4 p.m.

and this meeting of the Rochester Public Utilities Board is now called to order.

Thank you for everyone that's able to be here.

The first item on the agenda, item number one is the approval of the agenda.

Do I have a motion to approve the agenda?

I'll move to approve.

Second.

We have a motion, a second.

Any discussion.

Hearing none, all in favor say aye.

Aye.

Aye.

Opposed?

Carried.

The agenda is approved.

Item number two is our safety moment with our safety manager, Mr.

Bob Cook.

I've uh titled my safety moment this evening, Beware Thanksgiving Eve.

And as I was writing that, it reminded me of what the soothsayer told Caesar, beware the Ides of March.

And we all know how that one turned out.

So uh, but leave it to the safety guy to talk doom and gloom the day or day two days before Thanksgiving.

Uh, but there is a modern tradition that's become one of the most dangerous nights on our roads, and that's the Wednesday night before Thanksgiving.

And I recently learned that it has a couple nicknames, one of which is drinks giving, and the other is Blackout Wednesday.

Uh it's become one of the biggest bar nights of the year.

Uh, friends reunite, college students come home.

Bars run specials that draw big crowds on the surface.

It sounds like a fun way to kick off the holiday weekend, but unfortunately it has kind of a dark side.

Uh over the past decade, the night before Thanksgiving has also become one of the most dangerous nights for impaired driving, according to the Minnesota Safety Council and the National Highway Traffic Safety Administration from 2019 to 23.

149 drunk drivers were involved in fatal crashes on Thanksgiving Eve.

Of those, 107 were male, 34 were female.

The age group most likely to be involved are 21 to 24 year olds, followed closely by those 25 to 34.

And in 2023 alone, 30 drunk drivers were involved in fatal crashes on that single night.

These aren't just the statistics, yeah, statistics.

They're lives lost, family shattered, and holidays that turned into heartbreak.

So I think it's something we we all probably need to think about a little.

Uh so what do we do?

Uh, we can plan ahead, uh, make the safe choice, you know, drive 100% sober, designate a sober driver, uh, use a taxi or a ride chair if you need to.

And if it's your turn to be the designated driver, take that seriously.

Someone's life may depend on it.

And if you see someone about to drive drunk, well, of course, see something, say something, take the keys, help them get home safely.

So, because at the end of the day, we all want the same thing.

Enjoy the holidays, be with the people we care about, and to make it home safely.

So let's look out for each other, make smart choices.

And remember, as you see on the billboard along the road, buzz driving is drunk driving.

So thank you very much.

And have a great Thanksgiving.

Thank you so much.

I appreciate that.

Well said.

The next step on the agenda is our consent agenda.

And the consent agenda includes items 3A, 3B, 3C, 3D, 3E, um, including the attached resolutions on page 121, 124, and 129.

Do I have a motion for approval of the consent agenda?

I'll move approval.

Thank you.

Second.

We have a motion.

We have a second.

Any discussion of the consent agenda.

Hearing none, uh, all in favor of approving the consent agenda, say aye.

Aye.

Aye.

Aye.

Opposed?

Carried.

Next, we're at the part of our meeting open for public comment.

Um, this agenda section is for the purpose of allowing citizens to address the utility board.

Anyone wishing to provide public comment is welcome to appear in person or provide written commentary in advance via email.

Uh comments are limited to two minutes total.

Total comment period is 20 minutes.

Anyone not having a chance to be heard tonight will be the first to present at the next board meeting.

Do we have anyone here that wishes to join us for public comment period?

There are three people signed up.

The first person, I can't really read the name, maybe Jared.

Well, welcome.

And uh please come right to the microphone and thank you.

Uh yeah, it's James Rentz, R-E-N-T-Z.

Uh 7238th Avenue uh Northwest here in Rochester.

And uh yeah, I'm I'm up here to uh well argue against or hope for uh well hope that you don't impose this new grid access fee um for solar panels.

Um I'll admit that with my little array, I'm not especially happy about paying another five dollars in tax to uh to my utility bill.

Um but um from the letter I really don't understand why this is being imposed to begin with.

And um I did make a public record request, and just for the record, it's R012042 112425, and um did get an email back.

Um unfortunately the redacted attachment wasn't included.

Um, so I don't know if uh that can be alleviated or not.

And um just on a more general basis, I think this is just going backwards that um I'm I'm a firm believer that solar should be encouraged encouraged rather than discouraged, and I'm sure that anyone who's thinking about having solar um or added to their residents.

But when well, with the current president basically eliminating all subsidies, um all benefits and uh actively discouraging this um this added cost, this added tariff or tax, whatever you'd like to call it.

Um is just uh one more thing that is certainly going to discourage people from thinking about solar.

Thanks.

Thank you so much for your comments and thanks for taking the time to join us.

Next person is Evan.

Welcome, Evan.

Hello, hello.

Okay, I'm new at this.

Thanks for having me, everybody.

Um, some of you may have saw me in the news on KTC the other day.

Um they didn't quite get the crux of what I was trying to present, so I've learned my lesson, and I'm here to actually talk to you guys.

Um so I'm a DER customer.

Uh my concern is that the decision to tax DER customers creates a short-term solution that will produce significantly worse long-term costs for everybody.

I understand this is how government has been operating for the last 45 years, but I think our community can actually break that cycle.

We don't have to keep doing that.

We don't have to keep putting short-term incentives.

Um, we're only looking at the short term at the cost of long term.

Um, I think these DER systems are essentially public-private partnerships, and the public side of that should be expected to have some costs associated with the service.

But as you build the models out over time, you will find that the cost to everyone in the system increases at a faster pace when the partnership dissipates, and RPU is solely responsible for meeting the fastest period of growing demand that anyone alive has ever seen.

This is why, as you noted, federal tax credits for solar and other energy efficiency upgrades were part of the inflation reduction act of 2022.

Capital investment slows the rates of increases over time.

Um right now, some of you have probably just been hearing from DER customers, but I think in a few years you're gonna be hearing from a lot more people as they continue to see their utility rates increase by two to three times the rate of desired inflation, and they're gonna be asking a lot more questions about what did RPU do to embrace and to slow the rate of increases going forward.

Um wouldn't it be much more fun to be the utility company that's increasing rates at half the rate of everyone else?

I think so.

And wouldn't it be better to keep energy money in the community instead of sending it to Canada?

What impact does that have on your community to keep as much money here as you can?

You know you all know how much how many times one dollar in the community gets circulated, what the benefit of that is.

Um, but I'm not just here to complain.

I want to see solutions and I have ideas.

Uh so I do have a meeting scheduled for I think next week, and I look forward to continuing the conversation.

Um, but at this time, and since the news of this new tax really only reached us 25 days ago, I would certainly like this committee or whoever actually makes the decision to at least pause this thing for six months, give us some time to talk about it.

Um, and I think that that's a really reasonable request.

So I'd like you guys to vote on that tonight.

If you can.

Thank you.

Well, thank you so much for coming to address the group.

And we have our third uh comment.

Um, yes, that's Sarah.

Welcome, Sarah.

Thank you for coming.

Hi, yes.

I wasn't actually planning on saying anything, but my name is Sarah Dukek and uh 4619 Canterbury Court Northwest.

Um, I just like to say it was kind of surprised for us also with the solar panels.

Um, we did get them in this fall, so we weren't aware this is happening, and so we were kind of borderline anyway on just the decision whether or not to do solar.

Um so um with uh federal stuff leaving and the new tax, I kind of feel like anyone who's doing the math, it'll probably fall off a cliff starting next year for anyone who is interested in pursuing solar.

Um, and I really respect RPU and I always have.

I feel like you guys communicate really well in general.

Um, so I guess um, if at some point um we could have just more information about what that's specifically going to.

Um, am I gonna just expect further rate hikes continuously?

Um at this point, it's really not um as much of an investment for us, just uh sort of a like, well, I guess we're doing green energy, which hopefully is good for everybody.

But um, I know the energy overall will be continuing to go up with all this stuff they're talking about in with AI and other stuff.

So um, how can we um together try to decrease our dependence on other stuff?

Um that's all.

Thanks.

Thank you so much for coming and to everyone who spoke.

With no one else um registered to address the board tonight.

Um, we'll move into our regular agenda.

Um, item number four.

First up is item number four A, and director uh Todd Blomstrom will present to us.

Um, can I get a motion and a second on 4A and then we'll have the discussion or presentation?

Point of order, Chair.

Yeah.

Um, I would if if you don't mind, I would just like to offer for all the speakers tonight.

We have members of our marketing and energy services team here that would be happy to work with you on your specific accounts.

Josh Mason sitting at the table there and Jake Jones.

So if you'd like to discuss any aspects of your accounts, they're prepared to help you tonight, and we'd be happy to further the discussion as well.

So sorry for that interruption.

No, good point.

Thanks for saying that.

Um, is anyone comfortable making a motion and getting a second before we move to discussion?

I'll I'll uh I'll move uh to uh uh approval of the utility uh to authorize the 2025 budget amendment for the water utility to convert water main oversizing reimbursement costs up to 1.075 million from the water utility capital expense to a water connection discharge expense for fiscal year 2025.

Thank you.

We have a motion.

All second.

Thank you.

Todd.

Well, good afternoon.

Um Gender Item 4A outlines recommendation by staff uh to amend the 2025 water utility budget, and it's related to the escalating cost for trunk water main oversizing.

So we have a brief presentation um just to give some background on what led us to have this funding deficit and a little more explanation about why uh staff is recommending the solution that we are within your agenda packet.

So uh on the slide, uh it does show on the right side shows the uh growth in our overall water distribution system over the last 130 years.

So since about 1950, we have seen an accelerated growth rate every decade as the system continues to expand.

