Board of Public Utilities - Regular Meeting

To welcome you to the Board of Public Utilities. The meeting is called to order. We will now play the inclusion statement.

Pursuant to the city council rules of procedure in order of business resolution, the members of all boards and commissions in the public are reminded that they must preserve order and decorum throughout the meeting. In that regard, members of the boards and commissions and the public are advised that any delay or disruption in the proceedings or a refusal to obey the orders of the board or commission where the presiding officer constitutes a violation of these rules. The city of Riverside is committed to fostering a workplace that provides dignity, respect, and civility to our employees, customers, and the public they serve.

Brian, would you please lead us in the pledge? Stands, one nation under God, indivisible, with liberty and justice for all.

Roll call. Good evening board members. Board member Woolgenmuth.

Here.

Board member Wright is absent. Board member Rand?

Here.

Board member Montgomery?

Here.

Board member Evans?

Here.

Board member Becker?

Here.

Vice chair Sayana?

Here.

Chair Goldberg? Here. Thank you.

We will now move to public comment.

Public comment is now open for this item. Call (951) 826-8688 and follow the prompts to access the meeting. To request to speak, press 9. When called to speak, press 6 to unmute. You can also join via Zoom. The meeting ID can be found on the agenda.

For item one, we will hold an election Oh, I'm sorry. Do we have any public comment? Just guessing we don't. Sorry. For item one, we will hold an election of of officers officers for for the the Board board of of public Public Utilities utilities chair chair and and vice vice chair. Chair. Oh, I will read the rules. Rule f or sorry. Rule five f election of officers shall be conducted in the following manner. The outgoing charge shall call the nominations.

Any member may making nomination for officers, and such nomination does not need to be seconded by another member. Two, nominations will be closed only by motion of a member and a second by a member. Three, the board shall then vote for the officer by a hand vote. Four, in the event of a tie, the two members that receive the most votes shall have a runoff election conducted in the same manner. Five, in the event of another tie,

the officer shall be selected by a coin toss. We now call for an election for the chair. Please state your nomination. I would like to nominate Brian.

Are there any other nominations? Can I get a motion?

I move that we approve the nomination.

I think we have to close. We have to close.

I move that we close nominations for chairman.

Thank you. And a second?

Second.

Thank you. And a roll call. By hand vote, can I have those in favor of Brian Siana as president for the board? Cool. What? Vote for yourself. Okay. This has gone so far down. Don't we okay. We voted on it.

Now we do vice chair. Okay. Thank you. Do I have to read this again? Excellent. Can I get a nomination for vice chair? Pete.

I throw my hat in the ring. Excellent.

Oh, good.

Can I get are there any other nominations?

Well, I was gonna nominate you, Rebecca Goldwere. So I don't know. Maybe I'm messing things up. Anyway.

That's okay. They're now both on the floor.

Both are good options.

How do I do do Pete I call for Pete first? Those in favor of Pete? Oh, can I get a motion to close the nominations please?

I move we close the nominations.

Thank you. And a second?

Second.

Thank you. All those in favor of Pete for vice chair, please raise their hand. We can just call this one. Do we have to vote for me?

We all vote. There's no votes left.

Uh-oh. Yeah. It would be for me. All those in favor of me for vice chair? Okay. Can I vote twice? They're two different votes. Yeah. I'm gonna vote twice. That's fun. Feels like Chicago. That'd be interesting. Yeah. Why not? There'll be some meme about it later or something. I'm not that important. Okay. So, Pete, welcome to the vice chairship.

Thank you.

We did the handout. That's all closed. Can I move? Oh, excellent. Bye bye.

See you later.

This is a bad part.

I've had

received a sick person.

A new perspective.

Yep. Oh, there's no footlock for me now.

Okay. Thank you. For item number three, I'll ask our board members if anyone has any conflicts of interest to disclose on our agenda. Okay. There are none.

Okay. So, we'll move on to the consent calendar. Does anyone wish to pull an item on our consent calendar?

I move approval of consent calendar. Okay.

Second.

Thank you. K.

Oh, you never did public comment?

Oh, we did it beforehand. Yeah. You're switching the role.

Please vote. Six yes votes, one abstention. Member Rand, motion carries. Thank you.

Okay, Thank you. We'll move on to the discussion calendar. And we'll now open for public comment for item number six. And we call for presentation of item number six by Fareed Boushaki.

Good evening Chair Sayano. Congratulations Board Member Wogamuth. And good evening Board Members. My name is Ferit Boushaki, Principal Water Resources for Riverside Public Utilities. Today we have a presentation about the water loss audit results, the latest water loss audit results.

And we're going to have some discussion about the overall water loss program for RPU. So, as I said, we're provide going an update on RPU's water loss program and summarize the regulatory process that started in 2015. And we will have a review of system performance and trends compared to some other agencies results and highlights ongoing and proposed water loss reduction efforts. So, why water loss matters? So, first it supports California water conservation policies.

And there's a couple of more than a couple of policies that start going after the drought with regard to the conservation also to reduce non revenue water. It helps improve drought resiliency with energy efficiency and also reduce lost revenue and defers new supply projects or infrastructure needs for that same amount of water. And all this, it has to be on a cost effective way. So, on the regulatory process, Governor Brown in 2015 signed SB555 that requires annual validation water loss audit. So, by 2027, all utilities had to start submitting validated water loss audit.

At that time, it was due to the DWR by October 1. And I think in the last two years, it switched to December to align with the conservation standard reporting. So, these audits follow the manual M36. It's an AWWA manual that explains how the war audit methodology is conducted. I'd like to start with this cartoon here because the way we think about the water loss is it's an iterative process.

