Any discussion?

All in favor, please signify by saying aye.

Aye.

Aye.

Aye.

Any opposed?

The agenda is approved.

The next item in the meeting is our safety moment.

And we have our safety moment with our director of information technology.

Thank you much, Malachi.

If you'll notice on your not with your packet, but we actually have Swedish fish.

That's what we had initially done when we started kind of doing some of the cybersecurity training when folks would detect a message that was that was fishing.

And the reason I kind of bring that up, and the reason we still kind of even do this to this day is that fishing is still obviously the most effective way that attackers get into an organization.

So basically, you're like, well, it seems really basic.

Uh the truth is it's still the number one threat.

And so the FBI's uh what is it, Internet Crime Complaint Center or IC3 has basically said that yeah, the the business email compromise is is the most likely way that people get in.

And so just kind of want to reinforce that um with you guys.

Uh some of the stuff that I have also in front of you is some social engineering pieces, little things to look for, uh, things to look out for as far as a sense of urgency.

Um and I think really kind of the important piece really is that these these business email compromise attacks that they happen to have, um, they don't tend to succeed because the technology failed.

They tend to succeed because they take advantage of our busy lifestyles, our schedules, and they kind of hit us at just the right moment, and that's exactly what they're looking for.

So for board members, it's actually really important because you're uh you could potentially get an email from the general manager, the CEO, another board member, things along those lines, and it just happens to hit at just the right time uh when people are susceptible to it.

So the biggest pieces is and one that I want to elicit for you guys is that uh whenever you get one of these and you want to verify that something's legitimate, use a separate channel.

So you use a known phone number of the person who's writing a message, do a separate chat.

Uh, whatever you do, don't reply back to the email saying, hey, is this really Tim McCullough?

No, probably not.

The attacker's just gonna say that they are.

So um you have to use those right away.

On the backside of that piece of paper, though, um, actually have what we had previously done as a fish when we first started this program just last year.

Um, so you'll see some of the items are are kind of elicited on there that uh the sense of urgency, uh Tim's name is spelled incorrectly, things along those lines.

And some of these new phishing messages can get pretty tricky.

So just because there aren't any red flags doesn't really mean that the message is safe.

You know, sometimes these messages are really well polished and it's really hard for you to find these things.

But a good thing to remember is trust but verify.

So um so tonight's takeaway is you know, please just enjoy the Swedish fish, but don't take the bait, right?

Um, when an email creates urgency, asks for action or change in a normal process, stop and verify things.

So have any questions, please let me know.

Otherwise, I have more Swedish fish in my desk if you do really set.

Thank you, guys.

Thank you so much.

That came up last week when I had a docusign item to sign.

I didn't recognize the source and actually was able to call Tim quick and just confirm.

Am I supposed to sign this?

And you know, of course it was all fine, but never know.

Thank you.

Next item on the agenda is our consent agenda.

Um the consent agenda items are 3A through 3F, and these include minutes from the May 19 2026 meeting, uh, review of accounts payable, uh fleet vehicle purchase uh V789, articulating telescopic aerial device, uh P972, eminent domain for the mancato to Mississippi River transmission product and a poll inspection contract.

Can I get a motion to approve the consent agenda as presented?

I'll move to approve as presented.

We have a motion.

Um is there a second?

All second.

It's been moved and seconded.

Is there any further discussion on the consent agenda items?

Councilmember Keene.

I'd like to just check on uh just I'm trying to make sure I have my numbers right here, but uh three dot e on eminent domain.

Um I want to I I this apparently is just good planning in case it comes up, or is there something planned to come up?

Uh this is similar to what was done in 2012 in our participation in the CapEx 2020 projects.

So the uh the mancato to Mississippi River transmission project has an approved route by the public utilities commission being led by Excel and eminent domain would be used only as a last resort if property acquisition could not be um acquired through normal negotiation.

So it's a necessary tool.

Our participation in the project and the joint ownership group requires a governance level decision approval by this body and also the city council for authorization of use of eminent domain if necessary.

And it would be put in place by Excel Energy, who is the lead construction agency building that section of the process.

So it would only be used in connection with that project, and it is required based off of our project participation.

And again, just to check there, there's known planned.

This is a good governance thing to have.

And I did want to check too with legal.

We did a similar thing on Second Street, and it's a kind of a very organized understood process.

Um as opposed to, I mean, if if something came up that it really was eminent domain and using this as a that would come back, or would that now be done through this approval?

Maybe let Michael take the first part of that question or both, and I can and follow that.

