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

Excuse me. There we go. Good morning, everybody. Welcome to the Assembly Budget Sub 4 Committee. Our apologies for starting late, but they called us into a budget hearing with the Budget Chair and the Speaker and others and all the Budget Sub Chairs. So there's a reason they called us the Budget Subcommitee, because we are sub to the Budget Committee and needed to go there first. So, today we will hear from our energy agencies and the Department of Water Resources.

We have four items that are planned for discussion. For each presentation, I'll ask each of the witnesses in the agenda to introduce themselves before they begin. At the end of the presentation items, Members of the Subcommitee may ask questions or make comments on any of the 10 non-presentation items. We won't be taking any votes today. After all the items are heard, we will take public comment. Each member of the public will have 1 minute to speak.

There will be no remote testimony in this Committee. And if we could take roll, please.

[Roll Call]

All right, we'll go to Issue 1, and that's Energy Commission, Public Utilities Commission, and DWR General Fund Solutions and the implementation update. And I know you know what order you're going to go in, so I'll let you get seated and present in that order. All right, go ahead and begin. Excuse me, can you guys hear back there? Can't hear at all. Right, maybe I have to do something. Try it again, David.

Hello. Okay.

Much better.

Good morning, Chair. I'm David Evans with the Department of Finance. I'm joined here with my colleague Steve Wells, also from the Department of Finance. We will provide an overview over the energy budget and the associated General Fund solutions. We also have colleagues from various departments with us today to answer any specific policy or programmatic questions that you may have. The Governor's proposed budget includes solutions to address the estimated $37.9 billion shortfall.

Last years budget, the 2023-2024 budget provided approximately $7 billion across multiple departments to expedite the state's transition to a clean, reliable, and affordable energy future. The Governor's proposed budget includes General Fund reductions of approximately $419 million, maintaining approximately $6.6 billion of that initial investment of last year's budget. The budget also maintains the proposed $1 billion for the Clean Energy Reliability Investment Plan, also known as CERIP, with the remaining amount proposed over three years beginning in 25-26.

The initial $100 million of CERIP included in last year's budget is also maintained in the proposed budget. So to address the budget shortfall, the budget includes a balance of reductions, fund shifts, delays for several energy programs. I'm going to go through them. So for the reductions, which total $418.8 million, approximately $419 million, for the Energy Commission, there's a $40 million reduction to the Carbon Removal Innovation Program, there's a $40 million reduction to that program, leaving $35 million in the program.

So this program is still in early development, and this program is still in early development and that's why we made those reductions towards this program. The Food Production Investment Program, there's an $18.8 million reduction to that program, leaving $46.2 million in that program. That program is in the guideline development phase. It's still in the early development phase and it has available funding that's not been committed or encumbered yet. There's $22 million reduction for the Industrial Decarbonization Program. The Governor's budget leaves $68 million in that program.

Similar to the Food Production Investment program, that program is still in early development. There's available funding and also those funds haven't been committed or encumbered yet. For Equitable Building Decarbonization Program, the Governor's Budget reduces that program by $283 million, leaving $639 million available for that program. CC is currently in the solicitation phase of this program. And the reductions to the program, they occur in the budget year and then the out years, and that leaves $494 million available for that program.

And so the reductions for the Equitable Building Decarbonization Program is for funds that have not been appropriated yet.

$639 remaining or? $639.

Total plan for the program, $494 million that's already been appropriated.

Got it.

For the Hydrogen Grants Program, the Governor's Budget proposes $35 million reduction and that leaves $65 million total for the program. This program is still in the early development stages and no funds have been encumbered for this program yet. So for the California Public Utilities Commission we have reductions, we have a $20 million reduction for the Community-based Organization Capacity Grants Program that we're leaving $10 million in the program, and this program is still in the early development stages.

CPUC has started accepting applications for the program and that's where they are with this program, but no funds have been encumbered yet for it.

And excuse me, if I could take you back to the $6.4 million for the California Electric Homes Program. I think you jumped over that one.

I have several other as well. In addition to the energy program reductions, the budget also includes that $6.4 reduction to the California Electric Homes program, leaving $68.6 million in that program. And then there's also the $475 million reduction to the Climate Innovation Program, CC, in this program we're eliminating these funds and this program has yet to been implemented yet. The Governor's budget also includes General Fund delays.

So for the Department of Water Resources, there's a $55 million delay in the strategic liability assets, and we're delaying those resources from 24-25 to 25-26. This leaves approximately $2.2 billion preserved from the 21-22 and 22-23 appropriations. $20 million is going to be available in 24-25 and $130 million is going to be available in 25-26. So the delay will align with the appropriations with DWR's anticipated expenditure timeline. For the Oroville Dam Pump Storage Program,

we're proposing a delay of $200 million for that program, and this program is proposed to be delayed to address the budget shortfalls, and it does not alter the timeline for the program. There's a $50 million delay for the Distributed Electricity Backup Assets Program, that's our DEBA program, and we're shifting $50 million from last year's appropriation in 23-24 and we're applying $25 million in 25-26 and $25 million in 26-27. So it's a delay of the $50 million.

This program, again, was delayed to help address the budget shortfalls. The program is in the project solicitation phase and currently, right now there's $495 million that's currently available for this program. For the Residential Solar and Storage Program, there's a $200 million shift. We're shifting $75 million in 24-25 and $125 million in 25-26 to $100 million in 26-27 and $100 million in 27-28. This program has a large appropriation balance currently of $280 million that has not been encumbered yet.

It has not been committed for this program and so the proposal is just to shift the budget year appropriations, planned appropriations, and the out year planned appropriations to help address the budget shortfall. And then we have a couple of other General Fund shifts as well. So we're shifting and swapping the General Fund with Greenhouse Gas Reduction Fund dollars. And this occurs in the Long Duration Storage Program. So we're swapping out $56.9 million for the incentives for Long Duration Storage Program, swapping that with GGRF.

So there's been several awards that have been made with this program, and this shifts the remaining uncommitted balance of the Long Duration Storage Program. And then there's an $87 million shift fund swap for the Equitable Building Decarbonization Program and this program is in the solicitation phase. So there's still $494 million remaining in the program. And outside of the General Fund solutions for the energy programs for broadband, we have $100 million delay for the Broadband Last-Mile Program from 24-25 to 26-27.

And currently, right now the $2 billion is still being planned and maintained for the program. We're just delaying $100 million for the program. And then for the Broadband Loan Loss Reserve Program, this one, there's a $250 million reduction, leaving $500 million for the program. So the Administration, in making the reductions, the shifts, the fund swaps, reconsidered a general framework towards the solutions. We considered the status of the program, where they're at in the implementation timeline.

If the funds were committed, if the funds were encumbered, are there solicitations, like the dollars that are actually committed for it? And then we also considered if we could shift funds with minimal delay to the program. We also considered if there was previous reductions that were made to the program. And then also we want to see if there's any potential federal funding that could perhaps offset any potential solutions that we've made towards this.

Ultimately, there's tough decisions that the Administration had to make to provide a balanced budget, and those decisions are never easy. And so, that's.

Thank you.

Thank you.

Appreciate it.

Thank you. Sarah Cornette with the Legislative Analyst Office. So I won't repeat what the Administration noted about all of the different delays and budget solutions, but just some high-level comments for your consideration. So the Governor is proposing to reduce $419,000,000 relative to the 2023-24 energy package. And as the Administration noted, the Governor is also proposing various fund shifts to the Greenhouse Gas Reduction Fund and funding delays.

So even with these solutions, the proposal still retains the significant majority, about 83% of planned funding in the energy package. And outside of the activities that were included in the energy package, there's a couple of other delays and reductions. So the Administration noted a delay for the Clean Energy Reliability Investment Plan as well as the reduction of funding for the Climate Innovation Program, so that $475,000,000 reduction would essentially liquidate funding remaining for that program.

So ultimately, while the Governor's proposal represents one set of options, the Legislature could ultimately choose a different mix of solutions based on your highest priorities. And as you've been hearing from our office, we think you may need to identify some additional solutions based on the budget situation.

And in our report, we note a few possible options of programs that could be good candidates based on their status, the availability of funds they have remaining in their balance, as well as the availability of federal funds that could help offset some of those reductions. And these aren't necessarily recommendations. These are just kind of options to help you consider as you're making your budget decisions over the coming weeks. Thank you.

Thank you very much. And CEC.

All right, good morning. My name is Liz Gill, and I'm the Branch Manager of the Reliability Analysis Branch at the California Energy Commission. And I'm going to be giving a high-level overview of the state's electric reliability situation and ongoing challenges. So, as you're probably aware, climate-driven extreme weather events over the past several years that are outside of the range.

That is where the states experienced unprecedented climate change-driven extreme weather events over the past several years, that are outside the range of what is forecasted and traditionally planned for. In 2020 and 2022, we experienced extended west-wide extreme heat events. The 2020 extreme event led to rotating outages in the California ISO. The 2022 event set an all time record for demand, but we maintained reliability in part due to all of the actions the state has taken to improve planning, procurement, and deploying contingency resources.

In 2021, a wildfire in Oregon took down the California Oregon Intertie, causing the state to lose thousands of import capacity during a heat wave at the hottest time of the day and elevating the threat that wildfires pose to the state's transmission system and system-wide reliability. At the same time, utilities and load-serving entities across the state have been procuring unprecedented levels of resources in order to meet new projected demands, replace retiring resources, and to achieve the state's clean energy goals.

Unfortunately, in some years, some of these resources have experienced delays for various reasons, including supply chain delays, and so haven't been online for the peak summer months when they were originally planned for. So the figure before you on the printout illustrates how the agencies conceptualize how we think about each of these risks and how they play into how we plan for electric reliability contingency resources. So at the bottom, we have the dark blue, which illustrates the need for capacity to meet the forecasted reliability standards.

This is traditionally referred to as a 1-in-10 Loss of Load Expectation, or planning for a maximum of one outage in every 10 years based on forecasted demand. This is the traditional reliability standard that utilities plan for, and what is typically procured for through utility procurements. Above this, we show that if there are project delays, this can lead for our first need for contingency resources. On top of that, we may experience extreme heat events similar to those that we experienced in 2020 and 2022.

And then there is the need created by the risk of catastrophic wildfires impacting major transmission lines, reducing critical imports, or the ability to bring energy to load within the state. So, in order to address the need for contingency resources in 2022, the Legislature passed AB 205, which established the Strategic Reliability Reserve. The Strategic Reserve has three components that each address these needs for contingency resources through a different approach.

So we have DWR Strategic Reliability Reserve Program, which is the largest component and is focused on procuring supply-side resources with a focus on resources that would otherwise be retired in order to not compete with utility procurements. Then we have the CEC's Demand Side Grid Support Program, which focuses on enabling demand flexibility of existing loads and resources. And then we have the CEC's Distributed Electricity Backup Assets Program, or DEBA, which is largely focused on deploying new distributed energy resources.

