're looking into. One is at the direction of the legislature, looking at a common application so that people don't have to apply to multiple programs. That's something we're looking into.

Another one is looking at expanding the messaging and advertising to trusted messengers because often the LifeLine program, we rely pretty heavily on the providers. They use street teams, which are literally out on the street telling people about the program. There have been some, based on the CSUS evaluation, some issues that we've seen in terms of sort of credibility from those street teams. People don't feel like they want to sign up for that sort of service. So I think it's a lot smoother and more reliable to have an organization like CalFresh present the information.

And if we're seeing a decline in usage, why has the CPUC ruled to end the stacking of the LifeLine Program with the Federal Affordable Connectivity Program?

Thank you for your question. So the stacking we initially were doing with the Emergency Broadband Benefit, the EBB, which provided a $50 a month subsidy for broadband service and wireless service was also allowed to be stacked, and the PUC aligned the California LifeLine subsidy so that we would be able to add that to the EBB. In the process of subsidizing, in addition to EBB, we did a data request just to understand what California LifeLine consumers who were using the EBB were using in terms of data.

And the data request revealed that the large majority, I'm going to say over 90% of the users, were using less than the 6GB of data that was already included in the California LifeLine plan. So when the ACP came on board in January 2022, we just didn't see, as stewards of public money, any value in adding a California LifeLine subsidy where people were already than what was already part of the California LifeLine subsidy to begin with. And they were getting the $30.

Thank you.

Thank you very much. We have no other comments. We're going to leave this item open and we're going to go to. I'm sorry, LAO.

We have no comments or concerns with the request.

Thank you very much. And we'll go to issue number four.

I stay in place. California Public Utilities Commission, covering many areas, but I'll be joined by an assistant General counsel.

Why don't you sit in the front row, and then you can come and take a seat as we rotate you through, right. We have one more seat here. Yeah, there you go.

Is it possible to bring our General counsel up or no,

certainly

For our trailer Bill. Yeah.

We can. Thank you very much, LAO. We'll call you up when we need to. There you go. Okay.

So, chair, at your pleasure. Which agency would you like to go first? We have two different agencies. Two different.

We would like to have you guys work that out amongst you in terms of what you think is best. That's how we always handle it here.

All right, very good.

Up to you.

Why don't

Yeah I'd be happy to go first.

Go first.

All right, great. Well, good afternoon, or good morning. My name is Caroline Thomas Jacobs. I'm the Director of the Office of Energy Infrastructure Safety. Really appreciate the chance to chat with you all today and answer questions you have regarding our request.

I'm going to provide a background on the creation of the Office of Energy Infrastructure Safety, Energy Safety, and what we do, an update on the impact we have had implementing our new responsibilities to date, and an overview of the resources requested in the Governor's Budget. Energy safety was created by Assembly Bill 1054 and AB 111 in 2019. We were established first as the Wildfire Safety Division in January of 2020 at the California Public Utilities Commission, 18 months later.

We were then transitioned in July 2021 into a new independent Department in the Natural Resources Agency. In January 2022, the Underground Safe Excavation Board, formerly known as the DIG Safe Board, then also joined our Department from the state fire marshal's office. So we are effectively just three years old as a Department, we have several core regulatory responsibilities. We establish guidelines for and evaluate the electrical corporation's wildfire mitigation plans and assess compliance through inspections and audits. And then we conduct safety culture assessments.

We also, through the Underground Safety Board, we have responsibility for establishing safe excavation standards, providing education and outreach, and investigating dig ins that result in damage. And finally, as of September 2022, through Senate Bill 884, we now have also responsibility to review and approve or deny 10 year underground plans that may be submitted by the large electrical corporations.

All of our wildfire related regulatory responsibilities are conducted on an annual cadence and have to be completed in a certain order, which, as I will explain in our request, leads to overlapping workloads and significant impacts if we cannot meet expected timelines for those deliverables.

Since our inception in January of 2020, energy safety has hired, trained, and equipped our initial staff, developed all the operational procedures and regulations to conduct our work, transitioned that original group to the Natural Resources Agency, stood up all the necessary administrative wraparound services to run a new Department, and while building and transitioning the new Department, we've evaluated and approved 24 wildfire mitigation plans. These include five that we have required changes through revision notices, three plans that we've rejected and required resubmission.