Council Member Keene, um board member Keene.

Um I think I follow your question.

It is a similar process.

We need the similar authorization from the authorizing bodies in this case, both the um board as well as the city council.

Um, yes, a highly organized process, I would indicate.

Um, and certainly um the preferred option is to um reach resolution without actually needing to file any eminent domain actions for sure.

Second part of that question, it's my understanding that this authorization by the board and future by the council on July 7th would be the only governance step that we would be taking.

It would authorize the use of eminent domain if necessary by Excel from that point in the process forward.

Excel would follow state statute and the rules, and there wouldn't be any further decisions coming back.

This is effectively a pre-authorization to use if necessary in the project.

And if it follows the same framework as CapEx 2020, there was no subsequent decisions that came back to the body when that was a necessary tool, is my understanding.

It's different than local eminent domain, which has much more council oversight.

This is the board, council, Rochester acting as a municipal power agency in a jointly planned project.

Um, so it's just a necessary upfront step.

Very good.

I'm good with it.

I've done this before.

I just wanted to make sure with uh um what where we're going with it, and I have the discussion.

So thank you.

Thank you so much.

Is there any other discussion of the items 3A through 3F?

Okay.

Uh hearing none, we have a motion, a second.

All in favor of approving the consent agenda, signified by saying aye.

Aye, aye.

Any opposed.

Hearing none, the consent agenda is approved.

Next, we come to the open public comment section of our meeting.

The open public comment period uh is limited to 20 minutes.

Each person having two minutes to speak, and any speakers not having the opportunity to be heard tonight, will be the first to present at the next board meeting.

Is there anyone signed up for public comment?

There isn't anyone signed up.

Thank you so much.

Appreciate it.

Next, we move to item number four on the agenda, the consideration of bids.

And this is item four A, which is to accept the bids, including all bid alternates and award a contract to ONJ Coding Incorporated in the amount of $671,000 for the Apache Tower number 87 rehabilitation and repainting.

Uh, this item will be presented by general manager of operations, Mr.

Blumstrom.

Well, good afternoon.

Um, last year, about this time, uh, the board had reviewed the engineering and operations report for the water utility.

And one of the key performance indicators in that report was our backlog of maintenance and rehab of our water storage facilities.

And so, in response to some of the concerns that we had to prevent any growth in the backlog, uh the budgets for 2026 and 2027 were developed to increase our investments and maintaining our our water tanks.

They're very expensive components of our water system, and so it's important that we maintain those.

So we're pleased to be here today with the first of uh several projects in our future, and that is the rehabilitation of the water storage tank uh next to Apache Mall.

We call it the Apache Water Tower.

So uh the project includes many components.

Uh, it does uh include the complete removal and replacement of the coating systems for the tank.

And so that comes in three parts.

One is the exterior of the tank, the portion that you see when you drive by the tank.

Then there is the wet interior.

So that is the interior of the portion of the tank that actually holds water.

And then the third piece is the inside of the tank that is not actually in contact with the water.

So there's an interior portion of that in the vertical riser column, um, and then the dry tube going up through the center of the tank.

Um, one thing to note uh we did test the paint coatings before we uh went out to bid, uh, and the dry interior portion uh was detected as having some level of lead paint.

And so the contract includes remediation of that removal.

And again, I will emphasize that is not the portion that is in contact with the water, it's just the dry interior portion of the tank.

Um, a few of the other components.

Uh, we have some upgrades to the uh safety climbing system, so the cable fall protection uh that is on the ladders, uh repairing the grout and concrete along the ring foundation uh that the tank actually sits on.

Those tend to get corroded along the edges, and you want to we want to make sure that we maintain those and keep those in good condition.

And then uh replacement of the expansion joint in the pit.

So under the tank, um the water main comes in and it rises up through the center of the column that you see for the tank.

And during the year, summer and winter, that tank can expand and contract, and so there's an expansion joint at the base of the tank to make sure that the pipe does not pull apart.

Um, we did have a failure of one of those on a different tank last year, and so um we're being much more conscious of replacing those when we're doing rehab projects.

Um, and then as mentioned, there were alternate bids.

Uh, we wanted to make sure that we could bring the project in uh within budget.

Um so there are a few things we had as alternate bids.

One of them is the obstruction lights, though that's the red light on top of the tank.

Um traditionally they're sort of incandescent bulbs, um, they burn out, and then staff has to climb up there and replace the bulbs.

The LED obstruction lights last much, much longer and are much more reliable.

So we're going to convert over to LED.

