Senate Budget and Fiscal Review Subcommittee No. 2 on Resources, Environmental Protection and Energy

Senate Budget Subcommittee No. 2 on Resources, Environmental Protection and Energy will come to order. Good morning. The Senate continues to welcome the public in person and via the teleconference service. For individuals wishing to provide public comment, today's participant number is 877-226-8163 and the access code is 6948930. We're holding our Committee hearings in the O Street building. I ask all Members be present, and we can begin the hearing. We have nine issues on today's agenda.

We'll be discussing all the issues listed in the discussion section of the agenda. After discussion, we'll have public comment, and then after that, we'll hold a vote on the vote-only calendar Items 1 through 3. Before we begin, let's establish a quorum. Consultant, please call the roll.

[Roll Call].

Quorum has been established. Just one moment here. All right, let's get started with Issue number 4: Electricity Expedite Utility Distribution Infrastructure Undergrounding Program. Let's hear first from the CPUC and OEIS, who will present the Governor's Proposal. Go ahead when ready.

Good morning, Chair Becker, Senator McGuire, Senator Dahle, good to see you. Thank you very much for the opportunity to be here this morning. Rachel Peterson, Executive Director of the California Public Utilities Commission. I'll speak first about the CPUC's budget change proposal to implement SB 884, the Distribution Infrastructure Undergrounding Program. We've put forward a budget change proposal that we think will enable the CPUC to carry out our responsibilities for a utility submittal of a 10 year or less undergrounding plan.

I'm going to focus today on our responsibilities under the Bill. When a utility submits an application for a 10 year undergrounding plan, SB 884 directs the CPUC to evaluate whether the utility's proposal is cost efficient and whether the utility strategy is valid for retaining that cost efficiency over the lifetime of the plant. We are the rate regulator, and so we always want to know that ratepayers are getting real value, as in wildfire risk reduction, for the money that is being spent.

In today's affordability crisis, that is especially important. Within the nine months of an expedited proceeding, we'll undertake that cost efficiency analysis, take public comments on the proposed undergrounding plan, and assess whether utilities have exhausted non-ratepayer funding sources before proposing undergrounding. If a plan is approved, we'll also use our enforcement authority to see that the utility is making progress against its roadmap and take enforcement steps if appropriate. Over the years of implementation, we'll also ensure that the utility is hitting those cost and risk reduction targets that it set out.

I know that there are questions about our implementation today, so I'll speak to that. And my colleague, Director Caroline Thomas Jacobs from Energy Safety is here as well. CPUC and the Office of Energy Infrastructure Safety held a joint workshop on February 24 and are reviewing the feedback received from stakeholders about developing a staff proposal. For the CPUC, that staff proposal is important because it would set out the framework of how the program is meant to be carried out on our end.

In addition, we're also using the example of the PG&E undergrounding proposal that's pending in our General Rate Case right now before the Commission. And the party's evaluation of the undergrounding plan is contributing to the intellectual background policy work that we're doing to prepare ourselves to implement the 884 program.

And so we've submitted this budget change proposal, and if awarded, we'd prepare a staff proposal to be issued in Q3 of this year that would set out the program as ready to be established in Q4 of this year. Now, that doesn't necessarily mean that an application is happening right away. That's up to each utility that's eligible for the program. But at least establishing the program by Q4 is our present aim.

Thank you very much for the opportunity to be here today, and I'm happy to answer any questions.

Thank you very much. Yeah, would OEIS have additional comments?

There we go. Good morning, Chair Becker and Senator McGuire, Senator Dahle. Appreciate the opportunity to speak with you today. So I'll just add on in terms of our role in the 884.

We're requesting 18 positions. And our plan is, we have responsibility within the PUC's program that is being established, to review the 10-year undergrounding plan, research, select, and manage an independent monitor that will assess compliance with that plan, and assess whether the electrical corporations have cured any defects to that plan or deficiencies to that plan. To complete these statutorily mandated actions, Energy Safety must establish and maintain the regulations and process and procedures to conduct that plan review.

We've requested 15 positions, we'll staff a new division to do the programmatic work, two research data positions to collect, process, and maintain the data related to the underwriting plan, and one attorney that will provide legal support to our new division. So I just wanted to add that additional comment in terms our role in the plan. Thank you.

Thank you as well. Let's see. LAO, would you like to comment on this?

Thank you. Sarah Cornett with the LAO. We find that the proposal provides the resources to implement the legislation as required. The Department must staff up and develop the program. And there is some uncertainty about how many utilities will utilize the program and what type of workload could be foreseen, just based on utility interests. But overall, we don't have concerns with the proposal.

Okay, thank you. Finance, additional?

David Evans with the Department of Finance. No additional comments.

Okay, let's take it back to questions. I'll start with Senator McGuire.

Thank you so much, Mr. Chair. And again, I apologize about the delay. I want to say it publicly, and I said it privately about Committee, was coming from another meeting. First and foremost, I want to say thank you to both directors for the engagement, both OEIS as well as CPUC, on the implementation of the Bill. We have been meeting with the Director of OEIS a few times now.

Ms. Thomas Jacobson, want to say thank you so much to you, to Sandy as well, for your sincere engagement, and talk about how this damn thing is going to roll out and how it's going to get implemented. I'd like to talk about timeline here and with the staff up, especially on the OEIS side.

So, look, as we've talked about, and I have been candid about holding, in particular, PG&E accountable. I have tremendous respect for the women and men who are keeping the lights on each and every day. But what we've seen is, decade after decade, they have underfunded when it comes to hardening of their line, veg management. And if you take a look at, for example, SDG&E, SDG&E has undergrounded approximately about 60% of their lines.

When we take a look at PG&E, it's less than 1%. So that's when we advanced this Bill that would underground 10,000 miles of line in the most high fire threat zones. So, embedded within the Bill are those nine month timelines. So, would like you to back us into that because, get the money--knock on wood--now, right?

Essentially, come July 1. And then if you can back us into the nine month timeline, as it is urgent to be able to hold them accountable and to be able to get these projects moved. Madam Director, if you want to start, Ms. Thomas Jacobs first, and we'll go over through the Chair, if that's okay.

Sure, appreciate the question and certainly appreciate the need for expediting the process. So as soon as the Bill was passed, the Commission and our staff, Energy Safety, started working together to sort of start developing the, let's call it, "the intellectual approach" to how we're going to implement this statute. So work had begun in terms of collaborating on that immediately. What we've done, we also then assessed what the resources would take within our small Department.

As you all are probably aware, we're still a very young Department, just over three years old. So assess the resources that would be required to basically stand up this new capability within our Department. So we've identified those. We also are working on bringing on limited-term positions to be able to try and start this work even prior, if possible, pending your approval of the permanent positions.

We are also working on getting a contract that we're shooting for to get executed hopefully by the summer, so that we can establish process, again, to be able to receive the plans as soon as possible, because we are very aware that it is a timely effort that has to happen.

So we're looking at every opportunity we have to expedite standing up in collaboration with the Commission, the program, and all of the process and procedures that need to be required and established to be able to receive and expeditiously and appropriately assess the plans, so that they can then move over to the Commission for their application process.

So, Madam Director, just looking for some specifics. I just want to again say thank you, because you have been incredibly responsive, transparent, and you have been very clear about your values. You want to get this damn--my words--this damn thing done as quickly as possible. You have not swore. But I'd like to be able to get some additional specifics. So when do you anticipate OEIS will be prepared to receive a plan, and then you can begin process?

Yeah, so what we've currently got underway, and again, some of this is dependent on, I don't want to presuppose approval of the resources, but this summer, if we get the contract in place, get that executed, we'd be able to start the work of developing the, we call them guidelines. So the statute, government code, provides us the ability to propagate guidelines, think of them as regulations.

That'll be the vehicle, if you will, that establishes the process for us to receive the plan and provides guidance to the utilities on what and how they should create those plans and submit them to our Department for review. So as soon as we have that contract in place, we will start working on that. So call that Q2/Q3 of 2023, to initiate the guideline development process.

Pending your approval of the permanent resources, we are also preparing all of the paperwork, if you will, to be able to immediately hire the roles, the positions that were authorized--again, pending your approval--so that we can, in the late summer/fall, hire the positions, to then combine that effort with the contract resources to develop the guidelines. So come early 2023, sorry, 2024, we should be able to have guidelines well along in development and then be able to receive the plans later in 2024.

Because I think that the piece that--and I will not monopolize the conversation, I promise I'll yield my time--but I think that the piece is PG&E can't even submit plans until you're prepared to be able to take them with the guidelines. So I just want to repeat on what I'm hearing here today, and understand that this is a bit squishy in regards to the exacts.

So you believe that you're going to develop the guidelines that will allow you to be able to have that framework there to receive the plans done sometime by the end of the calendar year 2023.

Into early 2024. Again, it's pending the resources, both the contract and the people. So I just want to be clear about that. But that's. Yes.

Okay, so into 2023, sometime first quarter 2024, is that?

Yes, we would be shooting for around that again, assuming we can get the contract and the people.

And then as far as receiving the plan, once you have the guidelines in place, you would be prepared to receive the plans from PG&E on the undergrounding. And I know I'm picking on PG&E right now because of the Dixie Fire, the Thomas Fire, the Camp Fire and the Kincade Fire all burned thousands of homes, killed Californians and tens of thousands of acres. So that's why I'm focusing on that. So you think that you'll start taking a proposal for a plan in?

