Assembly Budget Subcommittee No. 4 on Climate Crisis, Resources, Energy, and Transportation

No problem. Thank you. Good morning and welcome to Assembly budget sub 4. Today we'll have informational hearing on proposals from our energy agencies. The Governor's Office of Business and Economic Development will not be with us today. As mentioned in the daily file, we will not be taking any votes today.

We have seven presentations planned today and 15 other proposals that we will only hear presentations if requested by Members of this Committee. After all the items are heard, we will take public comment. Each Member of the public will have one minute to speak. We'll get started now with issue one.

Before we begin, I'd like to correct the agenda on pages 3 and 6 that mentioned the proposal before us varies by 2 to 4 $1.0 million from the actual bond language and that the proposal allocates 4 million for the transmission financing portion. These reflect errors in the budget change proposal.

So if the witnesses and panelists would approach and introduce themselves when they're before they start to speak, we would appreciate it. And our first panel is climate bond Proposition decision 4 expenditure plan cast of thousands we have in front of us here today. All right, whichever one of you wants to start.

Good morning, Chair Members. David Evans, Department of Finance. Proposition 4 included 10 billion for various natural resource industries, energy, outdoor access projects and programs help mitigate the impacts of climate change. Of this amount, Chapter 9 of the bond specified 850 million will be dedicated for clean energy projects to implement the requirements of Section 94530.

The Governor's Budget includes 46.1 million for the demand side grid support program in fiscal year 25-26 with the dedicated allocation of 3.4 million for program delivery costs from fiscal years 25-26 through fiscal year 2031-32.

And we reserved an allocation of 375,000 for statewide bond costs so that will satisfy the requirement for the 50 million for that section. To implement the requirements of Section 94540, the Governor's Budget includes 227 million and 25-26 and 26-27 for the offshore wind development.

And we dedicated an allocation for 20 million for program delivery costs from fiscal year 25-26 through fiscal year 2032-33 and reserved an allocation of 3.5 million for statewide bond costs.

And similarly across all Proposition farm bond allocations, a portion of statewide bond costs were reserved and then finally for 325 million for public financing of interest energy transmission projects specified in bond section 94520 that was not included in Governor's Budget as it is pending allocation.

In consideration of the findings for AB3264 report to evaluate how to best allocate these resources to provide the most meaningful and direct benefits to communities. And I am also joined by colleagues from the California Energy Commission and various Department staff if you have any programmatic questions to the bond implementation.

Thank you very much, LAO.

Helen Kerstein with the Legislative Analyst Office I know you've heard our office's overall comments probably a few times on Prop 4, so I'm just going to talk about some of the energy related kind of connections to those overall comments. So there are three different issues I wanted to just raise for your consideration.

The first is on offshore wind. So as you heard from the Department of Finance, the Administration is proposing to appropriate nearly all of that funding for the next two years.

We think this is an instance where this is a new program, so it's one where you could appropriate the money but you could also wait on some or all of it. We think there could be some advantages to waiting which could include we may get more information on what the Federal Government is doing in this space.

There is quite a bit of potential change in their policies and activities in that space. Also this is an area where the Administration is still figuring out the specifics of how they're going to administer this grant and also they're in the process of administering another related grant. So there could be some more information on that.

The second point I wanted to make was on the demand side grid support piece. This is piece there are sort of two. There's a lot of moving pieces in this piece, but there are two main overall effects. So I'm going to just summarize it that way.

The first is to shift 50 million of funding that was unallocated in syrup, the Clean Energy Reliability Investment Program to demand side grid support.

So basically taking unallocated money that was for these General purposes, putting it in demand side grid support and the second kind of main effect is to shift 50 million of SIRUP funding that was going to be funded by the General Fund and GGRF and move that to Prop 4.

I know you all have talked a lot about those Fund shifts in the past, so just wanted to highlight this is one of those areas where that's occurring. So that's kind of a question for the Legislature whether it's comfortable for that.

And then the second one is of those unallocated funds, do you want them to go to demand side grid support or one of the other eligible activities? So those are the kind of two main policy questions for you in that piece and then third on transmission Fund the transmission piece.

As you heard, the Administration does not have a plan to allocate any of that money at this time. We think this is reasonable because there's a forthcoming report that could inform this funding.

But just would, you know, point out that to the extent the Legislature has priorities for this, this would be perhaps a good time to sort of think about those and direct the Administration in a way that would be consistent with those so that you can ensure that your priorities are reflected in whatever the ultimate proposal is, potentially next year or at some future date. So those are, those are our comments. Happy to take questions if that would be helpful.

Great. Thank you very much. Assemblymember, any questions?

More of a comment, really. And I understand the concern around the offshore wind. You know, I represent Humboldt County and we've been talking with folks about what the threats from the Federal Government look like.

I actually look at it a little bit differently where it might signal a willingness or a support from California to continue to push forward if we keep putting in place the infrastructure and the planning that we had said that we were going to do do.

One thing that I would like to see more of, and I know Assemblymember Stephanie has a Bill on this, is more technical support for local governments to actually implement what's going to happen with offshore wind. We know particularly for the County of Humboldt, they have a small staff to begin with.

It's a substantial project and it's a community changing project, but there's no technical assistance money that they've been able to gather for that. So I would like to see some of this go towards helping with implementation, helping with exploration for local governments that just don't have the resources.

But I do think that just because the Federal Government, every time we have a new tweet, we have a new direction, I don't think means that California needs to stop leading on these issues.

Thank you. So on this particular issue, I think, I think I want more information before I can sort of formulate my thoughts about this. So I'm curious, particularly, you know, with your perspective in terms of what's going on in Humboldt County.

So I look forward to continuing to have conversations, but I don't think it's inappropriate for the issue to be raised as to whether we should do the allocations now or whether we should wait for those allocations.

We certainly have a, to put it mildly, a fluid situation at the Federal Government level in terms of what is going on. So I have a question for CPUC and I see that we Have CPUC staff here and this. Am I on the. Yeah. All right. And so when. And maybe it's the Administration can answer this.

When will CPUC start the study and solicit public comment and complete the Study required under AB3264? That's the petri Norris regarding public financing of transmission. That's due on July 1, 2025. I saw the quizzical look on her face.

Good morning, Chair Bennett. Yeah. Let me bring this forward.

There we go. Okay.

Good morning, Chair Bennett and Members of the Committee. Rachel Peterson, I'm the Executive Director of the CPUC. And thank you for the question that the law requires us to prepare that transmission financing study by July 12025. We do have an active budget change proposal before you related to implementation of that law.

In the meantime, that first goal of getting that study done by July 1st. We are already working with I Bank, the Energy Commission and the Independent System System Operator on the scope and outline for the study. So so far we're on track for July 1st.

Okay, so you have started the study. Yes. Right. All right, great. And then for the Administration, not so much that I challenge it or I'm concerned about it, but I'd like to understand the administration's logic for starting with demand side grid support instead of long duration energy storage or distributive energy backup assets.

Why all of it on demand side grid support program?

David Evans, Department of Finance so we provide additional resources for the demand side grid support given the program success in offering incentives for electricity customers for incremental load reduction. The budget Bill Language, it does.

We did draft the language allowing it for it to be used for a variety of different programs such as like long duration energy storage, distributed energy backup assets, but based off of the program successes, that is the reason why we allocated the resources for holistically for demand side grid support.

We are open to having conversations with the Legislature if there's a desire to shift some of those funds or to reallocate them, but that was our rationale.

So I didn't quite catch the rationale. I caught that you did do it, but the why did you. Why did you go. Why did you go there?

The program success in offering incentives to customers for reducing incremental loads. Okay, so the success of the program so far in terms of doing that.

All right, thank you. The. So that's something that we certainly can still have conversations about as we move forward. And the question about what Department should the transmission financing be appropriated to and should funding be appropriated this year is right now. Where is the.

What's the administration's recommendation in terms of where the financing should be appropriated to which Department?

We're still working with various departments to end the reports and the findings of that report to best allocate those resources. There's a couple entities that we're considering, but we're still in the development, brainstorming face of that.

Okay, great. The $250 million for the revolving loan Fund. The funding was eliminated last year. I Banks begun the discussions with the private developers. And this question about the Salton Sea, whether we prioritize this for the Salton Sea or not, does the Administration have a sense in terms of what its priorities are?

Good morning. Meghan Larson, Department of Finance. Could you please restate the question or repeat it?

Yeah. Just where. What. What is the administration's position right now in terms of the financing for the Salton Sea? Prioritizing funds for the Salton Sea project.

Amen. Melbourne Department of Finance. We're aware that the original funding for I Bank Fund that line was removed as part of a General Fund solution in past years. We don't have a position at the moment. All right, great. Thank you very much.

All righty. Another issue that remains for us to discuss and perhaps when we have a larger number of Members here, will be that that particular issue. I know Salton Sea was a major issue of focus for the Prop 4 Funding of last year, and so I think we have to put that together. Anything else on issue one? Assembly Member. Right. Thank you very much. We'll move on to issue two, the energy package implementation.

Shall we begin? Yes, please. Good morning, Chair. Assemblymember Rogers and staff. Staff did a great job on the agenda as usual. Good morning. My name is Drew Bohan. I'm the Executive Director of the California Energy Commission. We are celebrating this year, our 50th year.

The Warren Alquist act was signed by Governor Reagan in 1974 and we've been in business ever since. Over the years, we've made substantial progress. I just want to give a brief background and then get into the issues you've identified in the agenda. You'd like to talk about today.

California's use about half the per capita electricity as the rest of the country. Our energy efficiency programs are not the sole contributor to that, but they are a major contributor to that. That our appliance and building standards that we update periodically have saved do save Californians Billions of Dollars, several billions of dollars every year.

So a very good value. Last year from January to September, we were serving California's entire load for part of the day for every one of the or two out of every three of those days for many months, 100% clean energy. And finally this past summer, which was the hottest in modern history, we experienced no outages.

And we think this is due to the collaboration of a number of the agencies and the support we've gotten from the Legislature. So you've asked for some updates on the energy package and I want to go through each of them. You noted there was a crowd here.

I brought a small posse that makes up a significant chunk of that crowd. I'll just go through briefly and invite obviously any questions you may have on a few of the programs. You alluded. Chair, to the demand side grid support Program, the DSGS program.

And I think, as you all know, this acts as an insurance policy basically to help maintain grid reliability during extreme heat events. And basically we provide incentives to electricity customers to reduce their load during these key times. We stood this program up in August 2022, literally weeks after the Legislature adopted the legislation authorizing us to do so.

So we got moving very quickly. We rushed around literally making phone calls, and we were able to sign up a number of of subscribers, and we ended up getting 3,000 megawatt hours of reduced load as a consequence of that. So the program worked right in the first year.

In 23, there was very little need, so the program wasn't used very much at all. But in that year we made some changes. In 24, we made some changes. And indeed tomorrow my bosses will be voting at one of our voting meetings on further changes.

Still and these are born of learning from the market about what works, what doesn't, what pockets of load can we target for these incentives? So it's evolved over the years, but in 2024, we grew to over 269,000 participants and 500 megawatts for scale. That's a modest size gas plant in terms of just the volume.