Um, installing a new tank mixer in the tank.

So this will circulate water, particularly in the winter, uh, and that prevents ice buildup inside of the tank when it's very cold.

One, it's not good for the operation of the tank.

And secondly, when you have ice forming in the tank and the water level rises up and down, it actually damages the coating and shortens the life of the coating in the tank.

So good investment in a lot of utilities are are deploying more tank mixers these days.

Um, there are landings as you climb up through the center of the tank as an employee does.

This is just a picture of standing on the ground looking up.

That's the first uh riser landing.

Um, there is a third riser landing that is a uh just a catwalk, and it's a little sketchy walking across that when you're 100 feet off the ground.

And so uh for safety purposes, that uh would get converted to a full plate landing, like uh the picture is depicting here.

And then it also catches the condensate coming off the bottom of the tank and and uh routes that down through a drain.

And then um on the left, you can see kind of a gray pipe going up there.

That's the emergency overflow for the tank.

Uh it conveys water downward and discharges out the base of the tank onto a concrete pad, and that concrete pad's in fairly poor condition, so it would replace that concrete pad.

Um, all told, uh we had a project budget of $700,000, and we had five bidders.

Uh these are the five companies that we would expect to bid.

So we had really good interest in the project, and that's good news.

Uh low bid was from ONJ coatings at uh 618,000 for the base bid, 53,000 for the alternate bid items for a total of 671.

So the bid came in below what we had estimated.

Um, and we've also checked references on ONJ, and uh they've done good work for other communities.

So we're looking forward to working uh with them on this project.

So with that, um, we are recommending approval resolution to accept the bids and award a contract to ONJ coatings and the amount of 671,000 for the Apache Water Tower rehabilitation and repainting project.

And I'm available for any questions you may have.

Awesome.

Could we get a motion and second and then move to discussion?

I'll move to approve the resolution to accept the bid and award contract to ONJ coatings and the amount of 671,000 for Apache tower number 87 rehabilitation and repainting project.

Thank you, council member.

Second moved and seconded.

Any discussion.

Wow, well presented.

So I'm really not important, but what color?

It will be matching the beautiful blue that is out there today.

Thank you.

Unless there is strong opinion otherwise.

But no, you've saved us some angry letters, so that's great.

Thank you.

Yeah.

Okay.

Any other discussion?

Not hearing any.

Uh all in favor of approving the resolution on board packet page 67.

Please signify by saying aye.

Aye.

Any opposed.

That item is approved.

Thank you.

Next on our regular is our first regular agenda item, uh, number 5A, uh, which is the 202 electric service rules and regulations update.

This is to adopt the revised 2026 electric service rules and regulations effective July 1, 2026.

And this item will be presented by manager of engineering, Randy Anderton.

Microphone, thank you very much.

I'll start over.

So uh we typically uh maybe sometimes on a three-year cycle, do an update to this.

It's not like hard coded that we always come three years, sometimes it's a little sooner.

Um, in our rules and regulations, it's really our uh you know, the guidebook that you know the customers need to, you know, new customers.

If it's a customers updating things, it's the you know what what it's RPU's rules, you know, we don't want the wild wild west.

So um the reason we're coming to you uh uh we we probably would have came next year.

Sometimes there's an update on the National Electric Safety Code or the National Electric Code.

We want to make sure we're in sync with whatever changes they've done.

Um, but we've had some of our own uh internal uh items that have kind of risen this to the level of we should probably just do a whole not a wholesale, but uh just bring it to your attention for approval.

And so I have just basically just two slides here, just highlighting the uh where do I point this?

It has a little bit of a delay.

Oh, there we go.

I went too far.

There we go.

Okay, so uh we added some new a couple new definitions and changed one.

Uh so computational load, if that's a new term to you, you've not heard that before.

Uh you're not well, I shouldn't say that.

So it's basically data center load.

That's kind of the hot topic in the industry right now.

And so, and we we uh we're not anticipating you know the big giga data centers here, but uh it's very realistic.

We could have some you know moderate size infill data center type load, and so we need to accommodate that.

And uh so we're trying to add that definition in there along with that.

It caused us to think about just large loads in general, um, especially as it relates to our resource plan, and you know, if we all sudden oh, we got an extra 10 megawatts, we didn't see that coming.

So, how do we accommodate and count for that?

Um then we have a uh change to a little bit of a modification to shared meter.

Um what that is is uh we we have some, you know, in an apartment building where we had some language that wasn't really clear.

We wanted to be a little more definitive on uh in an apartment building.