And through these evaluations, we have driven utilities to improve their ability to understand where their highest wildfire risk is on their grid and establish clear practices to target the mitigation projects in those highest risk areas. Also, we have driven them to adjust their grid operations, asset management and inspection, and vegetation management practices to more quickly and directly address that wildfire risk. We have conducted over 57,000 inspection activities to date and identified and directed corrective action on over 1000 safety defects and plan violations.

A few themes from these defects and violations include identifying damaged infrastructure, unsafe vegetation, and data inaccuracies. We've established expedited timelines for the utilities to fix those defects and violations that we find and we've completed inaugural safety culture assessments and issued reports in 2021. And we've completed the 2022 assessments and we'll be issuing those reports shortly. I have a number of stories of how this work has changed the way utilities do business.

But for time, I'm just going to give you two. The large utilities now utilize sophisticated wildfire risk models that enable them to risk rank specific segments on their grid to prioritize mitigation projects, and to give you a real world example of what that means on the ground. During one field visit that I was conducting down south, I had a frontline supervisor who had 30 years experience overseeing distribution pole inspections.

And he pulled me aside and said it is amazing to finally have the ability to choose which poles to inspect based on the risk of that pole as opposed to just executing an operationally efficient plan. So those are ways that are changing what they're doing. The plans also have required utilities to rethink how they are organized. For example, the large utilities all now have meteorology units within their organizations and have embedded wildfire risk in their senior leadership organization.

Those are just a couple of the ways that AB 1054 and 111, the new regulatory framework, has already driven meaningful change in how utilities build, operate and maintain California's electrical grid in light of the evolving wildfire and climate risk, and I am proud of the work energy safety has accomplished in these past three years. But we need to do more and we need to do it faster. To meet our minimum statutory regulatory responsibilities on time and with quality.

The Department needs additional permanent positions to ensure we can continue the implementation of AB 1054 and ensure we have stable quality and sustainable operations. Specifically, the Governor's Budget requests 58 positions and the associated funding to address the unmet needs the Department has in wildfire and excavation safety program areas. The majority of this request is 29 positions is to augment our resources to inspect and assess compliance with the wildfire mitigation plans.

We currently have 11 permanent positions in our compliance division who are responsible for all inspections, audits, investigations and regulatory development. Given the increase in wildfire mitigation activity over the past three years, our compliance division has not been able to keep pace with the building workload. To meet the unmet needs, we are requesting these positions so that we will be able to concurrently meet inspection and audits expectations, begin investigating reported ignitions, and have dedicated staff to develop the required standards.

We are also asking for 10 new positions within our Electrical Safety Policy Division, which is responsible for the wildfire mitigation plan evaluations, safety culture assessments, and issuing safety certifications. I mentioned earlier that our statutory responsibilities have a specific timelining cadence requirement. They each must be completed in a certain order because they feed into each other. With our current resources, which depend significantly on contract resources, we cannot keep pace with the statutorily required schedule.

For example, due to the time it takes to transition between contractors, we were not able to issue our 2022 safety culture assessments in time for use in the 2022 safety certification review. The 10 positions will enable us to conduct safety culture assessments in a timely manner and ensure we have adequate staff coverage for all wildfire mitigation plans. The positions will also eliminate the need for use of contractors for safety culture assessments and some plan evaluation activities.

Bringing the work in house will save approximately $2.7 million in contract funds and have the added and important benefit of enabling us to build the institutional knowledge within energy safety staff. Over the past three years, each time we've had to change contractors for one reason or another, we get delayed in our work and lose the knowledge that that contractor has developed when conducting the work on our behalf.

We are also requesting two positions to augment our Wildfire Safety Advisory Board staff to enable the board to provide individually tailored advisory opinions on publicly owned wildfire mitigation plans, which they have responsibility for reviewing. The board is also requesting $200,000 in ongoing travel funds to enable the board members to conduct utility site visits, attend board meetings, and participate in technical workshops. They currently do not have any dedicated travel funding. We are requesting four positions for the Underground Safety Directorate to establish a training unit.