And so while the Strategic Reserve serves as the biggest bucket of contingency resources to support the state during the risks that we just outlined, there are also additional contingency resources available through CPUC ratepayer programs and then non-programmatic voluntary load reductions that are coordinated through the agencies and the Governor's Office. And so, to wrap up, we will have specific projections for the contingency needs for summer 2024 in our Joint Agency Reliability Assessment, which will be released in early April.

So, a few weeks. At a high level, we are at a better position than we were last summer, but there is still risk associated with extreme heat and wildfire events. Thank you.

Thank you. Do we have questions, Members?

I do, yeah. I've got a handful of questions, but I want to start with a few about your chart. So I'm a little confused by it.

Okay.

I guess my first question is, since this is a budget hearing, why are there no numbers on the chart?

The numbers aren't available yet for this summer. So we have the projections for last summer, which we've already passed, they're probably less interested in, but we'll have those numbers available again in early April.

Okay. Yeah. I think it's hard from my perspective. This is my first budget hearing, by the way. Hello. Welcome. Given that we're talking about budget stuff, it's really hard to, in my view, have something that's still at a conceptual stage when we're being asked to make decisions about real dollars and real investments. But. Okay. A couple of other questions related to that. So you mentioned, or I guess the chart mentioned, shortages related to drought. Are we still in a drought?

So we're not currently in the drought, but there are years that we have experienced drought, and there's the possibility for that in the future as well. And so this is kind of a high-level conceptual chart to include all of the potential risks.

Okay. And you mentioned also supply chain and permitting delays, which I know we are still experiencing. How many megawatts of projects are currently delayed?

So I'm not sure. I don't know what the specific number of megawatts that are currently delayed, but in the past few years, we've typically experienced about 15% to 25% of project delays. What those impacts are on reliability are really dependent on what the project is, depending on whether it's a solar project versus a battery project.

Okay. All right.

Can you explain to us what's the pace for new resource development after 2025? Because we're phasing out the funding here, and I know you have a plan coming forward in April, but what is the plan for after 2025 in general, in terms of the pace of new resources? Because we have to keep bringing on these new resources.

Great. So for the pace of new resources through utility procurements, I think that's a great question that our PUC colleagues will have more information for. But for contingency resources, without funding for the Strategic Reliability Reserve, we'd then be dependent on those existing ratepayer programs or voluntary load reduction programs, and for those contingency resources for those extreme events.

Okay. So for the implementation of the funds already appropriated, will your report in April have this, or do you have it now? And that is, what programs are already implemented? Where's the money already committed, and how many megawatts of energy do you anticipate the programs are going to provide this summer?

Yeah, I think I'll pass this question to my colleagues that are involved in the program implementation for those.

All right.

Can you hear me? Okay. Hi. Good morning, Chair and committee members. My name is Ashley Emery. I am the branch manager over the Reliability Reserve incentive branch at the CEC. So that includes the Demand Side Grid Support program and the Distributed Electricity Backup Assets program. So I can start with a status update on the Demand Side Grid Support program. So that program offers incentives to electric customers that provide load reduction and backup generation with existing equipment to support the state's electrical grid during extreme events.

So to help meet immediate grid needs during summer 2022, the CEC worked quickly to get the DSGS program launched in a matter of weeks to support the grid during the September heat wave. Over 3,000 megawatt hours of net load reduction were delivered and compensated, which was about $7.8 million in incentives and eligible administrative costs.

I'll note that while the expense may appear low, the CECs pursued a highly cost-effective incentive structure where we pay for actual performance during the extreme event rather than a capacity payment for being available. To address lessons learned from summer 2022 and help bring on more clean resources, in July of last year the CEC approved updated program guidelines. These revised guidelines help bring on more clean resources with expanded participation eligibility and additional incentive options for clean resources.

That includes virtual power plants based on customer-owned batteries. And we worked on streamlining our processes. So the DSGS program currently has over 1,300 individual participants, and we are working with enrollees to validate performance from last summer. So we're working to process those claims as quickly as possible. We anticipate having that performance data by the end of Q2 of this year. We have also begun the stakeholder process for adopting guidelines for summer 2024.

So we are looking to further improve customer experience and grow participation from clean resources, including allowing bi-directional charging to participate, also referred to as 'vehicle to grid.' And so we actually released draft guidelines in March 6 for public comment and held a workshop yesterday to get feedback. So we plan on having these finalized guidelines brought before the CEC for adoption in May of this year ahead of the summer. And so preliminary stakeholder feedback anticipates that participation in the DSGS program will grow.

And now that providers and customers have had time to understand our program design since we had guidelines adopted midsummer last year, with the program revisions, they have more time to implement. And so we hope to continue growing our participation. And so we're also working to secure a multi-year contract for helping to administer and streamline our process for the DSGS program. For the DEBA program-

The what program?

The DEBA, Distributed Electricity Backup Assets. Yeah. So that is the program that incentivizes the purchase and construction of cleaner and more efficient distributed energy assets that will serve as on-call emergency supply or load reduction during extreme events. So, after focusing on the immediate launch of the DSGS program, since that works with existing resources, we began the stakeholder process with a request for information in November of 2022 to get feedback on potential program design that could incentivize the deployment of a diverse range of new resources.

So the CEC has been working closely with stakeholders and our reliability partners, including the CPUC, DWR and CAISO, to understand existing reliability programs and frameworks to ensure that the program does not inadvertently interfere with or duplicate existing programs or resources so that we can instead fill gaps and encourage innovation for participation during extreme events. So we adopted guidelines in October of last year, and these guidelines provide that funding will be issued through grant funding opportunities, the first of which was issued in December of last year.

So that was for $150 million for bulk grid efficiency upgrades, and those applications are currently under evaluation and we anticipate issuing our notice of proposed awards next month in April. Concurrently, staff has been working on a solicitation for the distributed energy assets, and so we've released a draft solicitation concept for proposing $250 million for those resources, including VPPs, in February. And we anticipate releasing the final solicitation by the end of Q2 of this year and hope to have notice of proposed awards in Q3 of this year.

Can you--specifically to this coming summer, what is the amount of load flexibility that's going to be created? There was a real sense of urgency when we said we have to get going in terms of doing this. So as we get ready for a hot summer, what's the amount of load flexibility that--can you identify how much load flexibility will be created for 2024?

Yeah. Based on our historical experience and current enrollment--it'll depend--but we have at least a minimum of 140 MW currently enrolled. But like I said, we're working to expand participation and we had several participants who were enrolling but anticipating to provide start enrolling customers for this summer. So the exact number is not known, but I would estimate up to 350 MW for the summer based on performance in 2022 and what we have currently enrolled.

Primarily demand response?

No, primarily backup generation is the biggest megawatts, but we are working with our two new incentive options to really grow that demand response.

And can you--and all the departments, CPUC and CEC--can you share where are we in terms of working with communities on the development of microgrids and what kind of energy's going there.

Yeah. So I know for the DEBA program, components of microgrids may be eligible, but I can hand it off to someone else. Another--do we have another? For that. That's focusing on microgrids.

Great. Thank you. This is our microgrid team here, right?

Good morning, Chair Bennett. Rachel Peterson, executive director of the California Public Utilities Commission. Thank you for the opportunity to be here this morning. We do have a role in the overall picture for this summer and beyond. And so thank you for the question on microgrids. The CPUC has been working within the statutory direction of SB 1383 in order to incentivize microgrids around the state.

We've actually issued five decisions over the last approximately five years in order to carry out that statutory direction. I do have with me a subject matter expert, Director Simon Baker, one of our energy division directors with me today, who can provide you a little more detail on the implementation of microgrids around California.

Good morning, assembly members. Simon Baker, director with the CPUC. June 2020 decision took some short-term actions in response to the public power safety shutoffs to streamline permitting, reduce regulatory requirements, and provide support for deploying backup power systems, including microgrids. And then a January 2021 decision further reduced regulatory barriers for more complex types of microgrids and ordered the large electric utilities to create a microgrid incentive program valued at $200 million, which was authorized.

This would provide financial support for the development of community microgrids in disadvantaged and vulnerable communities. Then, in July of 2021, we issued a decision that waived part of the standby charge for microgrids that had certain characteristics, namely that they have high availability, meaning on time, that they have high utilization, and that they meet CARB's distributed generation certification program emission requirements. Then, in December of 2021, we issued a decision that approved SDG&E's development of four substation battery energy storage projects totaling 39 MW.

These systems participate in the CAISO wholesale market to support summer reliability and provide resiliency to an entire distribution circuit. One of these microgrids serves a designated low-income community, multiple tribal facilities, and it is designated as one of the 1% worst circuits for reliability. And another one serves a designated low-income community. And in April of 2023, we approved a decision on the large electric IOUs' implementation of that microgrid incentive program that I mentioned earlier.

In addition, the PUC has approved the implementation of the large electric utilities' use of remote microgrids. These are microgrids that are not actually connected to the large electric grid, but they provide safe electric service to customers in high-fire threat districts. And this eliminates the need for overhead distribution lines at lower costs than hardening the system. Some current activities that are ongoing now in 2024 include overseeing the implementation of that microgrid incentive program that I mentioned.

Applications for that program are due in spring and summer of this year. And we're also building the record in the proceeding right now to standardize the rules, roles, and responsibilities for the deployment of a community microgrid. We expect a proposed decision on that later this year, and that will result in a new tariff for the large electric IOUs.

Assembly Member Petrie-Norris and then Assembly Member Connolly.

Hi. Good morning. I think this question is probably for the PUC, but also probably for the CEC. I just wanted to come back to the conversation around the CERIP program, which you're recommending that we provide nothing this year, in this year's budget. So that $1 million was part of a legislative, I guess, deal related to the extension of Diablo. I think as everyone knows.

And the reason that we set aside those funds were because of, I think, very real concern from the legislature, perhaps from part of the administration as well, that we were not actually on track to address some of the real reliability challenges that you're now talking about. So it feels like there is a broad recognition that we've got some real challenges in order to bring new clean energy resources online.

The delay of those investments feels like it's sort of contradictory to the recognition of how big those challenges are. So I guess my question is, kind of given the real urgency to get new clean resources online, isn't it worth considering some appropriation of those CERIP funds as part of this year's budget?

I'll turn first to Department of Finance. Thank you for the question.

David Evans with the Department of Finance. I'm going to take an initial stab at the question. And so the initial $100 million, a portion of that, I believe $32 million, that was appropriated to DWR to help with the establishment for a central procurement function--that is also to help with the reliability efforts. And so I know that PUC, you're currently in a proceeding to make a decision on if they will task DWR as a central procurement function.