We require an RPU meter on every individual apartment unit.

Uh we wanted to make sure that you know, going forward that any new apartments uh there wouldn't be just a single meter.

Um I'm I'm sorry, I I did want to get a clarifying question before you got I I understand this to be the rules and rights, but is this an internally published for ourselves or is this an externally published?

It's it's external.

Well, it's bolt, I guess it's for ourselves, but it's mainly for the customers and electrical contractors for them to know okay.

RPU is going to require this, this, and this.

So it just keeps everything so we treat everybody, you know, fairly the same.

And okay, so it is an external, like and and available for anybody to come and get.

Yes, we've uh typically posted on our on our website.

I think we have now the new ADA compliant uh version, so we'll keep it posted there.

That's helpful.

I I knew some of these could sounded like internal processes, but it's also it's important for external contractors to understand.

Yeah, it's mainly for external, but also it helps you know guide us internally as well, too.

Thank you.

All right, so uh section 407.

Uh, this was a new section.

Yeah, you know, basically like I said, the computational load, uh dealing with with data center type load.

Um, and then there's a change to uh section 602.

Uh then I already talked about that, I guess, where on an apartment buildings, multi-dwelling units.

We're you know, every unit has to have its own RPU meter.

And then the second slide.

That one, the next one.

It's it's basically uh kind of a legacy meterings uh that we don't really offer anymore.

It's not a huge change, it's just uh some technology that we're just moving away from.

Um the section 1101.

There was some changes made in the state statute uh dealing with here again.

A lot of times it's maybe in an apartment multi-dwelling situation.

There was a lot of language about de minimis usage, and we just had to do some language cleanup and and and our rules and regulations to stay in kind of lockstep with what the state statute language is talking about.

So that was basically that one.

And then uh we added a new section uh for dealing with street lighting and just kind of our you know, here's our standard street lighting we offer and that kind of thing.

And uh, so that was just a brand new section that we added, and that is really the extent of my very long PowerPoint.

Oh, thank you.

Are there any questions or comments on the presentation?

I have a question.

Um looks, you know, I'm just curious.

Kind of how did you notify or do you notify the customers?

I mean, one of them's internal, our uh public works, and it looks like that's what was going on.

So it looks like you just documented it.

But I'm just curious how you notify people beforehand and afterhand, you know, afterwards.

Uh a lot of times we do try to make, you know, uh put notice out there.

A lot of it's select the electrical contractors.

I mean, we don't provide this to every customer in the city, but we do sometimes try to make notice to you know, the contractors and things like that uh of changes.

We'll meet with the electrical, the building inspector, you know, safety, make sure they know what we've changed so that when they're out inspecting, they know what changes we've done.

So we do try to make some of those efforts.

And I guess one did you work with public works when you developed it looked like what was being done always done on the street lighting?

Yeah, we we've we've worked a lot of the street lighting is dealing with the the decorative lighting.

Right, I understand.

And so we have worked a lot with Sam and different ones over Public Works, Dylan, and so uh I think we're we're kind of see things pretty much the same way there on it looked like that, but I was just curious if you'd worked with them beforehand.

So yeah.

Okay.

Any other questions, Councilmember Keene?

This is kind of a knit, but this is you're gonna publish this in the July 1st and it's current, and it's current until the next one comes out.

That's correct, yeah.

Why do you call it the 2026?

Well, I guess we could say mid-year 2026.

I don't, I'm just it's just the current, or I don't know.

I so often when new uh national electric codes or NASC codes, they're published with the published year, and so it's following that same intent.

It's a it's a it's a convention.

It would indicate that that was the last revision year for those who are looking at it who might be familiar with previous revisions as well.

Okay.

And so when those other codes come out, they're not exactly coming out on January 1st.

And you know, then yeah, I was I actually wasn't looking for a whole date.

I was almost looking for just something that said current.

Yeah, it's industry practice to hard code the revision year into the title as we're following NEC and NESC type guidance there as well.

Thank you.

Good question though.

This might be off an off-the-wall question, so I apologize.

The shared metering that came about, I understand because developers may want to have one meter for all.

Is that a cost request from a developer?

That like how did this end up being a part of the discussion?

I guess is my question.

Well, we've had some recent uh inquiries about it, which kind of raised it to our attention about the language we had, and we need to kind of clarify the language.

The state statute actually, so the state statute language allows uh individual meters for apartments.

It doesn't guarantee the right.

We we as a utility can opt to not have that, but uh this the state statute language still requires the tenor the landlord, they have to still individually meter each unit.