The Underground Safety Board is required to provide education and outreach. However, they do not have dedicated resources to perform this training. Since a large portion of their target audience is Spanish speaking, we are also requesting $100,000 for Spanish translation of the training materials. The remaining 13 positions are operational and administrative support positions in admin, legal, communications and data analytics that are necessary to support the additional program staff and the work product that they create. Along with these requested resources, we are also proposing statutory language changes.

The changes are intended to update outdated references to the Wildfire Safety Division, which we were formerly known as, clarify review standards and timing requirements in vegetation management audits, and lastly, we are proposing to remove residual language originally proposed in the last session in conjunction with adding penalty and citation enforcement authority to energy safety through the legislative process. In the last session, the penalty and citation authority was not added to energy safety, but the related hearing regulation and judicial review processes remained.

So with that, I thank you again for the opportunity to present to you today and look forward to answering your questions.

Very good. Thank you, Chair. Rachel Peterson again to California Public Utilities Commission so we have a separate budget change proposal before you. Also, driven by permanent and ongoing work that stems from AB 1054, we have 29 proposed positions.

Thank you very much. I think we'll go ahead and finish the presentations and then do the questions, if that's all right with the members.

They are continuations of positions that the Legislature first approved in 2019, and we're proposing to make them permanent because the work is permanent and ongoing, wildfire remains the single largest risk faced by electric utilities in California and as a state, California is on a mission to reduce that risk, and the CPUC is part of that mission. For our role in this, we've achieved a significant amount of mitigation of utility ignited wildfire risk through the tools and expectations that were set out in AB 1054.

Those tools focus on utility wildfire cost review, enforcement and the CPUC's organizational effectiveness, including coordinating with the Office of Energy Infrastructure Safety. To step back for a moment, while there is a good amount of progress, we as a state are facing an economic and environmental landscape that is changing in real time.

The CPUC is presently handling more than $33 billion of proposed utility wildfire risk reduction costs in numerous active proceedings, and we are actively managing compliance and enforcement of their strategies, such as public safety power shutoffs, and fast trip. Even while we're doing this, the risk of wildfire is evolving because of the unfolding impacts of climate change that we are all living now in California.

And even if California experiences economic headwinds, this work is critical because wildfires themselves can impose enormous economic costs that can be even more difficult for Californians to bear. And what this means is that close evaluation of costs and effective enforcement are essential tools in California's toolkit. So to speak more specifically about the responsibilities that AB 1054 set out for the CPUC, we're first responsible for financial oversight of electric utilities.

We must seek to ensure that the costs that ratepayers pay are in fact reducing the risk of catastrophic wildfire ignition. The CPUC has handled 21 wildfire related cost recovery proceedings since July 2019, where the total amount being litigated has exceeded 33 billion. We anticipate cost recovery applications from each electric utility annually on an ongoing basic

because of the work of energy infrastructure safety and because of the continued risks and impacts of wildfires and climate change. The CPUC has conducted expedited proceedings and issued an average of two complex financing orders per year under AB 10504's securitization provisions, we regulate the utilities to constantly seek financing structures that will yield the lowest possible cost for ratepayers, and the eight orders we've issued represent savings of about $1.8 billion for ratepayers to date.

Our second major responsibility is to enforce laws and rules against utilities that fail to perform reasonable management of their electric systems. We have issued 11 enforcement actions, which include notices of violation, penalties, citations, consent orders, enforcement orders, and settlement agreements related to wildfires and safety since July 2019, totaling $3 billion in penalties that have been paid by shareholders.

Our staff executed a year and a half of enhanced oversight and enforcement of PG&E, specifically because it was failing to conduct vegetation management in the highest wildfire risk areas of its service territory. That oversight verifiably resulted in a change of operations at PG&E to make it safer, and this enforcement work is permanent and ongoing because we have to ensure that they continue to manage their electric systems safely.

And then third, we coordinate on wildfire risk reduction efforts with the Office of Energy Infrastructure Safety. We have received and produced for approval 23 wildfire mitigation plans for vote by our Commission since July 19. That's a significant handoff from agency to agency, and I believe we're coordinating well.

