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

Do roll back to start. Yeah. Alright.

Great. Before I read all this, yeah. Good morning. Welcome to Assembly Budget Sub Four. Today, we have six items for presentation and 28 non-presentation items.

At the end of all the items, we'll take public comment. Each member of the public will have up to one minute to speak. I'd like to kick this off with a rare opportunity to take roll with some people here.

[Roll Call]

Thank you very much. We have issue one in front of us today. And so if the members of the panel will introduce themselves before they begin to speak, we will appreciate that. This item is to authorize Distributed Energy Backup Assets program funding for the Demand Side Grid Support program, and Emergency Load Flexibility funding trailer bills. So this is one of our bigger items for today, and we look forward to having all of our panelists here with us.

Alright. Would you like to begin? Good morning.

Go ahead. There we go. Now we Okay.

Good morning, Chair and Members. My name is David Evans with the Department of Finance. I will be presenting the two trailer bill language proposals in issue one. The 2026 Governor's Budget proposes two trailer bill language proposals to consolidate the remaining funding for the demand side resources to respond to grid emergencies this summer for 2026, while also transitioning the state's efforts and resources toward emergency demand response efforts to have more reliable funding streams and to provide the greatest benefit to ratepayers.

So the administration's intent was for the program not to rely on ongoing funding from the state.

Given the General Fund structural deficit and the constraints of the Greenhouse Gas Reduction Fund, it is no longer sustainable to continue to appropriate funding to support the Demand Side Grid Support program, the DSGS program. Therefore, the administration proposes to transition the state's emergency demand response services to a ratepayer-funded program that directly benefits ratepayers.

So for the summer of 2026, the first language proposal listed under issue one authorizes the General Fund that was originally appropriated for the DEBA program, the Distributed Energy Backup Assets program, to be used for the Demand Side Grid Support program to support any emergency-triggered demand reductions during the 2026 summer session. So this is a redirection of approximately $26,900,000 General Fund. Originally, at the Governor's Budget, we estimated that it would be $22,000,000.

This is an update to that amount, so it's now $26,900,000 at Governor's Budget. That's DEBA funding that will be used to supplement the remaining DSGS money, for a combined total of about $56,900,000 to respond to the grid emergencies during this summer.

The second language proposal authorizes the accumulated interest that's in the CalSHAPE program, the California Schools Healthy Air, Plumbing, and Efficiency program, which is approximately $70,000,000, to be returned to electrical ratepayers for the use of demand response services for summers 2027 and 2028, or a cost-equivalent program underneath the PUC.

This language also directs the CEC and the PUC to work together toward transitioning existing electrical corporation customers that participate in the DSGS program to the ELRP, the Emergency Load Reduction Program, or an equivalent program underneath the PUC.

With me are my colleagues from the PUC and from the CEC who can answer specific programmatic questions regarding their respective programs: the Emergency Load Reduction Program with the PUC, the CalSHAPE program, and also DSGS and DEBA with the CEC. So this concludes my presentation, and we're happy to answer any questions that you may have.

Great. Thank you. Do any of your colleagues have prepared comments also, or are they just here for questions?

They're just here for for for Chris and Sarajan.

Alright. We'll go to the LAO's office.

Helen Kerstein with the Legislative Analyst's Office. We don't have any specific concerns on the proposal. One thing I'd want to note, though, is that one part of the proposal, as you heard, reallocates some General Fund from DEBA to DSGS. We wanted to highlight that absent this action, that funding would naturally revert back to the General Fund. So really, the tradeoff for you is: would you want that as General Fund savings, or is DSGS kind of among your highest priorities for General Fund?

Thank you very much. We will jump into this program, and I'm happy to begin asking questions. But Assembly Member Rogers, if you have a preference.

Yeah. Alright. Great. Okay. So I want to make sure we cover the questions that we presented, so that you guys are aware of these. So let's just go ahead and make sure we move through this. How much funding remains for the administrative overhead portion?

Is that the 26,000,000 that you're referring to in the CalSHAPE program?

I can take that one. Yeah. Good morning, committee members. My name is Deana Carrillo, and I'm the Director of the Reliability, Renewable Energy, and Decarbonization Incentives Division. I oversee CalSHAPE and DSGS.

Right.

As of the end of last fiscal year, fiscal year 2024-2025, the CEC had spent $9,600,000 in CalSHAPE administrative funding of the $30,000,000 that was totally available. And the CEC will be returning unspent administrative funds similar to the incentive dollars under CalSHAPE.

Next question. How many already awarded school projects, and what dollar amount of funding do you estimate may be unable to meet the encumbrance deadline and therefore return to the investor-owned utilities?

Good question, Chairman. And I'm a little hard of hearing, so even at this distance.

Great. And I have lectured everybody about being close to the mic, and then I failed to do that myself. Right? So how many already awarded school projects and the dollar amounts do you anticipate won't be able to meet the encumbrance deadline and therefore return to the investor-owned utilities?

Yeah. That's a hard question for staff to have insight into for the LEAs. So I would ask for the schools to be able to speak to that, but I can provide you some background.

Okay.

So we've provided $789,000,000 in grants. There's over 1,100 grants to over 6,000 schools. Grants were provided in tranches with a two-year term. The program's last extension ends 10/31/2026, and there are 109 grants totaling $113,000,000 that come to term on October 31. Roughly, we're seeing about a 15% rate of unused funds from the schools.

So schools that were provided grants and won't be moving forward, but I can't speak to the specifics of those schools.

If the statistics hold, 15 to 20 projects.

15%. Yep. Yeah.

And since there are 109

Of 109.

Yeah. Of 100. That's why I said 15 to 20. Yeah.

I would just say that the CEC has been doing a lot of efforts to streamline communication. We have office hours to strengthen the schools' ability to finish their projects on time.

Great. Okay. So on the DSGS and the ELRP demand program, our staff has identified some concerns about these programs, etcetera. So what was the total program budget and enrollment for ELRP in 2025? And what was it for DSGS?

I can take that question. Sure. Good morning, everyone. Leuwam Tesfai, Executive Director for the California Public Utilities Commission. So for ELRP in 2025, the budget was $219,000,000 across all three IOUs.

So Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric.

Could you give me that number again?

Yes. $219,000,000. That was the authorized budget. But, you know, I do want to be clear: the vast majority of that budget was completely unspent because we had no grid emergency events in 2025.

And so that represented about 237 megawatts of enrolled capacity, as well as 3,700,000 customers.

Okay. Thank you. Before I ask my other questions, I want to point out we have staff giving us the alternative to opine about option one, which is keep the funding with DSGS and the program at CEC, or move the funding per the recommendation of the administration. This is your opportunity to defend the administration side of that.

And so I just want to make sure you know that at least a significant percentage of Assembly Members are leaning toward option one, which is keep the program with DSGS and keep the DSGS funding stay with the CEC.

I say that in the spirit of cooperation and professional dialogue that we can have, but I didn't want this to sort of come at the end and have you go, I wish we would have known that. We would have said x, y, and z. This is your opportunity to say x, y, and z, because I would be remiss if I didn't let you know there's significant legislative interest in keeping it at the CEC.

So as I go on, feel free to work that rationale into your program. Do you envision increasing the ratepayer-funded portion of the ELRP program to increase enrollment, or will these one-time funds be the only program increase?

I can take that question. Okay. Great. So right now, we have an open proceeding on demand response, and so we have this opportunity to be able to get stakeholder engagement from everyone who's interested in these programs. Right now, ELRP is entirely funded by ratepayers through 2027, but the Commission issued a ruling on April 8, requesting feedback from stakeholders on the potential updates to the ELRP program, as well as specific questions related to the Demand Side Grid Support program.

So that we'll be able to have a robust record and make sure that we have these types of programs available to customers moving forward.

Okay. Thank you. Question three. ELRP ended residential enrollment at the end of 2025. Do you envision the successor program will continue to exclude residential customers?

So again, we're asking questions in the ruling, but I do want to reflect back on the learnings that we have had up to this point. The Commission decided not to continue the residential ELRP program because the data really showed that the program was highly cost-ineffective. And so the Commission right now is really focused on, as you know, affordability for customers and really trying to put forth funds for programs that are the most cost-effective.

But again, we have this ruling that opened on April 8 and is taking comments for about the next month or so and getting feedback from stakeholders on that issue.

What are the things that you think made it highly cost-ineffective?

Yeah. So I think to start, you know, if you have a program that isn't getting called because a lot of things have changed when it comes to the status of the grid, then ratepayers are potentially paying for something that isn't needed at the time. You know, I want to share data points that we've been able to bring on a host of new resources to the electricity grid just from 2020 to today: over 31,000 megawatts of new clean resources.

We have over 22,000 megawatts of contracts that are resources that are contracted and in development. So a lot of circumstances have changed since then.

I wanted to see if the Department of Finance had anything that they wanted to contribute as well.

No. We're not, we don't have any additional comments on that.

So I'm going to digress here for a moment. The situation has changed. We're less likely to be facing these emergency blackouts and brownouts that we were talking about in the summertime. But there is still a tremendous value in demand grid response and having a flexible system out there. So I think that's part of what's going on: that legislators think that's a good thing for us to have, that demand response.