And that accelerated growth rate rate continued up through about 2010.

At that point, we saw a bit of a slowdown um, I think overall in the housing market across the nation, but also in Rochester.

So the challenge we're faced with when we're developing the budget each year is to try and forecast how much expansion of the system we would expect over the next year or two years.

That's a little bit tricky.

Um we can take a look at the past uh trends over the last five years, or we can uh consider potentially accelerated growth like we've seen pre-2010 and making some assumptions to build the budget.

But nonetheless, all of these miles of water main are really categorized into two different categories.

One category is distribution mains.

So those are the water mains that are eight inches or less in diameter, and they really serve the function to provide water service rate to the properties that are directly adjacent to the water main.

And not only do those serve to provide water to adjacent properties, but they have extra capacity to convey water throughout the system, throughout our pressure zones or between pressure zones, between wells and booster stations and storage tanks.

So the split is about 75% of our water distribution mains are or of our water mains or water distribution mains.

About 25% are considered transmission mains within our system.

Well, some of this mileage was built under city contracts with street and utility improvement projects.

A vast majority of this mileage was constructed based on land development projects.

Developers come in with subdivisions, they go through a plan review process, and they are the ones that ultimately build a majority of the street mileage in the sewers and the water main within our systems.

During that development review process, our engineers look at each one of those development proposals and identify which of the mains within that subdivision need to be oversized so that we can tie the system together and we have transmission capacity through our distribution system.

So in exchange for making that requirement on developers, we have what's called oversizing reimbursement.

Water mains are not actually oversized, they're appropriately sized.

But to a from a developer's perspective, when RPU asks them to increase the diameter of the water main beyond what they would normally need for their land development, we typically term that oversizing expense.

So to have a fair and equitable system, RPU provides reimbursement for that incremental cost between what they normally would have put in an eight-inch water main and an oversized main, so that we have transmission capacity throughout the system.

Over the last five years, it has been relatively stable in terms of reimbursement demands.

We've averaged about 1900 feet of oversized main each year, and we've operated within a budget of about 150,000 per year.

And it has been relatively stable, like I say, over the last five years.

Things substantially changed this year.

We have seen seven uh large developments come through from approval processes last winter to construction starting in the spring and over the summer.

Um, quite a large amount of uh development has occurred.

Um, in fact, totaling what we had initially budgeted as 1,900 feet per year is close to 14,000 feet this year.

And the 150,000 uh that we have typically had to cover those reimbursement expenses is totaling 1.2 million this year.

So that's a substantial departure from what we had uh planned in our budget, um, really based on three things.

One, I believe we're seeing an a return to the accelerated development pace.

That's good news.

The city is looking to expand our housing inventory.

Um, there's targets to reach a thousand housing units per year.

We're seeing three of the largest national builders starting to come to Rochester and engage in projects.

So that's all good news, but it comes with an increased volume.

The other unique thing this year is there was a somewhat of a disproportionate layout in the development.

We see a lot of fringe development, um, which is really driving more transmission needs out on the perimeter of our system.

For example, two projects alone that you see on the screen, Badger Heights and Prairie Ridge.

Um, those are located just south of the 50th Avenue Hydro Pillar.

That's our second largest storage facility built a number of years ago, way out on the fringe of development.

Um, and now it is for the first time really starting to be fully utilized and tying that water tower into the distribution system to the south.

Uh, but that time process involves uh a large amount of transmission uh trunk water main to be installed.

So with that, uh we have a substantial expense.

Uh it was not anticipated, and we need to find a way to reconcile that deficit.

So there are really three funding sources for capital water main improvement projects.

One of them is our typical capital uh improvement budgeting that we do every year.

Uh, it goes into the budget.

In 2025, we have about 6.9 million dollars in our capital budget, but that's not just a pot of money.

Those are encumbered and allocated to specific projects that are being carried forward.

Um, I will say the city public works department has done a great job in delivering their projects this year.

Past years, some of those slipped, they get rescheduled, they don't move forward, they have moved forward with the projects they ended intended to this year.

So nearly all of that $6.9 million is encumbered on projects that are going to come due by the end of the year.

And there's very little contingency left to cover this additional expense.

The second funding source is water availability fees.

So we have a balance of about 2.5 million in that account.

The challenge with that account, though, is by Title 12 in the city code, those funds can only be used for storage improvements.

We want to work on that in future years, but today those funds would not be eligible to offset the trunk oversizing expenses.

And then the third option is water connection charges.

So those are charges that are levied on development projects.

RPU makes the initial investment to, for example, extend a large trunk water main out to the perimeter of our service area that then spurs development.

That development occurs, they pay connection charges to reimburse RPU for that initial investment.

That fund is sitting very healthy at uh about 3.6 million.

Um, and that again is funds that have been invested by RPU and have been recovered over time, and they are eligible to cover this expense.

The reason that staff is recommending the water connection charge be the source of funds to solve this.

If we try to absorb that additional expense in our current operating budget, that is going to draw down cash, and that is going to have upward pressure on rates for all of our customers.

So we're trying to avoid that.

And this is what staff believes is a good solution.

However, a question that you may have what about next year if this pace continues and we have the same issue.

Um, we are working on a master plan today, and we've we've had some brief discussions at the board level to look at some securing future water supply and identifying the infrastructure we need.

That's about half the story.

The other half on why the master plan is so important, is that we need to get the structure improved on our fees.

These expenses for wells and boosters and trunk oversizing really should be a development fee and not placed on the general fund for a couple of reasons.

One, uh, there's a subsidy element to it for existing ratepayers.

But also when these capital expenses aren't on development fees, as development accelerates, the collection of additional fees accelerate.

And when development decline, the revenue declines.

So that's why often uh the source for things like trunk oversizing rests with development fees, which we do not have today for that as a solution.

So perhaps a long description, but I wanted to give a little bit of background why we're proposing the solution.

We are um you have a resolution in your packet, uh, and it would amend the water utility budget for 2025 and converting those expenses from our general fund expenses to the water connection charge fund.

And with that, I'd be happy to answer any questions you may have.

Just let me say quick too.

I apologize.

The resolutions on page 132 of the packet.

So I did mention that earlier.

Thank you.

Yep.

Yes, Councilmember Keene.

I I think I understand what's happening here, and I appreciate the connections that you know, all the developments going on, how the difference between the way sewer does their development fees and RPU.

So I think I understand some of the background, but I I'm wondering about the solution of just showing the that we uh missed the budget this year and showing that we spent more than we had budgeted.

I don't see how that's gonna affect ratepayers.

Very good question.

Um, in the long term, and when the, you know, if this was a hundred thousand dollar deficit, probably could be absorbed.

When the number gets large enough and we absorb that cost, it draws down our fund balance.

We have to maintain certain minimum fund balances in the utilities.

And so as that minimum fund balance drops below what our target is, that is what starts to drive how we determine what rate adjustments are needed for the next year.

So that's sort of the direct connection if you absorb a large amount of expense that wasn't budgeted.

So it appears then the key thing is freeing up the 3.6 million out of the that.

That's what we're really doing here.

That is what we're really doing here, yes.

Okay.

Thank you.

A quick question.

Just I mean, it's I lived this in my old world, right?

I know exactly what you're going through.

Um, and I guess just it would be nice to get an update on how you know how that's the this new fee, so that the developers or the development pays for the upsizing or the past upsizing, or however that's gonna work.

Just be good to get an update on that.

Sure.

So as you're I'm very, very aware, um, the wastewater system went through a very similar process of looking at what their long-term expenses are for what is equivalent of our trunk water main, their trunk wastewater system, and the costs that need to be um recovered in those expenses.

They formed what is essentially uh water availability fee so that funds are paid on a per acre basis, goes into a fund, those funds are then used to uh expand the wastewater system, like we would cover the expenses for building transmission mains in our water system.

So a big part of the path forward for this master plan is almost replicating what the wastewater system had done.

I think it was about 10 years ago now, eight years ago.

Yeah, six probably six wasn't that long ago.

Maybe feels like uh, but it is very similar process, and it's not easy because not only do you have to just navigate that and and make sure that it's fair and equitable to developers, but you really have to have a good handle on what your future capital funding needs are so that you can calculate appropriate fees.

So, yes, that is the path forward on um what we hope to be back in front of the board with uh probably in the fall of next year.

Just a couple more points there.

We also recognize that those that fee structure needs to be also brought to the city council as well.

So we're targeting a series of engagements with the city council, probably starting in what did we say, June-ish.

Introduce the concept, talk about the progress on the comprehensive master plan for the water distribution system and target uh evaluating the fees and implementing them probably for fiscal year 27 for the following year.

So I'd also like to highlight we still see additional development growth coming next year.

So we're very likely going to be in a similar position next year with higher than budgeted trunk line expense.

And so both this year, this is a temporary solution.

It's not a permanent solution there.

If we don't do anything more, it will draw down fund balance if it comes from our enterprise general fund, or it will consume dollars in the water connection charge fund without replenishment.

And so addressing these fees in the future is critical to have a sustainable financial model as well.

Just wanted to preview what's coming next year.

We need to complete our planning work, uh evaluate a fee structure where development could pay for this type of trunk oversizing.

It's just always been the case for RPU water that we have rate funded trunk oversizing.

So it's always been an expense of our capital funded from our water rates.

We haven't had a fee basis for doing this for the trunk oversizing.

So we're at a point where that needs to change into the future, and this is just a preview for what's coming down the road.

Again, a short-term solution.

Councilmember Keene.

Yeah, I think we already have a motion on the table.

And uh uh, but I want to make the point here, just that it wasn't said straight out, but just more simply the the policy that we're trying to implement behind this is development pays for development, and it doesn't, those expenses don't land on the existing ratepayers.