We are statutorily tasked with ratifying OEIs's actions on the plans, and we're also tasked with approving each year any additional requirements for wildfire mitigation plans, performance metrics, and the processes for conducting safety culture assessments and wildfire mitigation compliance. I will stop there. I have an assistant General counsel with me to answer any more specific questions on the positions themselves. But I thank you again for the opportunity to be here and present chair. Thank you.

Thank you very much. appreciate you trying to keep your comments brief with a really important topic for people in California. And clearly there was a need for cultural change with the major players in this area. And I think both of your agencies have played a critical role in helping to create that cultural change. I don't have much in the way of specific questions, a little bit of concern about eliminating the hearing process, switching from shall to May,

are you going to do it, you think? But you just don't want to be locked in. But I appreciate that you do need process change there. So if you want to make a quick comment about either of those things, but very briefly, and we're going to move on.

Sure. Happy to and welcome the chance. So in terms of the shall to may. So, yes, we still plan on doing the audits. It's really about providing us discretion to prioritize them.

So, for example, there are nine electrical corporations. The Shao currently requires that we do the audits on all nine. One of those is a fully and urban area with a fully under the water transmission cable. So it is perfunctory in nature in the sense of, so we want to be able to have discretion to be able to target where we spend our time and energies to use the resources as wisely as possible.

But it is no way and intended to try and eliminate having to do the audits where the audits really have meaningful impact regarding the hearing requirement. Understand the hesitancy there. Again, this really goes back to that statutory language was added as part of the Trailer Bill last year when the Trailer Bill also included penalty and citation enforcement authority for our office. And when it was removed, some of the residual language was not.

If I may, if I can pass it over to my General counsel to maybe provide a little bit more specifics on the reasoning there.

Good morning. Excuse me. Stephanie Ogren. I'm the General Counsel for the Office of Energy Infrastructure Safety. We do feel that the hearing process is left over as a relic from kind of different approach shifts in the former iterations of the Trailer Bill in 2021.

And one of the kind of key points I want to point to in the existing statute, the 15475.4, is that it still makes reference to an amount determined in a citation issued, and there's no other reference anywhere in our statutory authority to citations or penalty amounts. So it's kind of incongruous with the rest of our statutory authority.

Thank you very much. And unless I hear any other comments, and I don't remember, Oh yep, Assemblymember Connolly.

Yeah, I had a quick proposed question I'll ask to the panel.

It looks like both OEIS and the CPUC have requested positions to implement SB 884. How do you envision the overlap of work and responsibilities between the two agencies? And what is the CPUC hoping to have consultation on to implement the Bill?

Do you want to start because your plan review would come first?

Sure. So we have already begun coordination and conversations with the PUC to ramp up to get ready to be able to implement this.

So there was a workshop that was held in February where there was an opportunity for the two agencies to sort of talk through our initial approach, as well as to get public comment and stakeholder impact on helping establish the program. The program does start with a plan coming to our office for review, and it has some prescription there on what we're reviewing in that plan.

And then once assuming we approve it, it would then move over to the Commission through an application process that they would then do their review from their perspective. So we are absolutely coordinating in the development of the program to ensure that we have the ability to get going.

One other additional responsibility our Department has is assuming it is then also approved through the Commission when it comes to the implementation of the 10 years, there is then also a responsibility for our Department to, through an independent monitor, to receive progress reports on the implementation of that. And because obviously underground plays a significant role in the existing wildfire mitigation plans, our Department would then also, where appropriate, make sure that we're assessing that underground implementation from a wildfire mitigation plan perspective through that process as well.

Yes, and thanks for the question. Again, an agency handoff is present in this law, too. And so what we would do is along the same lines of the responsibilities that AB 1054 sends out for us. The law, SB 884, requires us to examine the plans for cost efficiency and to understand how and whether the electric utility did a good job in examining alternatives.

It's a very expensive wildfire risk mitigation strategy, and so we want to make sure that, first off, they examined all feasible alternatives and really looked at the question of whether the risk being reduced is worth the dollars that would be proposed to be spent. And then second, whether they are proposing a cost efficient undergrounding program. And all of that needs to be done within nine months once the application arrives at our door. So we have a big cost efficient review and litigation role.