And by the end of 2024, we had one of the largest storage VPPs, virtual power plants anywhere in the country, and it was about 200 megawatts, all in. This VPP was dispatched for 26 event hours over 16 days across three major heat waves in 2024. So it was able to plug in effectively.

So we think the program's been delivering on its promises. To expand on my colleague's answer earlier about the reason for some of the shifting was we want to support this program because we think it's been very, very effective and very cost effective. Next, Distributed Energy Backup Assets program, what we call our DBA program.

This program provides incentives for the construction of clean, distributed energy resources and for power plant efficiency upgrades. In October of 2023, we adopted the guidelines for this program. And in April of last year, we awarded nine projects for a total of $123 million. These will add all in about 300 megawatts of new capacity by 2027.

And we believe we'll increase the grid reliability proportionately. About three quarters of the megawatts are from batteries, and the balance, about a quarter are from upgrades at power plants. So natural gas power plants were able to make changes to become more efficient, produce more electricity with the same amount of.

Of fuel, and with a very, very modest uptick in pollutants. So very, very efficient investments to date. We voted to approve three agreements, and we're aiming to bring the remaining agreements to the Commission this year for approval.

The first project will come online next year, and then all of them have to be completed, per the terms of our solicitation, by June of 2027. And we're anticipating that we'll get those done.

We released a draft concept proposal that we're getting feedback on for the next round of grants, and we're expecting to release the final version once we get a signal from the Legislature and the Governor about the proposals in the Bill to add funding to the DIVA program. Next up is the long duration.

Before you go to next up, please. I had a question. On the first one, I realized we'll get too far away from it. You. You talked about at one point your early signups. I thought you said gave you 3,000 megawatts.

To be clear, I've been mixing units that was 3,000 megawatt hours. And then the program is built to where it's now 500 megawatts, not megawatt hours. And those will be utilized as many hours. The difference between hours and that, that I.

...

In terms of long duration energy storage, to meet our goals in California that are very ambitious, we're going to need a lot of storage and we've been doing remarkably well in adding storage to the system.

As you all know, lithium powers everything from the cell phones in your pockets to cars, to large grid scale batteries that support the grid. Our LDES program, we call it, focuses on different chemistries. We have invested in five different chemistries, a vanadium based one, an iron based one, a zinc based one, to reduce our reliance on lithium.

Lithium is phenomenal, but we want to make sure we have other chemistries and lithium isn't as good a chemistry. After several hours, it's good for four hours. But beyond that, these other chemistries work a whole lot better. The program requires that any entity that gets funding must be able to do the following. They must have eight out.

They must be able to do eight hours of storage again. Lithium is typically four, so it's twice that. And some of them are much longer than eight, up to 100 hours, which can be very helpful in the winter. They have to be a megawatt or larger. So substantial systems, not small ones.

And they have to contribute to a safe and reliable grid. We have 10 projects in various stages of development right now and most will be operational by next year. One of them is at the Viejas Tribal Casino just outside of San Diego and it's nearly done. They've got all the batteries in place.

They've got dozens and dozens of chargers they've put in. They got a control system and it's just being commissioned, but that should be up and rolling by the beginning of next year. And this one will produce, when they're all done, will provide 700 megawatt hours.

Again, you can run them however you want, but 700 megawatt hours all in for, for these investments. And I just have two more and I'll pass it off to my colleague. Hydrogen grants you'd asked about. Our clean hydrogen program provides financial incentives to in state projects to either demonstrate or scale up clean hydrogen.

This is production, processing, delivery, storage and even end use. We really, we released a solicitation a couple of years ago with up to $4 million in cost share the Federal Government is supporting at a 10 to 1 ratio cost share and we have one project with UC Irvine where we put in 300,000 which drew a $3 million investment from the Federal Government.

Chair, as you alluded to earlier, there's some uncertainty about the way these federal funds are flowing, but we're proceeding and trying to remain nimble.

Finally, the SIRUP Clean Energy Reliability Investment Plan program that was discussed earlier noted the Budget act moved some funds around about 18 million of that was moved into the DSGS program and we have plans for the balance in the out years in that we submitted a plan to the Legislature some years ago.

If we get the direction to move forward, we will do further hearings and learn from stakeholders what they favor. And with that I thank you very much and I'll hand it off to my colleague. Great, thank you.

Good morning Chair Bennett and Members of the Committee. I'm Alice Reynolds, President of the California Public Utilities Commission and really thank you for the opportunity to speak with you today. I am providing a brief overview of CPUC's budget change proposals, but mostly we'll focus a little bit on affordability and opening comments.

And just as background in its regulation of electrical utilities, the CPUC is broadly and really steadfastly focused on four overall goals, safety system reliability, cost containment and clean energy. And today I'm going to be focusing on utility bills and affordability because as we all know, cost pressures are being felt by Californians across the state.

Not necessarily equally, but really acutely felt, especially by residents who are struggling to pay their bills at a time when the costs of insurance and other household necessities are also increasing.

In October 2024, Governor Newsom issued Executive Order N524 directing the CPUC to assess the underlying drivers of increasing utility rates and to identify potential actions to reduce pressure on customer bills.

Our public report was delivered earlier this year and the report outlines long term drivers of rising rates, including primarily wildfire mitigation costs that are accelerating in response to climate change. In the five years between 2019 and 2023, our investor owned utilities collected approximately 27 billion from ratepayers to pay for wildfire mitigation and insurance premiums.

By statute, utilities are permitted to file applications to recover many of the costs to implement wildfire mitigation plans after the work is completed, resulting in off cycle rate increases beyond the costs already authorized in the utilities General rate cases.

Additionally, legacy rooftop solar tariffs which include above market compensation and shift fixed cost system costs to other customers exacerbate the impacts of other rate increases. The CPUC's response to the Governor's Executive Order does outline several policy options for consideration.

I won't go through all of them, but to highlight a few Evaluating Wildfire Mitigation costs including the Wildfire Mitigation Plan implementation costs in General rate cases rather than through off cycle applications. Our General rate cases are the main tool for scrutinizing and evaluating costs.

Second, reallocating the California Climate Credit to have greater impact in supporting customers who are most impacted by increased electricity bills and then third, exploring alternative funding sources for costs of programs currently funded by ratepayers. The Commission is working to reduce rates and has already taken several steps to to address affordability challenges.

We've revised the structure of rooftop solar compensation for new customers to reduce cost ships. We've strengthened oversight of wildfire mitigation spending and we're exploring improvements on how those costs are reviewed.

So across the board we're also looking at how programs can be delivered more cost effectively and how different funding sources can support specialized programs without placing additional strain on customer bills.

These are fact specific, sometimes difficult decisions involving trade offs, but our focus remains on long term solutions that center safety, reliability and affordability at the same time, on a positive note, we've made significant progress in scaling low cost clean energy infrastructure.

So as a result of procurement orders issued by the CPUC, California now has over 11,000 megawatts of battery storage online, which is more than any other state. And we added nearly 7,000 megawatts of clean capacity last year in one year alone.

That's an all time record for California through the CPUC's Integrated Resource Planning process which was established under SB350 and expanded under SB100. These resources were procured through competitive solicitations led by the nearly 40 load serving entities which are designed to identify the least cost best fit resources available to serve their customers.

So those 40 entities of course are the investor owned utilities, the community choice aggregators and the ESPs. So this ensures that even as we expand clean energy, we're doing so with a focus on cost effectiveness and careful oversight to support long term affordability. We're also implementing recent legislation that strengthens utility oversight and accelerates connections of new customers.

For example, under Senate Bill 410 and Assembly Bill 50 we adopted new statewide targets to reduce the time it takes to connect new housing developments and other businesses to the grid. As mentioned previously, we're also working with our partners at CISO, CEC and Ibank on the study required by AB3264 related to transmission costs and ownership structures.

I did want to just briefly introduce the two trailer bills that CPUC has worked on this session to increase efficiency and enhance our capabilities to support our statutory responsibilities.

The first would extend our authority to collect the surcharge that funds the Deaf and Disabled Telecommunications program which is a long standing program that ensures thousands of Californians with hearing, speech or mobility disabilities have access to essential communication services.

The second provides a narrow clarification to allow the CPUC to enter into non disclosure agreements with energy coordination entities like the Western Electricity Coordinating Council and the North American Electric Reliability Corporation.

This is similar to agreements that we already have with our grid operator, the California Independent System Operator and would allow us to securely access planning and reliability data needed for California's long term grid planning and system reliability. And I do have staff available to speak to these items in more detail.

We have subject matter experts here during today's hearing. They're also available for questions. And finally, I did want to highlight that the CPUC has authorized more than 1 billion in broadband and telecommunications grants so far this year and this is a milestone reached because of the work of the Legislature in enacting SB156.

And these investments will help to close the long standing gap in access and reflect our shared commitment to narrowing the digital divide. I do thank you again for the opportunity to appear today and happy to take questions.

Thank you very much. Department of Finance.

David Evans Department of Finance no additional comments.

Lao ...Assembly Member

Yeah, I really appreciate the presentation. I think one of the things that there's a bit of a growing frustration with the Legislature is that over the last 10 years we've doubled the size of the CPUC staff and yet we are still hearing that there are delays that are causing increases in costs that are potentially delaying safety programs from being rolled out.

Can you speak to what that staffing is going towards? Because it seems like every single time a new thing is proposed, the response from the CPUC isn't any type of internal efficiencies. It's we just need more staff and I think this year it's proposed for 12 more staff. I think was the number to implement some of the bills that have been implemented. So help us understand that juxtaposition.

You know, we're talking about 10 years of work and responsibility. I can provide follow up with specific programs that all of our staff Members are implementing. Staff are all assigned to existing responsibilities. And so when we get new responsibilities, we do assign new staff to those and would look for additional personnel.

We have been implementing measures to increase the speed of some proceedings and to increase, for instance, claims for intervenor compensation, which has been a problem in the past. And still we're still working on reducing backlog. We have increased the number of proceedings that we're getting through.

And at the same time, some proceedings are lengthy because they involve ongoing work. So, for instance, the integrated Resource planning process is a proceeding that is left open because every year it has a new cycle. And so although it is a long term, it has been pending for a long time.

It is because there's ongoing work going on. So it really depends on the particular program and the particular proceeding. And happy to answer questions about specifics of individual time concerns. We have gotten recently direction from the Legislature to expedite certain proceedings.

Our normal cycle to comply with statutory requirements for process is about 18 months, where we have hearings at the beginning. We take evidence. Parties frequently ask for more time. And so we do grant extensions of time if they seem warranted.

And so those are all of the things that we take into account in the length of our proceedings. I think sometimes one person's expediting is another person's lack of due process. And so we try to balance the interest of parties to really have time to digest the lengthy evidence that comes in from the utilities.

In particular, interveners need time to assess that and evaluate it and provide good information to us in their filings so that we can consider that and make the best decisions possible. The PG&E case, for example, was 10, was 1,000 pages in our decision.

So there is a large volume of evidence, and we do try to expedite as much as possible. We also want to make sure that parties have the time to participate meaningfully in the process because we rely very heavily on intervener input, for instance, from the Public Advocate's Office and from TURN and other parties who participate.