I mean, if I were landlord, I don't know where the cost savings would be if I wanted to have an individual meter myself because I still have to for the tenants, they have to build a show.

Here's your usage, even though it's not it wouldn't be an RPU meter.

Other utilities do allow that.

We're we're trying to clarify that that's not something we're we're allowing.

Like I guess I should have been more specific in the development cost.

Is that what they're trying to just have one meter?

Does that lower their development costs?

Well, that's where I say they still have to have.

So if it's a hundred units, okay.

have to for the tenants they have to build a show here's your usage even though it's not it wouldn't be an RPU meter other utilities do allow that we're maybe we're trying to clarify that that's not something we're we're allowing like I guess I should have been more specific in the development cost is that what they're trying to just have one meter does that lower their development costs well that's what I say they still have to have so if it's a hundred okay they'll have a house meter but then they'll still have a hundred meters okay they wouldn't be RPU meters but they'd be they might be cheaper meters maybe I like I said I I literally don't know where the savings would be okay Peter I don't know if you have thoughts that we've talked about this or I would I would agree with you and I've dealt with this in prior roles as well where submetering arrangements become very problematic um because the ultimately the customers look to the utility as the managing entity of those in this case we are not and it becomes a conflict between the tenant and those who own the overall property often in manufactured housing communities I've seen it on water uh submetering requirements there.

And frankly that we've had some recent inquiries about this and some recent problems related to uh payment arrangements and who the relationship is with the tenant and the usage alert.

So it's best practice to have individually metered helps us maintain that relationship with ultimately the customer and not have the developer in the middle of that and I would agree with Randy there is a statute requirement that submetering is required.

It should be utility grade so there's really not a cost savings if the developer is putting that in and then often the developer steps out of those relationships and leaves it to a property management company who is not always set up to manage metering systems as well.

So I don't see that there's a significant cost savings.

And if there actually is I see that as a significant liability that they're not building the utility metering systems that are required to fairly balance the commodity costs.

Thank you.

Well thank you Mr.

Anderton any other questions or comments I might add just a little bit of color if if uh the board would listen for a moment the the reason for the computational load ads is also in reaction to policy and regulatory changes happening at the national level we received and I wrote about this if you read page 74 of my report last month um we we as an industry received an alert from NURC North American Electric Reliability Corporation about reliability risks specifically with computational loads that have emerged and NURC also put out an intent of rule making that in June this month they're intending to move forward with new rules and regulations around computational loads this is in alignment with that future regulatory actions computational loads have are very likely in the future going to have to be registered with the MISO organizations.

So these rules are written around defining that getting the relationship in place so that we can get the proper information from the computational loads and then file that with the energy markets because there's a distinct reliability risk.

Data centers of this nature um if there's a uh blip in the system will often switch to backup generation which it it doesn't necessarily increase the load of it doesn't change the generation side but it removes thousands of megawatts of load which becomes a reliability concern.

So energy markets are wanting to be aware of where computational loads exist and this is in alignment with that uh what those notice of uh rule makings are so that was part of the reason for the quick action here is getting that definition in reacting to the federal level policy changes that are happening thank you for that any other comments or questions hearing none uh may I have a motion to approve these updates I'll move approval thank you and do I have a second oh second thank you we have a motion to approve and a second all in favor of approving resolution the resolution on board packet page 70 please signify by saying aye.

I need opposed and that carries the second item on our regular agenda is item 5B which is the Cascade Creek gas turbine one recovery.

This is to authorize the expenditure of up to 20 million dollars for the GT1 recovery project and authorize the project manager as appointed by the general manager to administer the approved funds for the GT1 recovery project and this item will be presented by our manager of power resources Mr.

Zube.

Thank you Malakai afternoon board just a few quick slides here again as Malakai said I'm I'm talking about the recovery of Cascade Creek gas turbine one if I say GT1 it's that I say it a lot.

Uh that was inclusive of insurance reimbursement.

So the number would actually be a little higher, and gas turbine uh prices have gone up significantly in the last 12 months.

So that was a good estimate at the time.

Uh the next step in August last year, the board authorized $2 million for us to start evaluating the condition of GT1 and its major components, what it would cost to get it back into uh workable condition.

We've spent about 1.7 million dollars of that over the last 12 months, and we're in a good position now to uh make a decision or present the decision to the board today for the recovery process.

Um I will be asking at the end of this for the 20 million dollars to uh repair this uh in about a 11 month time frame uh to get it back into good operation next year.