I don't want to get too far ahead of the process, because I do want to allow, because it's really important for us to have a stakeholder process. Right? In terms of developing the guidelines. So I'm giving you the direction of what we expect in terms of guideline development, but part of that process will be establishing a schedule.

What I can commit here today is that our goal would be able to have that schedule be as soon as possible, and it would be sometime in early to mid 2024.

And I'm not at all trying to be crunchy on this. And again, I want to say thank you to the Director, because you have been nothing but accessible and willing to be able to talk. And I think we share values on this. But what I want to ensure is, one: I think the resources are on the table. And just assuming, since it's a thumbs up all the way around on the resources, that we're actually going to be able to get these high fire-risk lines underground.

So, I say that is, if we can't let two fire seasons pass before the state actually starts the process. Right? We have a fire season coming up and what I think that we need to shoot for, for a goal, and you are the Director--all we have is the power of the purse--is ensuring that before next fire season you're starting to process. Is that a fair time estimate?

I think that's fair, absolutely. I do want to add just so that there's clarity that the plans are not preventing the utilities from undergrounding today. Right? So we received in March the next three-year Wildfire Mitigation Plans, which PG&E specifically very much does, yeah, does include undergrounding miles.

So I just want to be clear that the timeline of receiving the 10 year Underground Plan should not be in any way hindering the utilities from already moving as expeditiously to harden their infrastructure including undergrounding through their Wildfire Mitigation Plan reviews.

Correct. I mean, they're moving on the hardening now, right? And I think their next goal is, I think, 600 miles of line. I think that's what they have stated.

So for 2023, they've committed in the plan, and we're evaluating the plan. So I just want to be clear that we haven't approved these, but what they have submitted for our review is 350 miles this year, 450 next year, 650 the following year. And then they also committed to, it's going to be a total of roughly over 2000 by 2026, is what is currently before us in the wildfire mitigation plans for 2026 as well.

Which would bring them up to a total of, I think, 600 miles of undergrounded lines by the end of this year total.

This year, yeah.

Okay. So look, Mr. Chair, I appreciate your willingness to be able to have this conversation. It has been disastrous on the North Coast, it's been disastrous in the north state where you have, there are three major reasons for wildfire in the state: lightning, vehicles and PG&E. It's the honest-to-God truth, and we have to hold this utility accountable. And I also know there's challenges down south as well.

But in particular, this utility has to be held accountable and we have to do everything we can to be able to keep California safe, because if we're not doing it, they're not going to. So, Madam CPUC Director, anything you'd like to be able to state?

Thank you very much, Senator, for the question. And I'll add a few pieces to what Director Thomas Jacobs said. So first, as to timing of the program. So for us, as I noted, the important thing is to put out a staff proposal that sets out the framework and structure, including a timeline for the program. So once that proposal is out, and under our process, the commissioners have to approve it, so that proposal and vote would hopefully happen in Q3 of this year.

That means the program is effectively open and live. However, as we know, the Office of Energy Infrastructure Safety has that first important role of taking in a plan. And so, as Director Thomas Jacobs said, their office would work at speed to create the structures to take in the plan.

What our teams are doing, and I think you'll hear about this in consideration of the next budget change proposals, is an extensive amount of coordination so that the CPUC staff team, when a plan is submitted, is already participating with the Office of Energy Infrastructure safety team to understand their evaluation of the plan, to get ready for the moment that a utility submits that application to us, because then the pitch clock is on us for our own nine months.

And so we will do everything we can to get ready behind the scenes to understand their analysis and get ready to evaluate the application when it is submitted to us. So I hope that speaks to your timing and the nine-month timing question. I'll add to the overall picture that PG&E itself. Fully, fully agree with you, Senator, on holding PG&E accountable, and we have done that in multiple ways at the Commission.

And one way that we're also doing it is in this close evaluation of their Undergrounding Proposal that they've submitted in the General Rate Case. That is currently a live case. It's under review and has been heavily litigated by the stakeholders. And we do anticipate a decision on that General Rate Case, including the amount of miles that they've proposed within that GRC. And so there is, as Director Thomas Jacobs said, there is already a fair amount of proposal and consideration going on.

I will note that one thing that we also take very seriously is ensuring that ratepayer value is there, so risk actually reduced via undergrounding and via other system initiatives for the dollars that are being spent. And so that's the nature of our review that's going on in the General Rate Case right now.

Yeah, and I think in a previous rate case, I think what it showed is something approximately--if they continue status quo on hardening veg management, et cetera over the next rate case--I think it was about 30 bucks per month, and under the undergrounding it was about $16.30 per month. So I think that was some initial figures that came from the CPUC. So again, status quo has not worked, and only this focus is on those 10,000 miles in the most high fire threat lines.

And I think that we can do both--of get these lines underground and advance a more efficient plan for ratepayers as they're already hurting. But again, it's a little less than half of the cost if we get these undergrounded, and I know that was some preliminary figures from the rate case that had been in front.

Thanks.

No, thank you.

Senator Dahle.

I just want to thank you for being here today. Thank you, Mr. Chairman. Just a couple of questions in this area. I didn't support Senator McGuire's bill, but I do support undergrounding in certain areas, and so I wanted to just--because there is a huge cost and it depends on the--I used to be in construction and built power lines, quite frankly--depends on the topography that you're going through is really to determine the cost of what it is that drives the cost, basically.

If it's solid rock, you're going to be paying a lot more than in ours if you're just plowing in a line. I'm very conscious of the fact most of my calls have been--I mean, obviously, we had the Dixie Fire and we have a combination, and I, in no way, shape, or form am here to defend PG&E because they have done so many things wrong.

But to compare them to SDG&E where it's two different types of landscapes and two lot different topography, quite frankly, in different service areas, so I don't think it's fair to say, you know, 'hey, SDG&E has done all this,' and when it's typically homes and different--it's just a different. We have literally a lot of miles. And I want to just touch on this.

And I know that the next issue is something I might want to focus on because it's vegetation and it's also hardening the infrastructure without putting underground as well. But my question is, they're putting forth their suggested areas where they want to underground--that's what you're saying. And then you're evaluating those now, is that correct?

Yeah. Which one would you like to--

Okay.

Either one.

Either or.

I can go first.

Sure, go for it.

So, let's see. So we are evaluating today a program that they've presented in their general rate case. That's one program. What's coming via 884 is PG&E's--I believe--incremental program on top of, in addition to. Now, I actually think the law is structured very well in the sense that it requires us to continually examine and enforce cost efficiency over the ten years of the program.

And cost efficiency means every year ensuring that the utility is hitting those per mile cost targets, which actually should change over time because if they hit the highest risk areas first, they've reduced risk there. The next set should be of lower cost, higher value in that direction for ratepayers. So there's an evolution over time, but we're meant to monitor and enforce and ensure that that evolution actually happens.

And if they slip and they don't meet the cost or value targets or the risk reduction targets that have been set out at the outset, then that's where we step in and say, 'okay, you are not'--well, I don't know what we'll say, but really look and evaluate and ensure that the program continues to deliver that value. So that's how we're anticipating implementing over the course of an 884 program.

And if I could add, so through the Wildfire Mitigation Plan process, right, that has already, already gone--we just finished our first three-year cycle and now we've just got plans for the next three-year cycle--what we're evaluating through that plan, which will then feed into this ten-year undergrounding plan through the utility process, is the risk modeling and the risk prioritization, but it's not at the individual project level.

So I think your question was, are we sort of approving specific projects, specific miles, if you will. We're looking at the energy safety through the Wildfire Mitigation Plan. We're looking at it what we call at the initiative level, so they have an initiative to harden their infrastructure. And we'll look at how are they identifying where their risk is and specifically PUC--I mean, sorry, PG&E--does it through--yeah, Freudian slip--so through the CPZ, right? They call it a CPZ, circuit protection zone.

So they segment their circuits into certain areas and they'll say, 'okay, this circuit zone, CPZ, has this rank based on our risk modeling, and we're going to target our top priority risk segments for our hardening.'

So we're not looking at the project level, but we're looking at the programmatic level and making sure that they have a smart way of identifying where their risk is and how they're prioritizing their risk when they're then selecting individual projects later in the process, which ultimately--and will get put into the plans--to then target where those projects go.

Okay. So I'm going to repeat back what I think you said, so we'll make sure we're on the same page. They're putting forth the plan. You're not micromanaging the plan. They're telling you, 'hey, these are the areas where we want to target in your CPZ zone.' And then later on you're going to come back.

And the reason I asked this question is because I don't trust PG&E at all when it comes to like, they'll pick the easiest place to go and say, 'we've undergrounded all this,' but I know there's areas where the wind is going to blow and that's where we have the problems is where we get high wind days and we have the ability for them to actually start a fire. We can't control all the other things: people, lightning, all those other things.

We can control two things: we can control hardening the line and we can control the fuel loading that's out in these wildlands. That's the two things we can do, which we need to do. This is focusing on that hardening. So I don't trust them to do it and do it in the areas that are where it needs to happen first because it maybe costs more to do it in those areas.

That's the reason they'll go somewhere else and they'll come back and tell us, 'hey, we've did 600 miles when it was plowing it in real easy where the wind may not be blowing.' So the risk is what I'm looking for, is we want to mitigate the risk, the highest risk first. Is this process going to do that? Are they telling you where we're going to go or are you actually going and finding out where the risk is the highest?

So what our Department does in evaluating all of the utility plans, right--so this isn't one individual utility specific, but I understand and appreciate your interest and focus--we look at how are they doing their modeling. And I say 'them;' it's all the utilities. And the large utilities are, I will just simply put, more mature in their ability to do risk modeling than the smaller utilities. And so our team evaluates how are they developing that modeling, and we push them to your point. Absolutely.