And it seems to be fairly efficiently administered by the CEC and fairly well subscribed, and could be better subscribed if we had more funding and went that direction. Why would we not want to, let's say we're pretty confident we're not going to have the blackouts, etcetera. It's your opportunity. So why would we not want to keep that program that has been fairly successful, and seems to have capacity to expand?

Yeah. So a couple of things. So when we're talking about cost-effective programs, you know, we want to talk about load flexibility in general. And so I think a really important thing that the Commission has been pushing forward has been time-variant rates to be able to support load flexibility. We had a rulemaking on that.

We actually opened a new rulemaking last month. I think you had asked me a question about this, Assembly Member Rogers, during the data center oversight hearing. So we have now opened that rulemaking last month to be able to enhance load flexibility through rate design as a more cost-effective way to be able to make the grid more flexible. In addition to that, we do have an open rulemaking on demand response, as I mentioned.

ELRP is a small portion of that, but we have demand response programs that run across all customer sectors, across all of the utilities.

And these are programs that we have worked for over twenty years to make sure that they are cost-effective and able to perform and provide that reliability to the grid. And we've seen these programs perform in times of grid crisis. And so right now, as we think about resources that are cost-effective and that are able to provide those benefits. We haven't had a grid reliability event.

So I think there's a lot of resources that we're talking about right now in this conversation that have not performed during a grid reliability event because we haven't had them.

So I think as we think about being most cost-effective with ratepayer resources, we want to work with stakeholders, build that record, and really find programs that are able to be proven to be cost-effective and reliable both. I wanted to just make sure that others had space to share their thoughts.

David Evans, Department of Finance. The term success, it's variable of how we could define that, but

Sorry. Start again. Say that again.

On success, there's different definitions or, I guess, terms in which we could qualify the Demand Side Grid Support program. But the overall understanding and our intent is that the current budget climate cannot sustain additional appropriations, either General Fund or Greenhouse Gas Reduction Fund investments, into the Demand Side Grid Support program.

So the trailer bill proposal is to utilize the existing resources that we have, and then transition toward a more sustainable fund source.

Thank you. If we're not having events right now, then why would we want to fund the ELRP program?

So as I said, there's a ruling that's out right now that is getting stakeholder engagement. And so we'll see what the outcome is of all of those comments that we get from, you know, ratepayer advocates, from companies that are trying to provide these resources, just the whole gamut of stakeholders.

And so this is a question for both you and for the Department of Finance. Is there something you don't like about the current DSGS program and the CEC's administration of it? Is it a negative, or is it just the issue of, you know, you're trying to transition the program so that there's not General Fund dollars? Because one option out there gets us all out on the table.

One option out there is fund this for another couple of years, and the program hopefully would be at the point where it could actually be able to support itself.

Right? As they get better at it, they get the economies of scale of it, etcetera. Right?

From the administration's perspective, it's not a matter of which program is better, or if we dislike or have components about the Demand Side Grid Support program that we dislike. The PUC's open rulemaking is to encourage that type of feedback to understand the lessons learned, what are the benefits from the Demand Side Grid Support program that can be incorporated into the ELRP or another alternative program. The administration's intent was that we provided resources.

It was originally envisioned to be for five years, and it was supposed to be a one-time, limited-term program. And right now, in our current climate, we have fiscal constraints in which providing additional resources toward this program is not economically feasible at this moment.

And then, also, we want to provide ratepayers with the best benefit. They're supporting the program, and so we want to have a ratepayer-funded program that benefits the ratepayers.

So if I can be clear, if we're just transferring the funds from one program to another program, it's not really a drain on the General Fund at this point in time. Am I correct?

No. Well, the Demand Side Grid Support program was funded through General Fund, and it was also supplemented through Greenhouse Gas Reduction Fund. Right now, we're just moving the appropriation from DEBA to DSGS. The Governor's Budget doesn't propose a new investment, so we're not draining resources or redirecting or reallocating resources or appropriating resources from the General Fund, because we have a structural deficit, and we're not making a new appropriation from the Greenhouse Gas Reduction Fund. So that's the administration's proposal.

I believe we're trying to say transfers here instead of transferring it and having the program moving into CPUC; keeping it at CEC would not necessarily do that. But Assembly Member Cottie Petrie-Norris, please go ahead.

Thank you. So it does feel like there's, I think, three questions at hand, and it seems like some of the responses are conflating those. So I think the first question is, do we think that demand response makes sense for California and for California ratepayers as we are building out our grid and as we are poised to bring on just record levels of new demand. I think that the answer to that is indubitably yes.

Would be curious if you don't agree with that.

But I think, as a foundational point, the answer to that is yes. The second question is, which program should we build on? Is it the ELRP or is it DSGS? And then the third question is, how do we fund that? I guess you can start with that first question.

Do you think there's any dispute that some kind of a demand response program is an important part of our strategy as we move forward?

I can start. I'm sure everyone has an opinion. I would say, yes. Cost-effective demand response programs. We have dozens of demand response programs that are currently in place.

So I just want to make sure that people don't think that these are the only demand response programs. We have other demand response programs: base interruptible program, air conditioning cycling program, and other programs that are very sophisticated and have been in place for over twenty years. So I definitely think they are cost-effective as well. So cost-effective demand response, I'd certainly think, is part of the picture. Anyone else?

So then kind of moving, I guess, to the second question around DSGS and ELRP. And I'll say, I think many of us were very surprised by this budget proposal and by the proposal to like, a sun effectively sunset DSGS.

So as the staff report notes, the DSGS program has an enrolled capacity of, more than 1,100 megawatts with a program budget of roughly $109,000,000 allocated. ELRP currently has about a 190 megawatt enrollment, which has actually gone down over time. So given the stark difference in capacity, why does this proposal Sunset DSGS rather than Sunset at ELRP? And I don't don't answer about, like how it's funded because that's the third question.

Currently, on the existing law, like the program does it does Sunset on unless there's a new appropriation that's being made. Those customers right now, the CEC and PUC are working together so they can transition those customers in that capacity that is within the DSGS Program and helping that transition to the ELRP. That way, you said not to mention the funding mechanism but that's a huge

But we can say-

a component of it, you know.

Whether this program is housed under the CPUC or housed under the CEC, we'll have to have a conversation about how it's funded. So my question is where

If it's under the PUC, it will be a Ratepayer Funded Program. So it wouldn't be it will be through the investor owned utilities and their

But not in the right? In the short term, you're using the interest from Cal Shape.

You're not, I think.

No.

What we the proposal the second proposal is to use the to transition the interest from the Cal Shape programs for the 2027 or 2028 to provide rate payer relief. That's in order to mitigate the impacts of like new enrollment for the ELRP program. But for the 2026, what we're doing, we're planning to transition or transfer the dollars from the DEBA Program to the DSGS Program.

So keeping an existing statute, plussing up the DSGS program through the 2026, and then working together collaboratively to transition those enrolled in the DSGS Program to the ELRP Program for the subsequent summers moving forward.

Okay. But again, I think when we I think so much we get ourselves a little bit confused when we think of California taxpayers and California ratepayers as different people. And I think one of the things that I've been very concerned about is that in times of general fund constraint, we find it really easy to just add stuff onto utility bills. Like, these are all the same people paying for this.

So I think that's why the conversation about how we pay for it needs to be the third part of the conversation.

Because I think that the the broad assessment well, I won't touch I won't speak for my colleagues. My assessment is that DSGS has been successful and has been cost effective. I mean, is there somebody from CEC here?

Right here.

Sorry. Okay. There. Is that the thank you. I was okay.

So is it the assessment of the CEC that the DSGS program has been cost effective.

What, what I can share is our 2025 numbers, some of which are in the staff report. So you you referred to about 1,100 megawatts enrolled in 2025. Of that, our budget was $50,000,000 of funding spent. 45 of that went to performance based incentives, and $5,000,000 was administrative costs for both CEC and the administration. Of that, 1,100 megawatts enrolled in the program, it's not always gonna show up every day.

It is voluntary. Right. We did an evaluation of our performance and found incremental capacity of about 525 megawatts during market and test events last year. There were no emergency alerts last year. And in time of emergency, the price of energy goes up.

So because the programs were designed to somewhat complement each other and test different things, it's hard to do a one for one comparison.

Okay. And, yes, acknowledging that. Though I will note and maybe this is unfair, but I'm just looking. So you just mentioned you've got 500 sorry, $5,000,000 in administrative costs in 2025.

Correct. That was our actual expenditure.

And then for the ELRP Program, you had I think in 2025 alone, SoCal Edison and PG&E recorded over $16,000,000 in administrative costs. So let me make sure I'm at least on the administrative cost comparing apples to apples. So how much does it cost to administer DSGS versus ELRP?

So CEC's administrative costs were $5,000,000 in 2025.

Okay. For remind me how much-

Our administrative of 1,100 megawatts enrolled capacity.

Okay.

And 525 megawatts of incremental performance.

Okay. And then the CPUC, your administrative costs were, I guess, $16,000,000 at least for how much of enrolled capacity?

So I would like to make a correction earlier the megawatt number. I think you had one something. So the number was 237 megawatts.

Okay.