Obviously, when we started doing the audit and then the validated audit, we start seeing numbers. And in order to get a grasp on handling how this dividing all these components of water that we're gonna talk about later on of the water loss. So, the process was to after we do the audit and then see the numbers, let's say do we focus on the apparent loss, real loss and then we come up with some intervention measures. And then after that, we do an evaluation and that feeds back to water audit and we continue the process. It's an iterative process.

So, this is a highlight just for some general information. So by the way, RPU actually starts doing the water audit before it gets required to be validated. Since 2014, we're using that to feed the urban water management plan. But again, so when it started getting validated, so that's 2017. And what we have noticed is that most of the water loss originates in the distribution system.

And that's actually the target of the water audit by the state. And for example, in 2025, we did the overall water balance from all the water that we produce and 92% of the losses were laid in the distribution system. So this schematic here shows and I know it's a little complicated, but it's part of the water audit. Specific numbers are for the 2025 water loss audit. And it divides the water loss into apparent loss, real losses and then authorized consumption and then the non revenue water in terms of volume.

This is a trend since 2017 of the water loss in terms of percentage versus the water supply. And what I mean here by the water supply is the water that reaches our complex Linden and Evans. And we see that there is a change going up and down sometimes. And that's basically due to the nature of this the water loss, the complexity of the components that are hidden in the water that is lost. And so we have some systematic losses and then some random losses that can trigger a one year high and so on.

So in terms of the progress and this is in terms of the amount or in terms of the value of the water that has not been recovered or non revenue water. So we've noticed that the cost dropped from 1,800,000.0 to $1,200,000 And mainly because of that iterative process I was talking about, so we start focusing at that time on the apparent losses because they are about 2.5x more expensive than the real loss component. And also we try to improve our data quality and the validation score for the audit. So I think we started we were like in the 60s at the beginning and now we are around 88, I believe. So here we have some benchmark comparisons to some neighboring agencies.

And the way we selected those agencies based on the Anaheim because they have a similar more or less population. San Bernardino, have similar in terms of the cost of water because they also have water rights and Western it's our neighbor and some of the Riverside customers are supplied by Western. And in the terms of the percentage, it's between 3% to 11% change or difference. And in terms of the apparent loss, the real loss you can see that Riverside we focus more on reducing the apparent loss first. And these are the numbers that are gathered from the state website up to their latest information published by the agencies.

This is the same kind of table, but this is in terms of the value of the non recovered water or the water loss in terms of a monetary value. And the Riverside sits at $1,200,000 of non revenue water and that's very comparable to the agencies I would put here. So this is another graph that shows performance in terms of the validity score and RPU sits at 88%. And also what we want to show here also is the system, our distribution system lengthwise and RPU sits at the highest more than 900 miles of distribution system. And this is actually the same graph as the table I showed earlier in terms of value.

And on the top, we see the amount of non revenue water component. And here they are disaggregated by the value associated to the loss and the value associated to the apparent loss. So, in terms of the ongoing water loss control effort, so as I mentioned earlier, we do the annual water audits and kind of feed us back to what we do next. And we do benefit cost analysis. And then I'm going to show some figures of and I think the numbers are put in the report.

But I'll show some graphs, figures of some types of water loss control efforts that we do. And then we also have the water theft ordinance that can help us curb the water theft which is a component that it's hard to account for. So here we have the hydrant valves figures that shows before and after installing the valves. And I think to my knowledge we are now at 40% of these valves are installed throughout our hydrant system. This is another program which is the increase of the service lateral replacement.

And we see that from 2022 to 2025, we increased our service replacement to seven thirty five and the service repairs to 183. So, the service replacement program actually helps It helps reduce to in theory the service repairs because those are based on emergency calls and they cost more. So I think the program was set to target an area and then change more. And that was approved by the Board. This program, I think in 2022 and then gets extended in two years after that.

And this is just some figures of when our crew the leaks into those laterals. And then another program that got expanded was the meter placement and testing. And this is focused on the small meters, which are two inches or smaller. And we see the change in the jump in the fiscal year 2025 in terms of both replacement and testing. Here's a different showing the data on the small water meters.

And this is by age distribution. So, what our crews found out that when the meters are higher than are more than 20 years old, they start losing accuracy. And so especially on the high flow. So I think the idea was to start going and doing the change. I think the change was by the old numbers.

The cycle was more than twenty years if I remember correctly. And then I think now we are about fourteen years cycle. And this is another program which is related to the small meters also. And it's a mirror test bench. And actually I went there the other day to see how they operated and very impressive.

It can take 14 meters at a time and it recycles the water. And I think the water gets recycled just changed like three times a year. That helps a little bit I guess in the wireless as well. And so one of the programs that also we brought to the board at one time and it was to approve a leak detection pilot programs. And we worked with two companies, two contractors in 2023 and 2025 that installed 40 units throughout some areas within the city.

And the recovery was between 25 to 12 acre feet. Also this one I think you got mentioned a few times here. And it's a pump out system which RPU customer engagement helped secure the funding and get an RPU contribution was about $15,000 for a total of 118,000 And that would save an estimated 4.5 gallons saved. So, what is this truck does is for when the firefighters do the training instead of wasting that water, they recycle it into the pod. So with that, our recommendation is that the Board of Public Utilities receive and file an update on the water loss.

And if we have questions, I have here Robin, Lenny and Teo and Charlie for if there's any technical questions. And thank you.

Okay. Thank you. And do we have any public comment? Okay, do we have any comment from the board? Tom?

Thank you. This is really important. And I really appreciate the fact that you're obviously taking this seriously because we feed the losses to our customers. Well, I guess I have one question before I go on. What are you defining as non revenue water?