We always are asking deep questions on exactly how are you building out your models and are you including likelihood of ignition? Are you including consequence? And then we issue, through our evaluations, we issue--either we can require revisions to their plan because we actually don't think they did something they needed to do, or if we approve a plan, we can say, hey, we've approved it because we think this is adequate per the parameters that we set out for approval.

At the same time, we want you to continue to improve in these areas for your next plan. We call them areas of continued improvement. And specific to PG&E, we have, last year we required them to revise their plan because we didn't feel like they were prioritizing their underground in the highest risk areas. So we had a revision notice, is what we call it, and we required them to commit to more of how they're focusing and prioritizing. So to your point, absolutely.

We don't take it at face value and just say, 'approve.' We dive deep and we push them. We also through that area of continued improvement process, right--because every year they're learning and changing--we are also requiring them to continue to detail out how they are targeting the highest risk areas and how they define highest risk areas.

Perfect.

And then we hold them and we do do compliance as well. So we look back and then say, 'you said you were going to do this. Did you actually do it?'

Awesome. Thank you. The last question is, I'm assuming TURN and those folks are in there weighing in on the cost of--they're not my favorite agency either, but you could give energy away and they wouldn't be happy about it. So who's monitoring the cost part of it? Because that's going to be ratepayer costs that eventually pay for that.

Well, so within the 884 program, within a general rate case, first and foremost, it's our staff, it's CPUC staff that's conducting that kind of ratepayer value analysis, but then, yes, our proceedings have a lot of participation and litigation interests and I assume that a number of entities that are concerned with ratepayer costs would participate in an 884 application, too.

Okay, thank you.

Senator McGuire.

Yeah, and I'll be really quick. Look, the bill describes where utilities have to focus. They have to focus in tier two, tier three, high fire threat zones, the most high fire threat zones that we have in the state. It's embedded in the bill. That's where the utilities have to be able to do the build first. In addition, they have to build in rebuild areas because what we've seen with rebuild areas, rebuild areas typically burn twice, sometimes three times.

So you have three focus areas within the bill: tier two, tier three, and rebuild. In addition--and this was a big fight at the end--an independent monitor is hired by OEIS. Once we have a budget approved and a scope of their undergrounding plan, that independent monitor is responsible for holding the utility accountable. The monitor is chosen by OEIS, not the utility, and then every December, that independent monitor turns in their report about the efficacy of the project. Have they stuck to budget?

If they haven't stuck to budget, here are the penalties. Have they stuck to the plan and the scope? So, again, trying to be able to create as many safeguards as possible and taking a worst first strategy within the bill. And again, thank you to the directors and Mr. Chair, and to the Vice Chair.

Well, thank you. I want to thank particular Senator McGuire for his leadership on this--obviously critical importance. I remember hearing that PG&E has enough wires to circumnavigate the globe, and so the prioritization part of this and the risk focus is all critically important. And I appreciate, again, him for his leadership, appreciate all of you for being here, and with that, we're going to move over to the next issue, which is Issue Five: ongoing wildfire safety implementation, and like to hear from both of you on this issue as well.

Yeah, you want to go first? Go for it.

Thank you again, Chair Becker. All right, thank you for the opportunity to be here and speak to this next budget change proposal. The CPUC's nine proposed--excuse me--29 proposed positions are continuations of positions that the Legislature first approved in 2019. When we received these positions for phases three and four of our overall wildfire safety and CPUC reform efforts from fiscal year 2020 and 2021, we promised to return to you, the Legislature, with a workload assessment of whether the work for these is permanent and ongoing.

Our assessment is that, yes, it is permanent and ongoing. Our workload to ensure a fair allocation of catastrophic wildfire damages, which we set out in our BCP then as phase three and achieving a more effective CPUC with the tools to manage a changing utility market, phase four is what I'll describe today. As we have already been discussing, wildfire remains the single largest risk faced by electric utilities in California.

And as a state, California is on a mission to reduce that risk, and the CPUC is part of that mission. We've achieved a significant amount of mitigation of utility-ignited wildfire risk through the tools and expectations set out in AB 1054. Those tools focus on utility wildfire cost review, enforcement, and the CPUC's organizational effectiveness, including coordinating with the Office of Energy Infrastructure Safety. While there's a good amount of progress, we as a state are still facing an economic and environmental landscape that's changing in real time.

The CPUC is presently handling 33 billion dollars of proposed utility wildfire risk reduction costs in numerous active proceedings. We're actively managing compliance and enforcement of risk reduction strategies in real time, such as public safety power shutoffs and fast trip. And even while we're doing this, the risk is evolving because of the unfolding impacts of climate change that we are living through now in California. And our work is critical because wildfires themselves can impose enormous economic costs that can be even more difficult for Californians to bear.

And all this means that close evaluation of costs, fair allocation of costs and effective enforcement are essential tools in California's toolkit. Now, to speak a little bit more specifically about the responsibilities and directives set out in AB 1054: we're responsible for financial oversight. We have to seek to ensure that costs ratepayers pay are in fact reducing the risk of catastrophic wildfire ignition. As I mentioned, we've handled 21 wildfire-related cost recovery proceedings since July 2019, where the total amount being litigated has exceeded 33 billion.

We anticipate these recovery applications from each electric utility annually on an ongoing basis because of the continued risks and impacts of wildfire and climate change. We have conducted expedited proceedings and issued an average of two complex financing orders per year under AB 1054's securitization provisions. We regulate the electric utilities to constantly seek financing structures that will yield the lowest possible costs for ratepayers. The eight orders we've issued represent savings of about 1.8 billion to date for ratepayers.

Our second major responsibility under AB 1054 is to enforce our laws and rules against utilities that fail to perform reasonable management of their electric systems. We've issued 11 enforcement actions, which include notices of violation, penalties, citations, consent orders, enforcement orders, and settlement agreements related to wildfires and safety incidents since July 19, 2019, totaling about three billion in penalties that are being paid by shareholders of the utilities.

Our staff executed a year and a half of enhanced oversight and enforcement of PG&E specifically because that utility was failing to conduct vegetation management in the highest wildfire risk areas of its service territory. That oversight resulted in verifiable change of operations to make PG&E safer, and this enforcement work is permanent and ongoing. As we've just been discussing, the utilities are still facing an enormous risk with respect to their operations and their electric systems in California.

And then third, under 1054, we coordinate on wildfire risk reduction efforts with the Office of Energy Infrastructure Safety. We have received and produced for vote 23 wildfire mitigation plans for our commission since July 2019. OEIS will continue those WMP annual reviews and approvals, and the Commission is statutorily tasked with ratifying the energy safety actions on those plans. We're also tasked with approving each year any additional requirements for wildfire mitigation plans, performance metrics, and the processes for conducting safety culture assessments and wildfire mitigation compliance.

And so with that, those are all the reasons that we're requesting permanent authority for the 29 positions presented in our budget change proposal. Thank you again for the opportunity to be here today, and I'm happy to answer any questions.

Thank you. Maybe we'll hear from Director Thomas Jacobs as well.

Thank you. So, since we are still a very young department, I was going to give a quick background on kind of who we are and how we got established, an update on the impact the Department has had since we have just completed the first three-year plan cycle under our department's purview and then obviously provide an overview of the resources that we're requesting. So Energy Safety was created through Assembly Bills 1054 and 111.

We were initially established as the Wildfire Safety Division, embedded within the Public Utilities Commission in January of 2020. 18 months later, we then transitioned over in July of 21 into a new department under the Natural Resources Agency. And in January of 22, the Underground Safe Excavation Board, formerly known as the Dig Safe Board, moved over into our department from the State Fire Marshal's Office. So we are effectively just over three years old. We have several core regulatory responsibilities.

We establish guidelines for and evaluate the wildfire mitigation plans, assess compliance to those plans, and conduct safety culture assessments. We issue safety certifications to corporations that request such certification, and meet specific prescribed requirements. Through the Underground Safety Board, we have responsibility to establish safe excavation standards, provide education and outreach, and investigate dig-ins that result in damage. And then, of course, as of September 22, have responsibility through Senate Bill 884 now for reviewing the ten-year undergrounding plans that we spoke of earlier.

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

Since our inception in January of 2020, Energy Safety has hired, trained, and equipped all of the initial staff, developed the operational procedures and regulations to conduct our work, transitioned that original group to Natural Resources, and then stood up the necessary administrative wraparound services required to run a department. While building and transitioning the new department, we have evaluated and approved 24 wildfire mitigation plans. These include five where we've required revisions to the plans before approval. We have also rejected three plans and required resubmission.

That's part of the 24. Through these evaluations, we have driven utilities to improve their ability to understand where the highest wildfire risk is on their grid, establish clear practices within the utilities to target those mitigation projects to that highest risk area, and adjust their grid operations, asset maintenance and inspection and vegetation management practices to more quickly and directly address that wildfire risk. We have conducted more than 57,000 inspection activities to date and identified and directed corrective action on over 1,000 defects and violations.

A few themes from these defects and violations include damaged infrastructure, unsafe vegetation, and data accuracy issues. We have also established expedited timelines for the utilities to fix these issues that we've identified, the defects and violations. And we have completed our inaugural safety culture assessments in 2021 and have completed our assessments in 2022 of last year, and we'll be issuing the 22 reports very shortly.