Yeah, I understand it. I understand it's complex. What I also know is we heard in the Utilities and Energy Committee that this is making it so that rates are going up, the delays are making it so it's going up. And that also there's a substantial safety factor that we're seeing across California.

I also wanted to ask really briefly about the central procurement function, because at times it seems like the direction coming from the CPUC is much more around reliability, which I totally understand, while also the programming that's coming from the CEC is much more focused on renewable energy.

And in particular you mentioned one of the programs, the the Equitable building decarbonization program and the distributed electricity backup assets.

And I know that there was a move for additional legislation last year or maybe the year before to require community choice aggregators to have additional resources that are on Reserve, that are not clean energy, that they're natural gas, they're other things. So how are the two agencies and the direction from the governor's office coordinating?

Because I can understand that there's two different outcomes there that are hope that you're hoping for. But at the local level the implementation oftentimes seems a bit schizophrenic.

I'll talk a little bit about the coordination and how we do planning. So the integrated resources plan process is a process that is managed by the Puc but it involves input and coordination with the CEC and with caiso.

The CEC prepares a forecast for the state and that is a forward looking forecast that then is taken by the CPUC and it's an input into our process and our oversight of a statewide procurement plan that then is carried out by all of the load serving entities including the CCAs and the investor owned utilities.

We've issued procurement orders which is essentially build the projects to implement those plans. We don't allow fossil fuel resources, they're all clean energy projects. So all of the projects that the utilities and the CCAs and the the ESPs are building to meet the targets that the CPUC is setting are clean energy projects. Their batteries, geothermal, solar, wind.

And looking forward we're looking at all of the research, long term, long duration energy storage, potentially offshore wind. All of those resources are part of the planning process.

Again it's that competitive lease cost process that then feeds into the CAISOS process to make sure that we have whatever upgrades of the system, transmission system are available to make sure that those resources can be shared and serve Californians where they need it, when they need it.

The Legislature established a few years ago a strategic reliability Reserve that is meant to supplement that, not compete with. Because we don't want the another competitor for those competitive projects to drive up prices in the market.

We want to have incremental reliability assets that are held and used for those extreme west wide heat waves when there's not enough power available. Those are that, that is the strategic reliability that kind of sits on top of the load serving entities responsibility to reliably serve their customers moving forward with clean energy again.

And so that is what the CEC is developing as part of the DSGS program and having other assets available. The other part of the strategic Reserve which is very helpful is trying to pull some gas assets out of the market.

So rather than having them on contract with the load serving entities for reliability purposes and again used when we don't have clean energy resources available, pulling them out of the market and only using them for reliability purposes so they're no longer economically dispatched. They would just be available for emergencies.

And so really it is the state's really innovative approach to find out what are some of those assets that can stay online but only be used very infrequently.

And so it's a new and kind of difficult balance to strike of how do we hold those fossil resources back that we need to preserve reliability for the near term, not in the long term, because our planning is to get to 100% clean, but use them as little as possible.

So that's kind of how the two things work together and we're doing it in a way to keep costs as low as possible as well.

Some Member Rogers, I would just add, provide an illustration with the DSGS program. So when we, I mentioned earlier, we scrambled around when we were mid summer when we got this authorization, we were able to sign up customers very quickly. They were dominated by diesel backup generators. So we were not our mission.

We are laser focused on a clean energy future, but we were in a moment of severe need. So that's what we signed up. Fast forward two years to 2024. Approximately 80% of all resources that are participating in the program are clean resources. And there's still some non clean resources. But we're trying to do that with every program.

There's times when using legacy resources makes sense, but we try to avoid it as best we can.

Yeah, that's really helpful, thank you.

Any other questions? Assembly Member.

So we mentioned delays in decision making. Can we quantify how much that's going to cost with the delays for the ratepayers?

I don't have a number, but we could follow up on that question if you want to send it to us.

All right, I have a few others then. So how many rate increases have we approved in the last five years and how many do you anticipate in the next two years?

So the PUC makes decisions on expenditures of the utility. So we go, we have a cycle of General rate cases. We review the utilities forecasted expenditures on a going forward basis, starting with a test year and then years into the future when those are approved.

Those do go into rates the way that utilities typically work Is they, they, they build infrastructure. New customers come online, they have increased costs, but they also have new customers paying for the service of the utility. And the expenses are approved periodically and those generally show up as a rate increase.

With the idea that sales and growth is also occurring. There are several mechanisms that result in off cycle rate increases, which I talked about a little bit earlier. We do have some cases where costs are somewhat uncertain and so they're not approved as forecasts.

And the utilities are allowed to track actual expenditures and then come for approval of those actual expenditures after they've been reviewed for reasonableness. Some of those, we call them memorandum accounts and balancing accounts. Some of those accounts have been required by statute.

And so we're required to allow the utilities to collect to do the work and then come forward with collections. What happens is they are approved by the PUC for collection of a certain amount. There's a time period when that collection happens and then it falls off the bills.

So we don't approve the instances where they stopped collecting that. But we do approve the initial collection and that for that period of time does result in a rate increase as well. So in the past year, for example, there were times when PGE had some of those especially legacy wildfire costs.

And so it has been happening recently, more than previously, because after SB901 and AB 1054, the utilities created more robust wildfire mitigation plans. They started the work, they went out and did the work, and then they came in later for cost collection.

So those costs are starting to hit bills at the same time that over time they fall off bills. So in the past year, PG&E, for example, had some of those expenses that were collected. Same with catastrophic events such as the earthquake storms come in as rate increases and then they fall off.

So rather than having just one adjustment at the beginning of the year where we true up costs of generation, but we also have General rate case amounts go into rates. We recently have been seeing more of these memorandum accounts that have resulted in rate increases, but also rate decreases as they fall off.

Assemblymember, I know you're in the middle of your questioning. We have a request from Assemblymember Boehner. She has to move on to it. Barner. I'm sorry, she has to head to another Committee and she has a couple of quick questions. She asked. Do you mind if we interrupt your.

Can I just get one? Sure. Just get a number. Like within the last five years, how many increases have we had?

We can follow up with ... for all of the investor Utilities. We can. We can follow up with that number.

Okay. You have more questions. Okay, great. Go ahead.

Oh, so I didn't have questions. I had questions about the definitive disabled program and some of the other agenda items. So it's not on this agenda item. Do you want me to ask those now or I just have to present a Bill. Hopefully it'd be quick and vote.

Actually, she's gonna be waiting for me because I'm presenting mine in a minute.

Zero, then you go present yours and then I don't know, it's up to you, Chair, But I had questions around issues 3, 12 and 14.

So you have to present someplace else.

Just over there.

Right. And I wonder which one of you is in is going first. I'm inclined to. We'd have to move these panelists out and we still have more questions for this panel. Oh, so it's CPUC. Okay, great. All right, then let's go ahead and let you. CPUC, if you'll be ready to address these questions.

And if the rest of you stay here, I think we can put CPUC right up here in this seat. Yeah, this. Yeah, the President want to step up here. Right. So we're jumping onto Assembly item. I mean, issue item three. And these would be questions about broadband and. Go ahead.

We're going to start with questions instead of the presentation.

Okay, well, maybe. Do you want to. Maybe we should do the presentation so everybody else knows what we're talking about. Because I think we know what we're talking about. But then it's just us having.

Then why don't we just finish up with issue two. We'll just see where, where you stand. So if you'll come back up, please. You can stay there. Right. If we're going to go to their presentation, because I don't think we have that many. That many more. More issues on that many more questions.

But I do have a number of quick things that I think I can ask. And so I'm going to start with CPUC. The status of the funding for Community Solar and how will these dollars interact with the federal Solar for All award program. Could you let us know where we are with that?

Thank you, Chair Bennett, for the question. So the status of the funding is that we have received the allocated dollars from the Federal Government. It is sitting in a federal account earmarked for California that took some weeks and months of close attention in the early part of this year.

And so that 249 million is ready and available on a drawdown basis for the program.

Not Likely to lose that.

I can't opine on that Assembly Member, but it is as secure as it can be in a Federal Government account.

For the record, put down that she guaranteed we're going to get this money. Okay. We certainly understand the fluid part of it. And so the community solar program.

Yes. So the. We waited to. We had prepared a ruling that proposes a work plan for how the program will run. We decided to wait until April 1st to issue it until we knew that the funding was secure at the federal level. We issued that ruling last week, April 1st.

And as always with our process, there's time for parties to comment on it in order to develop the specifics of the work plan.

Can you give us the basics of the ruling?

I would have to ask Deputy Executive Director Testify to come to the table. The overall philosophy of the program is that what we wanted to pay close attention to is making sure that California ratepayers pay as pay the exact value for the energy being delivered.

And so that was what the Commission's decision determined was to pay the solar projects the avoided cost value. Then we also advocated and won this grant from the Department of Energy in order to add an incentive to the program, which is what the developers and industry were requesting.

And so for ratepayers, the avoided cost value is the least cost that we can pay for the energy. And then we're adding the incentive of.

The federal grant as you calculate the least cost. You know, we could spend too much time trying to get into that calculation.

But I hope you will consider that part of the cost avoidance is the avoidance of having to build new infrastructure because of all of the solar that is there at 2 o'clock in the afternoon on a sunny day, and not just the marginal cost right now. And that's not easy to do.

But I just want to offer that I don't want to disincentivize rooftop solar. It is, I mean, if you, if you asked where should California be 30 years from now? I think having rooftop solar and batteries in most people's houses is, would be a good spot for California to find itself in, in terms of reliability, etc.

And I hope we don't lose sight of that as a, as a long term beneficial place for California to be. So I just would offer that. But go ahead if you want to give any other updates, add anything to it.

I think Executive Director Peterson's response provided many of the details and primarily we're looking to get party feedback in order to better understand the additional incentive level that we'll be able to offer to the developers and then hopefully to the customers by leveraging these non ratepayer funds, including the money from the Solar for all program as well as the $33 million that came from the budget.

Thank you. And then my other item for the CPUC is a conversation about rates and we're all interested in trying to keep rates down.

I hope what we will as we're making this transition over and we have more and more electric vehicles in particular out there, we need quite a few more before we can start to make this case. But people's overall energy cost hopefully will be dropping.

But we need to make sure we're educating the public that your electricity Bill may go up some because you're not paying your gasoline Bill as much. We just need a lot more adoption of those gasoline powered cars.

But as we convert more and more things over to electricity, that should, that should be something that we keep, keep trying to emphasize to people. The 88 million. How will the 88 million that the state has be used for the community solar side?

For community solar. The 33 million. Right.

And the 50 million for GGRF?

Oh, okay. So that will also be leveraged with the federal dollars in order to be able to help support those incentive levels and making sure that the disadvantaged communities that are accessing this program are able to get the Bill discounts.

So all of it will go into the incentive program?

Yes.

Great. Thank you. All right, and so that's it on that. And I'll just jump over to the CEC next with my questions. Is there funding that's uncommitted from prior appropriations to the distributed electricity backup asset program, the demand side grid support program? So we have unallocated funds there.

I think I'll look to my finance colleagues for the precise numbers.

The unallocated. The unallocated funds will be for the state bonds costs for that program. How much is unallocated?

It's not unallocated. I'm sorry. And gentlemen, it's not unallocated. I'm really trying to find out how much is unspent.