To Director Carrillo's point, the measurement of those megawatts is not the same between the two programs.

So as I said earlier, we have 3,500,000 customers that are enrolled. The CPUC actually derates the number of megawatts in the program to a lower number in order to provide the California Independent System Operator with a more realistic data point for the number of megawatts that are gonna show up in an event. So as we mentioned, there were no events last year where any program actually performed in the during a ten day heat wave like we saw in 2022. We didn't have that.

And so we think it's really important, at least for our program to derate the number of megawatts there.

So that 237 number, in years past, it was a higher number because it was if you're just going based on the highest number that could possibly perform. But we don't think that is a number that is appropriate to give to the California independent system operator so they know exactly what's going to happen. And as Director Carrillo said, it's a voluntary program. People are unlike the other demand response programs that I mentioned earlier today. If someone doesn't actually follow through, they're not getting penalized in any way.

But they're still getting, for example, in DSGS, a payment just for being in the program. ELRP customers don't get a payment just for being in the program. That was something that we did with how we constructed the program in order for it to be a bit more cost effective. So I think it's just there as Director Carrillo said, there's not an apples to apples comparison between the two programs.

That being said, the April 8 ruling that we issued does talk about both programs, and so we wanna be able to hear from stakeholders to try and possibly do a comparison of the programs, take the best of both of the programs, create a new program.

This is a big opportunity that we have, but I just wanna be clear that in the line of questioning, the two programs cannot be compared apples to apples.

Okay.

Other constructions.

I do wanna correct the record, Director, just the number that I gave you, the fives the excuse me, the 525 was demonstrated incremental demonstrated capacity based on test events. And with program experience, you can provide the D Rate. Now that DSGS has experience, we were providing that to the case.

So if I can, okay. So you think that 525 compares to the 237 that you just mentioned?

The 237 number is based on analysis from actual heat waves that have occurred and what performance occurred. So not from last year. The program's been in place since about 2021 for ELRP.

Yeah. I guess it does feel like to me and perhaps some of the information we have doesn't enable an apples to apples comparison. Feels like we should be able to get pretty close to an apples to apples comparison. And that we should do that before we make a decision about sunsetting a program that, like I said, barring any new information like, I think DSGS has been successful.

So if there's information you wanna share with us right now about why you think it hasn't been successful, I think that would be really helpful in order for us to make a decision. As the chair said, as outlined in the staff report, there's kind of the there's two options.

Number one, keep the funding at for DSGS at CEC. Or number two, move the funding, you know, to ELRP or create a successor program.

So that April 8 ruling that went out is that's the purpose of the ruling is to get those data points to try and do a comparison between the two programs, asking about both of the programs point blank. And that ruling was issued in our demand response, proceeding on April 8. So some comments have come in when we have reply comments that are coming in too. And so hopefully, we'll be able to get those two datasets and try and do this comparison.

Okay. Last question or perhaps comment, and then I'll you know, let my colleagues ask some questions. So I think the other thing that concerns me is while we've been, you know relatively fortunate, The fact that we haven't had a 2022 event, we haven't found ourselves in this this kind of an emergency situation. Doesn't mean that's not gonna happen this summer or next summer. And as you acknowledge, you haven't completed the public process.

The plan is like you're gonna design the New Load Reduction Program, or you're not you're not even gonna start designing the new program until 2027. Is that correct?

So we plan to have a proposed decision out in Q3 2026.

Okay.

But again, like Mister Evans said, you know this is really looking forward 2027. There is this current plan in place that has DSGS for the summer and all of the details that he shared. But we plan to have a decision out in Q3 2026 so that the market, the customers, all of the stakeholders have an idea of what's gonna happen in 2027.

Okay. I guess, so then how can we be assured that you're gonna have a plan developed in in place in time? I think particularly like in another proceeding, the CPUC's own staff proposed actually ending the ELRP pilots after this year.

Right. So that was in the past. This is the ruling that came out on April 8. The schedule that has been provided publicly was that we're putting out a decision in Q3 2026. This has you know, that schedule was put together because of this proposal, because of the work of our colleagues at the CEC.

So that customers and stakeholders will have an idea of what's gonna be happening in 2027. So we're building that record right now.

Okay. And I guess just my closing comment, I think that if the assessment is that DSGS has been a success, I would like to see us build on that success rather than sunset that program and effectively find ourselves starting over. I think that if nothing goes wrong, then we don't need these programs.

But doesn't seem like that's a good strategy for us to plan on.

I just wanna make sure everyone knows we have over a dozen demand response programs that are that exist and have funding for the next several years. So I just wanna make sure people don't think these two programs are the bedrock of our demand flexibility for the State of California.

Okay. Great. Thank you.

I think that's really a good point and thank you. But does take me, are all of those programs mandatory programs?

Yes. All of those are the existing programs are programs that have penalties for not showing up, are cost effective, and have a a multi year program budget.

And do those programs have incentives based on price?

Yes.

You're talking about trying to adjust the price to create the incentives for people to be in the program, etcetera.

Yes. We do.

Okay. So a question that I have is why not wait for us to make this funding decision until after you've completed your study?

I defer to Department of Finance.

Which is sort of what Assembly member

Currently, right now the funding for the like the remaining defunding, the encumbrance period it ends June 30 of this year. And so very in statute. We have to make a decision. And currently right now, the proposal is to extend that encumber and spirit by a year until 06/30/2027. Transfer the money, keep it in DSGS.

Okay.

So DSGS doesn't just pay for performance. Right? So, I mean they don't have it. So that should be a more expensive system because they're paying even when it's not the case. But it is actually it has five times the enrollment, you know in the program by comparison to this.

So it seems like it's more cost effective. But from my perception, it is more cost effective program. And if it is a more cost effective program, at five times the enrollment, it feels like the burden of proof this time.

Usually, by the way, we have these hearings so we can go through all the budget proposals from the Governor and we sort of have the burden of proof to go, "Hey, we don't think this seems like this one, the dollars and cents mean the burden of proof that we should end this program falls on the administration this time". And just from our perception now, of course, administration doesn't have to have to accept that in any way.

But that's what we're trying to give you this opportunity to as as forcefully and as clearly as you can explain why this program that from my perception is in, you know, one fifth the cost, in terms of what we're doing. So is that one fifth the cost would imply that DSGS is many times more cost effective. And we're talking about a short term transition of these funds, the interest money that you moving the money over from the DBA.

So we're not talking about the philosophical question of long term. What are we going to do?

We're talking about a couple year transition, '26 and '27, essentially. And so that's the issue. So I have one question for, I think CEC but what year did DSGS start enrolling customers?

2022.

Alright. And we add one option in 2022. The budget was approved and the program was launched in approximately five weeks.

Okay.

Uh-huh.

It was a- and then we went into the extreme heat event that the Western States experienced.

Okay.

Since then we've expanded the program to four different options. The one that is, most highlighted in the staff report is our market integrated behind the meter battery storage BPP. Which does receive a performance based capacity payment on a monthly basis, which is as we talk about how the how the programs are different, regardless of how many EAs or extreme heat days there would be, there's the aggregators get provided one payment a month.

Whether there is an event or based on the market prices, they're required to go in to to perform, ideally offsetting a heat event if it were to happen.

So you've been in existence, if I do the math right, you've been in existence for three and a half years?

Correct.

And you launched the program in five weeks?

Correct.

Right. And we are now at this, and you have four different versions of the program.

Four different participation pathways.

And one of those participant pass- participation pathways is performance based.

All of the participation pathways are performance based. Option three is the storage VPP, which is a capacity payment based on and you get paid based on your test event. So they get paid monthly based on their test events or participating in the market, if the market price was to get over a certain amount.

So

price is calibrated to extreme heat days.

Great. So I wasn't finished with my questions, but I'm gonna say sort of some of my concluding. So do we need DSGS even when we don't have these emergency crisis situations is a fundamental sort of philosophical question, you know, that's out there. It was asked by the Assembly member and the perception. I think I'm accurate in saying significant percentage of the legislators do think we need that.

And then the second half of the question is a program that was able to be launched in five weeks that's got this kind of enrollment after three and a half years. And we're talking about trying to keep it going for another two years and hopes that it gets to the point where it actually can sustain itself.

Why would we be ending that program and contrasting it with a much, a much more complex implementation process that takes more time, more studies, and has so far, you know lower results in in terms of this? And partially, there's an apples to oranges issue here because you're setting it up for when we have the crisis. But still, why in this one that strikes us as very efficient for a process that has not matched the same sort of sense of efficiency that's out there?

That's the question that still remains. And so I'll let you

And as a question in our April 8 ruling, we have heard this feedback that people say it's easier to enroll in DSGS than ELRP, and we're not really sure why. And the reason that we're not sure why is because ELRP, you know has a company that does the enrollments and DSGS uses the same company. And so we're not sure why that is, but that is a big question that we have.

And we wanna hear back from, in particular, the companies that are working with these customers to find out why that is. So I think that's a really important question.

But the proposals in front of us now.

Understood. But I agree with the question.

So if the response is, "Well, we're trying to find out why we should kill this program", that's a little bit different than sort of saying, "We currently have the answer as to why we would go after an efficient program" But we really appreciate this. And there's no hostility in this. This is just how professionals sort of try to sort out where we go here.