And so that's an active proceeding that the CPUC is actively engaging in right now. And so those funds are actively being committed and towards reliability. And so I believe that there are steps and those investments are going towards reliability as well. So the $100 million is being used in that process, and I believe $19 million of that $100 million was also appropriated for DSGS as well.

Okay, other thoughts?

Well, specific to CERIP, the Energy Commission is actually the best technical expert on that, so I would need to turn to them. My colleague from Department of Finance is correct that we, the CPUC, are in the process of examining and setting out an order with respect to which entity shall do the central procurement function, which we were in conversation with this body about this time last year. And we're going to meet that statutory deadline. That's one piece of this entire picture. That's to procure those long lead time resources that we know the state needs. It's not relevant right away, but we're still laying the groundwork for that longer term play.

Okay. Any CEC reflections?

Yeah. If it's helpful, too, just to kind of put a bit of a finer point on your question. So the $100 million last year that did go out for CERIP--just to kind of emphasize--that isn't proposed to be clawed back. So there has been already some funds that have been dispersed. And something that we kind of noted earlier was that for these reliability programs, there are some really significant funds remaining in those balances.

So if that's something that the legislature is concerned about, I think that's also something to keep in mind that for the DEBA program, for GSGS, there are significant funds. The significant majority of the funding that the legislature has appropriated are yet unspent for those programs.

Okay, thank you for that clarification. And then I have a broader question I think about kind of accountability and oversight related to all of the programs that are under your purview and the things that are being proposed. And this is kind of based on, picking up on a hearing that we had a couple of weeks ago related to our EV infrastructure rollout by the CEC.

And when those funds were initially rolled out, there were no accountability measures associated with it, like no performance metrics, which to me is really a shocking kind of starting point. And one of the things that we said in that hearing and all the agencies acknowledged was we are not going to be spending any more taxpayer dollars without clear performance metrics attached.

A lot of the hundreds of millions, billions of dollars that we're talking about are going out in huge variety of different grant programs. I guess my first question is, do all of those, without exception, have very clear performance metrics associated with them? And two, can you give us sort of a broad sense of how you track the efficacy of those investments that we're making?

So as far as grant programs, I would need to turn to the Energy Commission, who leads on grant programs. With respect to the California Public Utilities Commission, most of our programs are directed by statutory direction, and the commission manages open formal proceedings in which we take that statutory direction and in turn, apply it to the utilities that are subject to our jurisdiction. And so we both hold ourselves accountable in the sense that we are responding to this body's statutory direction, but then we're also setting accountability metrics for the utilities that we regulate in the context of those formal open proceedings.

David Evans with the Department of Finance. I don't believe that we have the appropriate staff for CEC to elaborate on the specific performance metrics. But several of the energy programs are still in the guideline development phase. So we recognize the need towards, say, have specific investments towards these umbrellas or issue areas.

So, like, for instance: the Carbon Removal Innovation program, that program is still in the early development stages of it; the Food Production Investment program; the Industrial Decarbonization program, those three programs where there's millions of dollars invested, they're still in the guideline development phase where those performance metrics will be developed.

Does LAO have a response to that, if you don't mind me interrupting?

Yeah, thank you for the question. I think it's a really important one to be asking, especially when we're in this tough budget situation, making sure our dollars are going to the most effective programs. And it's true, I think, as the Department of Finance acknowledged, many of these programs are still getting up and running.

So that's something I think that the legislature is--it's definitely worth thinking hard about and potentially considering whether it would be of interest to the legislature to kind of provide more guidelines or direction on those programs. That's certainly an option. But, yeah, I think just to emphasize, again, these programs are still new and that performance metric question is important, but we haven't really seen yet a lot of clear examples or evidence that there are those kinds of metrics in place.

Okay. Thank you for that clarification. And I think the good news is that it's the appropriate time, I think, for us to all be talking about that. I think there's way too many examples in our government where we look back and go, "Oh my god, five years later, we've wasted a whole ton of money and don't have anything to show for it."

So I think it's just whether the right folks are here or not, I'm not sure, but I just can't emphasize how important it is--and I think I speak for so many of my colleagues--that as we are getting these programs off the ground, we've got to ensure that there's very robust performance metrics in place so that we know that we're getting a return on those taxpayer dollars that we're investing. Thanks.

Assembly Member Connolly.

Thank you, Chair. I'll take advantage of having a microgrid panel and ask a specific question on that and then circle back to reliability and some of the broader themes that we're hearing this morning and kind of reinforce those. So, Simon, maybe to you--and appreciate you mentioning the CPUC proceeding. I'm also interested in some fixes potentially legislatively--wondering, can you share your thoughts on the impact of over-the-fence or across-the-highway power sharing and how a potential statutory change in that regard would help expand microgrids.

So I will turn pretty quickly here to Director Baker. I am not as close to the microgrid proceeding, and so I'm not as keenly aware of that issue. But I do know that that more generally is kind of a fundamental--it does often raise a sort of fundamental question of who is the entity that is providing over-the-fence, over-the-highway power, and how should one treat them? How should a regulator like ourselves treat them? Do you have any thoughts to offer on that?

Well, just to say that the record of the proceeding that has been implementing this piece of statute that I was talking about earlier has a lot of discussion about this issue with regard to the current law and the way that it's structured and how it's being interpreted. I would say it does go to questions about how you define a public utility. And so it really does kind of go to the core of some of the core issues that we deal with as regulators. So I think we would have to follow up with you more in terms of any specific opinions about legislation.

Great. I look forward to that follow-up. So, stepping back, clearly, what we're reinforcing this morning is the importance of reliability. I mean, we have it set out here theoretically, as was noted, without numbers. But the fact is, if you look at the last several years, the legislature has allocated upwards of $10 billion toward energy proposals to increase reliability, reduce emissions, advance clean energy, and increase affordability. That's a lot of money.

But what we're seeing in many cases is that monies have not been committed or projects have not been implemented fully or even started. So I guess given the--and this may go both to CPUC and the Energy Commission based on some of the prior testimony--but given the urgency to provide backup power to address projected energy shortfalls, why are so many of the reliability programs not fully implemented yet, let alone for previous summers? And what is holding up the implementation of these programs?

So you're correct that the Energy Commission has a role to play here, and I'm going to invite those colleagues to come forward while I tell you about the CPUC's role in regulating and ensuring reliability via the entities that are subject to our jurisdiction. So that is the utilities most significantly, and then for procurement and reliability, the community choice aggregators.

And so we use a combination of expectations, both long-term through the integrated resource program, and then short-term through the resource adequacy program, to ensure that all 43 of those are procuring sufficiently to meet our reliability needs month in and month out in California. Now, that entire activity is separate from the programs that I think you're asking about.

Good morning again. Ashley Emery, branch manager. So I can speak to the DEBA program. As I mentioned, we first focused our implementation on the DSGS program in order to meet the immediate grid needs of summer 2022, so we launched the program in weeks and then shortly, DSGS, the Demand Side Grid Support program. So that's the one that incentivizes the use of existing resources. And so we were able to leverage those existing resources immediately. And then shortly thereafter--oh, the summer program ended.

In October and November, we started on the development of the DEBA program with the initial launch of our request for information to get stakeholder feedback on a potential program design. There's a multitude of different types of resources that the program can leverage, and as I mentioned before, we really worked closely with the CPUC, CAISO, DWR to understand their existing programs and framework to make sure that the DEBA program is not interfering with those existing programs and frameworks, and as well as not being duplicative.

And so we've been working closely with those stakeholders and potential participants to develop a program design that is truly incremental in filling gaps. And then to the point of making sure that these resources will actually be available; so, developing performance requirements and as well as incentive structures to enable participation.

That's why we've been working during our initial guideline development process--we were required to develop guidelines for the implementation of the program and then through that have developed the grant funding opportunity. And so while that program has not encumbered funds, we are currently reviewing the applications and working on the draft solicitation process for the distributed energy resources.

I'll just add on a broader note for the contingency resources and the Strategic Reliability Reserve at large. The DWR portion of the Reliability Reserve has the largest portion of megawatts, and I do believe that most of those funds have been committed, although I'm--DWR colleagues to speak towards that.

And so on the whole, once you kind of add up all the programs that we have paid through general funds, as well as additional voluntary and CPUC ratepayer-funded programs, there's about 2,000 MW of total contingency resources available to support the needs, which is above--that would meet the needs that we're projecting. We'll have the final numbers for shortly going into this summer.

One more question. The LAO has proposed further cutting to transmission financing. That's concerning, I think, statewide, but certainly in my district in the North Bay and along the North Coast given the need to improve our transmission infrastructure. However, it looks like there could be additional federal energy funds that the state is receiving to support grid reliability that may, in fact, offset some of these reductions. Can the panelists elaborate on this funding? How much is the state getting? What kind of programs could it support in the transmission space?

I think I'll pass it to our colleagues from another division that can speak towards that.

In the meantime, as they come up, just, I think one note of clarification in our report. As you noted, we did list the transmission financing program, which has $225 million in its balance, as a possible candidate for a reduction. We did not kind of mean to note that as a recommendation. We're just kind of trying to provide the legislature options and possibilities for you.

And that was one program where we noted that funding has not really begun to go out the door, and there are a variety of federal funds available that could help cover some of those needs, and the administration would be able to speak to those sources better.

Can you hear me? Good morning. First, I want to start out by saying how lucky you all are to have Shai, we miss her at the Energy Commission. My name is Elizabeth Huber. I am the Director for the Sighting, Transmission and Environmental Protection division of the California Energy Commission.

And in reference to the federal grip two, which is the round two of these transmission projects, we have been working collaboratively with our agency, the California Natural Resources Agency, along with the CPUC, Cal ISO, DWR, collectively, and also with the investor owned utilities and other developers who are also putting applications in and being reviewed by the US Department of Energy. With that we have been assessing, and I forgot to also mention with our publicly owned utilities. So there's actually one with SMUD that just got announced.

So their application and there are phases to those applications. So they're either being championed or led by the IOU's or the POU's or developers, and then with support from these state agencies that these are feasible projects, or it's a collaborative approach. And that was first phase of these grip two, the second round. We're in phase two now, and where we have, I want to say, four or five projects that are moving through phase two at this point, but no money has been dispersed to us.

Our hope is that the state will see some funding like we have in other areas that I'll be reporting on. But that's about all I can tell you on this at this point. So we can definitely follow up as phase two closes and we know a little bit more of what kind of funding opportunities will be coming to California. Did that help, I hope?

So. You have a question?

Yeah, it is super helpful. And you may not have the answer to this yet, but do you or does anyone have sort of a high level goal or a high level sense of how much federal funding we are likely to get to support our huge variety of clean energy needs?