That that's what we're trying to do here, and it's difficult because you're looking forward and and the when public works did it with the sewer.

This was not something that uh everyone just said, Oh, yeah, I understand exactly why I'm paying these much higher fees than I was paying in the past.

This is a painful process.

It is any other questions or comments.

Okay, hearing none, we have a motion.

Uh we have a second.

All in favor of approving the resolution on page 132 for item 4A.

Say aye.

Aye.

Aye.

Aye.

Opposed.

Carries.

That is approved.

We will also bring this forward to city council on the December 1st agenda, which is next Monday.

The packet's ready to publish tomorrow.

So with the board's uh uh authorization here, we'll include that in the packet materials for next Monday and bring it forward with the same night we're asking council to approve the 2627 budget.

We'll be seeking a 2025 budget amendment.

Perfect.

Um, next we move to regular agenda item number four B.

Um, and this one is an authorization for battery energy energy storage agreements.

Um, and this is supported by the resolution on page 135 of the packet.

Um we'll hear from Director Bill Bullock on this particular authorization uh resolution.

Could I get a motion and a second before we move to discussion?

I'm I make a motion to approve authorization for battery energy storage agreement resolution on page 135.

I'll second.

We have a motion, second.

Thank you.

And Director Bullock.

Thank you.

I'm returning on the topic that we presented last month.

As you know, we have a pretty solid plan for delivering liable capacity and renewable energy, the reliable capacity includes a battery storage component.

We have not, this would be the first uh part of delivering on that battery storage component.

Um, and it helps balance our renewable portfolio, which is now at about two thirds of the goal for 2030.

Um, but it still gets us to net zero by 2030.

Um, so just a refresher on how the battery uh works.

Um the gray line is the cost of our overall power portfolio um at any point in the day.

This was happened to be July 23rd, 2025, a high peak day.

Um we would and here we've modeled uh what some of these assets would do.

Um so as you can see, the the solar is down at the bottom in yellow, the the wind is in green, um, and then our dispatchable resources, the uh Cascade Creek in West Side Station and the new um uh uh Mount Simon are in the blue shades.

Um the the pink shade is what we would still have to buy from the market um based on our load.

Um, and then the orange uh line is what the market price would be.

So as you can see, as load goes up, the the price goes up.

And the idea is to as it starts to get over uh our average portfolio and increases um very high in the market.

We we want to be able to uh to address it.

So as you can see, on the number one is where we would be anticipating a hot day, and we would charge the battery when prices are low.

As you can see, it's charging when there's a lot of wind on the system in the overnight hours, and then we're able to discharge it in the evening hours when prices are very high, um, helping to uh deliver at a very higher uh much higher cost of electricity.

Um, and that's the energy arbitrage.

So that's would be a net positive economic value for us.

Um capacity, um, this would provide us capacity.

That's why we're putting it in.

Um, if we're looking at the last auction, um, as you can see, prices were the highest that they've ever been.

Um, and that is primarily due to the decreasing margins.

There are um a lot of planned retirements in MISO, and those are decreasing the margins and making some assets run a lot more.

We definitely saw more hours that we were running this past year with our existing fleet, um, and we expect that pressure to continue.

Um the new bills that are in the MISO queue are are a bit more questionable because of the rising cost of interconnects as well as the repeal of the uh tax credits and just general inflation.

Um, and so the upward cost pressures are expected to continue.

So if we turn the capacity price that was uh in the last auction in the summer, that was $20.28 cents per kilowatt month.

Um again, that's a record high.

Um, it's lower in the other seasons, but you need it uh when you need it.

Um and this kind of gives the outline of the overall um uh annual economics.

Um here we would be paying in the vicinity of of uh $14 a kilowatt month.

Uh that is much lower than the $20 uh that we saw in the last auction for summer.

Um the the cost of operating the battery, the 20 megawatt battery would be higher than just buying the capacity, but then there are the additional benefits of having the battery that that energy arbitrage and the ancillary services from the battery allow us to collect some additional revenue and offset some of the additional costs from having the the battery in the off seasons, so in the fall, winter, and spring when capacity market prices are lowered.

Um so it is uh somewhat uh close to break-even.

Um, it will be different every year.

Um, we'll certainly be monitoring the performance of that battery um on a very uh close basis.

So this project will have a pretty fast deployment.

Um 20 megawatts uh uh are going to be at 10 megawatts at Zumbro Station, which is the substation over by the water treatment plant, and then one at the service center here.

Um the developer has uh um supply that's already on shore, so there's no tariff risk to it currently.

Um and they're connecting to the distribution system.

Um, so there's no interconnection delay.

Um permitting is relatively simple.

We need a zoning certification and a uh site storm water review.

Um there are no missions, so no air permit is required.

Um and then the contract structure is a tolling agreement.

So we basically pay the developer to build, own and maintain the battery, and uh we're responsible for dispatching it and acting as the market participant.

Um there's a lease agreement for the land under the battery.

Um, so that just grants site control to the developer so they can own and operate and get access to the battery.

Um the the lease and the tolling agreement are will are co-terminal, so they will end at the same time.

Um, and then the interconnection agreement is part of our ordinary business for any device connected to our distribution system.

Um so the two locations, one is here at the um at the uh service center, the other is at the uh Zumbro substation.

Both units will feed into the same substation, but on different feeders.

Um this is a layout.

Um, I know it's hard to see with the lines.

It's it's uh just uh planning out the space.

This is our at the RPU service center uh in the back here near uh uh near the building next door.

Um and you can see there are 10 containers of batteries.

Um basically 10 um containers that you would see uh shipping containers.

Um each one of those is four megawatt hours of capacity.

Um capacity.

Um then they have left room to augment.

So over time the batteries may degrade.

Um they do have performance requirements, so they will be augmenting the containers uh as they need to as the batteries start to degrade and uh they'll maintain the capacity that way.

Um, and this is the arrangement we'll see at the Zumbro substation.

It's angled because the parcel is oddly configured.

So they want to stay on in one parcel.

It's directly adjacent to our substation.

Um, and again, the same exact configuration with 10 uh containers uh with the auxiliary equipment.

So you have a resolution uh in front of you.

Um important to note that uh it's it's a tolling agreement.

We do need to ensure that this is uh part of uh that simple will consider this outside the supply agreement, meaning that we'll be able to take advantage of that energy arbitrage in the market.

Otherwise, we're buying power to charge the battery at the power supply contract price and selling it to them.

Um, you know, just lowering our load when we discharge it.

So we wouldn't be able to we take we'd get a little advantage of the uh battery that way, but not uh not the full market value.

Um simpa has agreed to take this up in their next board meeting.

Um there'll be a resolution that they'll they will um uh look at allowing all of their members to treat these types of projects outside the the supply agreement.

Um and uh and that so that's uh if you have any questions, let me know.

I'll weigh in on just one thing, Bill, to add to that.

Uh minor correction.

This is just a carve out for Rochester in the Simpa boardroom.

So Simpa is specifically not offering this to all other members.

Um there is general consensus amongst the board.

We had a retreat last week to consider these battery projects just as the Valley High Solar Project has been considered as behind the meter generation.

The only difference is this will have negative generation while it's discharging, but the treatment will be the same.

The reason that it's an RPU only kind of offering is we have a miceo node here locally.

There's already we're a load serving entity and we're a generation entity and we have market operations capability.

So um, yes, SIMPA is favorable.

I believe the board will um as long as there's no legal hitches in this last couple weeks, the board will consider supporting Rochester moving forward with this.

We did write the resolution both here and what we would intend to bring to City Council contingent on Simpa's final approval because this does not pencil out without support from SIMPA.

So we had a favorable response, really good discussion there.

Um grateful for Simpa and their partnership in this one as well, but it it will require them to commit to this contractually.

Um and we expect that in early December.

Councilmember Keene.

Uh yeah, thank you.

I I think uh uh General Manager McCollum answered some of this, but just on the capacity thing, 20 megawatts, and we're getting 100% on a on the MISO.

They give they give 100% of that to our capacity well, it will be accredited.

Um, so we do need to it'll be accredited based on its ability to meet the peak load, the coincidence peak.

And and I I'm just responding based on the stuff with solar and how you if you had uh uh uh our our nameplate says 100, you might get the capacity benefit of 30.

I'm making those up.

This is whatever is is a hundred percent of the of the nameplate, could be nothing is a hundred percent typically.

Um but this could be as low as 70 percent of the output could could be credited, but you'll know that when uh okay uh they they assume an accreditation when you first install but they treat it as on demand, they treat it as on demand, and it is easier.

You can tell it when to dispatch.

Yep, uh the response time is higher than it is for the other dispatchable assets.

Um the only issue is that it can only store four hours of yeah, yeah.

Okay.

So um with a gas unit, you can keep burning the gas, but but it seems like there's the use case for the evenings.

That's a perfect combination for the use case in the high energy evenings.

Yeah, okay.

The capacity of this will vary by season as well.

So MISO has already shown that batteries have strong accreditation in the high 80% range of nameplate in the summer season.

Winter is more challenging.

Uh so the winter capacity by 2030, we would expect to be about 50% of nameplate due to the double peaks on a winter day.

We're targeting this for summer capacity.

That's where our driving capacity seasons are.

So we'll get decent capacity out of this in the high 80% range for summer, spring, and fall if it performs as we expect.

And then winter would be the one season where there's less capacity there, but that's not our driving season.

Okay.

Thank you.

Uh number the other one, just um, is there any uh security concerns with access to our property?

Uh no, no.

I mean, uh they're you know, substations are critical uh infrastructure.