I have a number of stories of how this work has changed how the utilities address wildfire risk, but for time, I'll just mention three. Large utilities now utilize sophisticated wildfire risk models that enable them to risk rank, as I mentioned earlier, segments on their grids to be able to identify where the highest risk is and prioritize their mitigation projects. They have also planned requirements, have also driven utilities to rethink how they're organized as corporations and assess the daily weather risk across their system.

For example, the large utilities all now have distinct meteorology units within their organizations and have senior leadership positions that are responsible for managing wildfire risk within their organization. The last major change I'll mention, though there are many, is probably the most interesting, but actually not surprising.

The plan requirements have driven the utilities to build new enterprise IT systems within the organization to collect, manage, and analyze the data that they need to be able to understand where their risk is and then ensure they have timely, accurate information upon which to make risk-informed decisions.

Those are just a few of the ways that the new wildfire safety regulatory framework that 1054 and 111 stood up has driven meaningful change over the last three years in how utilities operate, maintain, and build California's electrical grid in light of evolving wildfire and climate risk. And while I'm proud of the work Energy Safety has done over the past three years, I believe there's more that we need to do and we need to do it faster.

To meet our minimum statutory responsibilities on time and with quality, the Department needs additional permanent positions to implement these wildfire safety requirements. Specifically, the Governor's budget requests 59 positions in addition to the 18 we have already spoke about, 59 positions and the associated funding to meet these unmet needs of the Department. Specifically, the majority of the request--29 positions--is to augment our resources to inspect and assess compliance to the wildfire mitigation plans.

We currently have 11 permanent positions in compliance who are responsible for inspections, audits, investigations, and regulatory development for compliance. Given the increase in wildfire mitigation activity over the past three years, our compliance division has not been able to keep pace with the building workload. To meet the unmet needs, we are requesting positions that will enable us to concurrently inspect and audit the utilities while investigating reported ignitions that we receive. It would also enable us to have dedicated staff to develop compliance standards.

Also, the additional inspection positions specifically that we're requesting will enable us to pair inspectors up to address safety concerns that we have when inspecting in remote locations. We are also requesting ten positions with our Electric Safety Policy Division, which is responsible for the wildfire mitigation plan evaluations, culture assessments, and issues safety certifications. As I mentioned earlier, our statutory responsibilities have a specific timeline and cadence requirement. They each must be completed in a certain order and it depends significantly--we currently depend significantly on contract resources.

The ten positions will enable us to conduct safety culture assessments in a timely manner and ensure we have adequate staff coverage for the wildfire mitigation plans. The positions will also eliminate the need for contractors for safety culture assessments and some plan evaluation work. Bringing the work in-house will save us approximately 2.7 million in contract funds and have the added important benefit of enabling us to build institutional knowledge within Energy Safety staff. We're also requesting two positions to augment the Wildfire Safety Advisory Board staff to enable the Board to more individually tailor--

If you could start to wrap up?

Move forward.

Sure.

So I'll wrap up with the last few. We're also requesting four positions in the Underground Safety Directorate to establish a training unit. The Underground Safety Board is required to provide education and outreach through preventative training. However, they do not have the resources to perform this training. Since a large portion of their target audience is Spanish speaking, we are also requesting funds for Spanish translation of the training materials. With that, I'll wrap up, and I appreciate the time and happy to answer any questions.

Thank you. I'll turn to the LAO for any comments.

Thank you. Sarah Cornett with the LAO. We don't have concerns with this proposal and find that given the workload needs, that it makes sense to make these positions permanent versus temporary.

Thank you. Anything else from Finance?

David Evans with the Department of Finance. No additional comments.

Jamie Gonsalves from the Department of Finance. No additional comments.

Thank you. Let's start with Senator Dahle for questions.

Well, I appreciate the information on what you're doing. I actually went down and toured in Oakland, the facility of the wildfire--mapping, wind. Pretty impressive stuff that PG&E has available. But I want to talk about the proposal for the positions. I'm in favor of that, but when you look at the trailer bill language, actually--it's in Section 5a of the trailer bill--it removes a bunch of--actually, I'll just read it to you.

'Following the end of the compliance period, the Office shall'--was what was in the--'consist with its authority to'-pursuant to paragraph one of subdivision of Section 35--'promptly audit the work performed by and on behalf of the electrical corporation.' Went from 'shall' to 'may.' It was, 'you shall do it.' This is an area where we had grave concern.

Under different leadership at the CPUC, over the years I've been here, they told us they were doing the work and even PUC didn't go out and do their job of actually checking the work. And so this trailer bill language is actually allowing you not to annually do it or it's trying to say biannually. So the trailer language and your presentation don't make sense because if we're going to make the positions full time, when I read that, I was like, okay, yeah, great. We need to get the work done. And I will just tell you personally, I have three different--for my--I live in a rural electric, my farm is in PG&E, and I rent here in Sacramento from SMUD.

So I have three different companies that supply my energy for what we do. The rural electric is the best, and I'm debating whether which one of the other two utilities are worse. We've been without power more in Sacramento than we have anywhere else. But on my own farm where the PG&E lines come through, we were without power in my community more times for public safety shutdowns than I think anywhere in the state.

And it's because the lines haven't just been upgraded, their poles literally have moss this much--they look like trees. They're so old. And so I know there's a lot of miles to do. I get that. And it's in a field, which is great. It's not in the timber, but there are lines on that same line that are in the timber.

My point is that, again, with lack of trust of the utilities saying they're doing one thing and then we're not backing up--my constituents over the years, which have experienced the Camp Fire--I had the Camp Fire. I had the Zogg Fire. Now, these are not fires--the Carr Fire was not a fire by the utilities, but Camp Fire was and Dixie Fire were both caused by utilities. And so I don't have a problem giving you the positions, but you have to do the work.

You can't lessen the amount of the work, and that's what this trailer bill language says. So I highlighted this. I want to talk about that because that's very important that we actually make sure they're doing the work. So can you respond to the trailer bill language which basically guts all the responsibility of your organization to go out and make sure they're doing the work?

Appreciate the opportunity to respond to that because I would just want to be really clear that the proposed change that we are is not to try and eliminate our ability or our duty to do the work. It is to make it so that we can prioritize based on risks. So currently the 'shall' means that we have to do it for all of the utilities. There are two utilities that literally have no vegetation, right?

So it means that we're doing work and having to issue formal letters and such on substantial vegetation management audits on utilities. That's not where I want our department to spend our time. I do want our department to spend our staff resources and time on the utilities where there is high risk. So the discretion that we're requesting through the trailer bill is so that we can actually dedicate and focus those resources in the areas where there is the most impact on risk and not be necessarily required on all utilities every year to do a perfunctory review of their veg management when there's not much there to review.

So I just want to assure the Senator that it's not to try and provide us the ability to not have to do the work, but that we want to be able to focus our resources in the areas where it's most valuable. And on the safety culture assessment one which is where we move from an annual to a biannual, is what we're suggesting.

And I just want to be clear: the resources we're requesting that we put forward was with the assumption of those changes, we would require more resources if we keep the cadence that the statute currently has. So the reason we want to do that too, again, the annual cadence safety culture is something that is deeply embedded, and it takes time for actions to present themselves in change and progress.

And what we want to do is have the discretion to where--again--focus our safety culture assessments in the areas where we believe that it needs our attention and then allow the time for the recommendations that we put forward to actually take effect and result in some change for us to then do an assessment again. The annual pace that we currently have, as I'll give the example as I mentioned in my remarks, we can sometimes just on the way that the flow happens, back up our assessments on top of each other where there's really not much time for our recommendations for the utilities to then implement those before the next assessment.

So the goal is in no way to diminish the focus in those areas to do the work, but to be able to then focus the resources to have more impact on those actions.

Okay. Well, I would suggest then in the trailer bill language that you talk about that because, trust me, we will be back and we don't have a lot of faith and--I don't, I should say--but there are Members who've been around long enough to live through this horrible situation where we had the--I can't remember--I want to say Zogg Fire, which was the original one in the valley that lost 5,000 homes. This was before the Camp Fire, right.

And we knew that the utility caused the action and we're starting to realize, hey, there's an issue here, right? And then we started moving on legislation to actually make sure that the PUC--we're like, 'hey, what's going on with the PUC, right?' Well, of course, as a Legislator, we get new members of the PUC in here every couple of years.

We get them every time there's an administration change, every time there's something goes wrong and they change people and we're still here at least for a little bit longer. So I would suggest in this language that you talk about what you're doing because there's not a lot of trust--at least for me--on the ability to be able to make sure we hold our feet to fire. This is including all utilities.

So you should say we're going to focus--on the ones that are buried lines in San Diego, I agree with you. I don't think you need to go look at it every year, but I think you need to make sure that the utilities that are in areas like Monterey where there's still lines and it's on the coast and there's trees there--or there's vegetation, I should say, that's higher fire risk--we need to be making sure we're doing our job there.

But on those lower places, we need to put that in the trailer bill because this basically gives you blank ability to not go--I'm not saying you're going to do that, but it has happened, and that's why we should make sure that we cover our bases because I'm going to bring this up on the floor. If it's not changed, I'm going to bring this up on the floor when the trailer bill comes through and say, 'hey, look; we're basically putting more money in and getting less.'

I think it's a good idea to explain what we're doing so the rest of the Legislature who's not watching this and not paying attention--expecting us to do our job--will know.

Thank you. Could you make perfect sense when you say, why would I go back if there's no work?

I think that makes--that's common sense, but we need to put that in the language because this is very broad.