And then second, we have an enforcement role, just like with AB 1054, if the electric utility has to submit a 10 year roadmap to get to this undergrounding program. And so we would have the enforcement responsibility to ensure that they are making progress against their own roadmap and then consider penalties or the appropriate enforcement response if they are not making the right progress.

Thank you very much. We will, I think, conclude this part of it, but I'll send you out with some of us are blessed to get to work on important things and you guys are blessed to get to work on something that's really important for California, changing a culture, protecting all of us from these catastrophic wildfires, particularly as the challenge grows with climate change and stuff. So go back and inspire your troops. All right, thank you.

Thank you.

Okay, non presentation items.

Any comments from Committee Members on the non presentation items? Thank you very much, Assembly Member Connolly, for being here. We'll now move to public comment. We'll start with public comment on the departments on the agenda. Everyone will have 1 minute to speak. We'll start with those in the room and then open the phone lines. And again, the number is 877-692-8957 access code 131-5447 you may begin.

Great. Thank you Mr. Chair and Members, Brian White with KP Public affairs here on behalf of Offshore Wind California.

We're a trade group that represents offshore wind developers, industry leaders and technology companies who support the responsible development of offshore wind in California. Speaking on item two regarding the proposed energy Trailer Bill and particularly the proposed language to create a central procurement mechanism for long lead time resources, we appreciate the governor's leadership and support for offshore wind.

And we support the proposal to create a central procurement mechanism which we think will bring needed certainty for the industry while helping address the state's energy reliability challenges, achieve the state's carbon reduction goals, and provide ratepayer benefits, all while creating thousands of clean energy jobs. Given the recent actions that have now established our ambitious clean energy offshore wind goals of 25 gigawatts by 2045, we think that California can become the epicenter of this industry. But there are some significant challenges that lie ahead.

We're essentially in a house of card situation where we have to have transmission, we have to have ports, we have to have infrastructure, and we have to have a workforce that's ready to go. But out of all those challenges, central procurement is really one of the top proposals and ideas that needs to be addressed today. That's why we support the administration's proposal. We think there is a need for some clarifications, definitions, but we think it's adequate.

We willing to work with you chair and members to get this right, and we think the budget process is the way to do it but we're happy to work with you through the policy proposal as well. Thanks for your time.

When you hear that buzzer go off, you know you've hit the 1 minute mark, right?

Absolutely. Good afternoon, Mr. Chair. Alex Jackson with the American Clean Power Association also here to speak in support of the proposed central procurement mechanism.

So we represent developers of Shorter term resources like solar and batteries. We also have developers looking at longer term lead time resources like offshore wind and out of state wind. I think the Administration articulated the problem statement very well and I didn't hear much disagreement about that. One, we need to diversify our energy mix if we're actually going to meet our reliability and clean energy goals affordably. Two load serving entities may face some challenges in procuring these diverse resource types.

And that begs the question, what is the solution? We like the proposal for two main reasons. One, it is being proactive. I think the energy landscape the state has found itself in right now has shown we cannot be caught flat footed if these problems persist. It provides an option. It's not a mandate. It gives the PUC that authority if there's backstop is needed. Second, we need that certainty. As my colleague noted, procurement is really the linchpin for a lot of these resources.

Once we get procurement, we can move forward, and I think with that certainty we get cost savings for ratepayers. Thank you.

Thank you very much.

Patrick Welch with the California Municipal Utilities Association. He's no longer here, but just wanted to say Commissioner Gunda has been a tremendous asset for the state. We appreciate working with him. He's been very collaborative and a leader on many of these energy reliability issues. Like other folks commenting on issue two, CMU has questions and concerns and commend everyone to the LAO's report. They did a really good job on the Trailer Bill, primarily on the capacity payment mechanisms.

We do feel like it is duplicative in an existing process that's already at the California independent system operator and there are questions about how ratepayers could be impacted. When it comes to the central procurement mechanism. We appreciate that it's an option to be exercised for municipal utilities. We do have a lot of questions about the structure of it and the scope of it.