This will be secured, it'll be fenced in with the same sort of protections we have in our physical security of do we already have other vendors coming into our property?

They will not be going into our substation.

They will be going into the there's a separate fence or round.

Okay, so it's carved off of our property, but it's not with it's they're not inside the security.

Yeah, right.

Thank you.

We will need to bring them on this property, and we have vendors routinely coming on this property that we can work with to give them security access, like our vegetation management contractors.

They they have cards and can get in and we we vet them inside the security perimeter.

So it's it's not something totally new.

I just couldn't tell when you had the separate building.

Um we talked about this a little bit, but this is this considered behind the meter that when we're charging this, is it considered it's yeah?

It it will be considered uh it will be behind the meter, but it but myself will be able to see it.

So we'll get credit for that.

I'm not thinking when it's dispatching, I'm thinking when you're charging it.

Yes, when we're charging it, we will get the um the locational marginal price.

So the the market price.

So we will be doing that really through the MISO market, even charge.

We won't do that like in our basement, is I would say it.

Right.

Right.

Yep.

It's it's a myso sees it as being able to play in the market, even though it's behind the meter.

So from MISO's perspective, it's not interconnected at the transmission level from Simpa's perspective.

They see it behind the meter because it's behind the town gate meters, and they're hopefully going to agree to treat it as effectively in front of the meter from their perspective.

From our perspective, it's in our distribution system and wouldn't be behind a customer meter.

So it depends on what seat you're sitting in.

Right.

Yeah.

When you talk about what behind the meter means, because it means something different to us to Simpa to MISO.

Key points is MISO will see it as generation.

We'll be able to play in the day ahead market there.

Simple will see it as a generating asset, really sitting like Valley High Solar is carved out of the contract.

So we're not paying for load there from what it uh we'll we'll pay for load as if it was being bought from Simpa there, and that works on the economics here.

Good.

My last question, it might be oversimplified.

I I'm struggling with the word tolling.

I'm not, I can't get uh a dollar amount in my head that if we're committing to a 20-year lease, or how are we paying for this?

It it is a fixed price, so it's based on the capacity of the unit.

But when there's no upfront capital, this no, there's no upfront.

Yeah, the other companies building this for us based on a contract that we're gonna buy so much, or I I'm I'm so they can't get it in my head, right?

Yeah, yeah, no, sure.

So they own the asset.

Yep, uh, they maintain the asset, and we get to use it um and and put it into the market.

So we we're responsible for all the inputs into it and all of the the outputs.

And they get paid based on us uh it being there, so and them maintaining the capacity and availability of the of the unit.

I I guess I went through the request for uh uh action and I went into the fiscal resources, and I I can't find a dollar amount, and I'm just struggling with this.

So the dollar amounts are protected under commercial terms, that's why it's redacted from the contract.

But we're paying a fixed monthly rate on this on based off of the size of its capacity.

No, I I think I have I think I understand it now, but yeah, all right.

Treat it like leasing a car.

We're gonna make them a monthly payment, and then we get to use the battery, but we put the fuel in it and drive it.

It's kind of kind of like that.

But it's it's a fixed monthly fee, it's not based on capacity or usage or anything like that.

We're gonna pay the same amount whether we charge it or discharge it or not.

So we're gonna try and maximize its value by charging it and discharging it every day to arbitrage low cost to high cost energy, as well as get it accredited for capacity so we can sell or use the capacity, which has strong value for us as well.

Last question.

If you could if you could have gotten double this amount of capac double this, go to 40 or 60, would you have done it?

Or is there something unique about the 20?

I I would have recommended we do more.

I like I would have done 80, but the sites were more difficult to find where we could quickly interconnect with the constraint was though was the site control and not in a residential neighborhood, yeah.

You know, properly zoned.

So all right, thank you.

Okay.

I was probably more cautious on the size here, wanting us to gain some experience with batteries.

Also recall that when we did our 20-year financial forecast, we picked uh we offered scenario five, which actually loaded more of our future capacity away from batteries because one of the risks that we're trying to manage here in the future is MISO tells you how many hours get accredited.

And so there is a risk that these batteries will lose accreditation, not because we don't discharge them or not because they don't operate well, but because MISO says you need a six-hour battery versus a four.

So we are limiting our battery investment at this point, small scale, get some experience, learn how to use it, and still looking to the future to say do we scale this up more for batteries in in the future.

So uh as Bill said, 20 megawatts, if we can get that accredited, is about 20% of our remaining capacity gap.

So we're making another significant step forward and securing capacity, but it's not the full step of what we need.

Right.

No, appreciate it.

Thank you.

Really good question.

Any other questions?

Just a quick one.

I think Martha covered it, but from the uh dispatching RPU will have complete control of the dispatching and the communications.

There's no cyber situation.

The vendor is not part of the communications or um reaching in from the uh from the outside.

No, it'll be a portal in the it'll be uh bringing we'll be bringing um communication back to our SCADA in a one-way sort of so there won't be um they won't be able to get into our SCADA from the system.

Yeah, so that makes sense.

And then the other thing, um, I assume will we will we be able to measure um and maybe report out after a year of operation?

Yes, okay.

Yeah, actually we'll be able to we'll be watching very closely.

Yeah, that's part of the as part of the learning experience.

Yes, we will do not only how it operates, but its financial metrics as well.

So at this contract right here, we're committing, help me bill with the annual total here, about three million dollars of annual expense towards leasing these batteries, and we're expecting that selling the capacity will gain us about half of that back, and then the daily energy arbitrage will cover the other half.

So we're planning on this being cost neutral, but its performance is critical for that as well.

Um, so yes, we will be reporting not only its performance like technically, but economically as well, so that it doesn't add rate pressure to our customers.

Any other questions from any of the other members?

If not, I had a couple real quick.

So um two things.

One, um, what happens at the end of life?

We get to year 20, this company's gone bankrupt.

Do we just suddenly own batteries or do they bring in with a forklift, pick them up, take them home?

Like what happens?

There is a requirement in the contract for them to um remove the site and re restore it essentially to what it was uh uh when they arrived.

Um, and there is a a security layer of credit that will be um um uh on file that we can access.

Okay, we're covered then in that and then um if something goes wrong with uh there's a maintenance issue, um we're not jumping in and working on it.

They're sending someone from somewhere to come to Rochester to to work on it.

Yes, yeah.

And it is a um it is a company with the coast to coast operations.

So they're okay, reasonably closer if we're able to get here.

So and we do, you know, if batteries are we we find that they're a good and effective way of delivering capacity.

We will, you know, we would like to train our people on maintaining them so that we could use it as a as a resource going forward.

Oh, I'm I'm excited we're doing it, and I'm really excited what we'll learn from doing it.

I think that's fantastic.

Last question um, what does insurance look like for it?

Do we have to maintain a little bit of additional insurance around the site?

Do they fully cover the battery if it you know yeah, they fully cover the the batteries if anything should happen to any of their infrastructure?

We are covered for liability if their battery causes any damage in the vicinity.

Um, and then of course, we've let our insurance company know that we are uh putting this there, and we've let them know what insurance is the the developer will cover will have so that they they understand what our additional risk might be.

So thank you so much for answering all those questions.

Okay.

We have a motion, we have a second.

Uh any other discussion.

If not, um, all in favor of approving uh the resolution on page 135 for item 4B.

Say aye.

Aye.

Aye.

Opposed.

Motion carries.

And it's approved.

Thank you, everyone, for those presentations.

Now we're going to move quickly to the informational section of our meeting.

Uh under bullet point number five.

First up is item 5A, an update on LSR on the LSR program and impact on need for water short-term debt credit facility.

Well, thank you.

Um it's a shocking that it has only been a year uh since we began uh this whole journey through lead service line replacement projects.

Just a little bit of the backstory.

Um, so in 2024, the lead and copper rule from the US EPA was updated.

Um, it set many new requirements for water utilities to respond to lead service lines in their uh distribution systems.

One of those being uh that uh lead service lines were to be replaced within a 10-year time frame.

That is from a compliance date in 2027.

So we're looking at about 2037 um to remove and replace all the lead service lines in uh Rochester service area.

There have been some changes to the funding availability here in just the last month, uh, and the public facilities authority had posted um a notice out so that it is quasi-official here uh as recently as last week.

So I wanted to give a quick overview on that.

Um, but just a quick recap of what we've uh accomplished so far this year.

Uh in 2025, uh we were able to establish a lead service line uh replacement program, kind of the foundation of the whole program.

Uh we set up a schedule of how we're going to work through our inventory uh over the next four years, uh, set up a website.

We had a lot of public education and engagement throughout the community uh to gain people's attention uh on the risks of lead exposure through lead service lines and seeking to get their cooperation and participate in the program.

Uh this summer we entered into a master grant agreement with public facilities authority, and we were awarded 1.7 million uh to get the program started here this year.

Um we did follow up and go ahead and submit all four years of our our lead service line replacement program, which was intended to get us all the way through the replacement needs over the next four years.

We submitted that to what's called the project priority list.

So to get on that list, that makes those projects eligible uh for the revolving fund, which is essentially the funding mechanism for state funding.

Uh and then we went ahead and followed up and and filed for the project for 2026 and the amount of 12 million dollars.

So we were looking at radically accelerating this program.

There is only so much funds available.

And for those utilities that could ramp up quickly, uh there was an advantage.

And the program from its sort of inception was almost set up as an incentive for those utilities that could respond quickly and move ahead promptly with replacements.

And then finally, we awarded a construction contract here this fall.

We had completed 87 investigations of unknown uh water services, and we have a contract for 48 service replacements.

To date, the contractor has completed 20 lead replacements.

Um we're losing the weather here pretty quickly starting next week.