So, if we go back to that and go back to the water balance. So we're adopting the definition from the M36 which is the AWWA standard. So, it's the sum of the apparent losses and the real losses plus the inbuilt consumption. And the inbuilt consumption it's a category for we have a special rate for it or special meters and they are used for example if we have a well that we need to use some water to clean the building and very much RPU uses. So the total of those three is called the non revenue water.

So it's water not built basically. It's a result of bad metering or meter issues. There's still revenue. We just didn't collect any revenue. Is that fair to say?

Yes. I mean, if we want to collect revenue from us.

That's the whole point of your meter replacement program is to reduce the number of meters that are reading incorrectly.

Right. Also, Board Member Evans, there's a few other things that go into unbilled consumption and the losses that are calculated here such as firefighting. Those the hydrants aren't metered for fire fighter usage. There's the leaks and the main breaks as well as meter inaccuracy, billing errors and unauthorized consumption. So water theft all goes into that calculation.

Okay. So hence the pod, whatever that firefighting device was called, that helps reduce that una unaccounted for water that would have otherwise been wasted. Okay. In 2018, in the cost of service assessment, the water loss factor, as I recall, was over 10%. And that's so in the COSA, it's coming up.

What's factor you're going to use? Because it looks like it ought to be around two well, it's a little confusing as to whether it's 7%, whether it's 4%, whether it's 2%, but what will your assumption be for the COSA?

We will have to circle back on that and get an answer to you. I don't have that information at this time. The 2% is based off of the total revenue, the 8% of water loss by volume. And so we will definitely circle back and get you an answer to that.

Okay. Because anything below well, it's certainly going to be below what it was before, it looks like, because you're doing a lot of good work to drive it down. But we ought to be able to have a common definition. We're saying, well, the losses are we're now pursuing losses and we're getting them down to 4% or 2% or whatever they are. But the key is that my expectation would be to see that the COSAs have a number closer to this slide than the 10%, which again will help keep rates down.

Yes. So, the 2% in terms of value, yes. The 8%, 10%, I think it was in terms of volume of water.

So anyway, I'm just saying the lower that number is, the better it is for our customers because it won't be we won't have to include in rates an amount paid for water that's being lost, not metered or whatever. So, appreciate the presentation you're making and the work that you're doing to obviously take this seriously. Thank you.

Okay. Thank you, Tom. Any other comments? Yes, Pete?

Hi. Thank you for the fine presentation. This is a really, really hard problem because most of the losses you can't even see until it's some sort of catastrophic event like a busted hydrant or something. And I agree with Tom that we're doing a lot better than we have been. And some of the metrics that you presented are are fabulous.

I mean, they're the comparative rates or statistics with the other companies and cities show that Riverside is well ahead of some of our competitors in many areas. So that's great. That being said, I was disturbed to find how much better the city of Anaheim does with their real water losses. Losses. It's 3% by volume rather than 8%.

I asked the question at the pre meeting last week. What are they doing better than what we are? Although we far outstripped them in terms of apparent water losses. And AGM, Robin Glenney, emailed me this morning and said they were able to contact the city of Anaheim. And they have a very robust program of looking at their pipes, looking and searching out leaks.

I don't know if they do it by camera work or what. But there's a lot of attention that they pay to their real losses. And I would hope that some of what they do can be adopted by the city of Riverside to try to decrease the amount of real losses that we're facing. Now real losses are a problem because as we were told 92% of it is distribution system and mainly the service laterals, which you can't see until they manifest at the surface. And even though the city and RPU has embarked on a robust program of replacing service laterals with 68,000 service laterals and you're replacing 700 a year.

You can see it's going to take like between seventy five and one hundred years to completely go out throughout the system. And if they only have a life expectancy of thirty to forty years, you've got to start all over again. So it's a never ending process. And we, I guess, shouldn't be discouraged by the fact that it seems so overwhelming when we're making good progress here. And I like to thank the utility for, as Tom said, spending the time and attention necessary to address the problem in the first place and taking proactive measures to try to short circuit the losses before they happen as best as we can.

I really like the hydrant thing where, you know, you turn old faithful into laboufedora. So it it really sorry. Forgot to mute my phone. It it's good. And I applaud RPU's efforts and look forward, as Tom has said, to improve numbers in the various aspects of evaluating this, especially the COSA values.

And my hats off to you, you're doing a great job for an impossible task. And hopefully, things will get even better into the

So,

seeing

we're said in your presentation that we're apparent losses are more expensive in than real losses, and that's just because an apparent loss is something that we haven't we would be billing for, and we would lose that revenue versus if we lost if we had a real loss somewhere in the distribution system. We're not billing for that. So and it's much cheaper for us than what we bill to produce that water. Is that effectively what you mean by that?

Logic is correct.

Okay.

And that's how it's laid down in the M36 in the standards.

Okay, great. Yeah, so this is really, I mean, from a revenue point of view, it's really great that our apparent losses are so low. I was a little surprised at how much of it was actual real losses and that's a bit unfortunate, given, you know, we do have limits. We're not at them, but we do have limits on how much water we can use from our, aquifers and so so forth. But I I recognize that it we have to optimize on cost, not completely, but you know, to a large extent and actually, unfortunately, there's not a lot of cost associated with these real losses per acre foot relative to the unbilled apparent losses.

Right? I mean, that's the real problem. So, okay. I have a question about Anaheim. How much are they getting a lot of their Where are they getting their water from? Is it mostly state water project or is it I'm just sorry.

I can share a little bit if the team isn't aware. Okay. I used to work in Orange County and work closely with City of Anaheim. And they're about a sixtyforty system. They have about 45 groundwater wells, but they all receive water from the State Water Project and the Colorado River. So it's about a sixty-forty split.