It says uncommitted. Uncommitted is unspent. Is that what you're saying?

Yeah. No question we have to bring someone up.

Okay. While you're looking for that, I'm going to assume there is some funding that's unspent. All right. And I'm interested in. We have water projects that are looking for clean backup generation. And so I'm.

Chair Bennett. My name is Aloke Gupta. I'm a Deputy Director at California Energy Commission overseeing reliability and renewables incentive program, including DSGs and DIBA. In terms of.

Could you talk right into the microphone, please? Yeah, yeah. There you go.

Could you hear me now?

That's better.

In terms of available funding, in DIBA account, all the money is encumbered. At this point, we have no unencumbered funds available to run a solicitation. But the DSGS account, in DSGS account. We have projected funding. Excuse me, projected expenditures this year. Once we account for that, the amount of funding we expect to exhaust next year.

So you could consider that unspent, but it is presumed to be utilized next year.

We have an interest from the Assembly side at $12 million for the cost share that we have for a federal award for clean backup generation for water facility resiliency and trying to find out what kind of time frame there would be if these funds were available.

It is a clean energy program, but it would be for a state water facility. My understanding is it qualifies. So we'll just let you know at this hearing right now, we're interested in having a conversation with you about whether that is funding that could be available and if so, what the timeline would be for us to do that. I'll leave it at that.

In terms of other, other questions for the CEC, data centers, I assume do not have much variability in terms of demand side response.

They were among the largest contributors to our early DSGS program because they have typically diesel backup generators. And so we asked them to flip it and instead of using the grid to supply them with their electricity and having the diesel sit idle as backups during the early days of the DSGS program, we said run your.

Run your generators will reward you for it. And then don't use the grid energy, the grid becomes your backup.

But we don't, we're not going to continue that. But they, they have pretty steady demand, I assume. I just trying to clarify. Yeah, General data center. Yeah, they.

In terms of battery storage, what does, what does the Cec, what can the CEC offer in terms of greater confidence for local Governments, we have local governments now because of the fire, that are throwing up a lot more resistance to battery storage being located in their communities.

Right.

And the new technology is supposed to be significantly safer. But does the CEC have information, things that they can do to create greater confidence that the new battery storage facilities would not have the same problems as the older ones? Are you guys working on that? Absolutely.

This is something that's a very significant focus of ours for the reasons you identified. We just through the Opt in program that allows various types of resources to opt into the Energy Commission's jurisdiction. We've had a lot of projects come in.

We just filed our staff report about a month ago on one of them called Darden in Fresno County. It's 2.3 gigawatts, it's massive, 1.15 gigawatts of solar and the same amount of backup storage. And the community expressed some concern along those lines.

And we've got others that are coming up in, where it's quite sparse in that part of the state, whereas the denser places, there's more people who are expressing interest. Just very briefly, there's a couple significant differences from the Moss Landing fire that got a lot of attention.

Those batteries were in a building and they were stacked and the footprint was about a fifth or a sixth of the approach that is being used much more widely today, which is instead of packing them all together and saving money on not using so much property, instead you spread them out and mitigate that fire risk.

So they're basically large containers separated by 8 to 10ft. So that should there be a fire in the future. And by the way, the six or seven projects that the Energy Commission has already approved of batters now, not one fire. We aim to keep it that way.

But the idea is if there's a fire and they can happen, it won't propagate to the other. Some of these have 23400 of these different containers. If you have a fire in one, it hopefully won't propagate.

And in fact, at Moss Landing, the same site where the large fire occurred recently, a couple of years ago, there was a fire in one of these containers. It scorched the neighboring two containers a little bit, but the fire went out.

And there was one obviously ruined unit, but the other 200 some odd units were in good shape. So we're very focused on this.

If you can help get that information out, if you, if CEC could put that, that data out about the difference between the new facilities versus the facilities that have had problems.

Absolutely.

I think that would go a long ways for California in terms of being able to make sure battery storage stays. We can implement battery storage as promptly as possible.

Yeah, absolutely. The other thing I'd just share with you very briefly is that there are different chemistries. So the chemistry used at the Moss Landing facility is different from some of the ones that have come forward. I don't know that the jury is out entirely, but there's some suggestion that the newer technologies have a lower fire risk.

Put that into your data, your public information data. Also, I have one final question and you may not have the answer. Now I'd just like to get the answer. And that is what's the data on the use? You talked about trying to only use the backup, the three backup gas plants at Ormond Beach, etc. Only during emergencies.

How many hours did we end up using them last year, et cetera. And you don't have to have that answer right now. She'll just get it to us so we can get on.

Someone will walk up here if they have it. The short answer is very little, but we can get more precise numbers. They've been in the single digit capacity factor 6, 7, 8%. But we can get you something more precise.

If you, if you could, I'd appreciate it because I want to get on to issue three for the Assembly Member. And so we'll now transfer transition over to issue three. CPUC. Thank you. Deaf and Disabled Telecommunications Program. Thank you very much.

All right. Good morning, Assemblymember Boerner and Chair Bennett, Members of the Committee again, Rachel Peterson, Executive Director of the CPUC. I'm happy to answer questions you might have on deaf and Disabled Telecommunications program and the trailer Bill that we proposed.

Yes. So I think it's more of a comment is I think you probably have seen that the CNC Committee prefers that this language be considered in a policy Bill. We've introduced AB 1532 to accomplish, among other things, we wanted some accountability around the CPUC.

And also in 1532 is the extension of the wheelchair access vehicle program, requiring the CPUC commissioners to be present at the request of the Legislature, an ongoing pain point, as you know, and a study from the Little Hoover Commission on reorganization of the CPUC.

So when we look at the Deaf and Disabled Telecommunications Program trailer Bill Language, I actually don't think this should be done in budget. I think this should be done under the policy. So really the question for you is are you willing to work with us on a policy Bill rather than putting it through the budget? Because we don't think it belongs here.

Well, so just first of all, I think we are always working with the Administration in order to decide the appropriate vehicle. I'm guessing that. Well, I think that the reason we propose this in trailer Bill Language is that it is about extending the surcharge for the program. The program itself doesn't have a sunset date.

And so programmatically we see the continuation of it. It's is really about the $0.12 per access line surcharge.

I appreciate it's about the 12% access line, but I think we should be cautious as legislators to extend a surcharge without what we would consider appropriate accountability and guardrails around the program. I appreciate the point.

Anything else?

I have lots of more things, but they're on 10, 12, 13 and 14. Great. And I have next up in Committee.

I'd like to just say something really fast. I'd just like to eliminate the sunset. Whether we do that in policy or via trailer Bill, I don't care. But I. I do think that this is one of those things that. Why are we even debating it? Right.

This program is depended on by a part of our population that needs this in a very, very critical way. So why don't we just get rid of the sunset? That's my concern.

I appreciate that. I was curious what your rationale was because I wrestled with this yesterday as I was reviewing and I came to the mild conclusion that, well, probably should have at sunset just so that we could revisit it every 10 or 15 years in case technology has changed or some reason, there's some reason that we would want to change it.

I don't feel strongly. So do you feel you'll work with Miles? Right. But. So that's the question is. So I have a question for those people associated with the program. I mean, can technology change?

I mean, with AI out there, et cetera, could things change to the point where we don't need the program and we could obviously end the program? I just don't know that we'll get around to doing it if we don't have. If we don't have a sunset, we may never get around to sort of reviewing the charge. Your thoughts?

Sure. Yes. So the technology that is eligible for the program is already changing. We continuously evolve the eligible technologies as to whether we'll reach a point where people don't need them. These are. They remain expensive. The technologies and the services need to be paid for.

And so that's the core value of the program, is that it's assisting three quarters of a million Californians right now with both devices and services that are constantly evolving.

Other Members have any opinion on sunset?

I think it is important for the Legislature to have oversight and to see how it is evolving and see how the costs may decrease over time where we don't need to have the same level of surcharge. What I worry about is that we put the same level of surcharge and what if the costs decrease over time?

People are paying more than they need to pay to a program that may hopefully technology will help us decrease costs and improve service. Occasionally does that and we like when that happens.

So I think saying we're going to set the surcharge in perpetuity doesn't take into account a variability in innovation that could decrease costs for ratepayers in the future.

Any other comments from Assembly Members?

I just fear that sometimes oversight means potential elimination. I fear that that could even be a possibility that this is such a heavy relied upon technology by those who actually this is not just a benefit, this is a need. And so I fear that sometimes a sunset means it could threaten the whole circumstance there. And I worry about that.

My, my brother is deaf and so I certainly, you know, feel passionately about making sure we have appropriate accommodations. But I don't, I have trouble thinking that anybody would eliminate this program during as a result of a sunset. So I'm not, I'm not overly worried about that.

But I certainly respect the comment being brought up and I'll let you have the final word. zero no, I'll, we'll go back and forth here for another second on broadband.

I like to have the flooded world but you know, no, I don't think there's a danger of elimination. I think when you put something in statute in perpetuity, changing it in the future is inflexible. I think we all represent, I think you said three quarters of a million people in California.

We all represent 3/4 of a million people. They're not concentrated in your district or my district. They're in every district.

And so I think we all have that incentive and I think by putting the guardrails, especially looking at how quickly technology is innovating and maybe how do we incentivize technology to innovate faster and better for that three quarters of a million California is maybe something we can look at.

But if we put it in perpetuity and we don't have a sunset, there's no way to revisit it. It would be very hard. Once we take out the sunset to reallocate that money for maybe other needs that emerge in the future. So.

Well, I share a different perspective just because I'm very aware of the developmentally disabled circumstances in some of their programs that have been gutted. Absolutely gutted is a reality that everything is in jeopardy. And so I worry about that. All you have to do is go to them and ask them what happened to them.

And I know Department of Finance wants to weigh in. I'm going to make one comment though which is a little bit different than the position that I have and sort of supports assemblymember Lackey's position and that is this, this charge has already sunset so we, we have actually stopped collecting the funding and we inadvertently did that because we had the sunset and we are all saying we definitely want to keep this program.

So having a sunset risks the possibility of having the sunset, you know take place and then we actually don't have the funds and we're re establishing it. But let's hear from the Department of Finance and who would have known this was the issue we were going to debate the most right?

Oh wait till we get to 10, 12, 13 and 14.

David Evans Department of Finance I just wanted to address the concern regarding the surcharge being collected but not the full amount not being utilized to CPUC. They vote on the allocation amongst the surcharges that are collected within their public purpose programs. And so the percentage of the surcharge that is collected as allocated towards the DDP definitely disabled telecommunications program.

That amount could fluctuate, could change based off of like the participation of the program. So it's not like the Commission will charge and collect but then it would it on like excess or that the allocation wouldn't be adjusted based off of program needs.

I would, I would bring this to a close by saying one of the things we could do is not have a sunset but have asked the CPUC to be sure to check back with us like in 10 years. But, but I have no confidence that we'll all be around in 10 years for that promise to be very meaningful and stuff. Assemblymember

yeah, I just want to say there's a while there's a surcharge aspect to it that I agree with Assemblymember Lackey that we need to make sure that we serve this population and they continue to be served.

There's a very large policy part of how we serve them, what gets served and that's what we're doing in the Committee Bill.