So some of that might have to wait till the spring.

Uh, but nonetheless, with the late start, I'm really proud of the the staff, uh, Luke Payne, Todd Osweiler, a lot of other people here to get the program up and running this year.

So to give a little bit of background of what's occurring, um, the lead service line replacement program has really two funding sources.

The 23 legislature, state legislator dedicated about 243 million in state funds to pair up with about 350 million uh in federal funding from the IIJA.

Uh so that totals about 593 million that are coming in for lead replacement funding uh from the state program.

To put that in perspective, uh the Department of Health has estimated the number of lead service lines statewide.

They have every utility's inventory, and based on what they estimate for uh the unit cost of replacing a lead service line, they estimate between 1.5 and 2.2 billion is needed for the program.

So doing the math, uh that's about a 27% to set 40% funding rate uh for the overall need.

Um otherwise, 60% to 73% is not funded with the funds that are available today.

So, as you probably could imagine, um, many utilities saw uh kind of the funding situation and the urgency of getting in line as quickly as possible.

The states reported that the 2026 request totaled 428 million.

So essentially the program funding was depleted within just the first two years.

The state, for good reason, has concluded that that's not sustainable, and this race to whoever can be first may not be the best overall approach for the city for statewide uh administration of the program.

So uh they have notified utilities uh that they have to change the funding mechanism uh to get this program stabilized.

They've essentially created three tiers.

So the first tier uh is basically utilities that have less than 50 lead services overall.

No reason to really stretch those out.

Economy of scale, it's good to just if they want to need to move forward, they can move forward and funding would be made available for those small cities and townships.

There are the cities that have between 50 and 500 lead services, and for those tier two communities, um, they're looking at placing a cap of $1 million a year uh in max funding.

And then there are the utilities that have more than 500, uh, which Rochester does.

We have about 520, so not by much, but we're over.

Um, those utilities they're allocating generally 10% of the replacements on a unit cost basis.

I think they're estimating about 25 uh0 or so per service.

All in all, um, we're going from 12 million to 1.5 million in funding for next year.

Um, it's a big disappointment.

Um, but statewide, there's 200 utilities that were trying to do the same thing we were basically.

And so they're all 200 are to some degree disappointed with the changes.

Um, but the decision is made.

Um, it's really not up for negotiation.

The state published the intended use plan last week.

It's up for public comment, and there's been adjustments on the funding rates for all the cities on that IUP list.

So that is set in motion.

We expect the IUP to be approved here at the end of the year.

Um, and so um we can pretty much count on 1.5 million next year.

That being said, um, for a city our size, we have relatively few actual lead services.

We have 250 known lead services, uh, about 268 galvanized services that need replacing.

Those are fairly low numbers.

There's cities with thousands of lead services in Minnesota.

We do have a large uh proportion of unknown services, about uh six percent of our services are unknown.

We simply just don't have records of of homes that were built 80 years ago, and the plumbing records are not available.

So we have a lot of investigation to be done with all of this.

Um two things.

One, our strategy needs to shift.

Um, we want to really concentrate on those homeowners that want to step forward and replace their lead services at the lowest possible cost.

We're looking at some things we can do with contracting, get the unit pricing down.

Um, but we're gonna probably spend a little less time pleading with people to participate in the program because those people that really want to, that's a much lower cost.

Those that get missed, we can keep them on the list and we can circle back with them.

Um, but we don't want to spend a disproportionate amount of our limited funds chasing people who don't seem to really be interested in participating in the program.

But again, that being said, we won't forget them.

And then our goal is to really knock down the number of unknowns in the system.

There's some what we call low hanging fruit um manufactured housing parks where you have 200 services, they're all listed as unknown.

We can investigate a few of those.

They were all put in probably in the same construction season by the same contractor.

We can knock off a couple hundred at a time of unknowns pretty easily.

So our goal is to get um the non-led category up to 95%, basically knock off about 800 to a thousand unknown services here in the next year, uh, as well as probably 50 more lead services.

The other side of that, uh, in the title of the agenda item, um, we did anticipate having to have some short-term borrowing for both the AMI project and this lead project coinciding at the same time.

It's a very heavy cash demand.

The 12 million is not permanently out of our uh funding source because it's a reimbursement process, but we have carrying costs with that amount of expense being extended.

Obviously, that greatly reduces when it comes down to 1.5 million versus 12.

Um, I think Peter's still working on uh what we may need for short-term debt, but I think it's greatly reduced compared to what we had originally estimated.

So that's an update.

Um, which I had better news, but uh we'll do the best we can with the money that we're getting available for any questions.

I have a question about that carrying costs.

When we were initially discussing this program, we wanted to be cognizant of the fact that we didn't have certain categories of rate carriers subsidizing replacement of services that other ratepayers owned.

Are we still able to include for our future requests from the state, albeit perhaps strung out over a longer period of time requests to refund those carrying costs, or would that be on the utility now?

Good question.

I think that the arrangement is still the same.

Uh the size becomes less, so the carrying costs are less, but they're carrying costs nonetheless.

And those are eligible expenses from what PFA has told us.

Um it is year to year.

So we come in with a 25 project, we're done, we seek reimbursement, we get reimbursed, the the carrying costs are satisfied.

You come into 26.

There's nothing that lingers throughout the whole five, four-year, five-year, 10-year cycle, but it is each year annual cycle, some carrying costs, expenses.

And again, uh, we've been told that's an eligible reimbursable expense.

Wendy.

I think it's a federal requirement to eliminate all of these by I don't remember.

2037.

Okay.

So are there is there talk about how to manage through that with this shortage of funds?

Uh I think there's a lot of talk.

I think there's even litigation challenging uh the requirement of uh unfunded mandate of this size.

It's a burden for us.

Uh a city like Baltimore, Philadelphia.

I mean, it's hundreds of millions of dollars.

And and they uh those states are are not as well funded as Minnesota is at least today.

So uh incredible financial burden, and there's some question if it's even feasible financially for some of those cities to meet the 10-year demand.

Yeah.

Councilmember Keene.

Um looking, I was trying to listen to your words, and I don't I couldn't convert them, but uh the focus will be on converting unknowns and basically get further along so that we know that we have you know not 520, it's more like 800 and whatever the right number is.

Sure.

Is there, I mean, is that going to be the focus, or are we going to try to split that half and half with the the money that's that's there?

A vast majority of the funds are going to be uh put towards in the field replacement of lead services.

Okay.

We're gonna have to absorb some of that work.

We're going to shuttle that off to a consultant, and with the limited funds, we're gonna try and bring more of that work back in house.

All right, yeah.

So this is another part of my question is how the spending happens.

Is it because I imagine there's engineering fees, but there's also construction, like yes, make it happen.

And those can be those are separate, or are they all in the same company doing it?

Uh so the engineering firm SEH that we have working for us, they're administering the program, doing the design plan specs, bidding, helping us bid, administering construction, and they have fees, and then there's construction contractors, independent bowlanders, the contractor this year.

Okay, and we have expenses, obviously, from them.

And and do we I'm I'm trying to get this breakdown between is SEH like our subcontractor, and then we don't deal with Olander, or do they or we hire both of them, one to do the planning, one to do the the operation.

I understand your question.

Yeah, so we have a professional service agreement with with SEH.

We RPU bid the construction contract and hold the construction contract in our name.

The engineering firm is our representative, but ultimately the construction contract is directly between RPU, the city of Rochester, and the construction contract.

Okay.

Yeah.

So I'm just trying to see how much control we have over that.

Because I I probably misunderstood you, sir, because when I heard we were focusing on the unknowns, I thought we'd spend a bigger part of our the money left on trying to knock that 2500 number down.

Another very good question.

So knocking it down from 2536 to 1500 will probably be you know, take a moderate amount of effort, probably in-house.

As that number decreases, it's going to be increasingly more expensive.

The last 500 to a thousand is going to be out in the field excavating a hole in there for we're not going to get to it with this kind of funding.

No, okay.

Yes.

All right.

Um, last question.

We're gonna have this process in place.

Um, and have like kind of the know-how and how to do it.

And I my theory is we'd be getting better at it.

Yes.

Is there a chance of chasing other money for this?

Uh I I think every utility in the state with lead services is chasing after every available dollar.

Um it's a valid question.

I I don't know of any other because it's so expensive, the federal IIJ and the state legislature were but I'm thinking of things like the Bush groups and things like those bigger things, something like this, especially if you have real know-how and can show that you're you're doing it.

I I would think it may not be state level money, it might be more foundation stuff.

But it'd be nice.

Just uh us having a relatively few number of lead services, our program is on the order of 20 million.

So that no, it is daunting the numbers.

Yeah, yeah, that would it it's a lot of it's very cash intensive.

Well, Ross, I'll I'll just say I'm glad we got into this when we did, and at least have some progress and a better scoping of what our issues are.

Yeah, good.

If I could add two more points, I think in line with your questions, uh Councilman Burkeen.

Our internal labor is reimbursed as well, is reimbursable as well, and some of our overheads, so that also relieves some short-term rate pressure for us since our labor costs are relatively fixed in a year with just the staffing levels that we have.

So there is some inherent benefit to our internal staff doing some of this work as well, because it is reimbursable through the state program.

Um, also like to note that on the legislative priorities, we did add continuation of funding for the lead service line program to both our federal and our state policy um agenda, and we'll continue to work next session with both state and federal delegates about seeing if there's additional funding support that could come in the future.

I will admit I don't have high hopes uh for additional funding coming from either state or federal in the current budget conditions, but it's part of our agenda.

Understood, thank you.

Any other questions?

If not, thank you so much for that update and appreciate it.

Okay, we're moving along quickly then.

Item five A is resolved.