Thank you all for the discussion and presentation here today. With that, we're going to move on to the next item. Thank you very much. Okay, we're now going to hear Issue Six. This is the Public Utilities Commission customer renewable energy subscription programs and the Community Renewable Energy Program implementation of AB 2316. And we will first hear from the CPUC.

Thank you. Thank you, Chair Becker. Again, Rachel Peterson, Executive Director of the CPUC. Thank you for the opportunity to be here to present this budget change proposal. I'll just start very briefly and then turn to our deputy Executive Director of Climate and Energy Policy, Leuwam Tesfai. We're proposing staff to implement the objectives of AB 2316 the customer renewable energy subscription programs and customer renewable energy program.

We are interested in implementing the objectives of this law with an eye towards achieving ratepayer value by evaluating programs with low uptake, increasing renewable energy resources to contribute to our clean energy goals and reduce greenhouse gas emissions, and improving access to clean energy programs for low-income communities in particular. Thus the broad overview of how we're approaching the mandates of the law. And with that, I'll turn to Deputy Executive Director, Tesfai for more detail.

Thank you. So good morning, Chair Becker and Senator Dahle. Again, Leuwam Tessai, Deputy Executive Director for Energy and Climate Policy at the Public Utilities Commission. Good to see you again today. And thank you for the opportunity to share more on the status of AB 2316 as well as our staffing requests here. So the requested staffing and consultant resources as part of our budget request include critical technical and administrative support to assess existing renewable subscription programs as required by the Legislature in AB 2316.

These resources are essential to designing and implementing a new program in accordance with AB 2316 and California's other clean energy goals.

In this request, we're requesting position authority for five positions as well as consulting services in order to conduct such actions, including making sure that new programs do not result in additional cost to ratepayers, to increase the amount of renewable energy resources contributing to the state's clean energy goals and electric system, reduce barriers to access to provide financial incentives for low-income customers, and reduce greenhouse gas emissions from California's energy sector.

Since 2015, the CPC has launched several community renewable energy subscription programs and some have had lower uptake. And so through this Bill, we'll be able to assess those existing programs and potentially create a new, improved program. So with that, I'll conclude my remarks and I'm happy to take any questions or provide further information.

Great. Thank you. I'd like to now turn to Ms. Cornett, LAO.

We find this proposal to be appropriate, given the requirements of AB 2316 as intended, to evaluate existing renewable energy subscription programs and have no further comments.

Okay, Mr. Evans.

David Evans with the Department of Finance. No additional comments.

Great. I do have a number of questions on this and thank you for your presentation. I guess the question is... we'll start. Is the Commission on track to implement this AB 2316 in a time frame that allows the program to capitalize on EPA and Treasury incentives in the Inflation Reduction Act?

Thank you, Chair Becker. So we do have an open proceeding that is actively working on implementation of AB 20316. Stakeholders to that proceeding have agreed to an expedited schedule in order to reach a proposed decision by Q3 of 2023 in order to be on time for the initial application deadlines for the enhanced treasury investment tax credits and the EPA competitive grant funds.

Recent treasury guidance states that in order for a project to be eligible for the enhanced ITC or investment tax credits, it must be placed into service within four years after federal application approval, which would be as early as the third quarter of 2027. So as such, it is reasonable that the potential California-based community solar projects from this proceeding, or community green tariff solar projects would be able to make this deadline with the resources that we have requested.

Let's see. And how do you intend to secure competitive grant funding along these lines at the EPA to expand access to community solar and search for low-income and disadvantaged communities? Do you think California risks not being competitive for federal funding if we do not appropriate state funds?

Yeah, great question. So this has been a multi-agency approach in the Administration. So just to start, the infrastructure bank or IBank and GO-Biz have been preparing for the notice of funding opportunities and are coordinating a multi-agency working group to develop our strongest response. U.S. EPA's guidance was released just yesterday and indicates that both existing and new solar programs can be supported with this funding across both loan and grant based strategies.

And the working group will identify the best, highest leverage paths to capital deployment consistent with the federal mission of solar for all. Importantly, U.S. EPA is indicating it will request notices of intent from all prospective applicants, with state governments expected to file first, followed by municipalities, tribes, nongovernmental organizations as well. U.S. EPA is indicating that the notice of funding opportunities will be released as early as June and we will be prepared to respond on a Q3 to Q4 time frame.

So even though that the CPUC does not act as a federal grant-pursuing agency, we are working closely with other entities across the Administration as well as through this proceeding to be able to set up projects for effectively leveraging these federal opportunities.

Okay, I do think that is critical. Guess along these lines, there's certainly feeling that California is far behind other states in scaling community solar and making it accessible. So how is the Commission intending to address that and our lack of success with current programs?

I think it's a really good question so the current open proceeding is evaluating California's success in decarbonizing our grid and meeting our renewable portfolio standard, of which California has been largely successful and a leader nationwide.

So solar and renewables overall, not just community solar, but pursuant to this Bill, we are determining how community solar fits into the needs of the grid. Rate affordability concerns as well from the Legislature and from customers is really important as part of that and the current procurement strategies to meet the requirements of SB 100.

So though we might not be the leader in community solar, we are the leader in renewables, and we're working very hard through this proceeding to be able to create an ecosystem for community solar to fit in with that, while also managing our affordability concerns and grid needs.

Yeah, that's good. I get the perspective on solar overall, but certainly, we're hearing from many environmental justice advocates about the unique potential for community-scale renewable and then to provide deeper benefits, enhancing Bill savings for low-income customers, and to have these kind of community-owned projects and projects located in and directly serving disadvantaged community members. So I guess just ask you again, how is the Commission thinking about actualizing these kind of benefits, and what do you think is needed specifically to do so?

Yeah, these concerns from the environmental justice advocates are very important to us. And within the open proceeding, we are actively looking at quantifying and establishing the tangible, targeted benefits of community solar, but in combination with our other policy goals, like reducing rate impacts on non-participating customers in these programs and providing clean energy and grid benefits.

So, though at this time, it is a bit unclear about how community solar can meet all of these needs, at the same time, within California's current renewable energy context, we are working very closely with staff and stakeholders in order to really be able to identify how community solar can meet the needs and support the grid as well.

Because the recent NEM decision is going to make it more difficult for community solar to pencil out. Is that correct?

So the recent NEM decision is really trying to make sure that resources like rooftop solar are able to be incentivized, particularly when paired with storage, to provide the most benefit to the grid. So that would be the same for community solar.

Community solar that is paired with storage is going to be able to provide more benefits to the grid as well as reduce greenhouse gas emissions by being able to leverage the community solar to charge those batteries and be able to deploy them at a time of day when we might be using natural gas power plants, things like that, so similar. That's the same theme from that proceeding as it would be for community solar.

We would like for these projects to be leveraging storage as much as possible. And that's what we would want to incentivize.

Yeah, certainly we want to leverage storage. We can when available. It's not always available. And I certainly agree. That's a goal, but I just, again, given sort of our lack of success currently and then getting more difficult probably with NEM, I just really want to make sure there's a focus, the PUC, in implementing this and making sure that we can leverage those federal funds and that we can do better to get these into long-income communities.

Absolutely.

Senator Dahle, anything on this? No. Okay with that, thank you. We will move on to the next item. I really appreciate the discussion. Thank you. Issue seven is water compliance and enforcement. And I believe Ms. Peterson, we'll hear from you leading off again.

Yes. Thank you very much. Last issue for the CPUC today. Thank you again for the opportunity to be here. This is a budget change proposal that we put forward in order to build up our small water utility compliance and enforcement program. So we've proposed two limited-term utilities, engineers, in order to establish and carry out a consistent compliance and enforcement program with respect to the about approximately 100 water and sewer utilities that we regulate and that serve 16% of California's population. Yes?

Customers or 100?

Utilities. Investor owned utilities, yes. Just to start out, our approach with this proposal is guided by the fact that many of those nearly 100 utilities that we regulate are very small. They can serve fewer than 500 customers at the smallest scale and up to 10,000 at the medium scale. They are responsible for delivering safe, clean, affordable, and reliable water to their customers. We want to build a compliance and enforcement program that is sensitive to that scale.

We work closely with our sister agency, the State Water Resources Control Board, which has set out factors that identify a water system as troubled or at risk. And as we develop our program, we'll use those established risk factors to assess their compliance and consider enforcement. Our standup of this program is also driven by a recent consultant report that we had done that identified this gap in our compliance and enforcement work with a need to focus on the small utilities that we regulate.

And so we've requested these limited-term positions in order to stand up the program and then return to you in a few years to discuss whether the workload is permanent. Thank you again for the opportunity, and I'm happy to answer any questions.

Thank you. And, Ms. Cornett.

We find the proposal and the workload justified, given CPUC's existing enforcement policies, and have no further comments.

Okay. Mr. Evans?

David Evans with the Department of Finance. No further or additional comments.

Okay, Senator Dahle.

So I want to just right up front say I am slightly confused, and then maybe you can help me out here, because we've seen so what we have. You said IOU. So these are publicly owned.

Investor-owned, yes.

Or investor-owned, but what about the privately owned water companies? Are you regulating those as well?

Let's see. Want to give me an example? Make sure I'm answering accurately.

So I'll just use my district. So Lake Tahoe, which we have several small privately owned water companies that are, we're trying to get them combined and they're privately owned. So our goal is to combine those and put in hydrants and do all the stuff that really needs to happen. And we were in a very keep Tahoe blue area anyway.

So I'm just trying to figure out where your jurisdiction is because there's many pieces of legislation that are coming through that are going to, I think Dodd has a Bill to regulate down to 15 connections, which is, that's what you have to have to be a water company. It's 15. So everybody's going to be regulated. So I want to find out where your jurisdiction is, number one. And then I have some follow-up questions after that.