Okay. So their water is much more expensive generally? Correct. I mean, to produce. I mean, yeah. Okay. So that's part of the motivations for their lower real losses, right? So for optimizing perfect, you know, just on, obviously, it costs more to to change service laterals and to change the distribution system out faster. And so we have to optimize. And optimization changes if our water is cheap. Obviously, we can't purely think in dollars. We wanna make sure we're not wasting stuff. But this is part of the problem is that our water is cheaper to us than their water is to Anaheim. Yeah? Okay.

Okay. I just wanna say I thought it was encouraging that our water losses I know the trend is noisy. Actually, I would have liked to have seen it in actual acre feet rather than percentage because I think it gets muddied when we I think the losses in acre feet are more constant than the percentage because our usage is noisy. So that was I think what was causing a lot of the the noise. But anyway, it's encouraging that it's decreasing.

But yeah, as Pete said, we've got these like century long replacement levels that we need to probably work on as well and keep that in mind in the long run. Okay. Thank you very much. This is very clarifying. Oh, yeah, Tom?

I move approval of staff recommendation.

Thank you for getting ahead of me. I'm still new at this. I appreciate it. Do I hear a second? Second. Okay. Thank you.

Thank you.

Please vote. Motion passes unanimously. Thank you.

Okay. We will now open for public comment for item number seven.

We Public comment is now open for this item. Call (951) 826-8688 and follow the prompts to access the meeting. To request to speak, press 9. When called to speak, press 6 to unmute. You can also join via Zoom. The meeting ID can be found on the agenda.

Okay. And we call for presentation of item number seven by Scott Lesh.

Good evening, chair Sienna, and congratulations. And members of the board, my name is Scott Lesh. I'm the assistant general manager for power resources division. And to my right is Tracy Sato, who is the assistant general manager for our strategic initiatives division. And tonight, we'll be presenting the allowable use of value and proceeds from the sale of greenhouse gas allowances.

And I will give the main presentation for this, and then Tracy and I will both be available after public comment to answer questions. So we'll start with a little background, which I think will be helpful. We've brought this to the board before. These next few slides are things you see each year during our annual presentation. But AB 32, Assembly Bill 32, which was enacted in 2006 by our state legislature and signed by governor Schwarzenegger.

This was the seminal legislation that started our carbon reduction program in the state, and it called to reduce GHC emissions to nineteen ninety levels by 2020. And that's what kicked off the program. A decade later, senate bill 32 in 2016 was passed, and this called to bring our emissions down to 40% below the nineteen ninety levels by 2030. And that senate bill was followed closely by assembly bill three ninety eight in 2017, which then continued and extended the cap and trade program through 2030. The cap and trade program now is the cornerstone regulatory program for how the state of California intends to continue to reduce carbon emissions.

And this program is applicable to almost every major industry in the state now. With respect to utilities and publicly owned utilities in particular, we've laid out here some of the high level criteria that we're responsible for. We all have an annual GHC compliance obligation. We all have to make sure that we can surrender sufficient GHC allowances to cover our GHG emissions. We have all received allocated GHG allowances through 2030, which were designed to cover our regulatory burden.

That was done by the state and carve on purpose to try to relieve the rate pressure that was going to naturally occur by decarbonizing to try to take some of that rate pressure off the rate payer. Ratepayer. For publicly owned utilities, which is different from the IOUs, we can actually allocate allowances directly towards our compliance obligations. So in other words, each year CARB gives us a certain amount of allowances. We can take those and split them into two buckets.

One bucket we'll use to actually meet our compliance obligation. And if we have anything left over, we can then go sell that in the auction. That is very different from the IOUs. Investor owned utilities have to sell all of their allowances into the auction every year and then buy back what they need for compliance, and they cannot use auction revenue for those purchases. That's an important difference.

It's really important to understand this because what that does for the IOU case is it means they have to raise their rates to recover the revenue that they need to decarbonize, and then they try to give that money back in the form of an annual credit or a semiannual credit. Some of you may have friends who live in territories, and they get these things usually I think in like February and August or something.

So does the same?

Yes, sir. So Calgas does the same, and that applies here in Riverside. So our excess allowances that we have after we've met our compliance, if we have any, we take them and sell them into the quarterly auctions, and that raises the revenue that we're talking about tonight. CARB, like I said, has allocated free allowances to the utilities. There were actually two points in time in the past when we received allocations.

I believe in 2012, we received allocations for 2013 through 2020. And then in 2018, we received allocations for 2021 through 2030. As it shows on the slide, basically up through 2025, the amount we received was approximately 1,000,000 allowances a year. That was primarily so that Riverside could offset its compliance obligations with the IPP coal facility that generated about 90% of our compliance obligations. We've met all of our obligations through 2025.

We've had excess allowances that we've sold in the cap and trade quarterly auctions, and we have earmarked those benefits as we report each year to policies or programs which we believe are consistent with the cap and trade regulations and relieve cost pressure for our ratepayers. Looking forward from now through 2030, we're going to be receiving proportionally less allowances each year. It's ramping down. They should be sufficient, of course, to cover our direct compliance obligations because we exited IPP last December. Finally, we're completely out of coal.

We'll take those excess allowances that we have and sell them into future auctions and, again, use those proceeds towards programs that can help reduce our rates. CARB has a very, very strict set of limitations for what we can use proceeds for. This is a regulatory and legislative compliance program that's not optional, and the rules are spelled out. You can find them if you're interested in California code of regulations in section 95,892. But at a high level, at a very high level, a couple key points.