And next up, informational item five B, cybersecurity professional development for us, yay.

And good, thank you.

Yes, professional development for you.

Um, actually, so General Manager McCullough made the slide title, so I had to make this work within that context as well.

So that is that is what it is.

Um, but yeah, good evening.

Thank you guys for for your attention to this particular topic.

Um interestingly enough, cybersecurity is is a business issue.

And so it sits alongside a lot of our other core services like finance things along those lines.

So it actually is really important that um we have a board component to our overall strategy.

So I think that's kind of a kind of an interesting piece that we're gonna do with this.

Um, but we won't get into the weeds on cybersecurity.

You know, we won't get any classified information, things along those lines.

But if you have questions, please please bring them up and I'll answer to the best of my ability as well.

So I always think it's really important.

So I'm going to skip past this one is to really start with why.

So when we start talking cybersecurity and why is it actually important for RPU?

The biggest part is, of course, you know, we have a very reliable system.

And part of that is the public trust that they put in us to maintain that reliable system.

And cybersecurity is kind of a core function of that one.

So all of those things combined is why we do this from a business perspective, too.

Which leads us right into what?

So what are we up against?

It's not hard to say that the cyber threat landscape is continually evolving, it's continually changing, and the number of threats is increasing at all at all times.

We have nation state actors, we have local actors, things along those lines that are actually trying to uh break into our systems as they are.

Uh the latest Microsoft threat report in this case indicated basically that the vast majority of our cybersecurity incidents are actually due for financial gain.

And as such, we have ransomware attacks as the primary reason or the primary threat vector that we have to deal with in cybersecurity.

Most of the ways that they come into our front door is your traditional phishing, you know, and we also have uh vishing and quishing, which is if you haven't had a phishing email, you might have had a phishing phone call, which is a voice call.

And then we also have quishing, which is kind of a fun one too, where people start scanning QR codes that don't go where they they should go.

Um so I actually dropped that on there because that's again the most common threat factor that that we have.

That's what leads to most ransomware.

Most of these, like I said, are predominantly financial gain.

That's why people are actually doing these things.

Uh in the event we have a nation state actor that isn't doing something besides financial gain, um, actual disruption.

The most common piece that Drago said in their last report said is going to be denial of service.

So we think about what that actually is.

Um taking down our systems and actually causing a disruption to how we do business is is the that's if we get to that next level when you think about it.

So and then actually, if you really think about it, what could all happen?

You know, I listed a couple of the pieces that are on here.

And really, if you just kind of take a moment and think about that, you know, what would that mean to you?

You know, as you know, a councilman with a with a ward of constituents, things along those lines, um, how would you respond?

And that leads us directly into effectively what we're doing.

So just like other departments uh within the utility here, um, we tend to go through uh uh a regular approach of being prepared for these kinds of incidents, you know, we try to detect them, and then of course how we respond, you know.

So we're gonna go through that same exact process.

Uh we provide or we do tabletop exercises, which is effectively where we mock an incident up.

Um we create little injects, things along those lines to throw things off.

But the whole idea is to test our incident response plan.

Um, shoot holes in it and do it in a in a mock scenario without actually doing it in real life.

It, you know, practice makes perfect, and that's the approach that we tend to take with it.

So we do these tabletop exercises since I've got here, we've done like three of them now.

And the idea is we just get better and better with some of these things.

Uh we actually do regular risk assessments, um, which is kind of an important part because the vulnerabilities keep changing all the time.

So when we actually do these, um, we're actually testing out our systems against some of the latest threats as well.

So we're doing regular risk assessments, and then of course we're training staff too.

Um, I'd be reminiscent to say if if we didn't have the staff um notifying us on some of these detections, it's the human mind can do some pretty amazing things when they see patterns and things like that.

So with that, I'm not gonna get into all the tools that we use.

We have a whole number of tools that are monitoring network traffic, looking for patterns, heuristics, things along those lines.

Um, but we're constantly doing this sort of behind the scenes.

Um, if you will, we're kind of looking at it and tapping into that that data and seeing if there's any patterns that effectively match other threats that we happen to have.

The other big piece is we just recently implemented the security operations center.

So all of our systems produce a lot of log files.

Um, these log files have all kinds of information in them, and it's like looking for a needle in a stack of needles to find the one thing that you actually need inside these log files.

Um, so we have a security operation center that's actually looking at it and trying to match those patterns with with common threats that we happen to have as well.

So we have that going on in the background as well.

And then, like I mentioned before, we have the human brain.

Our staff are trained to see those things.

Um, they're trained to basically reach out to the IT security scene when something actually seems abnormal, and we can start investigating and jump right into it, which is kind of the fun part.

Uh our actual response, which is our incident response plan.

Um if you don't have one in place, uh, you're kind of running around like a chicken with your head cut off.

It's not a not a not a great place to be.

So having a solid response plan is is absolutely critical.

And of course, our response plan, you know, since there's no one event that's ever the same, it's very modular in nature.

Um, depending on the type of event, the impact of the event, that leads us down different paths within this response plan.

So think of it as like a flow chart with multiple avenues to go through.

Um, and of course, that's the idea behind getting and starting to actually manage these incidents.

In the event you have one, you have all the resources available within that incident response plan, who to call, um, your FBI liaison officer, Department of Homeland Security, EISAC, things along those lines.

So our incident response plan, um, we've always talked about trying to actually make it smaller, easier to navigate, you know, more agile.

But as the incidents and things start to change, we just keep adding more to the incident response plan.

So the idea is having all that stuff readily available.

You actually have have to use it and deal with it.

I don't know any electric utility that wouldn't at least mention this.

Nurk.

So I don't know if you guys heard that.

There was a there's a little sigh out of some of the operations folks, um, when we mentioned this.

So, like every other entity, of course, we have we have our own regulatory frameworks that we have to meet.

And uh the North American Electric Reliability Corporation is the one that produces a lot of the standards that we comply with.

Um, it's how we architect a lot of our solutions.

Um we do also follow some of the other ones like NIST and CIS, some other federal cybersecurity frameworks.

Um, but we actually try to make all of our solutions fall along these lines so that um we can meet compliance, but then also stay protected as well.

So that's obviously a really big one that we have to deal with.

Um one of the things that we have as a utility, which is uh not a lot of people know this.

We have an entire information sharing network amongst all the utilities across the country.

So we are uh as RPU, we're actively involved in these threat sharing communities.

Um, we're sharing threats as we see them, as other entities see them.

Um, as a matter of fact, our last incident that we had, uh we were impacted by the incident, and then about 30 minutes later it came out on the on the threat community that others were seeing it as well.

I wish it was 30 minutes sooner, but it was 30 minutes later.

Um, but we actively participate in these because it actually helps us um, especially as we actually look at some of the vulnerabilities, the indicators of compromise, things along those lines, sharing that information with other utilities uh gives us a really unique advantage that we definitely do in in the utility industry.

So now we get to the meat and potatoes, or I guess you know, turkey and potatoes, I guess, if you're talking Thanksgiving.

This the stuffing, stuffing, we have to have stuffing for for Patrick.

That's great.

Uh, what's your guys' responsibility?

Right.

Uh so we're gonna get into this piece.

Um, my ask of you, if you will.

Uh the board's responsible for prioritizing cybersecurity.

Again, just like any other factor of the business, it's about managing risk.

So when you guys see some of these events, and as we bring things up uh, you know, to the board and uh basically know that we need to look at this and try to manage this risk as from kind of from a long-term perspective.

Um, so that's a really important piece.

Another one that we happen to have is if we provide training materials for you, please take some of the training so that you can stay abreast of that because I think being proactive and being a part of it is actually really important.

Um that's kind of like leading, leading by example, if you will.

Uh, so that's a really big piece as well.

And then, of course, the other one that I have, of course, is funding.

You know, as these threats evolve, as these these tactics and things change, um, new tools have to come out.

We have to stay abreast of some of those things.

So there's a large component of your guys' responsibility, of course, is the funding mechanism too.

So that being said, you know, RPU is known for its its five R's, right?

It's it's core to what we do.

So I actually took this and actually frame the five R's in the terms of cybersecurity.

Uh I'm gonna let you guys read this because you can read, so that's fantastic.

But the the simple truth is, you know, really when it comes down to cybersecurity is that basically it's you know, it's strongest really when everybody does their part.

And by staying proactive and informed and engaged as well, uh, we basically ensure that RPU remains resilient to some of these, some of these cyber threats.

Um, I think that proactive mindset and that kind of shared commitment are really a foundation of what our sprint is from a cybersecurity perspective.

So uh with that, I'll take any questions from anyone.

Any questions for Director Kelchin?

Yeah, just on uh I I remember going through this at actually uh I worked in the IT industry, but it was somebody went off to work uh do a volunteer job down at Luther College.

And what always stuck in my head is they would have like anywhere from a thousand to twenty thousand attacks a night, just with people trying, you know, this just these bots trying to break in.

But they didn't have a strategy of just protecting from all that because they had students who were doing all the you know their internet stuff and all that other stuff, and they couldn't just lock it down, but they had a very much a strategy of like um keeping their real uh corporate gems or the ground jewels, crown jewels not on the same, like on a separately protected place.

Does RPU have any concept like that?

Or like we have so many customer things and just marketing stuff.

Do we then say like, but that you can't get from there to to our customer list, or you can't get from there to something else.

Is it that layered version philosophy, or is it we're gonna just protect the front door?

Oh, it's definitely layered.

Um the simple answer is yes.

And I can have a conversation with you about some of those other things.

That's enough for public discussion, right?

Yes, we do have we do have uh a multi, it's a multi-layered defense.

It's not uh uh a single castle with you once you get across the drawbridge in the moat you're in.