Uh hopefully this isn't too busy, but Patrick, you asked me a question last month.

So this is for you.

This is Patrick's slide.

Your eight version there you go.

So uh the the top line.

Well, when I looked at this uh last month when I was kind of answering your question, I had two options in mind repair and replace.

And as I started looking through this to try to figure out okay, what which one is better?

How can I prove that this is a good decision?

I came up with another one, which is do nothing.

And you'll see that's not that's not a great uh not a great option, but it's worth exploring.

So the the top line there for expenses, you can see it's about 18.9 is the repair, which would be I'll call it year one, even though some of these costs wouldn't be realized in the first 12 months.

Uh, but repair is 18.9 million.

Replace is around 87 million, and that was back to my first flight of slide of 60 million plus the uh reinsurance or insurance reimbursement, and then the do nothing is what we've spent so far to recover.

And there's a little extra in there.

We didn't get it updated, Bill, but we're close.

Um it's it's very close.

So the do nothing is what we've spent so far, uh, plus an improvement to the Cascade Creek site.

The second line is very important.

It is the annual capacity that we would lose, which is around three, a little over three million dollars uh annually for not having the megawatts out of GT1.

And add the added to that is the lost revenue that we would not realize out of GT1's um uh generation electrical generation uh each year.

So I picked three years, kind of talked about year one, total impact, uh, what would it cost to to start off on each of those uh uh options?

And then the other two years I picked year eight, which would be the possible end of life for GT1.

Uh that gives us you know enough time to get through our Mount Simon and our 2030 resource plan and then plan for the end of that unit.

So and in year eight, there under under repair, we show a positive uh 3.8 million for revenue.

So that is basically the uh the year one impact costs, uh, and then adding in the loss capacity and lost energy, uh getting to to year eight.

Replacement that shows your initial impact uh again, minus the or adding in the the energy revenue and not having to replace capacity.

Uh do nothing just continually gets worse.

You don't have an asset in the ground, you don't have a generation facility, you're having to replace that capacity and not uh realizing that uh energy every year, so that just gets worse and worse the further you go out.

You can see that in year 30.

Uh commercial operation date, we would say about a year or less for GT1 and the replacement, knowing what uh Mount Simon is going through with air permitting and everything else we have to do, uh, that would be about a three to four year process.

Uh when I went year by year, about year three is when it flopped from do nothing is better, cheaper.

Again, you have no asset to the repair process is better.

But the the bolded year eight there is is the better option between the three.

Any questions on the slide?

I have a question for you.

This seems to be assuming that the expenses are not covered by insurance as well.

Oh, great point.

I got it written on here.

I didn't I didn't say it.

Thank you, Tim.

Uh yes, nothing on here is using insurance reimbursement.

Uh, however, the insurance rebirth reimbursement would likely be the same in any option.

So insurance is going to give you the least uh most effective, not a most effective, but but lease payment back to RPU option.

Whether we called it a catastrophic loss, they would still give us the repair amount.

They're not going to give us the 25 million if 10 million would repair the unit.

So I didn't even put it in here.

It's really the same across the board.

But it would we are expecting about 90% recovery out of the 10 or 11 million that is insurance applicable.

Yeah.

Thanks, Tim.

So the next few steps.

Uh this month we are working on finalizing full engineering scope.

We're waiting on one report for that.

Uh in July next month, we'll begin the actual engineering of the recovery, start procuring parts.

Uh generator repairs.

We've we've got the uh report from that.

We've got an estimate for that.

We're just waiting for the approval today to move forward with it.

Um September late late fall or sorry, late summer, early fall, we would start reassembling the turbine and generator, the two major components.

We should be ready for that in the fall.

We can do some of the building uh roof and and walls work, finish engineering design, and we can use the winter to implement controls, other engineering, balance of plant, auxiliary work, and then hoping for commissioning in spring of 27.

Well, thank you so much for that presentation.

Um, could and I apologize to the board just to be consistent with what we should be doing.

Can I get a uh motion and a second before moving to discussion?

I'll make a motion to, and again, based on the resolution as presented in uh in the packet to approve expenditures for the GT1 recovery project.

Thank you.

We have a motion.

Do we have a second?

I'll second.

Thank you.

Motion second, any discussion, questions or comments.

I'll I'll just say I'm I'm in support of this.

I think it is it's a good, like kind of going forward and trying to see what would be, and obviously the numbers hold out.

Uh as far as I appreciate having the you know the eight year the views of these things, but as we discussed it at the last meeting, too.