And we just want to point out, too, that there's a lot of talk about planning reserve margins and central procurement and who's procuring what. A fundamental problem right now is market tightness. There is so much procurement going on that our members are having a hard time getting responses to their bids. As one example, we have a member who issued two RFPs for RPs eligible resources. They got zero responses four or five years ago. They'd get half a dozen. Thank you.

Thank you. It's one of the reasons I've raised that issue. Thank you.

Thank you, Mr. Chair. Sean McNeil, California Community Choice Association want to applaud the Governor for making energy security a priority not only in last year's budget and this year's budget. However, we do have three major concerns with the energy proposal. One, central procurement. We haven't seen a demonstrated need for it. LSEs aren't struggling to procure. Quite the contrary. We're meeting every single state requirement to procure.

In the last midterm reliability procurement order, not only did we meet it, CCA has exceeded it by 500 MW. That's significant. So we're not seeing a procurement problem. What we are seeing is an infrastructure problem. So interconnection transmission. On the interconnection side, we pulled our members. We have 793 MW ready to be added to the grid, but we cannot do it because of interconnection delays. That's also significant. On transmission, our members are ready, willing and able to buy offshore wind.

The problem is not coordination or lack of willing buyers. The problem is infrastructure. The transmission lines are at capacity. We need to upgrade those. We need new transmission lines. If that isn't resolved, nothing will happen. A central procurement entity doesn't solve those problems. Thank you.

Good afternoon, Chair. Elise Fandrich from Tratton Price Consulting. I'm here representing a number of groups on a couple of different issues, so I'll do my best to stay within time.

So first, on behalf of the National Parks Conservation Association, we want to elevate concerns with item two, the central procurement mechanism, particularly the lack of definition on what projects and technology would qualify for long duration energy storage and the lack of sideboards regarding what would trigger a central procurement action and find that problematic. The Bill, as written, could lead to expensive and very large resources being hastily purchased that are not needed or cost effective and prevent a diverse set of long duration resources being deployed.

So we think adding definitions and sideboards there would be helpful. Second, on behalf of the Coalition for Community Solar Access, the Asian Pacific Environmental Network, the Green New Deal Coalition, and the California Environmental Justice Alliance, I want to express support for issue 16, specifically the funding to the CPUC to support positions for community solar and storage and implementation of AB 2316 and urge the Legislature to fully support the funding needed to implement this program, which is essential for making vulnerable communities.

Last one, on behalf of SEHA APUN and the Green New Deal coalition want to urge the Legislature to reject the delays and cuts to the CEC equitable DCARB thanks.

Thank you, Mr. Chairman. My name is Dan Jacobson with Environment California and also aligning my comments with Brightline Defense and Environmental Justice Group on item two. We're thrilled to see this issue come up on central procurement. It's been discussed for years.

The chair, Eduardo Garcia, has been working on this issue, was also in SB 1020 last year. So there's a lot that's been talked about it. We look forward to it. Going forward, it's critical to getting to our 100% goals, so we support that. We need to make sure that these resources are clean. So we're going to need to include guidelines in there. We don't want to see natural gas or other fossil fuels included. This is going to be critical as we have the goals.

2030, we have to be at 60%. 2035 we have to be at 90%. This is going to help us meet those. And finally, as we move to clean, we have to be able to retire the dirty plants. Thank you very much.

Thank you.

Good afternoon, Mr. Chair. Glenn Farrell, on behalf of the state water contractors, the public water agencies who contract with the state of California for water supplies. Just brief comments on two items on issue number one, specific to the $140,000,000 proposed for the 2023-2024 for the Oroville Pump storage project. We encourage the subcommitee approval of that item as budgeted in light of the Legislature's enactment of SB 1020 last year, which rapidly accelerates the achievement of 100% renewable, zero carbon goals for state agencies, including the state water project.

The Oroville Pumped Hydropower Storage project is an important feature to help accelerate and meet those goals. Additionally, that project also provides very important public statewide grid reliability benefits. So we encourage your support, inclusion of that in the package. Quickly on issue number two, related to centralized procurement, if there continues to be momentum to view DWR as a centralized procurement entity. We encourage the subcommitee to strongly ensure there are appropriate firewalls between that procurement role and DWR's traditional water supply role. Thank you.