I don't have an exact number, but definitely we'd welcome to come back to another hearing, but it will be in the millions and we do anticipate that the state will see some funding. Get the budget, guy.

Good morning. Damien Mimnaugh, chief financial officer at the Energy Commission. We're pursuing a number of competitive and formula opportunities, both in the IIJA and the IRA. Right now we're anticipating a total of about $1.2 billion over several years from those opportunities. That number, we hope, will go up as we're successful with more competitive or, excuse me, more competitive opportunities. But that's the figure at this moment.

And you think that's probably like a floor and then there's a bigger opportunity beyond that.

That's correct. That's a combination of competitive opportunities that we've won at this point and formula opportunities that hasn't necessarily been awarded yet. But because they're formula, we know the dollars are coming to the state. We're hopeful that the number will go up as we are successful with additional competitive opportunities.

Okay, so I'd like to have representatives from CEC, CPUC, and DWR. So our original people up here, I suppose, but I have some overview questions and some specific questions, and in the interest of time, I want to try to move to those. So if we could make sure we have somebody from DWR up on the panel and CPUC, most appropriate sort of generalist from CPUC, and then I think our finance person from CEC might be fine, but there we go.

So I'm going to try to move through. We have a number of questions. I want to try for the benefit of staff to make sure we get through as many of these as possible and get these answers on the record. But it looks like, from the questions that we have, that we don't know how many megawatts of electricity we can assume we're going to get this summer from the programs that we funded. Is that correct?

Can you identify how many megawatts we think we're going to get?

Yes. Thank you. Good morning. My name is Delphine Hou, Deputy Director of Statewide Water and Energy with the Department of Water Resources. Thank you, chair and Assembly Members, for having me here this morning. So I can only speak for DWR's program, but we do have several megawatts that we had in the Reserve starting from 2022 that we again had in '23. And then we can have a projection of what we're looking forward to for this summer.

So for DWR this summer, we are looking to have 291 megawatts of emergency and temporary natural gas resources. And in addition to that, we also have contracts with resources that were going to go into retirement, but have decided to stay out of retirement in order to be in the reserve. So that's another 2859 megawatts of resources. So in total for this summer, we're looking at 3150 MW available for the Electricity Supply Strategic Reliability Reserve program.

Great. Okay, and what's your evaluation of the cost effectiveness of those programs that are bringing on that? Nearly 3000.

It's a balance, we believe that the contracts that we have negotiated for are cost effective, but at the same time we understand that these are, again, they're emergency temporary generators that we had to put up in a very short amount of time in order to bolster state reliability. Many of those megawatts were actually created and built by DWR and partners in 2021 during the governor's emergency proclamation.

So really, hats off to our DWR engineers and our partners for having put in 120 MW in about a month, kind of record breaking speed. But we did it to ensure that the state had the resources and the steel in the ground to use and those assets were used and useful in the 2022 summer heat wave.

Great, that's helpful. Thank you for the once through cooling natural plants that are in the strategic reliability Reserve. How long will those plants need to be turned on before in preparation of an emergency?

Thank you for the questions. These are, as everyone knows, much older resources. They were on the verge of retirement, so they have various startup times. So if I can read out the times that I have on record is, for example, the generator at Ormond Beach, the Ormond Beach generator, that one takes approximately 20 to 30 hours to start. The Alamitos units also have some variation.

There's a minimum of 10 hours for two of the units and up to 34 hours to start the third and then the shortest time is the Huntington Beach unit, which will be about 10 hours to start again. Much older resources, it takes a long time for these coming out of a cold start scenario in order to warm up and get to an operating level.

Also, what is very different this year, because it's in the strategic reserve versus in the market with the PUC resource adequacy program, is that their operational requirements are completely different. When they're part of the resource adequacy program, they have to be available 24/7 for any time the grid operator would need them. And so the emissions profile there is going to be very different. But even then, these units were not used very frequently.

So, for example, the one at Ormond Beach had an annual capacity factor, meaning sort of how much did it run it out of the year, about 2%. So when it was in the resource adequacy program here, starting January 1st 2024 they're with the strategic reserve and their default position is off. So they will not be available 24/7 they will only be put into the market tested, potentially used if and when the grid operator sees, or potentially sees some extreme event.

So we're expecting the emissions profile and certainly the usage of these resources to be much lower and very different from where it had been for the last several decades of operations.

Good news. And you don't have an anticipated number of days or hours.

If I had that crystal ball, I probably wouldn't be sitting here, so. No, sir, I do not.

We would leverage you for all kinds of arbitrage and everything else if we could do that. How about PG&E starting to pay back the $1.4 billion? Do we have an anticipation of when we expect them to finish paying off those funds?

Thank you for that question. So, jumping over to Diablo Canyon, it's a little bit more complicated. So, as you probably have heard, the Department of Energy has made some progress with Pacific Gas and Electric, with PG&E for their civil nuclear credit program. And so there's good news on that end. But we currently only have the sort of initial release, the news release, in January 2024.

But we also need to be aware that there's three potential streams of payback, which also includes excess operating revenues in the final year of extended operations and any other federal funds. Going back to the DOE Credit award, what we understand is that the first time that DOE would likely be awarding any credits is in 2025. And that is because they need to do a look back audit, and they will look back to 23 and 24 and conduct that audit in 2025.

But I also want to caution that that's the DOE schedule just for doing and conducting the audit. There is also the DOE loan recapture period. So, from what we understand, and again, we're not party to this agreement, so we don't have the details, but from what we understand from publicly available documents, is that it is a four year recapture period.

And so what we think that means is if PG and E is looking at a time frame of '23 through '26, that that DOE recapture period could be as late as 2027. So any funds that the PG&E may be awarded from the DOE would be put into an escrow account to wait out that recapture period. So there's a lot of caveats there, but that's the best visibility that we have at this moment, is probably looking towards that 2027 time frame.

Semi-Member Conley, did you have follow ups?

Yeah, you asked one of them on the anticipated payback time period. I guess the overall question on Diablo, though, is how much funding is anticipated to be needed in light of the fact that there is a lot of federal money coming down the pike as well.

Funding from the state? Yes. So what we understand right now, based on projections of where PG&E needs the monies in order to conduct and finish their relicensing, is that we're looking at both the costs of the actual relicensing, as well as required disbursements under SB 846. So we are looking at a trajectory of the maximum $1.4 billion at this time. But again, DWR would have to evaluate those costs from PG&E to affirm that they're eligible, reasonable, et cetera, per SB 846 requirements.

Semi Member Petrie Norris.

Hi. Let me just go back to the conversation and your overview of those OTC plans. So what is the cost for those of those contracts?

Absolutely. So I'll call them out in aggregate. So in aggregate, those three ones through cooling units over three years. So the contract starts January 1st, 2024 through December 31st, 2026. In aggregate, it's a little under $1.2 billion in terms of a, I know that's a big number, but I think in sort of the language of the energy world, we tend to use a dollar per kw amount, and each of those are under 10.

And so if you wanted to compare it with other resource adequacy contracts that the load serving entities the IOU's are signing today, we believe those are well below the current market rates. But again, the understanding is that this capacity payment is really to not only have the steel in the ground and availability to the resource, but I do want to emphasize what's really, really critical is that these units were about to retire.

What is very critical for DWR is that we preserve the staff, the experienced, licensed operators of these power plants. It was critical that we signed these contracts to make sure we had the right personnel. We maintained the units so that they would be ready and available for the state. So that's why these payments are so critical, especially for a power plant that was on the verge of retirement. They were going to let their staff go. Everything was going to get shut down.

Maybe this is a sort of follow up conversation, but I would love to understand what alternatives we've considered, what analysis was conducted to determine that that was the appropriate, or that that's our best option. And I do think that kind of highlights just how critical it is for us to be making investments now that will then make that $1.1 billion unnecessary. All right, so to a question related to a slightly less eye watering price tag.

So I think last year you were appropriated $32 million to implement the central procurement function in AB 1373. I believe CPUC has until September to determine whether it will ask you to procure any resources using that function. Can you just tell us how much of this funding you're expecting to spend this year and for what purpose?

Absolutely. And actually, if you wouldn't mind, I would love to provide a little color to your last comment as well. Sure. So DWR worked very closely with our colleagues at the Energy Commission at PUC and the California Independent system operator in that decision to contract with the OTCs.

That was based on a reliability assessment by those entities that kind of called out the balance between maintaining those assets that were again ready to retire, but then balancing it with putting it into reserve that didn't run all the time, so it would balance the emissions while maintaining resources for the express purpose of allowing units, clean resources, batteries, solar, et cetera, that are under construction to advance across those supply chain hurdles and everything else that was coming out of the pandemic, et cetera.

So it really was a stopgap measure to buy us more time with assets that had not already gone into retirement and left without their staff, et cetera. So it was, I think, a timely kind of urgent collaboration, working very closely with them based on their reliability analysis. But thank you for that question.

In terms of central procurement, as was mentioned before, PUC has already started looking at central procurement through their, or will look at central procurement through their integrated resource planning process to determine a if there is a need for a central procurement entity, and if so, whether or not DWR would be the most appropriate entity for that. So what we have done is we've started preparing. We do need staffing because prior to AB 1373, we didn't have the authority or the staffing to do any of this.

And so we've started coordinating and following the IRP proceeding. We are also getting resources together and maybe securing contracts to be able to support what that role could ultimately look like to conduct competitive solicitations to support a central procurement function for eligible, long lead time, clean energy resources.

Okay, thank you.

Thank you.

So I'm going to move Assembly Member Connolly.

One final follow up on Diablo. So state $1.4 billion, federal DOE paying $1.1 billion. So do you expect that we would be called on to forgive the $300 million difference or would PG&E be paying that back?

I think it's too early to speculate on amounts. It is all possible. First of all, there was an SB 846, a requirement to put into the DWR PG&E loan agreement forgiveness provision. So that is provided for in the loan agreement as required by SB 846. But as I had mentioned, there are three sources of potential funding to pay back the state loan.

Again, there's the big one, which is the DOE award amounts, but there's also potential revenues over costs in the last year of extended operations. So we won't know that until we actually get through extended operations into the final year and then any other federal monies that we can find along the way, that PG&E or Diablo Canyon, I should say, could be eligible for.

So with those three unknowns, we really would have to go through those steps to figure out what is available and what potentially would need to be forgiven, if anything, at the end of that period.

So if I could turn to the CEC questions about the hydrogen grant program, and while we're anticipating cutting $35 million out of there, what do you intend to fund and when do you anticipate approving those grants?.

Got you. Damien, chief financial officer. That's an excellent question, unfortunately, I'm not the right person to answer it. So I have with me Jonah Steinbuck, who will be coming up to answer those questions.