The repairs on these really do seem to make them back to a 30 year life.

And that's that's important for this kind of work too.

So thank you.

Every time I've said GT1's going away, it does not.

You might be right, Patrick.

I got a quick uh do you have any rough estimate on when insurance finalizes, or is that a mystery that it'll be ongoing?

We submitted the first batch of reimbursement invoices, I think three weeks ago.

And what we did was we gathered everything from 2025, sent it to them.

It was less than our deductible, but if they accept all that, uh we're closer to the deductible.

And then we're gonna do it in quarterly chunks.

Gotcha.

So everything that is related to the fire to re rebuild should be reimbursable.

Uh, but it will be a conversation we'll continually have with insurance.

Yep, and they're done looking at it.

They came out, they looked at it.

They're I wouldn't say they're done, but they've been out many times.

Many times.

Yes.

I don't want to speak for them.

Yep.

Any other questions or comments?

Wonderful.

Well, thank you so much for that.

I really appreciate it.

Nice job.

Um, so having no other questions, comments, or discussion.

Um, all in favor of uh approving the uh item as presented.

Uh, please signify by saying aye.

Aye.

Hi.

I need opposed.

And that is approved.

Thank you so much.

Now we're gonna move quickly to the informational section of the board meeting.

Uh the first item is 6A, the 2025 power delivery engineering and operations report, which will be presented by the director of power delivery, Mr.

Nichols.

Good afternoon.

Uh so here to present the results of the 2025 power delivery power delivery engineering and operations report.

Um, if you've been here before, you've probably seen multiple reports.

This is the first year we're focusing on key performance indicators or KPI.

We really tried to lift that up into the front part uh of the document, and we're gonna focus most of our time on those KPIs today.

Uh, but we did select 40 KPIs and five different operational categories that we published in the report.

So we're gonna go through those in a little bit of detail as well as highlight some key graphs uh that I wanted to highlight from from the report.

First one, uh system reliability.

This is uh uh historically how utilities measured themselves.

There's a lot of data out there.

Um number one for us being a municipal utility is uh APPA publishes annual uh reliability statistics every year.

So that benchmark that you see there really is that first core tile of all municipal utilities in the country, regardless of system design or location.

That's really our goal.

Uh the first one is the the KD or customer average interruption duration index.

Uh that is the average time to restore power for all of our different outages.

So uh benchmark was 75 minutes.

RP team uh performed that in 52.63 minutes.

So on average, we restored an outage in 52.63 minutes.

So that status is green.

The next one, and probably the most the widely used to compare utilities is Sadie or the system average interruption duration index.

That what that means is it's the the time and the average customer is out of power for per year.

So our benchmark was was 90 minutes, which was that first quartile number.

Uh our performance came in at 50.64.

So again, uh above that benchmark.

The next one is the system average interruption frequency index.

This is the uh how many interruptions a customer has per year.

Uh benchmark at that first quartile is 0.8 or 0.8 outages.

Uh, we were at 0.89.

So that is a yellow.

We did not meet meet that benchmark.

Uh the last one is the average service availability index or E S AI.

Uh, this is a uh percentage of how available our system is over years.

So you take the number of customer minutes, assuming everything's on first and then subtract what what is off come up that percentage.

So um the benchmark, we actually were the were the benchmark.

We were the first quartile here.

Uh first quartile is 99.990.

We hit that mark.

Uh, generally, when we talk about ACAI, we talk about the nines.

Generally, we want to see four nines.

You get down to that fourth, the that fourth nine is an eight, uh, you'd probably miss the benchmark.

I just when I'm wondering if you're gonna talk about uh you know there's a not a lot, but there's a few yellows and reds, and if you're gonna talk about those, why it was yellow and okay.

Yep, I was all circle by okay.

Uh but yeah, so the only real yellow here is is our our uh system average uh or the excuse me, the the safety, the system average interruption frequency index.

And thank you for the lead in.

Here's our outages.

Uh so basically what uh what safety means is how many interruptions we have.

So the nice thing is our our CD is very high uh compared to the industry, which tells us even though we do have maybe a little more interruption frequency, our crews are restoring those that power efficiently.

Um, as you can see from our our KPIs, our our top three uh really are animals vegetation and and undetermined or equipment failures.

Um so we do have some systems in place, uh veget uh vegetation control for vegetation trimming to to reduce those numbers.

We also have some animal guards on our our key pieces of equipment and also wraps around poles to try to minimize those animal outages as well.

So we we do where we are aware of these outages and we have some uh things in place to try to reduce those numbers to improve that safety number.