Yes. So I gave the Director of our water division, Terrence Shea, a pass on attending today's hearing because I thought I could handle the questions. And I apologize, Senator. I don't actually know the specific answer to your question, but I can find out as soon as I return to my phone.

But the concept of an investor-owned utility, they often are essentially private in that they have often a manager, board of directors, and then they're responsible for collecting rates from the customers in order to maintain their system. So the concepts of what we're describing in our proposal sound like, conceptually at least, they would apply to what you're describing. I just don't know whether those specific ones are under our jurisdiction. I apologize for that.

Okay. So I guess my follow-up question then would be the PUC water division since 2017, 18, my understanding is that the Water Board and the PUC have an MOU to work together.

Yes.

And deferring water quality enforcement to the Water Board. So you're giving that enforcement part to the Water Board under water quality?

That's correct. We share responsibility there, but, yes, largely for enforcement about water quality that belongs to the Water Board. Correct that we work under the MOU in order to make sure that we're as lockstep as possible, because in some instances, their water quality, they're concerned about utilities that we regulate.

So is there duplication there or who's doing what?

No, sir, I don't believe there's duplication. There's just highly interrelated jurisdiction. But so the type of jurisdiction that we have is over rates. The Water Board doesn't have that. And in order to, when we have jurisdiction over rates, our concern is ensuring that these small utilities are actually collecting sufficient rates from customers in order to make the investments in their systems that enable them to ensure quality, safety, reliability in the water surfaces being delivered.

And so in some cases, the very small utilities don't come in often enough for a rate increase, ironically. And so part of what we're doing is part of compliance is going to those utilities, getting their manager, their board to prepare that rate increase proposal, bringing that in-house, having our staff evaluate it, and then approving a certain rate increase so that the utility then does make those improvements.

So these apparently are not then under Prop 218, they don't have to go to a vote of the members of their utility.

I hesitate to answer that question, not knowing the details. I can get back to you on that.

Well, my father-in-law actually runs a water district, a very small water district. And so the challenge is that the state has passed all these water quality and water conservation laws. So they're attempting to try to get the job done, but they don't have the resources to get the job done. So I applauded the Water Board, which has been giving out grants. We had a lot of opportunities for grants to help those small water districts out.

And they're not in a situation where they have another water company right next door. The next town is 5 miles away, and they're not going to merge. Now, I remember when I was in the Assembly, Senator or Assembly Member... anyway, they had six water districts all touching each other, and all of them are in trouble. And so they all have a board. They duplicate everything. And so in that case, it makes sense to consolidate and I'm all for that.

But in some places, there is no ability to consolidate because there's nobody next door to consolidate with. You just are faced with the regulations and the lack of customers to spread the cost and then the lack of the ability to be able to actually raise the rate. Because you have Prop 2, you put it to a vote of your people, and all of them vote against it, and so you're stuck, but you're going to be required to be fined. And this is talking about enforcement.

Well, if you fine them, they have to pay the fine. It doesn't help improve the water quality or the system. So as many people... it doesn't make sense, right? And it's hard as somebody who has literally hundreds of these small little towns that have a water system that is struggling and you can't get anybody to go run for the board, you can't get anybody to manage the system because it doesn't happen. So what happens? Nothing.

And you can fine them all you want, but there's no way to get any resource out. So I'm concerned about this area for I want to consolidate where we should consolidate. And then when you go to the bigger districts, one that was poorly managed and doesn't have the resources, you're basically saying the one that took care of their job and you're putting them in. Now you're having to spread the cost.

So somebody who did their job is picking up the cost for somebody that didn't do it. So that's the other issue you have in the populated areas where you have seven districts all next to each other. So I know this is not totally your problem, but is a problem that the Legislature needs to figure out instead of fining we should take the money that's available to fix the system anyway. So I want to make sure there's not duplication, number one.

And number two, what we're doing to help these utilities that are struggling out there with all these laws that are coming in, there's more laws, there's more laws that saying, hey, you have to report, you have to put it in 17 different languages when you have 15 customers and it just drives the cost up. Anyway.

I have a few responses. I very much appreciate your comments. And actually part of this is our problem. That's actually a significant amount of what our water division is working on. So in the first instance, yes, consolidation, that's a policy that the state wants to have happen. We do have examples where unconnected systems have consolidated. And so there is not actually required to be a physical connection between the acquiring system and the acquired. That has happened in California.

You're absolutely right that this fairness question between the ratepayers of the acquiring versus the acquired. There's a huge fairness question there. And we have an open proceeding addressing consolidation and how that fairness and allocation of costs should be handled. We have an existing framework that's, I'd say 15-20 years old that we're looking to update through that proceeding. So we're at work on that problem, too. I fully agree with you. The Water Board's grants are hugely important in this area. And we like to work with them.

We're partners with them in helping, making sure that the grants get out to the systems that need it. And then last as far as compliance and enforcement, that's exactly the sensitivity that I believe we have with respect to these small utilities. We don't want to penalize just to impose a new fine that doesn't do anyone any good.

And so our program is meant to achieve compliance through these existing structures, bring them in for rate increases, look to how they can finance those improvements that they need to make to their systems. All that is laying the groundwork for, hopefully, an improved situation. But absolutely hear you. The challenges are out there. We'd be very happy to talk with your office further about specific districts in your districts.

Would be helpful for, I think the legislators. Especially, I know that Senator McGuire, I will guarantee if he doesn't know he has them in his district and he's probably heard from them. We're between a rock and a hard place. We talk a lot about disadvantaged communities. All of them are disadvantaged communities that can't get there, and they're just stuck. And it's very frustrating. So what would be helpful for us is if you have those.

First of all, I'd like to know if they have to come for a rate increase or if the Prop 218 is an issue. And that's what I'm hearing is that because under Prop 218, you have to have a 62% vote? I think it is, or... it's pretty high bar. So which ones have to come to you and which ones don't would be very helpful for our office to understand.

We'll get back to you, Senator.

And then again, I know we're going to see tough budget times and the grants are going to dry up. And that's really the saving grace when we all. I think the Legislature, both sides out, has recognized that and tried to front-load those programs with money when we had one-time monies available to go fix these issues that we have. So thank you.

Thank you. Okay. I think that covers it fairly well. We will take that as a hold open as well. And thank you, Ms. Peterson, for your commentary and presentations on all these issues.

Thank you very much.

We now move on to issue eight, which is implementing evaluations and recommendations for hydrogen to support decarbonizing the California economy. This is from SB 1075, and we will have CARB first. Go ahead when ready.

Good morning, Chair Becker and Members. Brandon Merritt with the Department of Finance. The Air Resources Board has put forth this Governor's Budget Proposal. The implementing evaluations and recommendations for hydrogen to support decarbonizing the California economy to implement the requirements of Chapter 363, statutes of 2022, otherwise known as SB 1075.

CARB is requesting 3.1 million cost of implementation account for permanent positions in 23-24 including 2.3 million in one-time contract funding, to develop and publish an evaluation and provide policy recommendations on the use of hydrogen, specifically the use of green hydrogen. With that brief intro, I'd like to turn it over to my colleague CARB for further background on this item.

There we go. Good afternoon. Matt Otil, Division Chief at the Industrial Strategies Division at the California Air Resources Board. Thanks for having me today. I'll keep this very brief.

As Department of Finance mentioned, we are asking for resources to implement the requirements of SB 1075, and this really comes on the heels of the state developing the Carbon Neutrality Scoping Plan and getting that approved through our board in December, which calls for an expansion of hydrogen resources to meet our decarbonization needs in California for both the transportation sector, the industrial sector, buildings, and the commercial sector.

And so the analysis called for 1075 will help us identify the pathways for hydrogen production, the demand for hydrogen production, the greenhouse gas intensities of various pathways for hydrogen, as well as some of the infrastructure needs and the associated environmental and health impacts. So, really looking forward to being able to get moving on this plan, particularly given the federal incentives that are in play now with the passage of the Inflation Reduction Act and Investment and Infrastructure Jobs Act with the Biden Administration.

So happy to answer any questions you all have at this time.

Well, thank you. I do have a number of questions on this. Oh, sorry, but before that. Go ahead Ms. Cornette, please.

Thank you. We find that this request is reasonable, given the requirements in SB 1075. We do think it will be important for the Legislature to monitor CARB's work to develop an evaluation process to ensure its intentions with SB 1075 are met to develop a clear strategy around hydrogen.

Well, thank you. And just part of the request, I just want to kind of go through a few things regarding hydrogen, because it is very complicated topic. I was glad to see that Senator Skinner took on this effort last year and was thrilled to support the legislation when it came in front of me. Green hydrogen is going to be a very important part of meeting our climate targets, particularly for certain hard to decarbonized industries.

I was particularly happy to see the definition of green hydrolytic hydrogen in the legislation, which limited to hydrogen gas produced through electrolysis and excluded steam reforming and fossil fuel feedstock production. You may have seen in March of this year, coalition of 17 climate and environmental justice organizations put out a letter defining their principles for supporting the buildout for hydrogen in California. And I thought their considerations were very well done. Have you seen that letter?

I'd have to go back and look.

Okay. I'll get you a copy of it. Sure. I want to walk through some of those from their letter in today's hearing and ask about how or whether CARB is considering these as they develop implementations, you develop implementation for SB 1075. So, just to start out, how does the state plan to avoid hydrogen leakage and subsequent climate impacts through each step of the value chain? Production, transportation, and use.