Go ahead.

David Evans, the largely the consideration for this transition, this proposal is based on the fiscal climate that we currently have. And so we don't have the additional like, general fund resources or the GGRF resources to continue making appropriations for the demand side risk support program.

And I've heard you say that, and that's more of a long term question, because if we're talking right now about the short term dollars and ending this program and moving the short term dollars away from them, I completely hear your answer. And that's you know, the Assembly member talked about, should we treat ratepayers differently than taxpayers, etcetera?

If philosophically, if that's why we're doing this for that philosophical reason, that's different than saying this program hasn't been the effective way for us to go about demand response, you know, flexible demand response. So I'm not hearing anything that says this is not the program for flexible demand response. I'm hearing we don't want to fund it any longer with rate I mean, with general fund.

Right? And if we're gonna fund it with rate payers, we need to move it away from that. That's a longer term decision because right now we're talking about transfers of funds that we already have, the interest, etcetera. Am I accurate in that? Am I is there anything I said in there that you think is not accurate?

Looks like somebody's ready to jump. Alright. Go ahead.

I would say that your point is well taken and just yeah. I don't

Great. Thank you. Thank you. Again, I appreciate just to be able to clarify. So I have just two, I have three other quick questions and so that we can move on and then still if with do you guys have things you wanna jump in on this?

Okay. So I'm gonna make sure we knock these three questions out so that staff has everything that they need. Can you estimate what percentage of peak load during the declared EEA events is from residential customers? Anybody have an answer to that?

Partially.

Okay.

On an annual basis, residential consumption or residential comprises about 35% of CEC statewide consumption forecast. We would anticipate that percent to increase at that time of day. However, we don't have that specific data during an EEA.

Okay, thanks. Anything else?

Looking at 95%, and we would expect it to increase.

Anything else along answer that question?

Just because, you know, we received the question and it was focused on the EEA event. There was no EEA event last year.

Yeah. Okay. Thank you. And when does the CPUC anticipate finalizing program rules for the Successor Program? I know you sort of answered that already.

Yeah. And what is the status of reaching the demand response goal required under the Public Resources Code of the statewide load shift of seven gigawatts by 2030?

The CEC's analysis, which is in its draft 2024 IEPR, which is the Integrated Energy Resource Plan reports that, in 2024, we were at 3.4 gigawatts of load flexibility, and this is a 10% increase from 2022 largely due to customer battery storage adoption. CEC projects that under a business as usual scenario, the state will have four gigawatts of low flexibility by 2030.

And

May I contribute to that response? So just wanna be able to share. So I think you're familiar in 2022, the CPUC changed the Net Energy Meeting Metering Program to a Net Billing Tariff Program. And so because of that, customers receive that higher incentive when they pair their solar with a battery. And so that has caused the large uptake of batteries across the state from customers to help contribute to the load flexibility goal.

And I think that was really a wise thing on the part of the CPUC. So appreciate that everybody working hand in hand is the best way for us to to address this. But we won't hit the seven gigawatt goal by 2030, or will we hit the seven gigawatt goal?

I would say we're we continue to work across all of the energy agencies to meet that that goal. CEC, CPC, and they're not here today, but the CAISO as well has been a big partner in looking at the different options to be able to get there. And so, for example, we opened the new demand flexibility. I keep pointing to you, but just because you are the one that asked the question last time.

But the demand flexibility rulemaking that opened last month is gonna be a big part about helping us get to that goal as well.

So CPUC still feels like we will meet this goal?

I also yes.

Great. Thank you very much. Assemblymember Rogers.

Yeah. Mostly, I just wanted to chime in because there seems to be a philosophical disconnect that my colleague kinda pointed out, which is the legislature has been moving in the direction of trying to remove things from what rate payers are paying for and making sure that we fund them through other more appropriate avenues like the general fund. This is the complete opposite. I think that's why you're getting so many questions from legislators is whether we discuss that this program is effective.

Really, that's the philosophical problem that many of us are having with this.

Second, and I know you can't compare directly between the two programs. The data seems to suggest to legislators that one program has been more effective at enrolling folks for a cheaper administrative burden. And so my question really because I was on a Board of Directors for CCA in 2022 when we went through that event. How do you quantify or philosophically, how do you account for avoided costs?

Because I remember that when you had energy procures in that moment who had excess energy or had other contracts that they could call upon, it was not as substantial to procure that energy as it was for others. And it was pretty exorbitant, which then to the point that my colleague made about the difference between rate payers and taxpayers, really kind of insignificant at that point when you have pushed that additional unintended cost onto the ratepayers and they have to pay for it anyway.

I don't- I don't know if I heard a question there, but if you could just repeat it.

Question is how are you accounting for the avoided costs that not being prepared or not having a system that is capable of addressing these events inevitably creates for rate payers?

Do you wanna start?

I don't really have.

Okay. I can start. And then I wanna give others an opportunity as well. I think, something that you really point out, you know, the State of Play in 2022 because largely driven by the pandemic, but other factors as well, we were really behind on resource procurement. There were a lot of slowdowns for construction also large challenges with supply chain.

Still some challenges with supply chain, but it has been significantly improved. And so just looking at 2020 to today, we have been able to deliver on the amount of new resources that we need on the grid. Right? We've brought on 31,000 megawatts of new clean resources, and then we also have over 20 over 22,000 that are under contract in in development. And so the state of play about being behind on resource development has really changed significantly.

In order to meet our long term goals, we know we need to be able to build between six and seven thousand megawatts of new resources a year. And we've been able to meet that target for the last two years, maybe even the last three years. They don't have it at the top of my head. And so we really have seen a lot of big changes to our system to improve reliability and a lot of actions taken by all three agencies to to make it happen.

Yeah. So that in that answer is interesting to me because it fundamentally, what I just heard is you think that there won't be an increase in cost to ratepayers to not have the DSGS program because our resource, is more available than it was. But then what I was hearing was that the main impetus for this program is that its cost to the general fund was the issue.

So I'm trying to figure out how to kind of square those answers between one that basically says the program's not necessary because we've made these changes and one that says program's good, but we can't afford to do it. Perhaps.

I think to your question on how we evaluate the cost of not having something, it is a good one, and California has faced those constraints. I agree with Director Tesfai, that we're in a better situation than we were in '22. I would note that the risk is really those coincident events when there's a western heat wave, a fire and other elements. And that's and I defer to Department of Finance on their evaluation of cost.

Yeah. And I think just in general, given that we have seen one in 2022, if we were to experience one without having a program that was in place like this, I think we'd be getting questions from our constituents about why did you sunset a program that was designed after 2022 to fix that problem or designed during 2022 to fix that very problem.

So I think, you know, I'm supportive of option one in the way that this has played out so far and happy to have future discussions.

Thank you. Assemblymember Gallagher.

Yeah. I think, you know, from what I can hear, it sounds to me like ELRP is just not cost effective. Correct?

Neither program is cost effective. I do wanna be clear about that. Using existing cost effectiveness metrics.

And you guys have already identified many programs that are not cost effective. Right? And you sent that in a report to us. Is that correct?

Yes. Yes.

And so can you just discontinue programs that aren't cost effective at the PUC, or do you need direction from us?

We have opened a number of new proceedings. And example, a new energy efficiency rule making, a new demand flexibility rule making, where we are, including the that exact question, you know driven by these reports that we've been able to prepare to stakeholders to be able to to get to that issue. And and it is the top priority for the commission to be focusing on making either making programs cost effective or discontinuing programs that are not cost effective.

Yeah. I think we need to get at that in earnest. Like, if we've known about programs that aren't cost effective for many years and we're not getting rid of them so that rate payers can see real savings, you know. How long is this rule making process gonna take?

Typically, around eighteen months, but I do wanna be clear. The commission has taken action on some very significant programs mentioned with, Chair Bennett, the Net Energy Metering Program shifting that to a program that is more cost effective. Steps have been taken. Some progress has been made, but there's certainly more work to do.

Yeah. Well, I take issue with that, actually. I disagree. Your NBT is just screwed over the consumers who had who had solar and they're getting less credits. And, I mean it was kind of the only way for people to win on rates is to get some credit against their bill.

And that just, like, you know totally gutted it is what it did. So, you know we need to like, get you know, to the bottom of reducing costs and for ratepayers. And so eighteen months, that's too long. I mean, is there a fast track process to like, actually get to cutting out programs that we know aren't cost effective?

So, for this one specifically this, the decision will come out in Q3 2026. Eighteen months is just in existing state code, the the timeline for getting a proceeding done.

And then I'd say for I mean, this is just a comment. DSGS, if we wanna continue to fund it, we have a funding source. It's called GGRF. And, we could fund it out of GGRF, and there's a great place to take the money from. It's called the High Speed Rail that we continue to spend a billion dollars on and hasn't laid a single mile of track.

So if we wanna fund that, there's a pretty easy way to do it. I wanna talk to you about another program that I'm very concerned about, the Somah Program.

You know, there's been some allegations that this program is not you know, money is not getting where it needs to be and there may even be fraudulent activity associated with this. $900,000,000 and this is again, for this is for multifamily low income tenants to have solar and energy storage. Right?