So I just want to say I Still didn't hear agreement that, that you'd be willing to directly work with us on how we're doing this on the policy side in our Committee Bill with the surcharge being in the budget Bill.

Great, thank you. Anything you want? You want. Yeah, yeah. Anything you want to add there?

We will. You know, we selected a vehicle working with the Administrator Administration. If the Committee or a body decides to move a policy Bill, we'll absolutely work with the body that moves it. We chose this vehicle because of the fiscal situation.

All right, great. Thank you. Healthy conversation. I think if we don't have anything else, we're ready to move on to issue four, CPUC data sharing.

And yes, thank you Chair Bennett. As President Reynolds presented, it's a narrow technical fix to allow the CPUC to enter into non disclosure agreements so that we can receive more current data related to transmission procurement reliability so that we can better perform, properly perform the functions that we are required to perform.

Happy to answer any questions and Deputy Executive Director Tessfai has joined me.

Any other staff on the panel have any comments? I would just offer this and that is I know some people have concerns about how much regionalization we should have or not have, et cetera. I don't view this as that question.

This is more the technical benefits of recognizing that in a complicated world and increasingly sophisticated and technologically advanced world, we're all more and more dependent upon each other. And so we, we need basic information and we need to be able to trust that as we're sharing that information. It's all being handled appropriately.

So I don't have any problems with this issue. Assemblymember. Assemblymember. Right. That gives us the opportunity to move on to issue number five. Thank you very much. And we have DWR and the Electricity Supply Service Strategic Reliability Reserve where we will have more questions. Thank you very much for being here. Right.

Good morning Chair. Good morning Assembly Members. My name is Delphine Hou. I'm the Deputy Director for Statewide Energy at the Department of Water Resources. Thank you for having me today and allowing me to explain the two words and one comma.

We would like to add to water code 80710C with regard to the electricity supply Strategic Reliability Reserve Program. To provide some brief background, DWR acted very quickly once the legislation was passed under AB 205 to procure for three new additional gas fired generators.

These are ultra low emissions resources and they were constructed and sited at our partners at the Modesto Irrigation District, Turlock Irrigation District and City of Lodi. The reason I Mention that is at the time the legislation was passed, we had already gone through the rolling blackouts in 2020. We had a very high heat wave in 21.

And actually shortly after the legislation was passed in September 2022, we had our all time high at the caiso footprint, as we've all experienced. So at the time it was really critical to find sites and partners that we can work with expeditiously.

And one of the main criteria for these resources is to find a site that was suitable to take these resources and provide energy to the grid. And I mentioned that because unlike some of the other resources that we had, these are grid scale resources.

So we are looking for not only suitable sites with gas connection, but we needed the interconnection. So that was at a premium and we needed it very quickly. And our partners that we are working with in a developer were able to secure that for us.

But having said that, part of the agreement is they wanted to see a pathway to eventual ownership of these assets.

As the water code is written today, it would limit the ability, potentially limit the ability for DWR to sell these assets because it's requires that the limitations for these resources in the Reserve to only operate during extreme events is for resources constructed by DWR. It doesn't mention that it probably should be constructed and owned by DWR.

So if DWR were to no longer own the resources, there could be an interpretation that these resources would continue to be limited by the legislation.

So we would like to rectify that in order to potentially effectuate the sale and have that conversation with our counterparties and in order to recuperate some of the costs that the state has spent for these assets for our emergency temporary program. Thank you.

Thank you. Any other presentations by the panel Assembly Members makes common sense to me in terms of the write up with regard to this. And I think it's very appropriate that you're being cautious to make sure there's not a challenge to the interpretation of this language. And with that, glad we heard this.

And we have a couple quick questions. And what cost did the state pay for these resources? Capital costs, excluding staff and fuel?

Yes. Over all three resources, the capital cost was approximately $130 million for these resources.

And so we have a line in there saying we could sell them for $40 million profit from the sale of around 40 million. It's not profit, it's revenue from the sale of 40 million. Okay, correct. Great. All right, wanted to clarify that. And how does DWR anticipate using the quote, revenue. Right.

Rather than Profits from the new resource for new resources for the Strategic Reliability Reserve.

Sure. The timing of the discussion is probably the earliest we'll be able to have conversations with the site owners is approximately 2627. And the earliest a sale could occur is in 2028. So we would have to look at at what's available at that time.

It is daunting at the moment to think of the possibilities given the tariffs and the current federal Administration stance on certain things. But we are hoping that, you know, if there is opportunity to be able to use those funds towards clean energy resources, DWR would certainly like to see that.

But I will also note that as per our legislation, we don't want to compete with load serving entities as they're looking for the same resources. And as President Reynolds laid out very elegantly, adding that additional competition in the market will increase prices. So we have to be very careful when we proceed.

If the Legislature wanted to keep these three units in the Strategic Reliability Reserve, what would the ongoing cost be?

That's a great question. And it comes in a couple of components. So as a temporary and emergency program, we have had to work with counterparties with the interconnection.

So if the stance is that we want to continue with the Reserve but not provide a pathway to our current site partners for eventual ownership, their interconnection is extremely valuable to them because they can site resources there for their own needs, for their own reliability.

Right now we are using this site for only extreme events, but not for anything else. So it could be that our site owners say well, we want the r interconnection back. If there is no pathway to ownership, that would cause us to spend moneys maybe 20 million ballpark.

And again, costs are continuously increasing, but our latest estimate is about 20 million to decommission the units, take them out from where they are.

If we're not lucky enough to immediately find a new home, we would have to start store them somewhere and then we would have to find a new place to recommission them and spend more construction money to connect them somewhere else on the grid.

And again, it was very difficult in the first instance to even find these sites with interconnection capability the first time. So that would be another challenge that we would have to overcome is finding those new sites. And again, I think the reason we got lucky with these sites is because there was a pathway to ownership.

So all of these are additional costs that we would have to incur for.

A temporary program and this pathway to ownership agreement that we have. If they don't see a pathway to ownership, they have the unilateral right to cancel the contract.

I'd have to look back on the specifics of the contract. But it, the way the contract is structured and from my understanding of when it was negotiated is that that was a particular selling point for the counterparties. For the site owners, I should say is their ability to get that eventual resource into their portfolio.

So if we, if we, I'm really just trying to explore here, I'm not trying to advocate that we want to do this, but if we kept these into the strategic Reserve, then could other things that are in the strategic Reserve be moved out? You know like the three gas fired power plants that we have.

So those I assume you're referring to the large ones through cooling resources. Those contracts naturally expire at the right now. The contracts that we have with them end December 312026. So these assets that we're talking about today, these three different assets that DWR owns actually would run beyond that time frame.

Those contracts expire in 2026. But we're, we're talking about extending those contracts. If we kept these assets, would we be, would we not, would we be able to say hey, we don't need these other once through cooling plants Chair?

I'm not aware of discussions to extend those contracts. Our DWR's contracts with those resources sources as written today are expired 12-31-2026.

Thank you, thank you very much. Appreciate that. I didn't hear anything else. And so we're ready to go on to issue number six. Thank you for that information. CEC Grid Resilience and Innovation Partnership to the GRIP 2 federal authority.

Always interrupt me. We're ready when you guys are. Good. Good morning. Good morning. Pull that microphone a lot closer to you. As close as you can. Okay.

My name is Sean Simon. I'm a Deputy Director at the California Energy Commission. Okay. Well, the staff did a great job summarizing the background and the issues in the agenda today.

We did work on a application to the DOE for this GRIP program for transmission investment and partnered with the California Independent System Operator, the California Public Utilities Commission, two of the state's largest investor owned utilities, Pacific Gas and Electric Company, Southern California Edison, as well as UC Berkeley on an application.

In the spring of last year, we received notification of a conditional award of $600 million in federal funds that would be matched with 900 million, not state funds, but from ratepayers. And that number was increased to 630 million as reflected in the agenda. And we have executed a conditional award with the Department of Energy for those funds. I think I might just pause there and take questions.

It's encumbered, which is positive. No funds have been received by the Energy Commission. This is a reimbursable grant. So when we get to a final agreement with the Department of Energy, the Energy Commission will be receiving invoices for work performed, submitting those to the Federal Government and then dispersing those federal funds.

We are in a negotiation stage with the Department of Energy, as is normal. That paused with the Administration change, and we understand it will restart imminently.

So we'll take that as 100% guarantee that the funds will be there. Thank you. That was said in jest. How does the program integrate with all the other transmission initiatives out there, including public financing?

Yeah, it's a great question. It's one of the reasons why the Energy Commission partnered with the Independent System Operator and the puc. As you all know, all the planning and transmission work is coordinated under an MOU. And so this application was fully integrated into our process.

One clear example of that is the projects that come through this program. The need will have been identified by the ISO. Say that again. The need for these projects will have been identified or has already been identified by the ISO. Okay, so this is part of the state's planning and infrastructure that we need already.

And then same for the permitting and the cost recovery. It's all operating within the state's existing processes. The benefit here is that we're bringing in grid enhancing technologies to get more out of the infrastructure and buying down the cost for California.

Thank you. Seeing no other questions now we do have a question. Assembly Member Yeah.

Obviously one of the more sensitive topics right now is affordability. It's a very real problem that seems to be permeating right now.

And so my question, I don't know if you can answer it or not, is first of all, the $900 million that would be shared by the ratepayer, do we know approximately what kind of increase we're talking about and when that would actually start?

Yes. So the way the cost recovery process works, these projects will likely exclusively be under FERC jurisdiction for cost recovery and review. So the ISO determines the need. Then the permitting happens at the Puc. Once a project is approved and built and put into service, the cost recovery happens at Ferc. And then the costs go into rates.

So we're looking at, you know, this is A, the DOE's program is an eight year program. These projects would be built in the latter part of that eight year cycle. And once the costs are approved, they come into rates over a long period of time. So there's, you know, to smooth out that, that Bill impact.

And they're long lived assets. So that's the process. So costs will hit rates after the projects are built and approved at FERC incrementally over time. And then the first part of your question was how much? How much? So the, well, the cost share is, is roughly 900 million. The federal amount, 630.

That portion doesn't go to FERC for cost recovery. I get that. So you buy down that amount, plus you get the cumulative benefits of no return on equity for those dollars, which has a multiplier effect of four to $6.

Yeah, I appreciate that explanation, but it's not answering my question.

Okay.

And I don't know if you're able to, if you're not able to just say that.

Well, the budget for the transmission projects that are proposed is 1.5 billion. The 600 in federal 900 ratepayer. So 900 million.

But how that translate into actual cost per ratepayer is what I'm trying to figure out. Okay. Are we talking about a substantial amount? We talk. I mean any amount in some people's eyes is considered substantial. But I mean, are we talking $15, $20. Okay. The rate, $100.

Let me take that as a, as a follow up. Okay. Thank you. You bet.

Thank you very much. We will now go on to item seven. Thank you. CEC Demand Side Grid Support Trailer we're at item seven. Assembly Member we're at item. We're at item seven. Just starting the presentation. Gentlemen, whenever you're ready.

Can you hear me?

Yeah.

Thank you again with respect to the trailer Bill, let me just recap what we said earlier about demand side grid support.