Whatever we apply the excess monies that we receive, whatever we apply that to, it has to be used for something that's exclusively for the benefit of retail ratepayers. That's one very important program that we're funding important or, say, paying for excess renewable energy, whatever, the funded project or program, it needs to yield a meaningful carbon reduction. And there's also a rule that says all the money that we receive each time we receive some money from the auction that starts a clock on that batch of money, we have ten years to spend it on something. If we haven't spent it on something within ten years, then it has to just be given back to a great Bear. In addition to CARB's rules, CARB encouraged utilities to come up with their own policies.

The utilities policy cannot supersede supersede or reject any CARB rule or regulation, but it can set more stringent guidelines, if you like. Most cities that have adopted these policies, Riverside included, have adopted policies primarily to indicate the sorts of things that they feel that at some point in time they may want to spend money on. In our case, we adopted the first policy on the permitted use of GHG allowance value and proceeds back in 2014. That then underwent a pretty significant revision in 2016 and a much lighter revision in 2021. 2021 was the last time it was formally revised.

In 2016, one of the major revisions was to add the city council to the approval process. They now have ultimate approval authority for the policy. And policy was modified in some other ways, and some inconsistent proposals that were the 2014 policy were removed. For this board, it's that policy that actually requires us to come and give an annual report to you each year on what we're using the allowance value and proceeds for. So what I'd like to do now the policy document is not very long.

It's actually only four pages, and it was in your packet. There's a section in it where it goes through the specific provisions that Riverside has adopted, that our city council has adopted. And I'd like to, if I could, just walk through these briefly. There are five categories that are in the document. The first one says that we can use the funds for any investment or costs associated with existing or new renewable resources, and then it gives a list.

This is basically saying that we can we can expense these funds against costs for buying renewable energy. This is a CARB. This is totally consistent with CARB regulations. It's one of their one of their primary mechanisms that they encourage utilities to do. We also listed their RPO and local solar projects.

That's kind of redundant cause it falls under one, but I think that was put in there in 2016 because that's when our Tekaski solar facility went live. So it was just kind of a restatement that some funds were being used for that. The next category is any investment or costs associated with the planning, design, development, and procurement of distributed renewable resources on city owned lands. To the best of my knowledge, we have not used any value in this manner under this category. No funds have been allocated to this to date.

Third category is investment or costs associated with planning, design, development, procurement of cost effective energy storage technologies or devices. This is the category that was referenced back when the utility chose to apply funding towards the Ice Bear pilot project which was a thermal energy storage project for commercial customers for low shifting purposes. The fourth category is long. I won't read the whole thing, but it basically is focused towards any type of cost effective energy efficiency, demand response, or peak shifting programs that the utility can come up with that will benefit retail electric customers. Then it lists a whole series of things that are included under here, including electric vehicle infrastructure, building decarbonization.

And then energy efficiency and decarbonization products at city facilities or infrastructure that will result in GHG emission reductions and it was that component of this category that we pointed to when the utility undertook the LED streetlight program. And then the fifth category here is supplemental procurement of GHC allowances or offsets that are required to meet RPU's compliance obligation associated with this retail load serving function. This should have been removed during the 2021 edits. This is no longer an allowable use of funds under CARPs regulations and it needs to be struck from our policy the next time we bring it forward for an update. That's the city of Riverside's policy, and there are the CARB regulations.

And this table the board saw this table last year when we brought our annual report forward. This is essentially, to date, all the money that's been raised out of the CARB auctions where we had excess instruments that we could take to auction and what we have applied it towards. And the DC fast charger was just kind of a little blip, so I'll ignore that. We basically put the money towards three projects. There was the ice energy pilot program, like I spoke about, that ran from 2016 through 2019.

The citywide LED streetlight project, which I believe has been completed now. It was just completed last year, so when we bring the report in a few months for an update, you'll see that that's been finished out. And then the vast majority of funds have gone to pay for excess renewable energy. Overall, raised just slightly over $100,000,000 and have it expensed out to slightly under $70,000,000 with 80% of it going towards paying for the excess renewable energy. Looking forward, we've put some information here at the end of the slide deck about projects that staff are considering and discussing with the executive management team for potential future funding.

There some internal discussions ongoing about funding some EV charging infrastructure, potentially setting aside up to $10,000,000 for this. These are mandated vehicle conversions from gasoline to electric that we have to do under CARB's advanced clean fleet rule rulemaking. Excuse me. I'm losing my voice tonight. I'm getting over a cold.

We're also talking about potentially putting up to $15,000,000 towards some energy storage projects, primarily the 36 megawatt battery energy storage project that we would like to build once we retire the Springs facility. And we're talking about potentially setting aside up to $5,000,000 towards some new local solar projects that I'll talk a little bit more about in a moment. And then all the remaining funds would continue to go into excess renewable energy. Just a little bit more background on these topics I just spoke about. On the EV charging infrastructure, we have to electrify all of our vehicles.

Excuse me. This has to be done over the next four years, both light and heavy duty trucks. So we're gonna have to do a major charging infrastructure project at the EOC in order to charge all these vehicles and and take care of them, but we'll need some additional facilities probably at Poe and also the JW North facilities. So we're looking at all of those right now as potential things we might fund. The energy storage project I just mentioned, the main one is the 36 megawatt, 144 megawatt hour battery energy storage facility that we wanna build in place of Springs.

However, there could also be a small battery at the EOC that we're looking into. That Springs facility, we expect to cost over $60,000,000 to totally bill it and deploy it. For local solar projects, staff are considering repowering the solar PV car carport facility at EOC. That's been offline for a while. And by repowering it, we think we could get a order of magnitude increase in energy out of it.