Great, thank you. Good morning and welcome.

Good morning. I'm Angie Gould. And I'm Deputy Director for the Research and Development Division at the CEC.

Could you be a little bit closer to your microphone, please? Thank you.

So the clean hydrogen program was set at $100 million, but the Governor's Budget is proposing a $35 million reduction, so that would maintain $65 million. So we are working on a $45 million solicitation for centralized hydrogen production. So that would be for projects that are demonstrating or scaling up clean hydrogen production, processing, storage and delivery, in California. These projects would be producing at least five metric tons of Clean Hydrogen per Day.

They'd be producing how much?

At least five metric tons of Clean Hydrogen per Day. So that's equivalent to about at least 156 truck tanks of hydrogen per day. $20 million from this $45 million solicitation has been committed as cost share for the alliance for renewable clean hydrogen energy systems, or ARCHES hydrogen hub project. So we anticipate two projects, and one of those would likely be ARCHES. That $20 million was identified as cost share in the ARCHES application to DOE. That solicitation was released last week.

In addition to that, we have a federal cost share solicitation that we put out last year, and we identified three different projects for a total of $3.1 million. And these we anticipate being approved at a business meeting by July of this year. And then finally, we have a distributed clean hydrogen production solicitation for $10 million in clean hydrogen funds. So this would be for facilities that are colocated with their end uses to try to reduce clean hydrogen costs.

And these would be projects producing between 1 and 5 metric tons per day of clean hydrogen. So that's between 30 and 150 truck tanks of hydrogen per day. We anticipate one award with that $10 million, but we are looking into options to combine it with other sources of funding so we can get additional projects, an additional one to two projects potentially. And that solicitation we anticipate releasing in May.

And the $35 million, why $35 million? Why was that number selected? Is it relative to the grants that were out there that you thought you could Fund at this point in time?

Yeah. So I would turn to DOF.

David. David Evans, Department of Finance. The $35 million was proposed by Governor's budget that was looking at the available, the availability of funding based off of what the Department had planned to commit by the end of the year, by June 30 of 2024. So we're looking at their plans and their plan commitments. And so that was the amount that would have been available.

So you weren't anticipating having another grant award beyond the $65 million at this point in time?

Yeah, that's what we're planning for right now, is to put out solicitations that use that $65 million.

Thank you. And then in terms of the offshore wind port infrastructure upgrades, visit somebody else.

That would be another colleague.

Hello again. I'm Elizabeth Huber. For the record, the siding Transmission Environmental Protection Division Director at the California Energy Commission. And so your question was on the AB 209 Ports infrastructure grant, Correct?

Correct.

So we had a workshop on November 3 of 2023 that we laid out to the stakeholder community all the three categories that we're able to Fund in the AB 209 strategic in the ports program. Excuse me.

And so with that, we got a lot of feedback looking at the categories for infrastructure development or next phase partnership or matching funds, if you will, with the federal programs that are available out there. One example is the Humboldt Harbor District, where we had given a grant to them in an earlier budget item, and they were able to utilize that for the 429 million from the US Department of Transportation. So back to these grants.

Because of the success on the infrastructure work that's happening up there, we are going to be submitting a solicitation through our internal process, and then we look at by the end of quarter two. So by June of this year, we will be posting that solicitation for these ports to apply for these grants. There'll be a competitive process. We'll have a workshop, hopefully in July, walking through the solicitation, because it will be out for about 45 days.

And so our hope is by the end of this year to actually encumber those funds and distribute them.

I know that this wind energy investment that we're hoping the private sector is going to partner with us on has long lead times. And the infrastructure development is significant. And I know certainly at the port of Long Beach, that they will play a vital role in terms of whether we develop the infrastructure to actually construct these. And I'm concerned about whether we have identified what are the absolutely essential steps that need to fall into place to keep us on schedule in terms of that.

And so I'm interested, I know they have requests for some infrastructure investments that I'm sure they'll be applying for the grants for that. They have some real timing questions on in terms of continuing to move forward. But have we identified what are the essential infrastructure investments that must be made and what kind of time frame they have to be made on to keep sort of the wind turbine projects on schedule?

We do have in our draft strategic plan that was posted on January 19. Public comment is open through April 22 of this year. And we'll be having two workshops around the deployment of offshore wind. The immediate identification that you reference with the port of Long Beach and Port of Humboldt, who have been collaboratively working we know there's three styles of ports that we need in order to deploy safely and successfully offshore wind, and that staging and integration is in that first step.

And these two ports have been raising their hand the loudest. That's the type they want to in the development and expansion at their ports. And I say that because we also will need a port that will support the specific vessels for the maintenance and operations to get out to those wind farms. So a smaller port in the Port of Richmond has identified that they would like to really work and be a port to support those vessels.

In addition to that immediate infrastructure at the ports, we've identified the importance of workforce development, training and apprenticeship programs, and we've been working in our draft strategic plan. We worked really closely with our partner agencies over at the Labor and Workforce Development Agency and the Workforce Development Board on some strategic plans and how to utilize federal funds in order to get those training centers in the areas where the work is actually going to be conducted.

Then obviously, the topic that's already been discussed today and will be continued to be discussed is transmission planning and then the implementation of the transmission infrastructure specific to offshore wind. And we are collaborating with the Department of Defense, the US Department of Energy, along with the National Renewable Energy Laboratory, ENRAL, as it's fondly called, as well as some partnerships with the Cal Poly Humboldt's Shots Resource Energy Center on planning, and along with our partner agency, CPUC, and the California ISO.

Great, thank you. I know that the port of Wynmia is very interested in the workforce development aspect of this, along with the partner there in terms of the naval base and all of the technology that they have. So I appreciate that, I thought that a fairly compelling case was being made by Long Beach in terms of trying to stay on schedule or losing some of the opportunities that they might have in terms of keeping the right contractors, the right expertise there at this point in time.

And with that, I believe we have exhausted and very thoroughly exhausted the questions here. But this was certainly the most ambitious part of our program this morning. So I really appreciate all of the answers and all of the cooperation from all of the agencies, et cetera. Thank you very much. And we will now move to issue two, and that's Energy Resource Program Account, the IRPA structural deficit relief trailer Bill language. Thank you. Thanks. Let's stay in touch on this.

Yeah, keep, keep me informed as you're thinking about this stuff. And so whichever Administration witness would like to start off.

Good morning. Damien Mimnaugh, Financial Officer at the Energy Commission, and I'm here to present the Energy Resources Programs Account structural deficit Relief trailer Bill Language. The Energy Resources Programs Account, which we call IRPA, is the main Fund supporting the Commission. IRPA supports the bulk of our activities in leading the state to a 100% clean energy future. The revenues in the account are linked to the sale of metered electricity and that is retail electricity sales.

The surcharge generated approximately $71.6 million in fiscal year 22-23 and currently costs the average household about $2 annually, so about 16 cents per month. Revenue growth in the account has been stagnating in the last several years, and this is a result of two main factors.

The first factor is building and appliance energy efficiency measures that have reduced the growth of electricity consumption, and this is a direct result of the success of CEC's efficiency measures on items such as computers, clothes dryers, dishwashers, and so on and so forth. These policies reduce electricity consumption and have saved California consumers well over $100 billion over the last 40 years. However, the reduction in electricity consumption has also impacted urban revenue.

The second factor is an increase in behind the meter electricity from sources such as rooftop solar, wind, and non utility generation. We refer to this as BTM electricity for behind the meter. Under current statute, BTM electricity is exempt from the IRPA surcharge. As BTM electricity capacity grows and reduces retail electricity consumption, IRPA revenues decline correspondingly.

The Senate Office of Research looked into this issue in 2021 and published a report forecasting that BTM electricity will grow from about 7% in 2015 to 17% of total electricity consumed by 2030. So if you compare that to retail electricity sales, those are only anticipated to increase by about 1.6% annually between now and 2035. So the Senate report concluded that the growth in BTM electricity results in an inequitable cost shift from higher-income customers to lower to middle-income utility customers.

So while the revenue amount has stagnated, the amount appropriated each year out of IRPA has increased. This year's Governor's Budget proposes expenditures of about $95 million, and compare that with annual revenues of about $72 million. And this creates what we call a structural deficit. That's a situation in which annual expenditures exceed revenues. To address this issue, CEC and the Administration reduced IRPA expenditures by about $37 million in the years prior to the pandemic.

In the late 2010s, CEC submitted and the Legislature approved multiple budget change proposals to reduce expenditures out of IRPA. But at this point, we have exhausted the available options to reduce irpa expenditures. So that's why we have this trailer Bill Language in front of you that proposes to do three things. First, raise the statutory cap on the IPA surcharge to what it would have been if the cap had been tied to inflation. Second, tie the cap to the consumer price index moving forward.

And third, extend the surcharge to behind the meter electricity consumption. Extending the surcharge to behind the meter electricity consumption would more equitably distribute the IRPA surcharge among consumers. And this proposal would also allow the CEC to incrementally adjust the surcharge as needed to keep the fund solvent, balancing revenues with appropriations and expenditures that have been approved by the Legislature. So thank you for your consideration, and I'll turn it over to financial and the LAO at this point.

David Evans by the Department of Finance I would just like to add that and kind of shape the narrative that the proposal, the administration's proposal is to raise the surcharge cap and then to apply the cap to tie to the consumer price index. The proposal is not to increase the surcharge, so there won't be a surcharge increase that's being proposed in the Governor's Budget. It's to just restructure the cap of the surcharge. So I just want to, just to emphasize that.

LAO

Thank you. I'm Sarah Cornett with the Legislative Analyst Office. We generally believe this proposal is reasonable as IRPA is in a structural deficit and this account funds CEC's operations extending to behind-the-meter generation would help ensure these customers pay their fair share as they benefit from CEC programs and initiatives.

And while any proposal to increase or that could increase rates should be considered very carefully because our rates are so high here in California and rising faster than inflation, this proposal is modest and is expected to increase rates only by a few additional cents each month at a graduated pace.

And we recommend the Legislature approve the proposal but continue to monitor both future requests for increases for irpa spending, as well as the need and cost effectiveness of existing spending to try to constrain expenditure growth and keep the rates from increasing too quickly.

Any comments or questions? Assembly Member Connolly.

Thanks, I appreciate the testimony. So IRPA has a structural deficit. This is because revenues have failed to keep pace with increasing expenditures, primarily staff salaries and benefits, as well as growing costs to implement new legislation each year. So, Mr. Mimnaugh, can you provide more detail about the IRPA funds projected insolvency, and particularly what is most impactful to this deficit? Is it staff costs, implementing new laws or other factors? And then I have a couple follow ups.