Yeah, um, there's multiple layers inside of there.

Um, and really when you look at it, we're building out um layered defenses, uh layered detections um all across the board.

So it's not just one, it's not all defense.

Yeah, you know, there's there's some offensive pieces effectively too to shut down access, you know, rather than just let them keep hitting the door.

Um so we have some of those tools as well in our toolbox.

Thank you.

Good question.

One quick one question.

I was just so this might be old school back when I was at the state.

They mandatory shut your computer down every night and uh they automatically shut it, shut yours down at 10.

You could get back in, but they would have it once shut down.

Is that something or does that not even matter?

Because uh most attackers and things don't just work at night.

Okay.

You know, the idea is they're they're happening all the time, different time zones across the world.

Okay.

So yeah, I wish it was that simple that hey, we could also do that.

Well, I wasn't the only thing, but it was the one they uh who knows why they did it.

It's okay.

It's good.

Any other questions or comments?

If not, thank you for this.

I really appreciate it.

And I could not be more proud of how this awareness has evolved under the current GM and with the support of the board.

So thank you.

Thank you.

And now I'm just gonna turn the next two items, six and seven, over to General Manager McCullough.

Uh, RPU index of board policies, followed by the general manager's report.

Um, as the board will see in item five B, we've scheduled out policy reviews through the end of 2026.

So we've picked four of some of our oldest policies to address in the next fiscal year.

Um, if there's any feedback for the board, we've reviewed this as the uh board executive committee president vice president at our recent planning meeting.

Um, but we're always happy to address something that may be timely or have a specific interest to the board as well from a policy perspective, which will start in first quarter as we talk about our safety policy.

Um, it's one of our yet oldest policies that hasn't been revised recently.

So that'll be our target for first quarter next year.

Um, if I may, I'm gonna stay in my chair for the next item and I'll go into my general manager's report.

A little bit to update the board on uh from the SIMPA boardroom.

And I um we have some guests in the room, and I did want to touch on the grid access fee.

Um, some of the happenings that have been going on with our recent communications to customers as well.

Um couple highlights uh on the left there.

Uh we were awarded a grant for uh solar on public buildings to put a 40 kilowatt array on the roof of um the RPU service center.

Um, there was also a grant awarded for the DSIC building um as well.

We were made aware that there was still seven million of unallocated funds available at the state level.

We just got word today that there was an additional 12 arrays, I believe, awarded to other municipal buildings around the city.

So that is about a half a megawatt of solar that will be coming online across a number of other buildings, and we have a pending application for two more on uh RPU controlled properties as well.

Um, this is a good news item.

I would hope this is uh taking advantage of uh tax credits and both at the federal level and these state funds to try and deploy more solar that will benefit our customers, it'll benefit our bottom line as well.

Um as Peter would like to say, you can't beat the price of zero um since these are fully reimbursed um up to 70% from state funds and 30% still from the remaining um investment tax credits.

Um we think this makes a lot of sense.

Uh it provides very low cost energy for our customers, and it will do so on many public buildings that over time will reduce the overall cost of government operations as well, which will benefit not only our property taxpayers but our rate payers as well on our buildings.

We are approaching these in the short term as RPU assets on other city buildings.

We're putting up the initial capital and sponsoring the uh the grants and helping facilitate those during the term of the Simpa contract.

Uh, all of the city is considered a member of the agency, not just the utility.

So it makes sense to do it this way in the short term.

Um, once we get beyond 2030, beyond the agency agreement, we're working on a methodology that those could be turned back over to the other municipal operations.

And so over the long tail of these, um, it'll relieve tax levy pressure as well as uh utility rate pressure as well.

So good news there.

We're uh this came from grassroots amongst our team working on identifying more and more locations, and we just got the award notice today.

The new customer portal launch went live on November 7th.

I just looked at the dashboard today.

We've had 20,000 unique logins to the new portal.

Um, that's one in three customers.

I would say that's a very successful initial first month launch of the customers who were e bill or uh um already on auto pay.

That's a probably half of those customers as well.

Um we've been getting a lot of positive feedback on the new portal, and I would encourage all board members if you haven't already signed up on the portal to go look at your accounts and and see the both the energy and water um consumption displays, the bill displays, and the ease of use of that portal.

So very excited about that.

Um we had a simple board meeting as well as an annual meeting in October, as well as a board retreat.

So kind of three distinct meetings here.

Did want to park uh this as a point of training for any board member.

There's a governance training coming up in St.

Cloud on January 23rd, sponsored by MMUA, not Simpa, but Simpa reported that this is available.

If any board member would be interested in attending a governance training uh uh put on by the municipal utilities association, that could fit within our training plan for any board member.

Um the energy cost adjustment is the monthly pass through of wholesale expenses above or below the budgeted energy amount.

Um, we did see some relief.

Uh we saw a credit in September.

That's good news.

That's one of the largest credit we saw this year.

Um I won't have good news next month.

We just got the notice that we'll have about a half a million dollar charge for October.

So we're still seeing continued higher power cost adjustment pressure coming from SIMPA and the energy markets.

Yeah.

Again, if it's uh it might be timely to just ask here.

Do we as a utility decide what the energy cost adjustment is, or does Simpa pass it uh pass it to us to for what it should be?

It's the latter.

It's determined by Simpa based off of all of their uh there's several components of cost, but it's roughly fuel market operations, some of the renewable projects all go into that cost.

And as members, we take their number and apply it.

We don't like take our own English and say, no, we don't think we need to do that.

We just do what it's established in Simpa's rate tariff.

So it's an obligation that we have to pay those.

It was a rate put in place about two years ago.

And then we have a retail design on our side where we take those costs and they show up on the customer bill directly through what's called the power cost adjustment.

Either the costs or the credit.

Both sides.

It's largely been a cost over the last, I would say, three years.

Okay.

But I the only thing I was trying to establish is it it is our our supplier is is deciding that.

And as a member, we follow their lead, as does all the other members.

Yes, we also have our own wholesale expense that has components in the power cost adjustment as well.

So it's the combination of SIMPA's ECA plus some of our power supply that are blended together in the power cost adjustment that goes to our customers.

So it's a combination of our own market participation, our own fuel and uh the agencies charges to us as well.

So when I see it on my bill, it wasn't the Simpa decided how much it was.

It's Simpa gave a portion of it, and then the RPU uh uh team says it also has to be adjusted again.

Small fraction coming from our own our own charges.

Did you want to add anything to that, Peter?

No, I I think you hit that.

It's it's um all those different components.

The largest component by far is the pass through from SEMPA.

As we go into 2030, we'll see that mix change.

Changing over.

Okay, thank you.

We did make some changes in the current uh rate tariff and putting some of our generation uh margin into that as well, so that as we add more in the future.

So I think you're hitting all the right.

Yeah, I was just trying to understand it of control of who is doing it.

And I think it I think what it is is the controlled is by the percent of the supply.

It's really driven by the market.

If the market goes up or down the local LMPs, that's really what's ultimately driving a lot of those pieces there.

And again, when you say the market, it's a the um we generate some of our own, but the majority comes from Simpa.

So that's right now it does, yes.

Yeah, okay.

I think I understand it.

And we don't make these numbers up.

These are determined in our wholesale rate tariff that's formulaic and we the formula is followed to a T.

We have our own power cost adjustment here that has our own components.

And we just talked about that rate design a couple months ago of uh one of the particular changes was we buy capacity sometimes or sell capacity.

So short-term capacity um uh purchases would hit our power cost adjustment.

Longer term contracts would not.

So we determined that certain components of our cost will or will not go in the power cost adjustment by definition.

I I think you hit on the my concern.

It was who's controlling how's it how it's happening?

I would say there's two bodies controlling the Simpa board controls the ECA and you all, this board control the power cost adjustment definition in the structure and what applies there, and then we as staff apply that formulaically through to the customer bills.

The overall intention of this is it it's not an easy or fun task or particularly um pleasant conversation when we have to adjust rates.

I'm right with yeah, I'm supporting this, but I did I wanted to understand the mechanics too, just to make sure.

And to further that thought, we adjust rates annually to project forward.

We have an assumed cost of energy in there.

Call it seven and a half cents.

If the actual cost of energy varies to eight and a half cents, then we will see a one cent PCA on our bill.

And so it allows the variable cost of market energy to pass through to the bill without having to adjust our base rates.

So that's how the structure works.

It we really haven't touched it at the wholesale level for three years.

Um there's been some adjustments to the base rate uh uh in 24 and 25.

Um, but if you recall, there was a mid-year rate increase uh in 2022 by Simpa to the tune of about 10% rate increase.

Yes, it was late in the year, but it was late in the year in 2022.

And because the wholesale cost went up, our PCA was already in place, and so we were able to recover that just the PCA raised there, and we didn't have to adjust our retail rates mid-year.

Good, good.

Thank you.

Yep.

It also creates a discipline because of that standard rate on your wholesale cost, the gross margin, which is what we we work off of, all the rest of the operation and the budget uh kind of set with a fixed number based on the on the you know the rates that would that we've approved and charged.

So then this big variable, which is the wholesale one, you know, it just gets plus or minus, but it remains that you still have the discipline of this is what's approved on the gross margin, and this is you know what we've approved from a budget um by budget standpoint of what the spend is.

So it it it actually creates clear separation.

So you can see this is just the wholesale stuff moving around.

This is how the rest of the business is being run with sticking to the budget.

Very good.

Thank you.

One of the things I'm particularly proud about on our RPU connect app now is there's direct visibility on time series chart.

So you can look back two years on your account and you can see how much the customer charges, how much your energy is, and the power cost adjustment piece as well.