We could make it a small solar facility that we actually put in front of the meter, a CAISO registered facility. And it could also be used for backup power at the facility in case we need to island and energy arbitrage opportunities. There's some discussion I know, and Tracy will can speak more to it in the q and a section, but we might use public benefit funds instead for some of this or in conjunction with it. And then finally, the excess renewable energy. This is the area that we really think is brings the most benefit to our rate payers.

It helps keep our rates down for everyone, all customer classes. It's a reimbursement to the budget as we continue to decarbonize, and we've done, I think, a pretty good job of staying in front of the state mandates as we move to decarbonize the utility. So I'll close here tonight just with how staff really approach whenever a project comes forward, either if it's internally generated project or someone on the board suggested or it comes from someone else in the city. How do we decide if it's a suitable project, you know, when we're looking at all these regulations and guidelines? And I tried to boil it down here to the way we think about it as three supplemental questions that you ask yourself for any given project.

Project. This is how I approach it when people ask for my professional assessment on it. The first is does the proposed project or program provide tangible health, quality of life, and or economic benefits to all RPU ratepayers? Or if not all ratepayers, then at least all the ratepayers in the targeted customer class. That's one criteria.

Second, does the proposed project or program offset unavoidable costs that the utility will otherwise have to incur and then collect from the ratepayers? So in other words, will it help keep our electric rates and customer bills lower than they otherwise would have been without such funding? And finally, will the proposed project or program assist the utility in meeting and or exceeding its adopted decarbonization goals and or facilitate a meaningful reduction in the utility's carbon footprint. If a program or a project comes forward and it meets all three of these criteria, we consider that a very high value project that is worthy of funding, putting some carbon funds towards. With that, recommend that the public utilities receive and file this update on the city's allowable use and value proceeds from the sale of greenhouse gas allowances.

As I said at the beginning, we're happy to answer any questions you have after public comment. Thank you.

Thank you. Do we have any public comment? Okay. Can we put the caller through?

Hello. Good evening. Jason Hunter, Ward 1. I'm glad to see that we're finally it looks like developing a plan to use these proceeds the way they should have been used all along. I think they've been misused in the past.

I think when I see a presentation that says it needs to be used exclusively for the benefit of retail ratepayers, And then I see us, you know, launching a $10,000,000 LED replacement project for streetlights. I don't think that benefits ratepayers. I think that benefits the general fund and taxpayers, but not ratepayers. So I'm glad we're, you know, done with that, finally, that misuse, in my opinion, of funds. You know, Ice Bear was never a big fan of that either.

I'd like to know what happened to that money. Looks like we invested about $34,000,000 into that, and then that went away. Not sure we got what kind of return we ever got on that. I I would like to see, like, what's the return on these projects? Right? In the private sector, you invest like that into into a new technology. You're expected to get some sort of return on investment. You know? I don't ever see that in the city, even though the general fund does something or the utility does something. I mean, if it works, great.

Give yourself a pat on the back and take a victory parade. Right? But, know, sometimes these things don't work either. And I'd like to to know how good we are at, you know, prognosticating the next great technology of mankind, particularly on the utility time side where we should really stick to is on the utility side, not on the general fund side. So and I'd like to know how the LED program let's go back to that a second because that really was a spur, okay, in my socks.

I'd like to know how that passed muster over the last ten years on the internal guidelines that Mr. Lesch just talked about, and all three of them. How did that meet those three criteria? Because I don't think it did. So anyway, I can only, I guess, cry over spilt milk so much. Some of these programs have been long dead. Some are dying now, and it looks like we're doing better going forward, so that's good. So But I didn't like it when it was being done. There was never any accountability for the misuse of funds, in my opinion. Maybe one day. Take care. Bye bye.

Thank you. Are there any other callers? Okay. Any comments from the board? Okay. Pete?

Once again, thank you for the fine presentation. I must have heard this many times now, and I'm finally beginning to get it. So good job on the presentation. Or maybe I'm just a slow study. It's great to see that there seems to be woah. Some forward thinking. I'm out of time.

New rules with the new chairs. Sorry.

Yeah. It's great to see that there's a lot of forward thinking amongst the RPU management team about where things are going here. And I like that. I like to see what the expectations are for the future. And hopefully we realize that.

And I really like the three questions at the end there that Mr. Lesch articulated about what are the criteria for a worthy project. So I think that's rules and guidance that we can all live with. So in terms of the history, since the program's inception, it was stated that we collected like $100,000 in

$100,000,000

My bad. Dollars 100,000,000 in cabin trade allowances that have been spent 70% on various projects, primarily renewable energy. And we still got $30,000,000 plus in the bank to spend presumably before the hourglass runs out on the ten year mission. And I imagine that there's different categories of funding that needs to be spent for sooner rather than later on that. And the the future use allowances, I know there's a lot of questions about some of that.

But 10,000,000 for EV charging up to 15,000,000 for energy storage projects,

up to 5,000,000 for locally owned solar projects.

I mean, that adds up to 30,000,000. Now I know we're gonna get more allowances in the future, although less than what we've accrued so far. Right? Because we used to get, like, 1,000,000 a year, and now we're down to, like, 500,000 or something like that?

We will be down to 500,000 by 2030. We'll be down to 500,000 by 2027 if CARB's latest rule making clause back allowances like they proposed?

What would those be just out of curiosity?

How much would they claw back?

Why would they claw them back and how would they how would that impact the utility?

We're under a new rulemaking for cap and trade. Actually, the state legislature passed a couple of new bills last year. I didn't get into this in the presentation. Presentation. But Assembly Bill 12 o seven and Senate Bill eight forty, which have extended the program now through 2045, but also has it requires CARB to come back with an update to the rules.