Good afternoon, chair on behalf of Building Decarbonization coalition and echoing comments for the Natural Resources Defense Council in support of the governor's proposal for the equitable building decarbonization allocation. As the LAO highlighted in their analysis, this funding will be critical to support efficiency and energy improvements for Low income households that would not otherwise be able to undertake these upgrades.

We do not support any additional delays or cuts to this funding on top of the governor's proposal, as it risks leaving low income communities behind in their transition to a zero emission future. I'd also like to call out the Building Decarbonizations Coalition support for item number two on the vote only calendar, the Building Decarbonization Financing and Incentive Assistance program, which will further support the development of long term financing options for building decarbonization. Thank you.

Thank you.

Good afternoon Chair and members Tricia Geringer with Agricultural Council of California here in support of the Governor's Budget allocation of the Food Production Investment Program, otherwise known as FPIP, at the California Energy Commission. This is a manting grant program benefiting California's food and wine producers and processors in their work to considerably reduce energy use and lower carbon emissions through the use of advanced technologies. 82% of FPIP funds are going towards projects located in disadvantaged and low income communities and thereby benefiting priority populations by improving air quality.

And the return on investment for the state is substantial, with FPIP placing in the top 10 of all the California climate investment programs in terms of total GHG reduction and the cost per ton of GHG. So with that, we really hope, Mr. Chair, you would be able to support the Food Production Investment Program. Thank you.

Thank you, Mr. Chair. Maddie Munson, on behalf of the Agricultural Energy Consumers Association, just echoing the comments of my colleague Ms. Geringer in support of the FPIP program at CEC. That's a really important program that's done a lot of good work. We hope to see it continue to be funded. We also appreciate your comments and the energy conversation today in regards to ratepayer impacts, and we just would like to see the ratepayer perspective continue to be acknowledged as these conversations move forward. Thank you.

Thank you.

Thank you, last but not least.

Thank you. Katherine Brandenburg with the Brandenburg group representing Cinema Clean Power. I want to echo the comments that Sean made for CalCCA, but also add one more thing about resource adequacy. There's a penalty that is noted in the BCP and the issue is that there is not enough resources right now to be able to purchase. If we could, we would purchase them all. So what happens is the load serving entities are penalized.

That penalty will then go to the ratepayers and it just tax on more costs. So we have to really look at that and be thoughtful. Thank you.

Great. Thank you. That's part of why we brought that particular issue up also. Thank you very much. Today's hearing is adjourned. We'll be back next Wednesday. zero, I'm sorry, the telephone public comment we still have to go to. So operator, would you please open up the phone lines?

Thank you ladies and gentlemen, if you wish to register a comment, please press one then zero on your telephone keypad. You'll hear an indication you've been placed into queue and you may remove yourself from the queue by repeating the one then zero command. An at and T specialist will provide you with a line number by which you'll be identified and we ask that you please pick up your handset and make certain your phone is unmuted before pressing any buttons. We'll first go to line 22. Go ahead.

Thank you Mr. Chair Members Ignacio Hernandez on behalf of Utility Reform Network return in regards to issue for the Office of Energy Infrastructure Safety. We urge this Committee and the Legislature to take a holistic approach to any funding and extension of funding for OEIs because we are very concerned that the protocols and procedures that are currently in place related to the wildfire mitigation plan oversight are incomplete and does not allow for full and meaningful participation for ratepayer advocates and organizations such as turn.

Because of that, there are decisions being made that will increase rates to consumers in California and we need to address those. We have submitted written comments about the types of procedures that need to be in place and protocols, as well as the ability for groups to intervene in the proceedings there. So we urge you to include all of that in any funding for OAIs going forward. Thank you.

Line 19.

Thank you. My name is Sakereh Carter with Sierra Club California. We want the Legislature to restore and promptly allocate funding for the CEC's equitable building decarbonization program to promote healthy, resilient homes, address health elements associated with gas infrastructure and appliances, and support California's transition to a clean energy economy. The current gas dominant building sector is responsible for 10.5% of greenhouse gas emissions, releases several indoor and outdoor health harming pollutants, and is grossly inefficient compared to electric infrastructure.