$900,000,000 was set aside. There's still 500,000,000 sitting in that account. The goal was 300,000,000 megawatts. We're not even anywhere close to that. My staff has continually reached out to you at the PUC, and I'm gonna just go through this initial contract, March 5, asking for the contract of the with the vendor for this program.

March 5, follow-up email on March 16, a follow-up email. April 2, a follow-up voice mail, April 10 a follow-up voice mail April 20. We've gotten no response, and so that is completely unacceptable. Like, how can I evaluate programs if you guys aren't giving us information? We just want a copy of the contract with the vendor. And so my first question is why are you guys ignoring that request?

Is I mean, is there something to hide here?

David Evans, Department of Finance.

It's not to you, Dave. It's not Department of Finance. It's for the PUC. We've asked the PUC many times.

I'm happy to say. I'm not aware of the request, but we'll follow-up right after this.

Okay. Yeah. I mean, please. I mean, we'd love a response. We haven't gotten even a response back.

And I mean, what can you tell me about SOMAH? I mean, 900,000,000 set aside. I'm not saying that money's been stolen or you know, there are allegations. And right now, we have 500,000,000 just seeing an account hasn't even been spent on people who probably need help.

I'm sorry, Mister Gallagher, but we have agendas items that we've asked them to come prepared for. You're on a completely separate program that they haven't come prepared for. And I think it's certainly fine. Talk to me. Let me know in advance that you have something so that we can let people know and we can have the right people here, the people who do this particular program.

We could have them here. We could have them answering your questions. But given that we have limited amount of time and lots of items and we always run all the way up until the other committee kicks us out of here. I'm just gonna ask you to to please cooperate.

Mister Chairman, I've moved through this very quickly with my questions very quickly. Now I'm almost done. I'm just asking for a question. We're here on a subject of solar programs. This is a solar program.

And she actually just talked about all these other programs, many others that deal with demand charge. So I'm asking about a program that is well within the subject matter and asking what is going on with this program and why isn't the money getting out. And please give us a copy of the contract with the vendor so we can evaluate what's going on with this program.

Okay. Yes. We'll follow-up.

Fair enough?

And they responded. I'm just

She hasn't responded. So could she please respond to

She said she'll get you the information.

Yes.

Do you know anything today about the SOMAH Program?

I know that projects have been built. I've personally been to ribbon cuttings for projects built for the SOMA Program, and we'll follow-up with, the requested information after the hearing.

Okay. Thank you, Mister Gallagher. Department of Finance, you looked like you wanted to say something. I want to give you the opportunity if you still do or somebody else. Go ahead.

Erin Carson, Department of Finance. Just wanted to follow-up on kind of the conversation around which program is more cost effective, less cost effective. Just wanna emphasize that, you know the originally with the funding that was appropriated for the DSGS Program, there were several 100 millions of dollars appropriated out of the general fund. Subsequent GGRF appropriations were made. There were several reversions that were made.

So this the original intent was that this program would be a temporary program for five years. So the administration is, continuing with that expectation. And then just also wanted to note that, you know while a lot of general fund has been put into the DSGS program, the program has not always been activated to respond. Therefore, you know not all of the ratepayers have directly benefited, you know in a if the program hasn't always contributed to ratepayer benefits.

So it's a little difficult to kind of compare like, apples to apples comparison.

So just wanted to make that point that while we have put in a lot of money to the DSGS Program, there's other funds for the ELRP program. Because they're not always activated, the ratepayers aren't always gonna see those benefits. So it's the same type of situation for the ELRP. Last summer, we didn't have any extreme events to respond to. Therefore, you know, we're still putting money into the program, but can't always predict when the ratepayers will see that benefit because we can't predict the

Appreciate that. Just so I can be clear. So when there's no, events either, then the ratepayers aren't benefiting from those programs also. Is that correct?

When there is no event to respond to

Right.

There's no benefit necessarily to provide it.

Out there with the program.

I know Mister chair, I know we're trying to move on. Can I ask one just quick follow-up question to that or just put a put in the thing?

Because I have a follow-up question too, but I'll defer to your follow-up question. Right?

So just I think that and maybe this warrants a longer offline conversation. I think that the it sounds like the way you're doing the math around this doesn't does not make sense to me. Because if, I think you just said that unless there's kind of an emergency event that ratepayers don't benefit. But the concept of these demand response resources is that so you usually, the Grid is almost never utilized at a 100%. Now, the utilization is what?

It's like 60, you know an average of like 60%. If we don't have these demand response resources, we're having to invest in enormous amounts of infrastructure for new generation, new transmission, those costs are borne by ratepayers. So the question is whether you are building out the grid to an enormous level or if you're utilizing these resources to get more out of the existing grid. So as we are making assessments about cost effectiveness, we need to include that, calculation.

So anyway, maybe that's I'm gonna just put a pin in that, and I would love to have a follow-up conversation with Department of Finance on how we're evaluating ratepayer savings on these resources.

That's the exact follow-up question I had too because it is that

The Chair and I will have a team meeting with the Department of Finance.

Because yeah. That is the fundamental question. The question is, do we need the DSGS program, like I said, even when we don't have events? And I think philosophically, I think you're hearing us feeling like, yes, because it does mean there are there's the potential for avoided cost in the future, which is hard for us to put a dollars and cents right now cost benefit analysis with the program. A quick question.

Well, quick point. You you mentioned that it was designed to be a five year program, and they've had three and a half years of the program. So I guess that's what you're hearing us say. Let's get it to the five year mark, and let's use these transition funds to be able to help us get it to the five year mark is what we're saying.

So in terms of response to that. But CEC, would you identify and agree that the program's not cost effective?

I think the definition of cost effectiveness by the PUC terms is a formula and a construct developed under that PUC paradigm. DSGS was designed to be able to respond in an emergency for a coincident event in which, many things are not cost effective in those moments. That's the best I can do on the fly, sir.

Sure. I understand.

Is it okay if I just contribute? I just wanna make it clear what demand

I want to emphasize it is definitely okay. Alright?

Thank you, Chair.

Because I wanna say that because I want everybody to know we're much more interested in the back and forth than we are in the formality of answering a particular question. So just like she said, hey. I wanna go say yep. We want you to do that, and we want to encourage everybody. We want LAO to say, hey I have something to add here.

That's how we want, we want these hearings always to be like that. That's why I tolerate somebody even saying I wanna interrupt when they're taking the same question I have. Right? But, anyway, it's yeah.

Absolutely. So feel comfortable and feel comfortable for the rest of this hearing.

Thank you. So you know, with the demand response programs, there are different flavors of demand response programs. And so what Director Carillo and I are talking about DSGS and ELRP, these are for emergency grid events. And this kind of goes to the point LAO was making as well. There are a large suite of demand response programs that engage with the market on a regular basis, not just in an emergency.

To your point, Assembly member, Petrie Norris, they are preventing us from getting to that emergency. So they are constantly engaged in the market. They're part of a resource adequacy program, for example. And so, to the point that DOF was making, there are demand response programs that provide ratepayer benefit throughout the year, not just in an emergency event. They prevent us from getting to the emergency event.

And so a program a Demand Response program like that is going to be performing better on a cost effectiveness evaluation because it's being used in the market on a regular basis. It's not it prevents us from getting to the emergency. It's not used just in the emergency. And so I talked about a few of those, like the eight the Air Conditioning Cycling Program. There's Agricultural Pumping Programs.

There's a whole suite of them, but they regularly provide rate payer benefit and prevent us from to try and prevent us from getting to an emergency.

Great. Thank you. We don't ever want one of the panelists that are up here to walk away going, I wish I would have been able to say "x, that it would have helped the discussion". So definitely, we appreciate what you just said and that is a good point for you to make. I do have this question.

EPIC is a rate payer funded program where you collect rate payer money, and then you give it to the CEC to implement program. Correct?

So CEC is one of the main program administrators, but also San Diego Gas and Electric, PG&E, and Southern California Edison.

Okay. But ratepayer money does go to CEC, you know through three. So so is there any reason why we couldn't use ratepayer funds to fund the CEC administering the DSGS program?

I mean, CEC has a whole research and development staff and team working on ongoing EPIC projects, and I wouldn't want those people to lose their jobs or they're already that money is accounted for. I mean, I know Deanna not the Director of that program, but there's a whole team at the CEC working on EPIC on the EOIC Program. And I wouldn't feel comfortable saying that the money should be taken from that team and given to another.

Oh, no. No. I don't want it taken from EPIC. I'm just saying that your the concepts that well, if it's ratepayer funded, then it needs to be not the CEC DSGS program.

If it's ratepayer, this is more a question for Department of Finance, I suppose. But we already we already do use ratepayer money and fund some other things the CEC does. Why couldn't we take ratepayer money and fund this?

I would say that the constraint would be more on the the base the ratepayer base. And so the EPIC Program is funded by the IOUs, and then it benefits like the IOUs like the benefits of the EPIC Program have to be concentrated in IOU territories. The Managed High Grids Support Program, the SGS program, because it's funded with resources that are collected statewide, the program, benefits the entirety of the state.

And so EORP, it's very similar construct of the EPIC program.