And one thing that happened after the last allocation was SB100 passed a year or two after that. And that changed the 50 by 2030 requirement to a 60% RPS by 2030 requirement. So going all the way back to 2021, CARB has been saying that they need to come back and make that adjustment. The utilities have been pushing back against that because we planned

Right. You're actions changing the rules after the fact.

Right. But that's the genesis of

it. Okay.

Thank you for that clarification. So looks like we're pretty much got a plan moving forward with the balance of money in the reserve account plus the new sales to fund these various projects, which I agree would really benefit all ratepayers through all classes. And I think that's timely and worthwhile event. And I guess we're going to continue to focus on excess renewable energy purchases in order to meet our mandate. And it seems to me that the city has a more stringent target in terms of carbon

twenty

first And the I

Tracy

the Sotto, Assistant General half Manager of Strategic Initiatives. And I kind of want to address the city's target. So when the city had adopted their twenty twenty five Envision Rivers or Envision Riverside 2025 strategic plan back in 2020. They had established a carbon neutral electricity by 2040 as part of the policies moving forward in that strategic plan. However, that strategic plan has sunset at this point and so technically that policy has sunset.

That was five years earlier than our state mandate so we were required by and we are still required by 2045 to be providing 100% of our electricity generation from renewable or zero emissions resources. So we have to be basically carbon free for our retail customers by 2045 by state law. The city's policy went away when they sunset the Envision Riverside strategic plan. It's in question now as to whether that policy is going to come back as part of the climate action and adaptation plan. So in order to meet the GHD reduction requirements that'll be required as part of the next general plan coming or general plan update that's coming forward.

So it'll be something that'll be talked about and discussed over this next summer during that process. So we'll know where that policy is, where the city council wants to go, and that'll be an opportunity as well. The board will have an opportunity to weigh in on that as well as the community.

Okay. Well like I said I think it's laudable that the city has these high lofty goals. I don't think it should be at the expense of or detriment to the utility. However, I mean, the fact that we're ahead of the state, I'm not sure why that we're not in competition with them, I don't think. So why do we have these extra burden on us that we seem to have placed on ourselves?

And I would argue that the state goal is fine. Those extra five years might be important. So let's not get too wild and crazy about trying to meet their goals ahead of time just so we can basically say we did it. Okay. Again, thank you for the clear explanation on this program that I'm finally getting internalized here.

I think the bottom line is that we're in good shape as far as meeting our compliance mandates. And we will have access to sell. It's not as much as we did once upon a time. But hopefully, we'll be able to go forward. I also like the strategic buckets that you've lined out as far as where the money could be spent in the next well, in the near future as far as investing in some of these larger projects that we're not going to have money for otherwise.

So good job. I thank you for your detail and ability to explain it and look forward to seeing that the next report next year. Thank you.

Okay. Thank you, Pete. Any other questions from the Board? Tom?

Excuse me. Thank you. Would you the ten year is the ten year timeframe a rolling ten year forward?

Yes.

So if you look at this chart that you had where you show the unspent funds, we're close to a point where there's 4,000,000 or $5,000,000 that needs to be this that needs to be given back to customers?

No. It's first in for it's first in first out. It's how they do it. So

Okay. What does that mean?

That means you would take well, you can't do it here from this table because you actually need another column that shows the total amount of money that came in each year. But you would look at that money coming in. You'd sum it year over year. You'd look at money going out, and then you go back until you have balanced. It's about it goes back about three years.

Okay. Well, see, guess I would feel a lot better about this if there was a plan. I mean, Pete mentioned there's a plan. I don't think this is a plan. The plan has timeframes associated with it. So it seems to me that assuming we agree with your major categories that there ought to be some time factor associated with those. We talked about springs and having to do it by twenty or three years from now or something.

We were shooting for 2030.

Okay. So, if that's the case and you use this money and then we also have some discussion about the excess public benefit funds might also be another source of money to bring Springs into play faster than you might have otherwise done it. But either way, it seems to me there needs to be a time factor associated with this. And I can't see one. So and then the other question is there's if I interpret this right or what your presentation is, we don't we can't give this money back to customers if we chose to do it.

No, that's not true. We could give it back.

Okay. Well, I think that's another factor we ought to put on because my view is that if we gave every customer back their customer charge, the non commodity related charges, which a domestic customer pays, I don't know, dollars 22 a month for customer charge and then another very different amount for reliability depending on what size their main switch is. But we could give customers a couple $100 and in some cases a lot more than that if we've been getting some of the bigger ones.

CARB does have a rule that if you're going to do direct rebase to customers, it has to be on a non volumetric basis.

That's why I picked the customer charge and the reliability charge because those are not commodity based. Yes. Okay, By definition according to rate schedule it says

Originally you were talking about the NAC, the network access charge which is why I pointed that out. But yes you're right. The customer charge and the well

Reliability is based on main switch size.

So that is volumetric. Okay. Regardless, yes you could have an amount that you give back. The practical impact of that is depending on how much you want to give back. Obviously that's going to lower people's bills for a year if you do that for a year or two years, whatever you want to do.

But once it comes off, all that's back there, so it's like a rate shock again. So if you want to give money back to customers, usually in the PLU community the way it's proposed is you start at a target for something you want to achieve, like let's say I want to eliminate the 7% rate increase that happened this year for the average customer. You start with that amount and then you taper it down over a few years so there's gentle glide path off so people don't feel rate shock in their bills when it just drops off. That would be my recommendation to the board to consider.

Well, think we at least ought to see that as a consideration as an option. For example, if we gave everybody back their fixed their customer charge, which, like I say, is about $23 a month now, for smaller customers, would have some meaning to them. For larger customers, it may have less. But if you look at the school district and aggregated all their fixed charges, it's not a trivial amount of money. So I think we at least deserve to see that as something to consider rather than just receiving to file this.