We've effectively have a 16 cent summer rate because 14 and a half cents is what we have in our rate, and one and a half cent is about the average of what the power cost adjustment has been.

I bring that up for example for a solar customer example who um self-supplies their own energy.

They're avoiding not only the 14 and a half cent headline rate, but they don't have to pay the power cost adjustment either.

So they're actually getting a 16 cent per kilowatt hour benefit for consuming their own solar inside their house as well.

Moving on, uh general operating reserves.

Uh, this is a discipline that has been in place uh for several years at Simpa to uh establish an operating reserve bandwidth.

As you can see in the last three months since July July through September, um most of the coal pile at Sherco Unit 3 was converted into energy and sold.

That's why you've seen significant growth in operating reserves.

And this is also after considering that there'll be a cash distribution in January of 26.

We will see a million dollar check back from SIMPA.

And even with that, there's still projected to be operating reserves above max bandwidth.

It's an active conversation in the Simpa boardroom on how to work on being above bandwidth.

We have a discipline over time to work that down within the bandwidth, and that can come through rate relief or cash distributions.

Slipping into the get grid access fee.

What you're looking at here was actually my house back when we lived in Colorado.

This is an example of what a day of energy could look like in a house where very efficient home has a hers rating of 10, basically consumes 10% of the energy of an average house with a relatively large solar array, eight and a half kilowatts, and an electric vehicle.

So if my house were to be looked at over a course of a year, I would have produced all of my own energy.

So I would, in over a year, I was 100% sized to my load with an electric vehicle there as well.

On a daily basis, it was a push and pull.

So a lot of excess generation during the day, a lot of pull at night when the electric vehicle charged.

And so that's the function of the wires side of our business to work with net metering customers.

It is not true that net metering customers buy zero energy from us.

On average, net metered customers use about a third of their own energy off their roofs and sell two-thirds of it back to us.

And then later at night and other parts of the time when solar's not producing, they buy the other two-thirds of their energy from us.

So there's a strong transaction that happens on a daily, monthly, and an annual basis to be able to transact with a make a net metering system.

This is what it looks like on an annual basis.

So this is an example of a chart from our app actually.

And you can see an example of the dollar impact of what a typical home over a two-year period is going to see for energy charges.

So this is one where there was a utility bill in December, January, and February.

That's the blue you can see there, kind of two seasons.

And then the rest of the year when sunshine is better.

That's the red line chart there.

Solar irradiance changes by month, and it's better in the summer than the winter with snow cover and shorter Js in the winter.

And so this is also very common month to month.

Many customers have a credit that runs all the way through the summer.

And then in the winter time, they're buying energy from us as well.

So this is part of the a two-year look of what a solar customer would be there as well.

I want to also point to our responsibility with rates as well.

So we've talked at length about our 100% renewable energy by 2030 goal and what it's going to impact rates.

We recently signed wind contracts that are in the range of about 45 a megawatt hour.

You look at the center there, our Valley High Solar Array, that has a rough cost of about 60 to 90.

Other utility scale solar has about $90 range right now.

And net metering energy, the excess there has a cost of about 110 to 145.

So under the net metering arrangement, that type of energy net excess off of roofs has some of the most expensive forms of renewable energy there is.

And there is upward rate pressure from that that we're absorbing with partnering with customers as well.

The implementation of the grid access fee is just a portion of the wires recovery.

There's still the times of excess net energy that we're buying that's coming at a high premium cost because of the full retail compensation requirement of the state level.

Also, like the this is a distribution of our actual solar customers here.

So this is each slice of that is about a 10% uh wide slice of sizing to load.

So the red line there is exactly at 100%.

So this is a customer that produces all of their energy uh netting over a year.

And so we have a more than 50% of the solar customers that we partner with have their systems sized, some percentage greater than 100%.

And that's where the subsidy or the cost disparity gets even larger because it's not only covering your own load, that looks like we're buying 145 energy up above there as well.

Under the current state statute, there's no ability to cap the size of systems, anything smaller than 40 KW must be allowed.

Anything smaller than 40 KW must be allowed.

And we've partnered with customers to follow the statute and work with them.

And that's all at retail energy cost there as well.

So there's not only a fraction of the wires cost that we're missing.

There's also some significant oversizing that's happened, either intentionally or unintentionally as well, compared to load.

Um, we did the cost of service study here.

That's actually a page out of our cost of service study.

Um, that's the basis of this.

This board, uh the previous board reviewed this in 2024, um, based off of our study in 23 and implemented it in 25 to take effect in 26.

It's really designed around recovering only the component of wires that supports solar customers.

On average, we've seen about 10 to 30 percent of what would have been the full benefit that comes back to net metering customers now will be contributed towards the wire side.

Most customers are still retaining 70 to 90% of the value of their net metering systems, weighted pretty heavily in the 80 to 90% value is still there.

As energy costs go up, which we're projecting at the value of these systems go up as well, because there's less energy that they'll be buying from us at higher cost.

So I would say that net meets solar will continue to grow.

Um it's still um available to offset people's costs, and but this makes it more fair.

Quick yep, go ahead.

Just a question or comment.

I have we figured out like we did this um passing the new uh grid access fee in September of 2024 with the idea of not applying it in 2025 so that we could get the word out.

Apparently, we didn't get the word out.

Is there any sort of like we understand how that happened or any sort of thoughts on that?

Yes, I have some thoughts on that.

Right.

Um I'll leave it at that.

Yep.

We I'll go into it a little bit more.

Um most people uh we worked with solar developers and uh put it in our tariff and put out information there, but there are people that either didn't see it or we didn't get communicated with that had made investment choices during that time as well.

I think you heard one from tonight with a customer who had worked with a solar vendor and put it on a roof, and this was a surprise to them as well.

We recognize that that we're not getting out to touch everyone.

Um, but the delay of implementation was to allow us to design the systems and communicate with customers there.

And so that was part of why we sent out 770 letters to inform customers about this coming.

Um looking back, I think we could have done better for sure on communicating with customers, probably with a stronger push of press release, stronger push of notifying existing and potentially new customers.

The information was there, it just wasn't always visible.

Many many solar customers rely on their solar contractor to do a lot of the interaction with the utility, and so it's also incumbent on the solar contractors to pass that information through to customers as well.

Thank you.

Well, I have you know, you do a really good job of explaining it, right?

When you explain it, I think it makes sense to people.

Have you thought about doing a meeting, a public meeting?

Just I mean, I'm not saying I know they always sound good and people don't come, but it it feels like this is a group of people that are more active and might be more willing to come.

Yeah, uh considered it.

Um, bring your pitchforks, I guess.

This is the type of meeting that you can invite everyone into.

I've taken five or six individual meetings with people who have strong voices or strong passions in this area as well.

And I think after after we have a chance to talk, there's all there's a growing understanding of what the basis of this is, especially when we can better communicate what value is retained by the customer as well.

It's hard for some customers to understand what benefit they're actually getting from solar.

We're building some tools that we were previewing today internally that with the press of a button, you can say, you've saved $3,000 over the last year.

And when when customers are able to see how much value they're actually getting out of their solar, it de-escalates some of the conversation.

Um I get it.

I was a solar customer myself, and my utility back west changed the rules halfway through implemented time of use rates.

And I went from paying $1 a year to paying $200 a year in rates.

But I was also on the other side of that as the utility professional and knew how much transformers costs and wires and all those things that supported it.

It really is around equity.

It's around supporting not only our solar customers, but those who are also bearing the additional costs there.

Done two radio programs on it, then a yeah, we would be happy to host more.

It's also difficult to get people out of their homes and their routines.

People are busy.

So we'll continue to do the outreach and education around it.

Do you think we might have some sort of like a FAQ in the newsletter or something like that?

Because there are some common questions coming up.

Um not only that the obvious what is this, why are you doing this?

Whatnot?

Um, but a few more, you know, pretty good nuanced questions too.

Like, how does this compare to the customer charge that I'm already paying?

Aren't I already paying for the system?

Yeah.

And I think getting ahead of that and just having a place for people to have their questions answered might be helpful.

It's a great idea.

Appreciate that.

I did not update this with the new announcement, but that amount of grant funding will go from $90,000 to over about $2 million of grant funding coming in to support those up to 17 solar installations this year.

Um that will have a strong uh positive impact on rates in the future.

I mean, that's a half a megawatt of solar energy that will come at zero capital cost to our ratepayers and reduce that pressure.

That's the type of solar that makes a lot of sense for us to pursue as well.

Um a few points here.

The December 1st date is wrong.

I do anticipate that the next board member appointment will likely occur on either the December 8th council meeting or the January 5th council meeting.

Had a brief communication with the mayor's office today, and there's still interviews ongoing for the next board member there.

So maybe even not by the 16th meeting, it might be into the beginning of January before we have an understanding of the next board member appointee.

Um, would like to note this is uh the last meeting.

If you would take a moment to this is a legit QR code, I will admit.

It's been vetted, but this is an initiative across the whole city to try and do better public meetings and get feedback from those who attend.

This is going to be mostly staff and appointed and elected officials here.

But if you would take a moment to fill out the survey to contribute how we could better improve our public meetings, I would appreciate it as well.

And with that, I will pause for any more questions.

Any additional questions.

Hearing none, thank you so much.

Uh General Manager McCullough, appreciate it.

Next, uh move to the uh section of the meeting, division reports and metrics.

Um, you have those in the packet uh for November 2025.

Are there any questions on those?

Hearing none, is there any other business to come before this board?

Hearing no other business, um, I would accept a motion.

Move to adjourn.

Thank you.

Is there a second?

Second.

Any log lengthy discussion?

Hearing none.

All in favor say aye.

Aye.

Aye.

We are adjourned.