Those benefits have to be concentrated within the IOU territories. And so, CPU CC. Sorry. CC, there will be a conflict of taking ratepayer funded resources from the IOUs and providing that benefit to the publicly owned utilities and those not ratepayer base. And so there's that dynamic.

Okay. Appreciate appreciate that answer. As the assembly member said, I'm not sure that we need to slice and dice a lot between rate payers and taxpayers or which rate payers in exactly which area, but I very much appreciate the answer. And with that, anybody else have anything else? Assemblymember Gallagher.

Maybe just as a final quick comment. You know, one, talking about this without talking about how we kept the lights on during that heat event. We brought we kept the lights on because we brought in modular natural gas plants and paid for them and made sure we had baseline power. That's how we kept the lights on. So, like, you know and we're talking about getting rid of natural gas plants.

We're talking about getting rid of our last nuclear plant. And man, we're gonna have to have a whole lot of backup storage if we're gonna go without those things. So that's one thing to be thinking about as well as our base load power.

And then I think this is a as a final, I've you know, I do think we need to be looking at all of these programs and we should be thinking about the ratepayer and using more ratepayer dollars for something else or pushing more program cost onto ratepayers is the opposite direction that we need to be moving. We need to be moving in the direction of removing those costs so that we can lower rates.

It's the only way to do that. So, I mean that's where my focus you know, I think we need to be on this.

Thank you very much. And with that, we really appreciate this. I'm gonna end with one thing, which is we expect, I expect, that good government public servants are proud of the work they do. So we expect them to come and defend the work they do. And when they both work for the same administration, but they're in separate departments, there will be some tension there that is perfectly healthy.

That happens in the Federal Government. That happens between the Army and the Navy. I mean, that's just that is normal. So it's normal for people to be proud of the programs that they're in. It's normal for the CPUC to be proud of what you're doing, and it's normal for the CEC to be proud of what they're doing.

And the issue is for us to hear all of that and for us to try to figure out how we partner with the administration to reach both the goals of the legislature and the goals of the administration. So we sincerely thank you for a sometimes, not as comfortable as other times kind of conversations that we've had here today. And we'll move on to item two. Thank you very much.

Appreciate your time.

And item two is Energy and Modernization Affordability. SB 254 Transmission Accelerator Program, Prop 4 Trailer Bill Language and a recognition that Assembly member Petrie-Norris, was the lead on this last year as we were doing things, in terms of transmission accelerator. So after we do the original comments, we're gonna go right to you, Assembly member.

Okay.

Alrighty. Great. And whoever would like to go first, please identify yourself.

Good morning, Chair Bennett.

Oh, you gotta pull that microphone a lot closer.

Closer, okay. How's that?

Even more.Come on. You gotta be right on top of it for them to hear you in the back.

There you go. Much better.

Good morning, Chair Bennett and Committee members. My name is Rohimah Moly, Deputy Director at the Energy Unit at the Governor's Office of Business and Economic Development, aka GO Biz. The BCP before you is related to legislation that was passed last year, SB 254.

Among other things, 254 charges the energy unit with standing up a first of its kind transmission infrastructure accelerator, comprised of the Public Utilities Commission, the Energy Commission, the CAISO and IBank to administer and support a public financing program for qualified transmission projects. SB 254 also requires the accelerator to develop a public private financing strategy to be delivered to the legislature.

The IBANK team works with GoBiz in tandem and will collaborate with the energy unit and other accelerated parties to implement the provisions of this measure. Specifically, IBank will evaluate projects selected by the accelerator and improve them based on financial viability. I think we'll continue to monitor and service the loans for the life of the debt even after their authority to use the funds sunsets in 2031. The BCP requests staffing and resources, about $26,000,000 in total for program administration over five years.

This includes 10 limited term positions to support the accelerator, Further implement the requirements of SB 254 and manage incoming program funds from Proposition 4 and AB 1207.

Over a five year period. With me today is Andy Nakahara, CEO of the IBank. And thank you for the opportunity to present this proposal, and we'll take any questions you have.

Yep. Thank you very much. Any other anybody else ready to testify? LAO?

Just a couple quick comments. So we haven't raised any specific concerns with the proposal. We would note however, this is a good example of when we talk to the committee about that Prop 4 framework and how to think about it. This is a new program. We know the legislature has provided some guidance.

This is kind of modifying that somewhat. So making sure, one, that the modifications are consistent with your intent and your goals for the program. And then also, because this is the first time you the legislature's appropriating this program for this money for this brand new program, we think this is a really important opportunity for the legislature to make sure that whatever whatever guidance you want is really memorialized here because this is the full allocation of the funding, and it's a big allocation.

And so it'll be important to get it right, whether that means this, whether you're okay with what's proposed or whether you wanna tweak that somewhat. So, just wanted to point that out.

Thank you very much. Anybody else? Assemblymember?

Well, good morning and thank you for being here, and thank you both for your work on this. I think it's really exciting. Recognize it's kind of the first the first and very important step in in a long journey to save Californians money as we're making these historic investments in transmission infrastructure. And I'll just say that, I think our assessment is that the trailer bill's moving in the right direction. I know that we've had some conversation about a couple of potential concerns.

I think the primary one being ensuring that the FERC revenue requirement must reflect on actual capital structure. I think that's on your radar.

Could you say that again, please?

So there was a requirement that there was some language in an understanding in our conversations that the FERC revenue requirement must reflect on the actual capital structure. And I think that was struck through in the trailer bill. What we've been told is that your understanding is that requirement is reflected somewhere else in the bill. So we're just gonna continue to have that conversation to make sure that we lock that point down. But just your intent is consistent with that.

Correct.

Okay.

Perfect. Great. Thank you. Thank you. Yeah.

Other question.

It's great.

Thank you, Mister chair.

Could you and then I'll catch you, Mister Rogers, in just a second. And that is could you summarize for us where the state's liability will stand? Who will own the transmission line financed this way? What you know, we're trying to do this to avoid the cost of ratepayers paying 10% forever on a capital improvement. We'll try to make sure for the public we have that sort of out in the open.

What's the state's liability? Who would actually control this line? How does this work in with CPUC sort of rate calculations, etcetera?

So, the way that is structured, eligible projects are limited to those projects identified in the competitive solicitation process, identified at CAISO. So, every year they do a TPP Transportation, Excuse me. Transmission Planning Process. And the recent and they will identify the bigger projects that are going to be competitively bid. And so those projects, there are private developers who bid on those projects.

And the accelerator would and could amongst those projects identified in the competitive solicitation finance or provide state financing to that project. And so that is where the state's liability is. And

So if the state provides the financing?

A part of that financing.

Part of that financing.

These projects are can in the billions of dollars. And Prop 4, I think the total allocation is 325, so it would be a small portion of that.

So what is the ratepayer savings that would then come from that?

I think it's really hard to identify the rate savings, but the idea and structure of this is that with some state financing it would lower the overall cost of the project. And that in turn, when they go to request for the rate of return at FERC and at CAISO, that they wouldn't be able to include the state portion and the tax credits that's been that they've been given for this project be included in that rate of return and therefore lowering cost.

So hypothetically, a $10,000,000,000 project that the state somehow was able to help leverage billion dollars of that. Then when they go to ask for their rate increases, they could only do that on the $9,000,000,000 that's left. Is that how you understand it also? Great. Alright.

And you know, some of the estimates that an analysis that was done is we were moving this through the legislature. Again, there's several permutations of how you might structure these arrangements. So the savings range everywhere from 10% of a project lifetime cost up to 40% of the lifetime cost to repairs that could be a savings as a result of this.

Can you make sure you structure it so we get all the 40% ones? Right? Okay. Great. Thank you.

Assemblymember Rogers.

Yeah. Absolutely. Thank you, Mister chair. So last week in the Utilities and Energy Committee, we had a comically large graphic visual of the transmission adequacy across the state showing that there's not a whole lot. But especially North Of The Delta, there's very little capacity.

And I always take every opportunity I can to talk about how, in areas that have already been left behind, they continue to be left behind in the program design or in the construct for programs like this. So my question really is, how are you going to address or how are you going to take into account historic inequities in that level of investment in some of the projects that are pushed forward?

I can try to answer that. So, the way that the transmission accelerator would work is that we're limited to just looking at the projects that have been identified for competitive solicitation in the TPP. And so, how they do that study and identify projects in underserved areas and you know, where it needs more transmission. We're the the accelerator, we're not within that process.

However, the other part to this is that if there are, for example, three projects identified in the competitive solicitation, you know looking at the policy, you know, we would have to evaluate against policy objectives for to to receive financing.

And those objectives, some of it are laid out in statute. But there is another there is flexibility for the accelerator entities to determine other state policy objectives that it meets. For example, you know, if it is an area that is congested or doesn't have enough transmission. Like, if that transmission line meets those objective then that can qualify or raise up to the top of the one that may be eligible to receive financing.

Gotcha.

Andrew March, Department of Finance. I just echo everything that my colleague from GoBIZ has noted is that, CAISO has its own process for determining what projects are identified in the TPP, and these are very large projects, as my colleague noted, are several billion dollars, that span for tens to hundreds of miles across the state, depending on the various needs and various, forward looking projections for generation across the state.