I'll take the first question first, having to do with forecasting the structural solvency of the Fund. Without this proposal, we anticipate that the Fund balance would fall below a prudent Reserve in fiscal year 26-27.

With the proposal and the incremental revenue increase that would accompany it, the Fund would not be insolvent until 2027-28 on the second question, in terms of what contributes to the growth of expenditures, we do budget adjustments every year for a combination of staff salary and benefit increases, as well as to implement new legislation. So over time, as the cost of those have outpaced the increase in revenue from increased electricity retail sales, that has led to the structural imbalance that we're seeing.

What percentage of the Europa Fund is being spent on projects in comparison to administrative costs like salaries?

So the question is what percentage of our costs are related to staff versus non staff costs such as contracts?

Correct.

I don't know if that's that off the top of my head, so I can plan to get back to the Committee if that's.

Yeah, I'd be interested in that. This is touched on a little bit, and that is something we all know too well, and that is that our constituents are paying some of the highest rates for electricity in the nation. We're all receiving calls. It's probably the top issue right now. How can we justify another cost, albeit minor, in effect, that will add charges to electricity bills right now?

I think that also could be a question to the Administration. I think in our office's view, IRPA is in a structural deficit and as an agency that is being kind of relied and called upon by the state, as our previous panel noted, the CEC is doing a lot to implement a legislative direction regarding energy policy and reliability. And if the Legislature wants to ensure the Fund remains solvent, we find the proposal to be a reasonable solution.

That being said, it is very important to consider impacts on ratepayers.

Yeah, I think that's right. And let me tee it up this way, and this could be part of the follow up, too. Are there additional steps the Commission can take to reduce, for example, staff expenditures so that we do not need to double the IRPA surcharge?

Yes. First I want to go back. I think I made a mistake in terms of which year I was looking at in the column of this chart here. With the additional funding and revenue from this proposal, this account would go insolvent in 28-29. It would fall below its prudent Reserve in fiscal year 27-28 which require us to take action. So thank you for letting me clarify that.

With regard to opportunities to reduce costs to IRPA, we have worked collaboratively with the Administration, as I mentioned, the consecutive budget change proposals in the late 2010s to reduce costs off of IRPA and move existing staff onto more appropriate or other appropriate, I should say, fund sources. That's something we can continue to explore with the Administration and something that we explore every year as we're developing the budget.

And potentially as an alternative to the rising surcharge. So, yeah, if we can maybe get back on that.

So are you asking for?

I'm asking for what is a percentage of staff costs relative to actual project work? Potentially, are there ways of cutting those costs? And I guess ultimately, to an extent where it could at least potentially offset the need to raise the surcharge by double, given sensitivity around rates now.

Got it. I would point out the proposal in front of the Legislature is not to increase the surcharge, as my colleague from the Department of Finance mentioned, just to increase the surcharge cap. The proposal would extend the existing surcharge to behind the meter electricity. This would more equitably distribute the existing surcharge, which would generate about four and a half million dollars in the first year, $10 million in each year.

After that, the Commission each year would look at the expected expenditures and revenues in the fund and would adjust the surcharge incrementally, either up or down as needed to maintain a prudent reserve.

Good morning. Rachel Ehlers with the LAO. Just one thing to add. You have a lot of discretion as the Legislature over how much the Commission can spend.

So again, this proposal before you would give them the authority to raise the surcharge over time, but they can't really raise it reasonably beyond their authority to spend, you know, if they were to double the surcharge and raise a bunch of money, they can't spend that money unless you have given them the authority to do so through the Annual Budget Act.

So really, I think one of the reasons we felt comfortable with this proposal is because every year in developing your budget, you will decide how much you want the Commission to do, how much you want staff compensation to be through your authority to ratify MOUs with collective bargaining agreements, through what activities you kind of authorize them to undertake. And that's part of our recommendation, is that you take that really seriously.

And each year, as you have BCPs come before you for spending out of IRPA to make sure it's really important and to look at what they're doing right now and make sure that that's really important. That's a key tool that you have to try and make sure that these surcharges don't continue to increase, even if they have the authority to increase it up to a higher cap. You have the authority to tell them how much they're allowed to spend out of that fund each year.

Assembly Member Cottie, Petrie-Norris.

Thank you. And I guess recognizing that, as you said, the proposal would have a modest impact, I think I share a number of Assembly Member Connolly's concerns almost on a philosophical level. And let me make sure that I first understand this chart. So if I'm reading this chart correctly, it's not showing that revenue is declining. It's showing that revenue and transfers are steady and expenditures have grown above revenue. So the structural deficit exists because you're spending more money than you have.

And if you're a small business owner, if you're a family, when you have a structural deficit, you have to start spending less money. You can't go to your boss and say, oh gosh, my credit card spending is $1,000 more a month than what you're paying me. I need you to give me more money. That's just not a thing.

So I, like Assembly Member Connolly, would very much like to understand an alternative proposal that would keep expenditures within revenue and transfers and understand what that would look like and what, if any, impact it would have on some of the key projects and initiatives. Because if I'm understanding correctly, I think these are largely kind of administrative costs. Like, we've got hundreds of millions and billions of dollars that have been allocated to projects and initiatives, and that's different than this.

So while it's a modest cost, I think particularly given the financial situation the State of California finds ourselves in right now, I think that we need to be taking a really hard look at what it's going to take for us to live within our means in the same way that all of our constituents are required to live within their means.

David?

David Evans, Department of Finance, I would like to provide clarification on that chart. So the chart would display not just like expenditures, but authorized expenditures of what the Commission is authorized to spend to meet statutory requirements or staffing costs towards chapter legislation or things like that. And so it might not reflect necessarily what they're actively spending. And so when we do our review of their Fund condition statements and their expenditures, that will be like the actual expenditures.

I want to provide clarification that it's not that the Commission is spending more money than they actually have the revenue for. We're displaying that the authorized expenditures each year, either due to increased regulations or statutory requirements, the Commission will say that to meet these requirements, we would need x number of staff and that would be implied. And so that charge is showing, in order to meet the statutory requirements, the authorized expenditures are exceeding the authorized revenue that they're allowed to collect.

Got it. And that is a super helpful clarification, and I think, you know again maybe then I'll add, kind of addition to Assembly Member Connolly's follow-up request, which is, when you look at what would it take to live within the existing revenue stream, I think it is important then to outline, here's the stuff that the legislatures asked us to do that we would not be able to do. And I think we need to do more of that reckoning because then we can all take a look.

Oh wait, are all of those things really high enough priorities for us to ask for more money from California taxpayers?

Appreciate that. Before we go to item three, I would just to follow up in terms of what the Department of Finance said. I know we are asking the CEC to do more and more, particularly with all of the issues that are out there. I know that we're also identifying that with the rate of inflation and the wages and salaries and benefits are going up.

And so really the fundamental question is what would you do less of if we don't do this so that we can compare this? Because what I don't want to do is, I know that there are some very specific things that we want the CEC and all of the agencies to do a better job of, which is performance requirements, all of those kinds of things. And if we want to do those, we have to be properly staffed in terms of doing it.

So the idea that we should make sure that we have a regular revenue stream, that revenue streams grow with some kind of modest regularity to cover the normal kind of increases so that we don't find ourselves, because there's a number of departments where we found ourselves where the revenue stream just stayed flat. And so consequently they just did less and less and less. And then we were frustrated because we couldn't get certain things done. So I will welcome an investigation into exactly this.

What would not get done so that we can clearly identify that it looks like somebody's coming up to help us maybe a little bit to answer that question. Now.

Part of that, at least.

Great.

Good morning. Rob Cook, Director of Admin for the Energy Commission I've unfortunately lived with this issue and tried to resolve it since 2016. And what you're asking of us is exactly what we ask of ourselves every day. We have put forward three separate reports to the Legislature on this very issue, and we have, over the course of time, reduced our expenditures by $37 million through various actions that this Committee, your predecessors on this Committee have helped us carry.

Those have been shifts to other funds to help us carry out our mandates. It's been actual reductions in IRPA expenditures, actual cuts. We used the last increment of our expenditure or revenue authority to increase IRPA revenues to about two and a half million. But we're capped out. Several years ago, about 2018. The high watermark for this Fund was $75 million. That was the most it could generate. It has since declined. It is now hovering around 72 million. It is a stagnant Fund source.

One of the things that we found is we were doing reductions over these several years. We'd make $15 million worth of cuts and then we'd have a $4 million increase in salary and wages because of negotiated agreements. And so we would take a nice big step forward and then we'd slide back. That happened, in fact, has occurred every year.

One of the benefits that we've found, at least, silver linings that we found in our operations as a result of the pandemic is we've been able to reduce our real estate footprint by 40%, which has saved us a lot of money, and we're always looking for opportunities like that. We are currently examining our real estate footprint further, and we think that we can find several hundred thousand worth of savings there. Like I said, we're continually looking for operational efficiencies, but our revenue source is tapped.

It is never going to grow in its current structure. It cannot grow above where it is. And roughly 80. Well, we'll get back to you on the actual number, but roughly 80%. There's a substantial proportion of our staff who are working on all of our mandates are funded out of this fund. And when we put forward a budget change proposal to address legislative mandates or whatever, most of that money is staff costs. That's how we get our work done. We're a knowledge worker organization.

We try to solve very complex problems regarding the energy system in the state, and it's know every new mandate means we need more staff to fulfill those mandates.

Could I ask Department of Finance, what would the fee be if we had just allowed it to be increasing for inflation during this time?

David Evans, Department of Finance, and so if we raised the statutory cap to what it would have been in 1974, it would be 0.00066. That would be the surcharge rate. We can get back to you on the actual fee for that.

If I understand the question. Is the question what would the surcharge need to be at this point in time to cover the anticipated expenditures out of IRPA? And how does that relate to the current surcharge at this point in time?

No. If you just would have matched it with the rate of inflation.

That is part of the proposal. The proposal is to increase the surcharge cap up to what it would have been had the initial surcharge cap or surcharge been indexed to inflation from the get go in 1974. It's 0.00066 per kilowatt hour.

Right, okay. And so we're not increasing the revenue stream faster than the rate of inflation that has been experienced by people in California at this point in time.

That's absolutely correct. Yeah. The overall increase in retail sales expected over the next decade and a half or so is about 1.6%. It increases at the end of that due to forecasted increase in electrification. However, at no point in time is it reasonable to expect that increase in revenue to ever surpass inflation.

Right, great. Thank you very much. Any other questions or comments? Right. Okay, good. All right, thank you. We will move on to issue number three, Broadband. We had the benefits of a nice oversight Committee already on Broadband, so that was helpful. And whenever you're ready, whoever is going to lead off for the Administration.