Excuse me sir, when you look down, you move away from. So pull this down and lower if you want to look down. Yeah, pull it down. But yeah, you're hard to hear. There you go. That is my first time.

So thank you so the Demand side Grid Support Program is intended to act as an insurance policy for maintaining electrical grid reliability during extreme events such as heat waves, by providing incentives by demand flexibility aggregators to electricity customers to provide load reduction when grid emergencies are imminent.

The Governor's January budget established the Administration's intent to provide additional funds to Demand side Grid Support Program given the program's success in offering incentives to electricity customers throughout the state for incremental load reduction and the program's need for a reliable, predictable funding source, the Longer Term from an industry perspective, longer term funding certainty provides assurance to private market entities that are undertaking the risks associated with making the necessary investments in providing the aggregation and enrollment services in support of the DSGS program that are critical to expanding participation in the program and increasing available resource capacity to help grid reliability during extreme events.

DSGS incentives to date have provided electrical customers have proven to be vital to the State of for Maintaining electricity reliability during extreme heat events, particularly during the 2022 extreme heat event.

As of October 2024, the last season we just completed, DHGs had over 250,000 customers, participants and more than 500 megawatts enrolled, including over 200 megawatts in the largest storage virtual power plant in the country.

So the program has demonstrated its ability to scale and it is the cleanest resource available in the state's Strategic Reliability Reserve that DWR referred to earlier. Currently, the Strategic Reliability Reserve is largely supported by fossil fuel resources, which are expected to retire again.

As DWBAR colleagues explained earlier and more recently, CEC in consultation with CPUC and CAISO in 2023 developed a statewide load flexibility goal of 7,000 megawatt by 2030.

So as California transitions to 100% clean energy, the DICS program seeks to pilot program mechanisms to grow clean demand flexibility resources to support the reliability results as well as the statewide load flexibility goals.

So as we have been engaging with stakeholders, they have made it clear that the stability in DHGS funding level is imperative and poses an immediate risk and any uncertainty poses an immediate risk to sustain participation in strategic Reliability Reserve.

So as an emergency response program, DSGS needs to retain flexibility to adapt to changing market conditions and incorporate the latest learnings from program implementation experience which the trailer build language provides.

Although the program is a bit more established now, we as we prepare for a new season, we have less than a year to adapt any lessons learned from a prior summer and in fact we have made changes each year and being able to make changes to program design guidelines enables the program to implement lessons learned each year.

The contract flexibilities also enable us to timely secure a third party program administrator and make amendments to the contract as the program evolves.

For example, when we need to execute work authorizations to implement new incentive options in just a few months, we prioritize stakeholder feedback in our program development process and release draft guidelines for public comment or public workshops before bringing proposed guidelines to the CEC business meeting for adoption.

So it only gives us a narrow window in which to develop templates, data platforms and processes to implement guideline changes in time for program season that begin in May. As we really don't know when a grid emergency will occur, due to its very nature it cannot be planned.

Hence the flexibility provided in the Bill remains critically important so that we are able to respond as needed. I can pause for questions.

Great. Thank you. Questions?

Not really questions. I appreciate the presentation, but I do want to concur with the staff comments here about the four different transparency metrics that we have here that I think weren't able to be done at the beginning when this program was stood up.

Now the program is far enough in that I agree with the staff's comments about eliminating those provisions so that we do still have the apa, the State Contract Manual, the Public Contracts Code that those would still apply.

I heard this question. You made a comment, not a question then. Right. And I'm sorry, but I was having a conversation here. Was your comment about the question that staff posed here?

I was supporting the excellent work by staff and agreeing with them.

Great, thank you. I've two questions. One, the whole issue with regards to using residential batteries, consolidating them all together and having that eventually be some kind of demand side response, you're investigating that. Is that technically possible at this point in time? What would it take for that to happen? Is it something that is a possibility in the future?

We're actually demonstrating that today in the demand side grid support program, we have three participation options. One of them is referred to as option three, storage virtual power plant. And in fact, more than 90% of the batteries enrolled in that option are residential batteries.

So residential customers today with batteries can enroll in this program. They can and they have in large numbers. Great, thank you. And then the three of the four exemptions that you're looking for, the state Contracting Manual, the public contract Code, and the contracting requirements of Article 4, you're asking for exemptions for all of those. Right.

What would be the impact if you didn't? Note I'm leaving off the Administrative Procedure Act. Right, but what would be the impact if you didn't have those exemptions?

That's a hard one. I mean, especially the contract, the contract exemptions. It will stymie us in terms of any reforms we make, any efforts involving the third party administrative in which we rely a lot. I mean, it would delay program implementation easily by a year. Is there anything else you can add?

Damien Mimnaugh with the California Energy Commission. Director of Administration, Sure can. Is this better?

Yeah, closer.

Okay. Damien Mimnaugh California Energy Commission, the Director of Administration. One of the things we can envision with this program is that it's an emergency response program.

And so should we need the ability to enter into contracts quickly to obtain new third party administrator services or other services to support the program, we'd want to be able to move quickly to support the state's reliability goals. And so that's really the impetus behind maintaining these contractual exemptions.

We're not anticipating using them as we did in the first time when we went and obtained the third party administrator. But this does allow us to retain that flexibility to support the state in the case of an emergency.

We of course, hope that doesn't happen, but we want to make sure that the program is set up to support the state in case it does.

Now, this is a proposal for bond money that the Administration wasn't asking for. Right. And now if you do get this bond money, you're saying you need to have these exemptions, right? From that standpoint, is that correct?

The proposal would be to apply these exemptions to the program writ large. The program itself has a appropriation for multiple sources of funding.

An initial appropriation of General Fund from 2022 and subsequent Appropriation 2023 of General Fund, which is subject to a Governor's Budget Fund swap, and then a GGRF appropriation in 24, and then a proposed $75 million appropriation in 2025.

So, I mean, the issue for us is we. We granted these during the emergency. We're not in an emergency now. But I'm hearing you say you want to do this only if there's an emergency. You want to do this expansion.

The proposal is to maintain the trailer Bill Language, or the trailer Bill Language proposes to maintain these exemptions to allow the Commission to respond to an emergency quickly if one develops. We certainly, again, hope that doesn't happen, but we can envision a case where it does.

We want to be able to enter into contracts quickly to support the state's reliability, excuse me, reliability goals if it does happen.

So will you not expand this program if there's not an emergency? Sorry, could you. Will you just park the funding for this until there is an emergency?

Let me take that. So even though we are technically not in an emergency from a reliability perspective, the role of strategic reliability Reserve as an insurance policy hasn't changed. Right? I mean, during. In extreme events, we could have an emergency at any time.

So to continue the effectiveness of that insurance policy, we do need to evolve the program quickly to capture opportunities and scale the resource. I mean, 500 megawatt is still a small resource relative to the entire liability Reserve, which is dependent on fossil fuels. And the goal is to transition that to clean resources as quickly as possible.

So for that purpose, I think the flexibility will be still very important. As an example, for the summer of 2025, we have introduced yet another participation option that's focused on smart thermostats, heat pumps, and smart electrical panels. That effort started in October. Without that flexibility, we would not have been able to introduce that option for this summer.

And that is the item that's on the Commission's agenda tomorrow for consideration. Okay. Hopefully it gets approved.

Great. Thank you. Just let the record show from our standpoint that we're certainly in agreement with our staff's recommendation in terms of the exemptions for those.

Because I might have a little different perspective. I believe that the APA oversight exemption is really quite concerning and somewhat potentially problematic because if everything is an emergency, nothing is really an emergency and I find that to be very concerning.

Okay, great. So we have bipartisan support for staff's recommendation right out there at this point in time. Thank you very much. We're going to go to the non presentation items. I have a question on issue nine and the on issue nine, which Department are we talking about here? Electrical transmission grid AB3264 and that would be CPUC. Great.

And the question is, you know we have $3 million to implement the Bill with minimal requirements for the state. Right. You have $1.0 million for ongoing staff for the Bill that has minimal ongoing work. You have to report every three years the information to the Commission. How did you determine those costs? Right. We've given you this question in advance. Hopefully you're ready for it.

Thank you for the question, Chair Bennett. So the law gives us two jobs. One is the transmission financing study that's due on July 1st with six some public outreach, public vetting, that's one deliverable under the law.

The other is a large new project to create an energy wallet costs and that is the analysis that the positions are that we've proposed are tied to that energy wallet expands. What we typically look at, we normally look at the cost of electricity and natural gas that are the fuel that's powering California.

The analysis asks us to include propane, diesel gas at the pump in an overall look at what are the, what are Californians overall energy wallet costs.

Additionally it asks us to take a 10 year scenario, look at what the cost will be in the future and then propose approaches to to reduce those costs by 510 and 15% respectively. So it's quite a big analytical project and deliverables that are required under the law, which is why we propose the permanent positions.

Thank you. Any other questions on item nine? All right, thank you very much. Assemblymember. We'll turn it over to you. For which items still you have 12.

I think 10, 12, 13,14.

All right, so we have a request to hear 10, 12, 13 and 14. So for item 10 we have PUC and state operations and local assistance. California Lifeline.

Yeah. So I don't know if you want to talk about the California Lifeline program. Obviously in our Committee we're very, very worried about the Supreme Court case. Supreme Court case regarding Universal Service Fund can you talk about how Lifeline uptake has changed over the last, say, five years, 10 years?

And what plans are you guys thinking about for the case where the Supreme Court does strike down the Universal Service Fund?

Yes, thank you for the question, Assemblymember. I'll start with a broad sense of how we're monitoring. And then Deputy Executive Director Johnson has really been looking at possibilities here. So just like you, we are monitoring the Supreme Court case closely.

Of course, I do not know how it might turn out, but what we've noticed when, for example, when the Affordable Connectivity Program ended, there was an immediate uptick in Lifeline subscribers. And so anything that happens at the federal level to remove subsidies and supports really has an automatic, almost automatic ripple effect here in California.

And so with Lifeline, we have been, we're responsible to forecast every year. We forecast subscribers first in September and then again in May. And so we've done that and are constantly looking at what the federal picture is in order to try to see that whether we can forecast that we'll be experiencing another uptick in subscribers.

We have some other programmatic ideas that we've been working on that Deputy Executive Director will speak about. Unless you have another.

Yeah, just to build on that before the Deputy Director speaks, because I'd love to hear the ideas that you guys are thinking about for people who maybe just give a one sentence explanation, the difference between Lifeline and ACP. I know the difference, but we had 3 million people, I believe in California who subscribed to the ACP.

Lifeline isn't one to one the same as the ACP. So maybe describe that and say you said we had an uptick of Lifeline, but I assume it wasn't at the magnitude of the 3 million that were taking ACP. And they're not a 1 to 1 overlap.

So I don't know if you can comment on those numbers before then we. Hear the deputy directors.

In order to get it accurate. Why don't I go straight to her?

Thank you. Good morning, Assembly Member Boerner. So you are correct. Since the sunset of the ACP, a number of California customers have actually utilized the Lifeline program. And there are differences.

The California Lifeline program offers a discount on phone service, but also it allows a discount to be applied to a bundle, voice over IP and broadband. That's very different than the acp. That is a standalone broadband plan that you can apply your subsidy to any plan that the customer chooses.