Yeah. I appreciate that. And I just wanna bring it back to kind of the linkage between some of the other states' priorities. Like for instance, the staff comments call out offshore wind. It's obviously a huge economic opportunity and environmental opportunity up on the North Coast, but it needs adequate transmission to be able to move those projects forward.

And so it's really key component. And I know that there is a push from myself and a number of other folks to make sure that the additional $250,000,000 ish is allocated from Prop 404, the offshore wind port development. And that goes hand in hand with this discussion about transmission capacity.

Any other questions? Thank you very much. We're gonna go on to oh, we do. Assemblymember Connolly..

Can I I'll do a follow-up on that? Because I was gonna ask a a similar question. What is the status of the $247,000,000 toward offshore wind or development through Proposition 4.

So I believe that funding is going to through CEC.

So sorry to jump in. We allocate half of it last year.

Correct. But I just wanna point out that currently Go Business is at the table, so they're not gonna be able to answer that question. But we can get back to you sort of on the status of the funding. Not all of the funding has been spent, to date, which is why we didn't propose additional funding in the budget.

So we're still working through that funding that was appropriated last fall.

I think the the push and to take back is there is an opportunity to do bigger grants and do bigger portions of the project if that additional $250,000,000, which is very limited in the Prop 4 language for this for these types of projects. If that is allocated in this year's budget, again should be it's general fund neutral. It's allocated in Prop 4, but would open up those opportunities. So I think that's the push.

Anything else? Assemblymember Connolly? Great. Alright. Thank you very much.

We're gonna go on to issue three. Right. Those panelists would please come up. Go ahead and introduce yourself.

Great. My name is Alicia Gutierrez. I'm the director of the Energy Assessments Division at the California Energy Commission.

Okay.

And I'm joined with by Varsha Sarveshwar. That is she is the Deputy Director of Policy in the division of Petroleum Market Oversight. I am here today requesting support for RBCP. And good morning. I did not greet all of the committee members.

Good morning to you. Since the passage of the special legislation in in 2023, the state's petroleum sector has experienced several major challenges and changes, including closure of two of the state's refineries and more recently, the Warren Brown that is disrupting global markets. These dynamics have resulted in a shift in the focus, scope, and complexity of CEC's work. In 2023, staff resources were focused heavily on data collection efforts and developing analytical frameworks to provide more transparency and to refinery profits.

When ABX2-1 was passed, we were focused on measures to address price volatility.

With closures of the refineries, CEC was asked by governor Newsom to develop holistic strategic approach to the transition, and the strategic approach necessitated increased coordination with industry to ensure supply stabilization measures will have the desired impact on in state supplies. The work being done by CEC and in coordination with DPMO, CARB, and other agencies to monitor conditions and remain in constant coordination with refiners resulted in stable prices in 2024 and 2025.

The elevated delta between The California and The US has been smaller in the past two years than what we saw in earlier years 2022 and 2023. We are continuing our coordination with partner agencies to ensure prompt and coordinated action in California's if California supply conditions get too tight. And this BCP is requesting $1,700,000 for seven positions that will be responsible for implementing the requirements of ABX2-1.

Now I'll turn to Varsha for her, her opening comments.

Thank you, Director Gutierrez. Good morning, Chair Bennett and members. My name is Varsha Sarveshwar, and I am the deputy director for policy with the division of Petroleum Market Oversight. The BCP before you today from DPMO is 473,000 from the energy resources program account to convert one limited term position that we have at DPMO into a permanent position, and that's a research data specialist position. As a bit of background, DPMO is an independent division of the Energy Commission established by Senate Bill X12 in 2023.

SBX one two tasks DPMO with protecting California consumers through market oversight, investigations, economic analysis, and policy recommendations. Thanks to the governor and with the support of the legislature, DPMO was able to quickly staff up in 2023 and 2024. But by 2025, after the passage of Assembly bill X21, we needed additional in house capacity to process the very large volumes of data that we analyze for a number of our market oversight functions.

And so to meet this critical need, we hired a skilled senior data scientist in a limited term role. And this single position provides some really critical support for both our economics and our investigative teams.

Making this position permanent is essential for DPMO to fulfill our independent responsibilities under the statute, protect the integrity of the market, and provide you as policymakers with the best possible information as we navigate the transportation fuel transition. Thank you, and I look forward to answering any questions.

Thank you. Department of Finance?

Nothing to add.

LAO, we have seven new positions being asked for in the petroleum market supply research. Have you had an opportunity to analyze whether you think they are necessary relative to the fact that our fourth question we talk about to CEC has paused the price gouging penalties for five years, didn't complete its regulations about price gouging. So couldn't those positions be used for the new positions that we have here?

So as part of our review of the proposal, we did ask a variety of questions, and we did meet with the department. I think in the course of that, work, our view was that they provided adequate justification that there was sufficient workload associated with the bill and their and their larger efforts in this space, so we're not raising specific concerns. But, that is certainly, I think, a great question.

And I think when, additional positions are are being added, particularly if other work is not is not occurring, that's, I think, a top of a question that's always top of mind. So should the legislature feel differently?

Certainly, you know, it could take different action, but we didn't identify some any specific concerns that merited raising with the legislature.

Well, in our in our hearing in our first hearing, we sort of had a love fest with the CDC in terms of their efficiency and productivity with that with that program. But it is a significant question for me, and that is the fourth question here, which is, you've you've and you've paused the price gouging penalties, for five years. You didn't complete the regulations. You had people doing that. Can those people can those positions be applied to this?

And if they can't, I'd love to hear why.

So we did have a couple of individuals that were hired on to do the analysis to support the max margin and penalty and make that recommendation to pause. Those individuals are continuing to work on the analysis we did in our business meeting where we considered and approved the pause on the max margin and penalty.

We did commit to providing an analysis in January 2027 time frame that would, include the same considerations, framework, and and make another revised and updated analysis and recommendation based on the current conditions on the max margin and penalty and whether we should extend that pause for additional years. So they are continuing to do the analysis of all the supply stabilization measures that are before us and are being considered, like minimum inventory and resupply. There is

the same analytical framework and rigor that is required. We have to look at, impacts to supply, impacts to the economy, other, costs and benefits of each measure. So we're trying to do this systematically, implement the same framework, throughout all of the supply stabilization measure measures, and that is what that is what our resources are doing now. These resources will help us to bolster all of those analyses and make sure that we're implementing those supply stabilization measures very well for the industry and good for California.

Let me let's say two things. One, I think that given the volatility of gas prices, given the price gouging that we used to believe we saw and that the CEC sort of discovered, the legislature very much supports the idea of funding the CEC to do a good job of understanding inventories and all of all of these all of these issues.

So we really we support that, and we actually need it because the public is so sensitive on this issue of of of gas prices and trying to identify what of the what what of it is, you know, international changes to the price. And why is it when the price of oil goes up by 10%, price of gasoline goes up by 40%? The people have questions and CEC helps us answer.

So very much want us to get this program right. But at the same time, we wanna be as efficient as possible as we do things. Are you saying that even though this program the the the price gouging penalties were paused for five years and even though you didn't complete those regulations, those people are still working full time doing that stuff and that there's been no pause in their work or their their they they why would it take so long? Is it because of changing conditions?

I just need to hear that justification of why these people can't. Why they have to keep working on this if if there's been that pause.

I hear you. So they I would not say that the work is one for one, but they have shifted. So there is one individual that is full time continuing work on the analysis. The other individual is somewhat splitting time between the other supply evaluation and assessment of the other supply stabilization measures. Right now, our focus is on the resupply regs and getting those in place this year.

So that individual has been focused on getting the the analysis to support that. And we will be doing a workshop in the next month or two on resupply regulations.

David Evans, Department of Finance. I would just like to add, onto my my colleagues' responses that, the SCC was resourced for the work of, SBX 1-2, which had several different components. One was that maximum, gross gasoline refining margin, which has been paused, but, also, they still have to collect daily, monthly, weekly, and annual reports from from major, crude or producers, petroleum transporters, importers, exporters, and businesses.

Department of finance.

That work is still ongoing, and then also, they're responsible for having the, developing the triannual transportation fuels assessment, and the transportation fuels transition plan. So that that work for SBX 1-2 is still ongoing.

The CEC was resourced for that work, but they were not resourced for ABX 2-1, which established a minimum supply regulation. So those regulations are so ongoing, and that's why they're requesting additional positions in order to do that additional workload that was placed on the department.

And, chair, if I may briefly. So the division as an independent division of the CEC, we don't the regulation is with the energy commission. It's not with DPMO. So with the initial 10 positions that we received in 2023, those were not sort of bespoke for the gross gasoline refining margin and penalty. Those were for all of DPMO's responsibilities under SPX 12.

So we don't have sort of specific Max margin penalty resources that we would be reallocating here.

Thank you. That's all very helpful. And I just wanted to point out that we have a note from somebody sitting in the back that says David was the best speaker into the microphone. He held that thing right there real close to his mouth. Just show us again that technique for you.

Will you see that? Look at that. That that is what everybody could benefit from. Assembly member Gallagher.

Well, I I don't wanna put him in a bad position. What he did used to work for me. So Ah. That's yeah. It's it's good to see you.