David Evans, Department of Finance for Broadband. Sorry. Here we go. For the Broadband Loan Loss Reserve Program, there was a $250 million reduction to the program. So last year the budget appropriation for the program, the plan was $750 million for that program. The Governor's Budget includes a 250 million reduction, leaving 500 million for the program. So currently appropriated right now for this program is 175 million. That's like money that was actually appropriated. The plan is leaving 500 million for the plan and then for the Broadband Last-Mile Infrastructure Program.

The proposal is 100 million delay from 24-25 to 26-27 leaving. And the administration's proposal is to still have the 2 billion for the Last-Mile Infrastructure Program. It's just delaying 100 million in the budget year of 24-25.

Leaving how much again?

So currently, right now there's 1.45 billion that's been appropriated for the program, and that's through appropriations since last year. This year, the plan for the appropriation in the budget years is 150 million. Originally, last year's budget agreement was for it to be 200-250 for budget year and so the proposal is just to delay 100 million to 26-27 instead. Go appropriate. 150 million this year.

All right, LAO.

However, given the serious budget problem facing the state, we recommend the Legislature consider other general fund budget solutions using some of the remaining broadband infrastructure funding that is available. These could include additional reductions in last mile project funding, particularly given the anticipated receipt of additional federal funds from the broadband equity access and deployment or BEAD program in 24-25, as well as additional reductions to the Loan Loss Reserve Fund and on the CPUC's ongoing implementation of broadband for all proposal.

We find that several of the broadband programs and projects have long or ongoing implementation periods and so will require permanent staff, and therefore, we recommend the Legislature approve that proposal as budgeted. Happy to answer questions.

We're here to answer your questions. Chair happy to be here.

Thank you. Anything else?

Thank you.

Thank you.

The demand for the Loan Loss Reserve, we're cutting those funds, and we have an expected demand and ability to also fund the middle mile projects. An so, how do we cut these funds and still increase the demand for the middle-mile projects or meet the expected demand and ability to fund the middle-mile projects?

So, I'll begin with that question. Chair, thank you again. Rachel Peterson, Executive Director of the California Public Utilities Commission. I'm joined now by Director Rob Osborne from our communications division. So I'll start just by; I know you were at our oversight hearing a couple of weeks ago, but I can just describe the three-part strategy that Loan Loss Reserve is part of. After SB 156 was passed, we began with the 50 million Local Agency Technical Assistance Grant program.

We issued 105 grants to tribal entities, local governments, new special districts in order to give them the chance to plan and engineer last-mile networks. That has now built up the groundwork for those grantees. We know three-quarters of them have now applied to the Federal Funding Account program, the major grant-making program.

The third prong is Loan Loss Reserve, and that is a credit enhancement tool, as I know you're aware, that is aimed to support these new entrants into the internet service provision market and by providing them a means to ensure that they can finance the last mile networks that they've now engineered have submitted grants for and would like to seek credit enhancement for.

There is no question that with the administration's proposed cut, which we're aware we need to do because of the overall budget picture, we do know that fewer entities will be able to secure the credit enhancement tool. But nevertheless, we think that there's still a sustainable strategy going on between the three approaches that we've been deploying.

When do you anticipate awarding the general fund last-mile projects?

Our first awards will start to go out in June.

Okay, great. Assemblymember Connolly?

Yeah, just a couple of quick questions. So the background analysis we received states that out of the $2.3 billion in general fund dollars that was appropriated in 23-24 across the middle mile network, last-mile project grants, and LLRF, only $30 million has been expended, leaving 1.5 billion for state broadband infrastructure. Is there a reason so much money is still on the table for these projects? Are there barriers preventing funds from getting out the door to these projects?

So of the three that you spoke about, Assemblymember, I can speak to one of those, the Loan Loss Reserve program, because that is the fund, if I'm correct right, that was appropriated last year in the Budget Act. So, the State dollars for last-mile networks that are in what we call the federal funding account were appropriated a few years ago. So those grants are on their way, and we've distributed already some 105 local agency technical assistance grants.

The Loan Loss Reserve program, once it was approved last year by the Legislature, took some time between the CPUC and iBank, the infrastructure bank, to design because we wanted to make it as useful as possible to these new publicly oriented public entities that are becoming internet service providers. We used our formal proceeding to propose a set of rules for the program. Stakeholders commented, we made revisions, and the commission adopted it. The window is opening; opened yesterday. Today is March 13. It opened yesterday.

And so the first round of applications are coming in now.

And then, quick follow-up: how will federal funding for broadband be utilized by the CPUC? How much can we expect, and will these funds be able to make up for potential cuts?

So, just to clarify, I think you're asking about what is likely coming through BEAD, broadband equity access, and deployment, right? So, I do always like to note that California was initially allocated 900 million in that program. Our staff's analysis that we submitted to NTIA demonstrating the extent of the need in California, doubled that allocation to the 1.8 billion that we are expecting to be allocated. We have not been allocated those funds yet.

We've been going through the steps that the federal rules require, which was to submit a five-year plan, a volume one, and a volume two. And those volumes 1 and 2 are under review by the National Telephone Information Administration, NTIA. And so it is only after their review and approval that California will actually receive that allocation. We don't know the timing. We're very much hopeful it's going to be in the next few months.

The thing I'll note, though, to your question is a cut to SB 156 funds to the state funds is a cut. It would have a programmatic impact on the last mile networks that grantee applicants have submitted applications for right now. There is a footnote, and I know that we respectfully disagree with our colleagues at LAO on this, there is a footnote in the notice of federal funding opportunity that says that BEAD funds shall not supplant, shall supplement.

And we take that to mean that we cannot assume that the Federal Government would allow BEAD funds to make up for any cut to the SB 156 program. That's why I focus on ensuring that SB 156 stays intact, even with the budget and the proposed delay that the administration has set out; we think that that won't have any programmatic impacts. That's what's most valuable in my mind to what the Legislature's original intent was.

Did you have a comment?

I just wanted to respond to the comment about the supplantation language that's in or the non-supplantation language that's part of the BEAD Program. The notice of funding opportunity for the BEAD program does include non-supplantation language that says that, as you mentioned, the funding shall supplement, not supplant, funding that's already been identified for broadband infrastructure funding.

If I could go back to the CPU, you had mentioned that they're going to be making awards in June, and that's with the federal funds, correct?

We're not challenging the idea that previous or current appropriations would be subject to that language, but we are saying that prospective appropriations, those that have not been appropriated yet or that are planned for appropriation, could potentially be reduced in light of the additional federal funding. So, just to make that clear.

Yes.

What about the general funds? When will the general fund awards be made by the CPUC?

I'll probably turn to Director Osborn for some assistance with this one. As you know, we received 484 applications for far more than what the FFA fund has in it. And right now we're completing the objection and the rebuttal process. That was a requirement set out for this program as we come to the end of that process and figure out which applications we can begin to fund. We'll use the federal dollars first because they have the fastest timeline associated with them.

Answering let me turn to Director Osborn, on potential drawdown at encumbrance issuance of grants for the state dollars.

Yes, I'm Robert Osborn, Director of the Communications Division at the Public Utilities Commission. And as Executive Director Peterson said, we are going to prioritize expending the capital projects funds, which is about 550,000,00, first because that has a deadline for liquidation at the end of 2026. The remainder of the money is through general fund. It doesn't have the same restrictions.

Thank you very much. And then just. I know you were discussing the BEAD Program and stuff, but do we anticipate that there will be another funding request for that program, or does the CPUC plan to utilize the requested staff to administer the federal BEAD program? Are you going to have a separate funding request?

Oh, as far as a staffing, yes. Yes, we do anticipate submitting a staffing proposal to this body.

A separate one for that?

Yes.

Great. Thank you very much, Mr. Connolly. Anything else? We're going to go on to issue four. Thank you very much, everybody. We're close to the end here. So this is state operations and local assistance, the fall estimate.

I forgot that it was a separate issue. David, do you have an interview?

So, if we'll go relatively quick on the presentation, we'd appreciate it.

David Evans, Department of Finance, for the 24-25 November estimate for the California Public Utilities Commission Universal LifeLine Telephone Services Trust Administrative Committee Fund, also known as the California LifeLine Program. We're estimating that the expenditures for 24-25 they will decrease approximately about 17.6% in comparison to the 2023 Budget Act. So, the total amount will be 345,961,000, and of this amount, 318,000,000 approximately will be for local assistance, and 27.8 million, approximately, will be for the state operations.

Okay. LAO

We don't have concerns or comments about this proposal.

Okay. All right.

Here to answer your questions Chair.

Anything else?

Great. Are you considering how best to leverage the LifeLine program in light of the affordable connectivity program for broadband expiring and that had a lot higher participation?

First off, I'd like to say Rachel Peterson, Executive Director of the California Public Utilities Commission. We hope that it won't expire in the first instance. It is still a live issue in Washington, DC. However, it doesn't look good. I will acknowledge that. Our President, Alice Reynolds, and the Director of the California Department of Technology, Liana Bailey Crimmins, wrote a public letter a month ago or so to the FCC urging that they do everything they can to ensure that ACP stays fully funded.

It is an essential subsidy for millions of Californians. We know that. It is different in nature from ACP, which is a broadband-directed program, while LifeLine is grounded in the Moore Act and was always intended to be a voice-focused program. However, the good news is in thinking about the future and how to continue helping Californians, our communications division has actually run a pilot combining ACP and LifeLine and like to ask Director Osborne to speak about that pilot.

Thank you, Robert Osborne, Director of the Communications Division at the CPUC. So, the ACP pilot began in June last year, and there are currently three providers providing service to about 90,000 participants. So that's something that we have going today. And as Executive Director Peterson pointed out, ACP and LifeLine are not mutually exclusive, but they're also not overlapping. So, I wouldn't compare the subscriber numbers between those two programs. You have some cases where LifeLine subscribers also take advantage of ACP separately and not through the pilot.

Great. Okay, Assemblymember Connolly, anything on this? Thank you very much. We appreciate it. We're going to move this hearing on now. Any questions on the non-presentation items? Okay, we have none. So, we'll go to public comment now. We'll start public comment on the departments in the agenda. Everybody will have 1 minute to speak.

Mr. Chairman: Oracle Gonzalez, on behalf of the California Alliance for Digital Equity and NextGen California, on issue three, we want to urge the Committee to reject the proposed reductions to the FFA account.

We also want to be emphatic that even if the state receives its full allocation under bid, it won't be able to use those funds the same way that it can use the funds in the FFA account because the funds in their bead are incredibly restrictive with over 500 applications and over $4.6 billion in requests, the need for these dollars is unquestionable.

And Maintaining this funding along with the proposed and-a-half $1.0 billion that the Governor proposing to finish the Middle Mile is how this state is going to bridge the digital divide. Now is not the time to go backwards. Thank you.