We must divest from the gas distribution system to reap $20 billion in annual health benefits, significant greenhouse gas emission reductions, and grid conservation benefits. The EBD program is also critical for protecting low income communities from financial stress associated with being tethered to aging gas infrastructure, health harming, polluting pollutants from dirty fuel sources, and inefficient gas systems in underserved communities. For these reasons, we urge the Legislature to retain critical funding for the equitable building decarbonization program. Thank you.

We'll go next to line 11. Go ahead.

Hi, my name is Marsh Namayne. I'm on the board of Physicians for Social Responsibility. On behalf of thousands of health professionals in California, I'm asking you to protect the funding for equitable building decarbonization and not delay the funding for Low income communities. California has some of the worst air quality in the country. Low income and communities of color are least protected from the heated climate and are three times more likely to breathe toxic air.

Gas appliances not only lead to bad air indoors, but also outdoors, causing illness and death. If all residential gas appliances were immediately replaced with clean electric alternatives, California would save more than $35 billion in monetized health benefits over the course of just one year. Protecting this funding will save lives. Please protect the funding.

Line 21.

Hello, Good evening, Assembly Members. My name is Edgar Barraza and I'm representing the Building Energy Equity and Power Coalition, a coalition made up of environmental justice organizations across the state.

I'm calling in to support the protection of the $922,000,000 CEC building decarbonization plan to stop the delay of the $283,000,000 from being invested into low income communities. Communities of color have experienced disinvestment for decades and are now extremely vulnerable to the impacts of extreme weather events. The CEC program, dedicated to environmental justice and low income communities, will help rectify wrongs and finally provide social, health and economic benefits to communities who have not been benefiting. Protecting this money will save lives. Thank you so much for your time.

Line 13.

Hello, my name is Bret Andrews and I'm a neurologist in Oakland. Please fully Fund the Equitable Building Decarbonization program and oppose the recommended delays for public health statewide. Homes and buildings in California generate nearly two thirds as many toxic knocks as California's 16 million passenger cars. Fully funding this program now will save lives and help prevent disease by reducing indoor and outdoor toxic air pollution and climate altering greenhouse gas emissions.

Air pollutions pm 25 s and nitrogen oxides are correlated with increased stroke, dementia, Parkinson's disease, and with impaired brain development in the young. As a neurologist, I can only attempt to mitigate these harms after they happen. You have the opportunity to help prevent disease and help save lives by fully funding this EBDP program without delay. Thank you.

line 17.

Grace Pratt from the California Energy Storage alliance, or CESA, representing over 100 Members across the energy storage industry. Thank you all for the session today.

We want to speak in support of some of the items in the Governor's Budget proposal, particularly after Vice Chair Gunda's presentation today. We want to emphasize the importance of funding the strategic reliability reserves, particularly the DEBA and DSGS programs that Vice Chair Gunda talked about, which can provide near term capacity but also help deploy clean resources that we can leverage in the long term.

We also would like to speak in support of Governor Newsom's proposal for $630,000,000 for low income residential, solar and storage to support communities in deploying these resources, and lastly, support the $140,000,000 for the program for the CEC's long duration energy storage program in order to help support these long lead time resources. Thank you.

line 20.

Mr. Chair and Members Dan Chia with Omni Government Relations on behalf of Clean Power alliance.

We're aligning our concerns with CalCCA regarding central procurement, but more specifically, we're concerned about the capacity payment penalty payment for resource adequacy deficiencies. We feel that yet another penalty or stick will do nothing to address clear market deficiencies within the program. Despite best efforts, load-serving entities are not able to procure RA at competitive prices. So we're concerned about that proposal. Thank you very much.

And Mr. Chair, we have no further lines in queue. Thank you.

Thank you very much. We appreciate all the comments from the people that phoned in and the public comments. Today's hearing is adjourned, and we'll be back next Wednesday to hear from the Department of Parks and the Office of Planning and Research. It might be one of the few meetings that will end before lunchtime. We've moved the Department of Water Resources to April 19, and that will be a substantially longer meeting. Thank you very much. Meetings adjourned.