Yeah. So I know that there has been some preliminary work to look at potential hydrogen leakage in the transmission and distribution system. And so we're looking forward to getting into the analysis called for in 1075 to be able to assess the various different production pathways, the ability to produce hydrogen, not just from renewables and electrolysis, but also from other resources.

We flagged this as part of our work in the scoping plan that there is, and you mentioned it in your opening remarks, there are a number of different production pathways for hydrogen. Some of those may involve transportation, some of those may involve transportation over transmission and distribution and lines, which could result in some leakage. And so there's been some work that the PUC has done to look at this.

We're looking forward to working with them as part of the 1075 report to also look at what some of the transportation and transmission and distribution needs are for hydrogen and what that could mean from an emissions leakage standpoint. I will say that this is kind of a new area. Some of that work that was done previously made some assumptions on hydrogen leakage based on kind of the existing natural gas infrastructure.

And so as we move forward on hydrogen deployment, there's going to be a need for looking at what additional infrastructure is needed, how it's engineered to minimize leakage, given that it's a valuable resource, and given that we also want to reduce any effect of hydrogen leakage into the atmosphere. So, looking forward to getting into that analysis network with a PUC as part of the 1075 work.

Ones that the analysis is so far considering the use of hydrogen. And which ones are you considering excluding? Yeah, which industries are you considering including?

So we're going to really pull from the work that we did here on the scoping plan as a starting point. And I think, as you know, right now, a majority of the hydrogen demand in California is really in the industrial and refining sector. But as we looked at, how do we get to carbon neutrality as a state and achieve carbon neutrality by 2045? We need an energy transition, and we need to be able to deploy different energy resources into different sectors to decarbonize those sectors.

And so what we looked at in the scoping plan was hydrogen deployment for fuel cell electric vehicles in the transportation space, hydrogen deployment to replace fossil gas use in the industrial sector and in the commercial and building sectors, and then hydrogen deployment to also help on our electricity generation needs.

And so that's really our starting point and that we're going to use for looking at where hydrogen can be deployed as part of the 1075 analysis, and then also doing a deeper dive on the various different production pathways to be able to supply that hydrogen. Because obviously, if we're going to be reducing fossil natural gas use and gasoline and diesel use in the transportation sector, that means a pretty big ramp-up in hydrogen demand and need for supply in the state.

And so that transition from kind of where it's being used today to where it could be used in the future is really kind of the core of the 1075 work.

Okay, just want to clarify that a little bit more. Would you include an analysis on the cost-benefit of investing in hydrogen for the transportation sector versus, say, investing EV infrastructure or other mobility?

So I believe 1075 does require us to look at the cost of various different production pathways. I do not think, I'd have to go back and look at the legislation, it requires a cost-benefit comparison across different strategies. So what we are planning to do is look at the various different kind of costs for delivery of hydrogen in the state based on the different pathways for production.

Okay. Yeah, I think that kind of cost-benefit analysis would be important, so maybe we can follow up on that. And CARB is also responsible for describing strategies for using hydrogen and difficult-to-decarbonize sectors of the economy. So could you explain CARB's understanding of what those difficult-to-decarbonize sectors are and confirm that they're not focused on the residential commercial buildings or light and medium heavy-duty vehicles? When you talk about that, what is the definition of difficulty decarbonized?

Sure. So there are a number of areas that we identified in the skeleton plan where hydrogen could really play an important role. And those are traditionally what we kind of called difficulty carbonized sectors. And so those include things like aviation. They include things like industrial contexts where you have high heat requirements. They include things like on-road heavy-duty vehicles where they have longer distance travel that they maybe need the fueling capacity and the energy content of hydrogen to be able to meet those duty cycles.

So those are a couple of the areas. We also identified that not every single commercial and residential building can move to electricity. It's going to take time. And so we will still have some fossil gas use that will be used in the building sector. And there might be an opportunity to also use hydrogen in the gas system to help reduce the carbon intensity of the gas use. The ongoing legacy gas use that we have in California.

That's interesting. I'm not as convinced about that, but we'll be following that. But I do appreciate your other definition of hard to know. You said high-heat areas like steel, you mentioned aviation, maritime shipping, I think heavy-duty trucking, heavy-duty vehicles. But if built on properly, there is potential to leak and cause further GHG submissions. So I'll be watching to make sure the report is limiting that kind of sectoral use.

Are you including or considering any limitation to prevent the blending of hydrogen into existing natural gas pipeline? And how will the state avoid climate and public health and safety risks from blending of hydrogen in existing natural gas pipelines?

Yeah, so the CPUC has done some initial work on this. They had a study that looked at blend rates for hydrogen into the gas pipeline. We're going to continue to engage with them on this as we roll out the 1075 report. I think part of the requirements of 1075 are to look at the end uses and the production uses and the various different environmental, including air quality impacts of those various end uses and production pathways.

So that's work that we're going to be doing as part of the 1075 report. I think that there's probably going to be more scientific studies coming about the impacts of hydrogen leakage and the engineering needed to ensure that we minimize leakage in the hydrogen distribution system as it moves forward. So look forward to doing that work as part of the report.

Okay, good. Yeah, because heard a lot of potential leaks and safety concerns when hydrogen reacts with steel or polymeric materials. So it's a strong concern. Also heard a lot about the importance of hourly time matching of electricity production. And how will this report ensure that we're accounting for that hourly time matching of the electricity production used for creation of hydrogen?

Yeah. So I think this question is really one of, as we look at hydrogen deployment, because hydrogen is an energy carrier, right? So it can be produced through things like electrolysis that can be done from electricity generated from various different energy resources, renewables, or even fossil resources. Hydrogen can be produced from biomass, for instance, which also has a number of feedstock pathways, things like woody biomass, for instance, through advanced technology can produce hydrogen.

Each one of these pathways has their own carbon intensity associated with the production of that hydrogen. And so this question about hourly versus annual electricity accounting is another one of those complexities about how do we look at what the carbon intensity of a hydrogen molecule that is produced and used in the state. And so I know that there's been some work that's been done now to look at what is the best accounting method for hydrogen production from electricity resources.

We're looking forward to getting into those analyses and looking at that as well as part of this process, the state typically uses annual accounting when it comes to emissions intensities. And so this is going to be something that I'm sure that we'll have a public dialogue on as part of the report development.

But it really goes and it speaks to some of the complexities on doing the lifecycle assessments on hydrogen production and kind of why we need some of the positions and the contract resources to get into the specifics and set a framework for California. I mentioned in my opening remarks that the Biden Administration has passed the 45V production tax credit on hydrogen production.

And so we know that there's going to be hydrogen producers that are moving forward on hydrogen production in response to what the Federal Government has done. And that's good news for California and being able to decarbonize our energy system. But we need to be able to evaluate those pathways and provide a framework like 1075 calls for, for that production here in California, and especially on the lifecycle assessment, the carbon accounting, because we need to fold it in.

Yeah. Again, just be clear. I do believe it's critical that we account for the hourly time matching of that production, and that's something we'll be certainly watching for. Would there be incentives to physically colocate hydrogen on-site? Is that something you foresee?

I think looking at 1075 specifically, the Bill largely calls for us to do this analysis first. And once we work on and complete the analysis by mid-next year, then we move into the policy development of how do we make sure that we're folding in hydrogen production and demand uses in California appropriately into our policies across CARB, CC, and the PUC. So I think that's too early to say on that particular question. We need to work through the 1075 analysis first.

Okay, I guess the last thing on the energy use part, and then I just have a couple more. Just wondering if you're going to examine potential for hydrogen production to exacerbate summer peaks and grid emergencies. If hydrogen producers add new load to the grid without building additional renewable resources to meet their energy needs, this gets to the time match piece of that.

Yeah, I'm going to go back here to a couple of things. One, the work that we did on the scoping plan at CARB clearly showed that as we decarbonize across many sectors, we're going to be relying increasingly on electrification as a strategy to decarbonize. And that means that we need to grow the electricity generation resources in California to meet that growth in electricity demand.

And so there certainly is the potential that as the demand on the grid grows, we have some constrained constraints and hydrogen production will put another constraint, more demand on the grid. And so what we projected in this scoping plan was this increased growth in generation capacity to be able to meet demand. We're going to be looking at it again as part of the hydrogen, the 1075 analysis that we need to do.

But one thing that we did flag is that hydrogen as an energy storage medium can provide grid reliability too, because we can use it to support the grid when we're in peak load systems, peak load times. And so I think there's both a demand-side effect of hydrogen production and then a supply electricity supply-side effect of being able to deploy hydrogen into the electricity generation system to help us on the electricity supply side as well.

Okay, thank you. Just two other areas in terms of the existing hydrogen. Currently, refineries use high amounts of hydrogen, generally made through fossil fuels, through a process that does lead to air pollution. Bloomberg presented recent CC workshop that it would take about 8.4 gigawatts of new solar to decarbonize refineries' hydrogen supply. Is CARB examining strategies for cleaning up the hydrogen that's already used in California before we develop new amounts of hydrogen demand?

Yeah, so as you mentioned, refiners are large users of hydrogen in the state. They produce that hydrogen largely through steam, methane, reformation of fossil natural gas. And so a couple of things that we at least identified in our initial work, and then I'm sure that will be more fleshed out as part of the 1075 report, the state's refiners are going through a transition.

Part of that transition is to support biofuel production to meet our low carbon fuel needs in California, but also with respect to the passage of some of CARB's rules on the vehicle demand side, as transition from on the vehicle fleet to increasing percentages of zero-emission vehicles. This just came through in the special session legislation.