And secondly, we see, whether including giving the money back to customers, if there ought to be a schedule so that we kind of have a sense that there's something that's actually going to happen in a year from now, we don't sit here and say, oh, we're talking about the same thing. So, I don't know how to do this, mister city attorney. Do I have to make a vote? Can I make a I make a motion that we request the staff to come back with this report with a time schedule associated with the recommendations they've made as well as a recommendation on how to return money to customers directly, assuming we were to choose to do that?

Okay. Okay. That's legally sound.

Okay. That's my motion.

Okay.

But I know it has to have a second. I'll second the motion.

Okay. I'm new to this.

Nope. Oh, I've been corrected. Oh. So this is a receiving file. So what you can do is

Well,

you can vote to receive and file. You're gonna have to do that or elect not to. But I'm trying to find the proper vehicle for getting your concerns addressed.

Well, I had the same we had the same discussion last time when it just came up, and and the request was to bring it back so that we could make a recommendation.

Okay. So staff feels you can make a recommendation on this? So you could vote to receive and file with the recommendation that they do as you request.

Okay. Well, I'm I'm fine with that. I I still had more comments. And, Rebecca, do you have relevant comments too?

Yes. Okay. Scott, does this have to be filed with anybody?

This report? Yeah. No.

Okay. Also, since we're tagging work onto you, I would like to see an economic impact study done on the projects that you all are presenting and what that impact is to the city and how it can benefit versus giving people money back. Thank you.

So that would be not a formal action by the board because this is not agendized. Right? And so the public may want to

I'm giving them a heads up.

Okay.

Okay. I'm going to make a few comments first before we vote on this. First of all, okay. I think you answered my first question on the ten year timeline that we're only kinda three years back because, yeah, we've spent all that initial money from a decade ago and we're only a few years. We've only got like the equivalent of the last two or three years worth of revenue saved.

Right? Correct. Okay. And then, I guess philosophically, we're spending we can spend this money on renewable energy. And we have a lot of renewable energy in our portfolio, a lot. And we're about to have a lot more, like, this month.

80, yeah, $80,000,000 a year.

Right. Which is far more than any revenue we've ever received from these allowances. So in principle, it could simply be used I mean, I'm not suggesting we do this, but I'm just saying, like, in thinking about this, we could just use this money to offset the cost of the renewable energy that we already purchased. Yes? Yes.

And these other projects like the battery, this is something that if if we didn't have these allowances at all, my impression is that this is something we would be pursuing regardless of these allowances because of the RA benefits and, resiliency benefits and so on. Is that correct?

Yes.

And then the electrification vehicle electrification and the build out for that is something we have to do anyway, right? And so these are sorry. Yes.

Okay. Those would be costs we would incur.

I mean the only one that isn't is like the like solar at the UOC. UOC. Whereas that's more That would be optional. Right. That's more of a like a I mean, sure, it would produce renewable energy and it would be a but it would also be resilience and, yeah, having that on backup in case of emergencies is pretty important in that.

Right. But the vast majority of this stuff is stuff we would do no matter what. And so I guess philosophically, what this means is that we could think of it as it is saving the ratepayers money because these are things we're going to be doing anyway. And the only time it isn't that is if we go off on a little adventure and try new spend a bunch of money to try new things. So I think we should keep that in mind that it I don't know.

Every year, both in water and electric, we have proposed projections from our budgets and rates and whatnot. And sometimes we're a little high, sometimes we're a little low. And we don't propose throwing that money giving that money back. We just kind of correct slowly with changing the rates. So I don't know.

That's my philosophy on it. I agree we shouldn't be we really should be quite careful if we're going to spending money that isn't something we would have been spending on anyway. And there's a little bit of that in here. But anyway, this is, I guess, is a comment for another time if we're gonna see this brought back. But I also wanna say that I agree with Tom that I think the timelines would be useful.

We do have a pretty big pot of money here. And these some of these things are need to be done reasonably quickly like the EV infrastructure and of course we could opt to spend more money on renewables and whatnot now. So, I do think, yeah, it would it would be nice to see a little bit more I I understand these are all like projections and whatnot and estimates, but I do think it would be nice to see timeline and to see where we can to move these things forward and use these funds. Okay. So, we have a motion in addition to receiving a file that you wanna see this come back to the board with more specificity on timeline and with the option about returning some of the funds to the rate payers?

To the customers, yes.

Okay. That's fine. Is that specific enough language? Yeah. Yeah. Okay.

Just out of curiosity, how long might it take for that to come back?

We'll add it to the list that we have, Tom, that you have created for us that is got us about six months behind already, but it will be added to the list.

Okay. If that's satisfactory. All right. Do we have we've already had a motion. And a second. So, we just vote now.

Seven yes votes. Motion passes unanimously. Thank you.

Okay, thank you. Thank you Scott and Tracy. Do we have any board or staff communications report for on item number eight? No? Okay. Are there any items for future consideration for item number nine? Okay, promising. So, we will now turn the time over to David Garcia for the general manager's report.

Thank you, chair. I do have one item that I'd like to report out. We did have a visit from the state of California. The Wildfire Safety Advisory Board came down to visit the city of Riverside, RPU, to look at our operations, as well as have a board meeting. Staff met with the Wildfire Advisory Committee, gave a presentation, several tours, also invited the fire chief to also give a presentation.

It was a great visit from them. They send their thank yous for being here at the city of Riverside. They want to extend their thank you to this board for allowing staff to entertain them and educate them about RPU in the city. They were very happy and impressed of what they saw and that concludes my report.

Okay.

And this meeting is adjourned. Thank you.