Since the sunset of ACP, we have seen the California Lifeline subscribership increase from 1.3 million to 1.7 million customers. So around 400,000 new subscribers have come over to California Lifeline.

That is not at the same level of magnitude as the acp, but we are looking at updating our Lifeline program to look at potential pilots and exploring pilots that will be very similar to the ACP that allow for a standalone broadband service. We continue to explore those options to actually meet the needs of Californians are seeking today.

As far as eligibility, the Lifeline program and ACP share a lot of eligibility similarities, such as participating in other government programs like the lunch program, Medi Cal, Medicare, those type of programs. The income level is different on the California lifeline compared to ACP.

For example, ACP, I believe is 200% of poverty level versus lifeline is 185% of the poverty poverty level.

Thank you. And so when you say you're looking at different options to deal with it if the US Stuff goes away. So we're, for those of you don't know, we're one of the few states who has a state Lifeline program in addition to the Universal Service Fund funding from the Federal Government. 400,000 is not even like 1.67.

Even with the uptick. Million is nothing close to the 3 million that we had under ACP. So we're leaving, even with the income differential, we're leaving a lot of people behind. So what are the thoughts that you guys are having on how to reform Lifeline? Because we're having similar thoughts on what to do.

I'm just waiting till June to figure out what the scenario is before. And if anybody wants to do this other than me, you're welcome to. I don't need to take on Lifeline 2. But like it seems, I keep asking other people to do it.

And not a lot of people want to reform Lifeline or want to take on the hurdle of reforming Lifeline, but we would need to do it quickly. And one of my challenges, I think, of doing things through the CPUC is it's not quick enough for Californians.

So if you want to give us a preview of what you're thinking of, maybe there's a way of us working together so we could get it to people faster. Because we know when people don't have access to phone or broadband, kids aren't uploading homework to Google Classroom, people are getting telehealth appointments. People aren't applying for jobs online.

There's like, they're very basic things that people need to do. And I always talk about this and I say, if you have broadband, you don't think about broadband. It's part of your life. It's one of those things that happens in the background. It's why people think I'm crazy for caring about it as much as I do.

But if you don't have broadband, you acutely are aware that you don't have broadband because you can't do basic things that anybody sitting in this hearing room can do.

That's right. And broadband is an essential service that all Californians rely on today in order to be able to participate in today's economy, healthcare, education. Without it, you cannot access those essential services and public safety.

So what we are doing in the California Lifeline program is looking at a pilot to include a standalone broadband option which is currently not available at the moment. Something similar to what ACP offered.

And we hope to move quick on it since we will be trialing it as a pilot rather than like a long term change to the program. And our work continues to look into what the parameters and framework will be to turn that on.

And what is the scope, what is the magnitude of the pilot like? Is it a geographic area or income area? And what would be the cost?

Because one of the things that we worry about is the, you know, we know we're facing a very, you know, difficult budget year and the costs of replacing the ACP is not something I think we can really. We currently have funds to bear right now.

That's right. So we are continuing to develop those frameworks, but it will be statewide available to eligible Lifeline customers. As the eligibility of Lifeline is today, will there be an impact to the Lifeline budget? We would expect so.

Maybe on a granular level, not all at once, but once the pilot is rolled out to be able to allow for that option to customers to utilize to offset their broadband Bill, we do expect a level of increase to our fiscal year budgets.

And then how are you dealing with the problem that Lifeline is? I'm going to forget the acronym. It's ETC. They're qualified ETCs and ACP wasn't. So none of the cable providers can participate. Really, none of the cable providers who participate in the ACP could participate in Lifeline because of the ETC requirement. How are you thinking about that aspect.

As part of the pilot? We are considering that not limited to just etc, but any Internet service provider that would like to participate in the program. Again, those are all items we are researching and looking into develop because we want it to be successful.

We want to make sure that customers are able to subscribe and we want to make sure that the top, the largest providers that cover 95% of Californians are able to participate as well.

So those are all factors that are under consideration as part of the pilot right now on whether or not to require an ETC to participate, but with enough parameters to hold companies accountable in making sure the right utilization of public funds are taking place.

Thank you. Should I move on to 12 chair or should did you want to do. Move on to 12? Yeah, move on to 12. Okay. So for issues 12 and 14, implementation of and support for AB14 and SB4 with the CASF regard to CAS permanent positions for CASF, I think it's more of a statement.

I personally oppose giving more permanent positions to the CPUC for broadband activities without a more comprehensive conversation about the structure of the agency's broadband programs. And I bring it back to an example. The ffa EMBIID were intended to be temporary programs with limited time funding.

But instead, because of all the delays we've seen, the CPUC is attempting to make this a more permanent program and ask for permanent positions. I don't think that's the right approach. And the Legislature. What I think we should do is is consider a standalone broadband agency.

I've brought this forward many times, bringing it forward again this afternoon to let the CPC focus on more pressing issues because I think a standalone broadband agency would actually be more efficient over time and be quicker to market than what we see with very complicated CPC proceedings that not all aspects of broadband requirements.

And so that is more of a statement for you is I think asking for permanent funding for what is meant to be temporary programs just highlights the fact that we need a standalone agency because there's other work that needs to be done in broadband.

You know, we don't know what's going to go on with all the anti DEI rhetoric from and policies from the Federal Government. What does that mean for our our digital equity programs and implementing those within cdt? So splitting it between CDT and CEPC is actually causing inefficiencies in the implementation, duplicating resources and creating delays in timelines.

So that's probably more of a statement than a question. And I think regarding Divca on SB28, the CPUC is requesting new permanent staff administrative law judge, analyst and attorney. And it's unclear how administrative law judge would support the ongoing implementation. And if the Legislature this is a question.

If the Legislature intended for the CPUC to accept customer complaints, why isn't the CPUC requesting staff in the Consumer affairs branch? Why Are they requesting the staff where they're requesting them?

Yes, I'll speak to that. So, first off, this is a request to convert limited term positions to permanent, just like the ones for AB14 and SB4.

And while we are always training our Consumer Affairs Branch staff to listen to the wide range of calls that come in with issues that customers have with different regulated entities, the question of video franchise holder service in local communities is a pretty specific, complex question.

And so that's why we're proposing staff in the Communications Division who are technically trained and know about DIVCA and know about the responsibilities.

Couldn't you just train the people in the Consumer affairs branch? Because that's where the complaints go. So, like, that's again, maybe something to rethink in terms of how you're structuring it so there's more streamlined efficiency within the government rather than saying this branch isn't.

What I heard was this branch isn't trained up enough, so we're going to put them over here. When this branch is supposed to be trained up enough to deal with it.

We can and do train our CAV team all the time and they are active. In return, they answer tens of thousands of calls per year and return tens of thousands of dollars to customers from utilities and other regulated entities.

All I'm saying is that even if CAB receives the phone call, they might be able to address it initially, but it's a pretty technical, complex area and so would likely end up with an analyst in Communications Division anyway.

Okay. I think my position is clear. And how will Administrative Law Judge support ongoing implementation if the proceeding to adopt the customer service requirements will at some point be closed?

Yes. So the Administrative Law Judge will be in charge of the proceeding that has to set out the framework for what is expected of video service franchise holders. I'm never sure that I'm saying the words in the right order. You can say DivCo.

So we need to put all the holders on notice of the expectations, then we execute on finding out whether they're complying with those expectations and then we go into enforcement. So the judge will be responsible for both leading the proceeding and then handling the formal complaints that come in, should any oak come in.

Those are the more formal ones, as opposed to what you were referencing initially with customers calling up.

But if the proceeding as to customer service requirements at some point will be closed, why would the Administrative Law Judge be needed?

Because in an ongoing way, we probably will have complaints and then occasionally when we have enforcement actions, we need to handle them through formal process in order to provide due process to the entity plus the, and whoever's bringing the complaint.

And you don't have that currently in any other proceedings and any other things that you do, it seems like you would have enough staff who do all this stuff anyway. So to add that, you don't need another administrative law judge.

I mean, this is where the questions about the level of staffing come in. Right. And we are operating under a large number of statutory mandates and a lot of the positions that we have carry statutory mandates.

And so when we are presented with a law like the DIFCA law, we look at the resources that we have, we find efficiencies where we can and then we propose the number of positions that we think we need in order to carry out the work plan.

Yeah, and I think that just goes back to my point is if we were to streamline all brand backed broadband activities into one agency, you wouldn't see this constant need to increase because you're doing, you know, you're getting more statutory mandates here.

You'd have one agency that would do it all, and I only have like Lord of the Rings references, but one agency to do it all that would. And other states have done this and they've been more efficient both in staffing time to implement the laws and more agility in doing those laws and more accountability to the public.

So that's why I do it. And you're going to get more efficiencies. And so that's why I'm always very, very hesitant about increasing more staffing for the CPUC, because I don't see that we. We're serving less people now the ACP's gone, we're serving less people.

You know, we're having continual delays in implementing broadband programs and delays in proceedings. So I think increasing staff with all the delays is something we've seen time and time again and it's not the way I think we should be going with regard to the budget and broadband. Thank you.

And which Department would you like to consolidate everything into? If it was up to you?

It would be the Office of Broadband and Digital Equity.

Thank you.

That's going to be in my hearing today.

Assemblymember Rogers, you have a issue on item 18.

Yeah, so actually similar in kind of thought process. So on item 18, this is actually an issue that the State Auditor called the CPUC out for in 2023. You agreed to implement changes. Here we are in 2025 and you're requesting 12 positions.

So my basic question is what have you been doing for the last year on this issue, how have you been addressing it? If you didn't have the 12 positions approved, how would you address the issue?

Because I think when we were talking about rate of return variances across the state, there's an assumption that this is an area where the CPC should have oversight and should not just now start doing it, but be looking out for people's best interests.

And I'll note, and I talked about this a little bit earlier, over the last seven years, the public advocate's office has only added six positions. But then you've had 400, let's see, 580 positions added to the CPUC, with 406 of them having some level of regulation over utility overlap.

So if they're making do as Public Advocates with six positions while trying to look for things like this, what are you all doing with the additional 406 that you've gotten?

Thanks, Assemblymember. And I'm interested in that statistic because I've been the Executive Director for four years and we have acquired some new positions, but I'm not tracking it.

It's from the Department of Finance's website.

Okay, thank you. I'll look it up and take a look.

Some of them are page 20. Of their. Of their analysis.

Okay, so in the first instance. So back to AB 2666 that you're asking about.

So when the Auditor issued findings and we proposed corrective actions to them about the utilities rate of return, their primary finding that they wanted us to do was to bring greater transparency to the distinction between a forecasted rate of return and then an actual rate of return.

So in order to meet the Auditor's expectation, what we did was set in place a system by which we are requesting from the utilities what was your forecasted and then what was your actual. And. And that's going on our website. So that was a major transparency finding from the Auditor.

What the new law delivered to us was a new additional responsibility to examine the cost categories and the actual costs that are different from forecasts. So a forecast happens within a General rate case, then utilities spend towards that that forecast, and then there's an actual what did they actually spend at the end?

There are thousands of cost categories in every General rate case. And so what the law now requires us to do is to examine those differences between forecasts and actuals across numerous cost categories.