Recently, there's more work to be done on how those refiners transition to meet the future demand for fossil fuels and for biofuels in the state that will ultimately decline over time as we implement our vehicle regulations at CARB. And that will also have an effect on how much hydrogen they actually need on their refining operations.

So, to answer your question directly, there is an opportunity to look at how we can support the industrial end uses of hydrogen that include the refining sector with low carbon hydrogen production in the interim, while that transition is happening over the long haul. And that's something that we can look at as part of the 1075 report. What are the production of low carbon hydrogen supplies? How can that support the industrial sector as they're transitioning, particularly on the refining side?

Okay, I guess lastly, thank you for that. This report is going to look at water usage and related costs, as well as impacts on air quality.

Yes, that's part of the requirements of 1075. And some of the contract funding that we're asking for is to help do some of those assessments.

Okay. And do you anticipate impacts on water usage from... to ramp-up?

So, certainly production of hydrogen, particularly on the electrolysis side, is a water demand source. And so this is also why, when we identified in the scoping plan the need for staying open to multiple pathways for hydrogen production, and not putting it entirely on the electrolysis side, given that there might be other opportunities for hydrogen production, like I mentioned earlier, from biomass gasification, for instance, that have lower water demands. But this is again part of the analysis on 1075 that we need to look at.

It's those different production pathways, what some of the associated effects and the demand on water use, and then also on what the air quality impacts could be.

Okay, good. Well, a lot of issues. I'm certainly supportive of the funding for this study. Thank you for letting me walk through some of the things that I think are going to be important to focus on. Any other questions? Okay, thank you for that. We will move on to issue number nine, which is carbon capture, removal, utilization, and storage program, SB 905. And I believe, Mr. Botill, you're leading off for us on this one as well? Okay. Or do you want to start with Department Finance?

Good morning. Chair Becker and Committee Members Brandon Merritt with the Department of Finance. This is a joint departmental item involving the Air Resources Board, Department of Conservation and the State Water Resources Control Board, all of whom are proposing resources to meet the requirements of Chapter 359, statutes of 2022, also known as SB 905. CARB has been designated as the coordinator for this proposal as it contains the majority of the planned expenditures, positions and overall implementation of this legislatively approved Bill.

At high level, CARB is requesting 18 permanent positions and five and a half million cost of implementation account quoia and 23-24 and 24-25 which includes 1.7 million in contract funding and four and a half million 25-26 and ongoing thereafter. Department of Conservation is requesting four permanent positions and six and a half million quoia in contract funding spread over three years, and the State Water Resources Control Board requests one permanent position and $280,000 of quoia in 23-24 and ongoing. With that brief introduction, I would like to turn it over to my colleague at the Air Resources Board for further discussion.

Thank you, Chair Becker, and thanks for having me again. So, once again, for the record, I'm Matthew Botsma, Division Chief of the Industrial Strategies Division of the California Air Resources Board. The work under 905 really comes at an important time in California's fighting its climate change.

As many of you know, when we adopted the scoping plan identifying a path to carbon neutrality, we identified as part of that effort that, and this is backed up by many scientific and technical analyses, that we need to deploy all tools to achieve carbon neutrality. And hydrogen is one of those tools, carbon capture, utilization storage, carbon dioxide removal or others.

And really being able to deploy these tools by 2045 will allow us to achieve carbon neutrality and hopefully allow us to achieve net emission net negative emissions post 2045 to really start reducing the concentration of greenhouse gases in the atmosphere. We are continuing to load greenhouse gas in the atmosphere. Without this technology, we are at risk for exacerbating climate change even further.

So we are expecting increasing deployment of CCUS and CDR technologies over the coming decades, similar to the hydrogen situation, particularly as federal funding support has come forward in the form of tax credits and billions of dollars in investment from the Biden Administration in the Infrastructure Investment act and the Inflation Reduction act. Sorry, infrastructure Investment and Jobs Act. I need to get the full name correct.

As you know, SB 905 was passed by the Legislature and signed by the Governor last September, and it requires CARB to establish a carbon capture, utilization and storage program in coordination with Department of Conservation and the state Water Boards.

And the Bill requires that we evaluate technologies that facilitate the capture and sequestration of carbon dioxide, and that we also adopt regulations for unified permit portal for CCUS and CDR projects and adopt regulations for financial responsibility and report on the status of those technologies and projects to the Legislature every two years. So look forward to answering questions on the Bill.

The resources asked for in the spring finance letter would allow us to move forward on the 905 requirements and also really complement the movement on the federal side on this technology.

Thank you, Ms. Cornette.

Thank you. We do have just a couple of brief comments on this proposal. This is a fairly significant proposal as it's providing CARB, with the Department of Conservation and the State Water Board, the resources to develop an entirely new program and fulfill the requirements of SB 905. There is a lot of uncertainty in terms of workload and policy development, as these technologies are new not only for the state, but also for the world and are only just starting to be developed in California.

We do find this proposal reasonable as a starting point, and the Legislature may want to track the development of the program closely and revise its workload and policy considerations if needed as the program gets underway.

Well, thank you, of course, Ms. Kennedy from the Lao. This 905 was an important part of the package of bills that was agreed to at the end of session, and there's a lot of positions, as noted, but there's a lot of work to do to develop the centralized public database, as we talked about, to develop monitoring and reporting schedules, development, adoption, updated protocols, support additional methods, the regulations, financial responsibility, as we mentioned. So a lot of work to be done here.

And I guess my question is just maybe a little bit on time frame regarding some of the federal money. How's car planning to implement this program to best support California projects in maximizing the available federal funds included in the IRA and in the bipartisan Infrastructure act?

Yeah, no, I think it's a great question. I'm really glad you asked it because I think the biggest kind of hurdle we have right now is moving quickly, given the IIJA and the Inflation Reduction act passage. We've seen a significant increase in the interest in CCUS and CDR deployment in California and across the nation.

And so many of these companies are moving forward with their plans to be able to deploy this technology, and they're looking to carve, at least here in California, Department of Conservation Water Boards. They're looking to us to help implement 905 as quickly as possible so that they have clarity on what the framework looks like for projects here in California.

I think there's a lot of appetite for these projects, and they will, based on kind of what we've seen, really start to move forward in the next two to three years to take full advantage of the timelines available to them under the 45 Q tax credits, as well as some of the DOE money that's coming out that is providing grants for these technologies.

Okay. And lastly, do you think we can. I'm sure you do, but how can we show these three departments are going to work together to limit duplicity and ensure a coherent statewide effort?

I'm happy to answer it, and we've got colleagues here at the table that probably would love to jump into. We worked very closely on the development of this joint proposal on the spring finance letter to make sure that the activities that we're proposing are complementary in terms of carbs responsibilities, looking at technologies, being able to develop the unified permit portal, doing the reporting to the Legislature. As well as adopting regulations, we're going to continue that coordination, and I'm happy to have other folks at the table also chime in.

Sure. Jeremy Lancaster, associate state geologist. Sorry about that. Jeremy Lancaster, associate state geologist with the California Geological Survey, Department of Conservation. Yeah, in our small role in this effort would be to characterize geologic reservoirs, ensure that they're suitable for carbon sequestration projects in an effort to minimize risk upfront, which will lead to really streamlining the permit process.

Good afternoon. Karen Mogus, division of water quality at the State Water Board. And I'll just, plus one on the coordination. We've spent a lot of time working together to come up with this proposal. We also have a very small role, but a critical one, to ensure that water quality is protected as we move forward with these types of projects and any research that's needed to ensure protection of water quality moving forward. So committed to working together hand in hand and not duplicating effort.

Thank you. Senator Dahle, do you have anything? No? Okay, well, thank you for answering those questions. I appreciate it. And without moving on to the next item. Oh, and that was the last item. So now we will be moving to public comment. Thank you all, everyone who's participated, and we'll start with public comment here in the room and ask folks to keep it to one to two minutes, and you can start when ready.

Mr. Chair, Members, John Winger here for the Renewable Natural Gas coalition, speaking in support of issue eight. I think that's a very important study to get done and appreciate all the comments about looking at all the different life cycles to producing hydrogen thank you.

Thank you very much. With that, we'll move to the phone lines. As a reminder, today's participant number is 877-226-8163 access code 694-8930, moderator if you can prompt any individuals waiting to provide public comment, we will begin.

Thank you, Mr. Chair. If you would like to testify or public comment, please press one followed by Zero at this time. One followed by zero. Get those instructions again. One followed by zero. If you would like to make public comment at this time. One followed by zero. Mr. Chair, nobody is queuing up.

Okay, we will move then to the vote only calendar. And let's see. We will take initially a motion on issue one that is moved by Senator Dahle. Consultant, please call the roll.

[Roll Call]

Three to zero is the vote. That issue is out. We will now have entertain a motion on issues 2 and 3. Tenor Mcguire moves. Consultant, please call the roll.

[Roll Call]

The vote is two to one. Those issues are out. I would like to entertain a motion next on issue seven. Absolutely. Senator Mcguire makes the motion. Consultant, please call the role.

[Roll Call]

The vote is 2 to 0 and that issue is out as well. So with that, we'd like to thank everyone who participated. If you were not able to testify, comments are still welcome. Or suggestions in writing on the budget and fiscal review Committee or visit our website. Comments, suggestions are important to us. We want to include your testimony. Thank you to all who participated today. We've concluded the agenda for today's hearing. Senate Budget Subcommitee number two is adjourned.