You've trained him you trained him well.

Yeah. I know how to use a microphone. Yeah.

We've noticed.

Yeah. So I have a simple question, which is why did we decide to fund this using the IRPA program, which is supported by rate payers, electrical rate payers why are electrical rate payers paying for, like, a gasoline oversight program?

Absolutely. I can respond to that. The CCE's main operating fund is the Energy Resources Programs account, IRPA. And it funds a variety of different, like, energy resources programs and activities that has overlapping benefits for the state population, but not necessarily directly benefits to rate payers. The CCS, other special funds, but those funds don't have sufficient revenue in order to take on this work.

And then or there's specific allowable uses that will preclude, them from being able to utilize those those other fund sources.

Okay. And so, I mean, essentially, we're trying to cover a hole. Right? Will there be impact to the rate payers? I mean, it's gonna be additional cost to rate payers by doing doing this?

Not necessarily that there would be additional cost to rate payers. Currently, right now, there's, like, a standard charge. And right now, the CEC is just operating within their existing budget, their baseline budget in order to do this. And so we would be adding on to that, but if there wouldn't be, like, a increase in fees or charges to the ratepayers in order to cover it because it's it's currently capped right now.

And then to, you know, the folks from CEC, so during this time that you guys have had this in place, did you guys find evidence of price gouging that's been done by

I'm going to defer to my colleague.

Biners or

Yeah. Thank you, Assemblymember Gallagher. So, we try to be pretty circumspect when we talk about price gouging because there's a there's a criminal price gouging statute in California under a penal code section 396. You know, there's sort of implications there for increases in prices above 10% above cost during periods of emergency.

Yeah. I just mean under this system that we created with this special legislation.

Right. So when we're talking about sort of general opportunistic pricing, we're often talking about situations in which there are increases in price above increases in input costs. And in the period that the legislature identified in 2022, you know, DPMO has said previously on a number of occasions that the evidence from that period is consistent. So you do see an increase in prices and an increase in margins that's not matched by an increase in crude oil costs or other input costs that market participants face.

Yeah. But, again, did you find any evidence that that was a result of some bad faith on the part of the refiners or the oil and gas companies?

So in terms of details of particular investigations, I think speaking sort of more granular than just the data, I think I'm not able to sort of speak to that at this time. We try to be really, really careful in terms of disclosing details or particular oversight or investigative matters.

The answer is no. Right?

I can't comment on any of our investigations.

Okay. That's that's great. So from everything I've seen from since we started this and from what's been made available to the public, I guess what's being not disclosed, which is a problem. But from everything that's been publicly disclosed, we found zero evidence that this program has helped us stop, well, that we even found gouging in the first place or that it stopped, you know, price gouging. So that's one question.

Like, why do we continue to fund a program that doesn't really seem to be getting results?

Am I able to, can I respond to that?

Well, here's another question for you. So on the supply side, I mean, so we have we stabilized supply at the Phillips 66 refinery in in Southern California?

So I'm going to ask my colleague.

Well, the answer is no because they closed down. Right? So there's no stabilized supply there. Right?

Are are you wanting to get into details about

No. I'm saying now right now today, is there a stable storage of refined gas at Phillips 66 refinery in Southern California?

She wants her colleague to come up and try to answer the question and yet you I'm did did It's closed.

So I hope the answer is no. It's not that hard.

That that that's fine. But you've you've asked the question now twice. So is it rhetorical? And then if that's the case say so.

I mean, yeah. I'm being told I can't we can't discuss answers. Yes. An answer would be great.

Yes. The Phillips 66 refinery is closed. That's it.

So there's no stable storage supply there?

I think Phillips 66 is still involved in some marine terminal activity.

Could you speak into the microphone? They just hold it.

Yes, I'm so sorry. Phillips sixty six is closed, but they're involved in some marine terminal activities. We have to get back to you on that with some details.

How about have we is there a stable storage supply at Valero's refinery in the East Bay?

Benicia? Benicia, it's they have given notice, and they have they ramped down their operations. They have closed down as of April.

So no. Right?

So this is part of the challenge, I think, and part of the changing dynamics that I mentioned in my opening comments. We are dealing with a a lot of fluctuation in the supply, and, I think that warrants more investigation and careful thought about how we implement the supply stabilization measures that I mentioned. Resupply is the focus right now, and then once we see how resupply requirements with the results of that, then we will turn to minimum inventory. If I may just clarify

Maybe just to, like, simplify this. Like, since you guys started, you know, your program over there, we've now two refineries in the state have shut down. So 18% of our refined gas is gone. So is it safe to say that since you guys started, our our gas supply has actually decreased?

So the in state refining capacity has decreased. We are importing more fuel supplies.

Oh, from where?

Multiple locations.

Sure. Go ahead. Name them.

Okay.

Yeah. Importing from the from from North Korea sorry. From South Korea, they're importing from various parts of Bahamas. They're importing from Middle East. So they're importing some now.

Oh, from the Middle East. Where are we where are we importing from The Middle East?

It comes from Middle East, from South Arabia, from from don't have the specifics here right now from multiple countries.

Assembly member, apologies. I've looked at the data probably a bit recently. So as a rule of thumb, about 50% of imports of gasoline into California come from domestic sources, so they primarily come from the Pacific Northwest or from The US Gulf Coast, sometimes via The Bahamas for Jones Act purposes. The rest 50% are typically foreign imports largely coming from Asia, not exclusively Asia, and that would be India, Singapore, and South Korea primarily.

On the refined gas side.

That's a good answer.

Correct. On the refined gas side.

Crude oil. There's a different story. Right?

On the refined gas side. Right?

Crude oil is a different story. So California has been a net importer of crude oil since the late 1980s. About a good chunk, I think usually about 20 to 30% of crude oil in California comes from California. Another 20 to 30% typically comes from Alaska imported from Alaska, and the rest is imported from foreign sources. It's pretty diverse of a mix. Typically, The Middle East, Latin America are their largest representations there.

And now even more so. Right? Because we have less domestic production and refining capacity. Correct?

Yes. But there are sort of two trends that cut against each other here. So as you have

Yes was the answer I was looking for.

Well, I'm trying to just

I'm sorry I'm sorry, but that's not the tone we're gonna have here. This isn't an inquisition. This isn't defense lawyers and prosecutors saying that's sufficient. Right? We are going to have a healthy conversation.

And whether you want the answer or not, we're gonna make sure she gives she gives the the complete answer to the question in a in a appropriate amount of time.

You're right. I like to give a

It should not be an interruption of no. Don't give me any more of your answer. Yes.

We we also have to get somewhere in this hearing, mister chairman. And I agree with you. I like allowing people to answer a question and give context.

Yeah. And I'm still

What I don't like is equivocation. And equivocation should not be the exception.

The equivocation is in the eye of the beholder. But I'll tell you one thing.

It's actually pretty obvious. And I think it's obvious to the people in this audience and everybody watching this hearing.

And I'll tell you what what won't be appropriate here is that these people are coming here voluntarily. They do not have to show up at these hearings.

They they show that that's correct. They have they do not have to show up at these hearings.

Are they not answerable to us?

Hey. Would you let me finish? I did not interrupt you while you're talking.

Would you let me finish?

I just think you're

Not true.

If would you let me finish? These people are professionals coming here, need to be treated as professionals, not like the enemy. And so our questions can be strong in terms of what they're doing, but the tone should not be in any way an harassment of these people as they're doing it. And so when somebody is trying to give an answer and we cut them off by saying no would be sufficient or this is it doesn't meet your, your definition in terms of an appropriate answer.

That's not how this should happen here. And so I want you to be able to finish your answer now, please.

Appreciate that, Chair Bennett. And and Assemblymember, always welcome from from all of you the hard questions on these issues. In terms of crude oil imports, the reason that I was as giving a bit of a caveat answer is because crude oil imports into California will actually likely decrease this year. As refineries close and as supply changes from essentially, you're replacing crude oil imports with refined product imports. And so, just on a numbers basis, it's actually not an increasing trend over time.

Yeah. I mean, so the bottom line here is, like, we have increased our amount of imports. We have become more reliant on imports for our gas since you guys have been set up. We've lost refinery and supply. We found no evidence of price gouging, which was the whole impetus behind creating this this program.

this legislation was flawed from the beginning, and we're here talk and, you know, mister chairman, my point about this is they absolutely need to show up to our hearings because they are incumbent they their their program is completely relying on us funding them in the budget. So maybe it's voluntary to come here, but, you know, we get to make the decisions about whether or not we fund your program and whether or not it's working.

Why are we funding this again? I mean,

Is that a question for me?

And I think it's very clear it is not. And now we're gonna fund your program with rate payer money.

We're paying we're people who are paying their electric bills are gonna pay for this gas gasoline oversight program that's not working, and it has made us more dependent on foreign oil. It's ridiculous. I mean, I I can't even believe we're even considering it. Should be rejected outright.

Thank you very much for your comments. I am going to respond to a few things. Number one, I think her answer was very appropriate, and the accusation that it was going to be equivocal is just not accurate. That was a great answer, and we have a real professional that understands a lot about this data here. So I think it was inappropriate to cut her off, and I think that her answer really, really demonstrated that.