I'm going to interrupt just for one second because we're very close to the end of this and sending Member Rogers. I want to make sure he can finish those questions then we're going to go to public comment but I have to go add on in elections Committee.

I'll be back in a matter of moments but if this hearing comes to an end and people want to make public comment we'll open it back up for public comment as soon as I get back. You can continue.

So just continuing on how we'll how that what that law requires us to do how we'll implement it so asks the Commission to then adjust the future going forward revenue requirement of the utilities based on their performance of actual versus forecast in the prior case. So that is a new more granular responsibility that we have never had before.

It also is a setting of expectations for the utilities that again we have to handle through a due process focused evidence based proceeding in order to say to the in order to identify why did the variance happen, what were the reasons for it and should the utility therefore receive less in that cost category going forward requires being put on notice, establishing the criteria, measuring against the criteria and then making a decision.

I'm not sure I understand though. If the utilities are required to already report what they're expected is going to be and they're required to report what their actual was and you already have staff who are doing GRCs that take into account these data inputs already. Why do you need 12 new full time positions?

Some of that is a simple spreadsheet. What was proposed, what was the actual and I understand you have to dig in and find out the why for the grc. But you already have somebody doing the grc. A lot of people doing the grc.

Yeah. I'll turn to Deputy Executive Director Tisfai in a moment. But again the GRCs are very large cases, thousands of cost categories.

Our decision but again you have a lot of staff already doing it to go back to the 406 that you've had added in the last seven years alone for this work they're not so why is there no efficiencies there if you already have the data being provided to they don't even have to go out and get the data. The data is being provided to them.

I will look at the ads but again we've added people and positions in telecommunications, transportation, water, energy safety, administrative law Judge. It's across the agency.

You have you've added 580 across the agency based on the DOE's Department of Finance's report. 406 were specifically for regulating utilities and working presumably on the GRCS.

Of the 406 many are working on numerous Other programs like energy efficiency, community solar, a number of the programs that we've spoken about here. So yes, General rate cases are a core element, but it's not. There are not 406 people dedicated to it.

Thank you. Leuwam Tesfai, Deputy Executive Director for Energy and Climate Policy. I'm the head of our Energy Division. The Energy division has about 270 staff. Those, a number of those are also limited term.

And so this large number that you're speaking of would also include oversight of utilities, including water utilities, also including our telecommunications utilities. There are also entities like rail and transportation as well. To go into more detail about the new work that will be occurring here, the staff that we have working on our General rate cases.

General rate cases are a forecast based work. So they're looking at historicals to make to help assess what the forecast should be. They also look at a number of other metrics that would indicate that the forecast perhaps should be higher than what the historical is.

So, you know, indicators like inflation, but also increasing costs for different capital components as well as labor costs. The specific exercise that needs to be done here has a number of additional components.

So this part about going back and changing the earning for the utilities is a completely new exercise that has to be done across thousands of cost categories. In addition to that, some of these assets are California jurisdictional at the Public Utilities Commission. Some of these assets are FERC jurisdictional at the Federal Energy Regulatory Commission.

Also, a number of the assets are actually partially split both in capital as well as labor across the Federal Energy Regulatory Commission component and the Public Utilities component. So there's this heavy, we've been calling it entwinedness of these different assets. So if you are going to.

And then in addition to that, there is a specific rate of return that's authorized by the Public Utilities Commission and and then a different rate of return that is authorized by the Federal Energy Regulatory Commission.

So these additional staff will first be creating through a stakeholder, open stakeholder process through an oir because some of the staff in the BCP are for the Energy Division, but we also have, for example, an administrative law judge. So there will be a new order instituting rulemaking prepared by the Commission and issued publicly for comment.

That order instituting rulemaking that I, I expect based on the legislation will include the creation of a completely new methodology to be able to pull apart all of these different categories between the jurisdictions, as well as how to do that transparently do that assessment across all of the thousands of cost categories and so we'll of course get the perspective of the Utilities on that, but we'll also get key perspectives from the Public Advocate's Office, Utility Reform Network and all of the other stakeholders that represent labor and other entities in our proceedings.

And so it'll be very important for our staff to not only have these new skill sets to be able to do this parsing and create the new methodology, but also to be able to work with all of the different stakeholders to transparently create that whole new methodology.

So that's the first step and that will include, of course, workshops and other opportunities for public participation. Then after that, we're going to have to figure out how we take that new methodology and integrate it into our existing General rate case process. So this is a process that occurs every four years for each utility at a staggered.

We try and do it at a staggered basis because some people will work on multiple rate cases at a time. So we'll have to effectively integrate this brand new methodology into the General rate cases and then be able to implement it from there.

So it is a very complex process and is a very new, daunting challenge that we have at the Public Utilities Commission that we'll be addressing.

So then how are you meeting the need right now? Or are you?

I would say that we aren't meeting the need right now. In order to respond to the audit, we have started some things with our existing staffing, including data collection from the Utilities, at least, so that we are able to at least start understanding the data at a high level of the actual rate of return, authorized rate of return.

Again, what we're already observing is that entwinedness between our authorized and the FERC authorized. And so we haven't begun the process of trying to pull that apart. That is what we need these new staff to be able to do. But we have started at least collecting that data and posting that data to our website.

Okay, I'll continue to talk with the chair. I think the concern is at a time when every other Department is trying to figure out how to tighten their belt, there's at least 20 something new positions being requested for the CPUC.

When you look at the amount that has been added over the last decade, it certainly outstrips any organization or any Department that I can think of.

And so I'm going to have a lot of heartburn about continuing to add staff when we also don't always feel like we're seeing the impact of adding those staffs in terms of timelines and in terms of workload. But thank you.

I really appreciate that and look forward to continuing conversations with you, particularly based on the information you got here. How many positions are you going to lose as a result of the 8% cut?

56.

Okay, thank you. It's good for good for us to have that information also. So you're going to lose 56 and add these 22 positions here as we go forward.

But the whole issue of efficiency and number of employees is one that the Legislature has lots of concerns about and we really need to find some way to connect greater confidence level that staff is really being used as efficiently as possible.

So I look forward to working with my colleagues and working with agency staff, not just the CPUC on how we can do that, find a way to get greater assurance along those lines and stuff. With that, this meeting is going to move into the public comment section of the meeting and the race for the microphone begins.

Hello. oh, good morning Chair and Members. Thank you so much. Kim Stone of Stone Advocacy on behalf of the California Solar and Storage Association with two comments. Issue number one DGS and the Climate Bond. The Demand side Grid support has a customer battery virtual power plant program called Option 3 that is a smart and innovative design.

That virtual power plant program started in 2023, grew dramatically in 2024. It delivered when we needed power, can continue to deliver and show the potential of customer batteries to shore up our grids reliability. DSGS needs funding support and certainty to be able to show its potential.

And so CALSO supports allocation of that 50 million from the climate bond to DSGS. And then second point is the energy package from the Governor's Budget, DSGS and DIBA allocations, the 75 million from the greenhouse gas reduction Fund and the 200 million DBA from the greenhouse Gas Reduction Fund.

The demand side grid support program is already showing that customer batteries and other energy resources help contribute to grid reliability. Additional funding for those programs is important to send a signal to customers and virtual power plant operators that they can be confident and enroll and participate in the program.

And the Distributed Electricity Backup Assets program does have significant potential to show the value of customer batteries and other flexible devices to enhance grid reliability and we support that.

Thank you very much.

Good morning. Jordan Curley on behalf of American Clean Power California and California's five offshore wind. Leaseholders here to support the Governor's proposed. Allocation a Prop 4 Fund allocation for. Ports and offshore wind generation. As we all know, offshore wind projects. Are a critical part of the state's. Goal to procure 100% zero carbon renewable resources.

To meet these goals in time. It's critical that we allocate these funds now to begin upgrading the state's ports. Upgrading these ports will likely take up to a decade. Therefore funding is needed now to begin that process. Allocating these funds now sends a critical. Signal that California remains committed to the.

Industry which continues catalyze further private investment in port development and the industry more broadly. Thank you very much.

Thank you. Teresa Cooke. On behalf of Equinor, one of the offshore wind developers, happy to align my comments with Ms. Curley and ACP.

Chair Members Dan Shaw. Gonna make two comments on behalf of two separate clients, so bear with me. First, on behalf of the Port of Long beach, reiterate the comments that were just stated. Strongly support the governor's proposal to allocate these Prop forward monies. The market signal is critical and to support any nascent industry.

Public seed funding is absolutely necessary and that's what these funds represent. One kind of further comment on this.

Working backward from the timeline in the CPUC's recent request to the Department of Water Resources to stand up the central procurement entity, the port will need to start construction of its pier wind project in 2027 in order to meet the 2035-2037 online dates spelled out in the PUC's need determination.

So that, that is sort of an indication of why we need to get going now. Port Long Beach is, is doing that and so appreciate your support. Secondly, separate project, separate client.

The only. You only have one minute per lobbyist. Yeah. Not per client. Yeah. You can get in line and come back again for your next one. Right. All right.

Good morning OR Good afternoon. Mr. Chairman is Brian White on behalf of Offshore Wind California represent technology companies, engineering firms and those folks who are supportive of offshore wind. Floating offshore wind to the point that Jordan currently made request regarding the port modernization. It's critical. You know the voters already approved Prop 4.

There's no really time to really debate about whether or not we need to spend it. We need to spend it quickly. That is why we support the government's proposed budget. It's really getting at the heart of we gotta get ready for these projects now.

You know, all the other planning that has to go that we need, the Federal Government needs to do. That's years beyond whether or not the Trump Administration does that or not. What we can do meanwhile is upgrade our ports. So we support the Governor's Budget without any hesitation. There's no confusion.

The only confusion is if we don't spend this money. So we got to get it out now. So thank you.

Hi, good afternoon, I'm Meg Snyder with Axiom Advisors sharing comments on behalf of two different clients today on behalf of Invenergy. On issue item 1. Invenergy supports the 471 million appropriated from the Prop for Climate bond for the CEC for the development of offshore wind generation. Their comments are in alignment with American Clean Power.

And then on behalf of Rewiring America for agenda item two, Rewiring America requests the Legislature sustain the EBD equitable decarbonization program with an 8.8% or 400 million continuous appropriation from the Greenhouse Gas Reduction Fund.

This 400 million investment would deliver over 1.9 million in health cost savings annually, 4.7 million in energy Bill savings annually, as well as 414,900 tons of. Carbon pollution reductions annually. So thank you.

Thank you, Mr. Chair, Edson Perez with Advanced Energy United here to align our comments with prior supporters of DSGs and DIBA and also. With the Committee's comments as well. These programs are critical, as you know, to bring clean distributed energy and help replace peaker plants. And so they shouldn't be backfilled with Prop 4 funds.

The prior commitments should stay and Prop. 4 funds should be additive. I wanted to specially note that for. Dsgs, the Energy Commission with stakeholders have. Been working for over a year on expanding it and including smart thermostats and EV chargers and the Option 4 expansion.

But now the CEC has exempted PG and E territory from this expansion at their meeting tomorrow. So just want to urge, I think, further collaboration to see how we can properly expand the program to make sure that the benefits are fully realized. Thank you.