Thank you.

Mr. Chair and Assemblymembers: Edson Perez with Advanced Energy United. I wanted to first thank you for the great reliability conversation earlier today. I'm here to support DEBA, the DSGs, and the residential solar and storage programs. So I just want to note that, as the Energy Commission noted, those programs were just getting off the ground. The DSG program is just scaling up. The DEBA program is going to dole out funds in Q2 of this year.

These programs are really key test cases of how clean, distributed resources can make the grid more reliable. Currently we rely mainly on dirty energy to get over these emergency periods, so we really need to plan to move away from that for the future. As you know, extreme heat summers are just going to keep getting worse. This summer we may actually have a La Nina event, which may make conditions worse and would strain the grid further.

So we're also looking forward to that reliability assessment in April to look at how that's going to dole out. But the future of the grid needs to be clean and distributed if we're going to meet SB 100 goals. Right. And if we're going to continue leading the world.

Thank you

So support for those programs. Thank you.

Mr. Chair. John Geesman, on behalf of the Alliance for Nuclear Responsibility, a couple of points on the Diablo Canyon General Fund Loan; first, numbered paragraph seven from last July's amendment to the DWR PG&E loan agreement identifies an amount of $800 million as potentially subject to offset from the federal grant.

I would recommend that you familiarize yourself with that number and also carefully review any response to last week's letter from the Joint Budget Committee to the Department of Finance to determine if there are current-year funds that have not yet been dispersed that could be added to that 800,000,000. Second, and more generally, it is inconceivable to me as a taxpayer that DWR has not thoroughly familiarized itself with the terms of the DOE grant agreement. They certainly have the legal right to that document.

Thank you very much.

It is inconsistent with responsible stewardship of the general fund. Not to be more familiar with it.

Thank you.

Good afternoon. David Weisman, Executive Director, Alliance for Nuclear Responsibility, I'd like to thank particularly Member Connolly for his noting that the taxpayers need to be made whole for that missing $300 million between the $1.4 billion loan and the $1.4 billion grant.

His questions take on greater urgency because that federal program, which granted its one and only $1 billion to PG&E, has now closed out its second year without granting a single penny, and there is no surety that that program will be continued in its current form at all at the federal level as a possible source of revenue. Likewise, his concern that DWR responds that well, there'll be a profit of 300 million in the final year of operation would seem highly speculative.

At this point, upon which to depend on repayment. Considering that in the grant application for the $1.0 billion, PG&E admitted having racked up over $2 billion in above-market costs for Diablo Canyon in the preceding five years, which doesn't bode well as a profit center in the future. So, thank you for your continued inquiry.

Thank you very much.

Good afternoon. Kendra Harris, the Climate Center. I'm commenting on equitable building decarbonization. The EBD program is a vital part of California's clean air safety net and one of the best tools we have to provide relief to households facing indoor air pollution, skyrocketing energy bills, extreme heat, and unhealthy living environments by funding whole home retrofits to increase energy efficiency and provide the latest in high-efficiency electric heating and cooling. Cutting EBD funding by 283,000,000, a 30% reduction would mean continued exposure to harmful indoor air pollutants that put our most vulnerable residents, especially children, at risk. Unfortunately, we can't just rely on the Inflation Reduction Act to cover these needs. Federal funding is insufficient to meet California's home retrofit needs. For example, the federal home energy rebates are estimated to reach only 1% of low-income houses in California.

So I just urge you to consider that. Thank you.

Thank you very much.

Good afternoon. Chair and Members: Rebecca Marcus, representing American Farmland Trust in the California Climate and Agriculture Network. I'm speaking on issue one today. We ask that you restore partial funding to the CEC's Climate Innovation program. It is currently the only program in California that has the potential to fund agriculturic programs. Farmers and ranchers need this program to help our state combat climate change and minimize future impacts from droughts and extreme heat.

If done responsibly, it is possible to grow renewable energy while strengthening farm viability, reducing irrigation demand, providing necessary shade, and protecting healthy soil. There are farmers, researchers, and developers ready with projects to go on the ground once funding is available. Thank you.

Thank you,

Michael Jared, on behalf of the Community Alliance with Family Farmers. I'd like to echo the prior comments and, on issue one, urge the partial restoration of the climate innovation program at the CEC. CAP would very much like a piloting of agrovoltaic projects in California. We believe it offers a really win-win for the creation of clean energy, protection of small family farms, and protection of crops, workers, and livestock from the impacts of extreme heat. Thank you.

Thank you.

Amara Eger, on behalf of the Building Decarbonization Coalition, I just want to echo comments made about the CEC's equitable building, decarbonization funding, and maintaining that in this year's budget. We also support any final climate bond package that includes at least $400 million in funding for this important program as we move forward. Thank you so much.

Thank you.

Good morning, Chair, honorable Members, and state partners. My name is Patrick Messick, and I'm here on behalf of the urban, rural, and tribal communities that have been bypassed for generational infrastructure investments by this body and big telecom for generations. Safeguarding the governor's $1.5 billion proposal to complete the MMBI is the only way this once-in-a-generation infrastructure investment reaches many of California's highest poverty, disaster-vulnerable, and most poorly connected communities.

This includes El Toro, South Costa Mesa, North Fillmore, farm worker communities in West Marin and Byron, mobile home parks in Reseda, and fire-vulnerable communities along Highway 178. Fully constructed, the self-sustaining 10,000 middle mile network will foster competition, lower prices up to 90%, and enable economic growth for decades to come. On supplanting FFA with BEAD, it's irresponsible to talk about broadband infrastructure funding accounts as interchangeable.

BEAD has the most restrictive eligibility requirements of any infrastructure funding and effectively disqualifies any area where incumbent monopolies over state service to protect their market dominance. The state's FFA last mile account is the only fund that equitably allocates funding to every county throughout the state based on their proportion of unserved, including those evacuated by the pandemic, which is the directive of these federal dollars. Thank you very much.

Thank you, Chair and Members: Phoebe Seaton with Leadership Council for Justice and Accountability. We work with people in the San Joaquin Valley and the eastern Coachella Valley, folks impacted by extreme and intensifying heat. We align our comments with commenters before opposing cuts to the EBD program. I just want to note, in addition to what they said, the EBD program is one of few programs that moves us forward towards climate resilience, energy resilience, and addressing poverty and extreme health impacts.

If we make cuts to this program, we are leaving the most vulnerable Californians behind, both in our decarbonization goals and in our fight against climate. Thanks so much.

Thank you very much.

Chair and Members. Dan Chom, on behalf of the Port of Long Beach, greatly appreciate your recognition, staff's recognition of the importance and the criticality of getting the $45 million in port infrastructure planning monies out the door asap. Also recognize the great work, hard work of the CEC staff in getting the program off the ground.

Unfortunately, according to the schedule outlined by the CEC just today, there is a substantial risk that the Port of Long Beach will have to pause or terminate the substantial planning and permitting activities it has taken to date at its own expense to get a staging integration facility off the ground. Simply put, the port cannot continue to expend its own limited resources past June without some tangible signal from the state that it desires to continue to partner with the port in meeting its offshore wind goals.

So appreciate your continued support.

Thank you.

Good afternoon, Mr. Chair and members of the Committee. Brian White, on behalf of Offshore Wind California, wants to second the comments that my colleague from the port of Long Beach made. We are at a critical stage right now in terms of, and we appreciate your leadership, by the way, and continue to express the need for doing what we need to do to get offshore wind off the ground. But we are at a critical stage right now.

There are a number of things that need to happen. We appreciate your leadership last year in getting the procurement bill passed through the budget trailer bill. That was critical, but we also need to make sure that we have the actual ports that will help develop these projects. Without ports permitting, transmission, and procurement, we really have a house of card situation, and they really all have to be going together.

So we would support getting that money out the door quicker and also support the need for long-term funding, which is why we support the need for funding through a bond. So we're supporting some Assemblymember Burr's efforts to do that through AB 228, and we look forward to working with the Legislature on this. Thank you.

Thank you.

Thank you, Mr. Chair and Members: Crystal Strait. On behalf of American Clean Power California, we represent the five leases that already have leases for offshore wind. We are very much in the process of making sure that wind is a significant and reliable resource for California's clean energy goals.

The leases have already invested nearly three-quarters of $1.0 billion and started pre-survey work and other items to prepare for offshore wind implementation, which makes it a growing concern about any delays in the state processes for funding, including port infrastructure, central procurement transmissions, et cetera. This is all to say thank you so much for today's hearing.

We really appreciate your comments, understanding that it is a long lead time, but we do need these processes to continue to move expeditiously, and we echo the comments of the previous members about the ports as well and making sure that funding gets out the door. Thank you.

Thank you.

Hello, I'm Andrew Dawson with the California Housing Partnership. We are a state-created private nonprofit committed to increasing the supply of affordable and sustainable homes for low-income households. My comments are about the rules building decarbonization program that were mentioned earlier. Pretty much the same thing. It's a really important program for low-income households in California. Thank you.

Thank you.

Good afternoon. Amanda Gualderama, I'm with CalBroadband. We just wanted to note that we agree with the LAO's recommendations with regard to the broadband programs within the CPUC. We also believe that the CPUC should provide detailed estimates of the number of unserved households that will be connected when the almost $4 billion in program funding is exhausted.

California must be focused and clear in its goal of serving the unserved, and we hope that the Legislature will increase their oversight of these programs to ensure that that goal is met. Thank you.

Thank you.

Good afternoon. Chair and Members: Tricia Geringer with Agricultural Council of California here in support of the Food Production Investment program, otherwise known as FPIP. This small but mighty program is helping local food producers improve their energy efficiency and reduce greenhouse gas emissions as they process our California-grown food. Importantly, the funding is going primarily into disadvantaged and low-income communities, and about 80% of the program funding is going into those communities. We really hope that you take a double look at the reversion that's proposed.

There's an almost $19 million version of current year funds for the program. We hope you take a double look at that, given FPIP is ranked in the top 10 out of all the California climate investment programs when it comes to total GHG reduction and cost per ton of GHD. So, given the effectiveness of it, the fact there is no federal program similar to this, and that it's going, over 80% of the funds are going into DAX and low-income communities.

We hope you'll take a look at it. Thank you.

Thank you very much.

Hello. My name is Marissa Arechavaleta, and I'm with Equinor Atlas Wind. We are the furthest northwest lease on offshore wind off the coast of Morrow Bay. Equinor or Atlas Wind supports the 43 million allocation immediately to the CEC for critical funding for design studies and other immediate needs focused on staging and integration ports. This is needed for investment and economic expansion at these ports to support offshore wind and other clean technologies as ports decarbonize. Thank you.

Thank you very much. And with that, we will now adjourn this meeting.