Next KPI uh set is our asset management and preventative maintenance.

Um the first one we'll talk about is is vegetation management, and really we're looking at miles trim per year.

So we're on a 10-year cycle.

So we want to be able to go through our corridors on our distribution system and trim that corridor every 10 years.

And in order to meet that benchmark, we need to trim 81.9 miles per year.

Um unfortunately, last year we're at 77.3, uh, which means we're a little bit below our benchmark.

So we did not meet that benchmark.

Uh, luckily, uh, through budgeting and other things, we were able to raise some of our tree trimming dollars uh to raise the amount of uh miles trim that we can do because uh that uh that trimming is done by contractors.

So we're able to use this data to raise up some of our budgeting for next year to get above that line.

Um talking about all the everything bad all the time, but the the substation maintenance, a third one down.

Uh, we did uh perform 95% of that, which is a great preventative maintenance.

Uh, one of the other uh causes of outages is when equipment fails.

So proper preventative maintenance keeps those systems uh working well uh without any uh disturbances on the system.

Uh the last one we'll talk about.

I guess we'll go down to uh manhole repair and replacement.

Um our goal is to replace four per year, and again, we're looking at uh um kind of a cycle here to go through and change out all of our old manholes.

And in order to do that in the 10-year cycle, we need to hit four per year.

Unfortunately, last year we did not meet that.

So uh kind of refocused our budgets and added some budget in uh in 26, 7, and 8, and 9, and 26, 27, 28, 29 to catch up there.

I'll jump in here and support some things that Scott maybe might not be saying here intentionally.

Part of the challenge on vegetation management and manhole repair is we have experienced cost increases on what it takes to accomplish these.

So if we hold budgets constant and it costs more, we in effect are clearing less miles per year and less manholes for longer tenure board members.

You've seen the cost of the manhole rebuilds go up each year, which means we're doing less of them.

Um we're setting our own benchmarks here.

Uh, these aren't necessarily benchmarked against anyone else.

So this is a board level decision as we develop budgets as to how to come back, and we are in indicating yellow here, indicating these are areas where we may be falling behind on our maintenance.

The solution here is to do more, and that solution has a budgetary consequence.

Uh so part of why we're highlighting it here is just showing in areas of our reliability why some of these are becoming challenges.

And it's really because labor costs con uh professional services costs have gone up and we're accomplishing less with the same amount of standard dollars that we do in the budget.

So I'll say the things that Scott's kind of reserving here, and just indicate that's one of the reasons we develop these KPIs.

And I and I should have said that.

There's lots of good stuff here.

I saw that, but I was thinking, well, either they're not good KPIs, I was not assuming bad stuff.

And I always focus on the negative.

So and Tim's a lot more eloquent than I am.

So and you can get away with saying some more things than I can.

Um the last one really is on the generation side, uh, generation availability factor.

Um, that's all the uh percentage of how available is our generation to be used.

Doesn't mean it's being used, but it is available.

Obviously, the the red one, as Tony mentioned, was was CT number one going down.

Um, the last one is is forced outage rate.

Uh that's really an indication if the unit is running and has to be taken offline for um some sort of failure or unplanned outage uh are taken out of the market for an unplanned outage.

Um, that that is what forced outage rate is again.

Not surprised GT1 is on there.

Uh, I think uh GT2 had a uh issue um with one of the runs that uh dropped that number down below.

So I'm sure Tony is group will be focusing some of the maintenance dollars on making sure that is better next year.

Uh the next set of KPIs is system planning and analysis and expansion.

And as Tim mentioned, uh, these are self-imposed in this section, RPU benchmarks.

There's really no national benchmark to benchmark against these.

So these are our own.

Um so the first one is uh new service editions compared to budget, and uh we planned we want to be within plus or minus or under 10 percent of uh what we planned.

Unfortunately, last year we had a lot of new service additions, uh, which put a lot of rate pressure.

That's why this is a KPI.

So if we underestimate our new housing starts, the money has to come from somewhere.

So we're now we have to reprioritize funds to maybe make sure that uh that work is done.

So we're trying to hit that number as best we can.

So uh we were we kind of blew that one out of the water.

That one, that's why it's red.

I don't think there's a color higher than red, or it would be so um other things, you know, studies.

There's three studies there.

It's kind of a yes or no to we do them, but ultimately these are studies to ensure that our protection and our system is robust and operates well.

Um and it's it's hardened against outages, growth, uh faults, things of that nature.

So uh we try to do those on a on a yearly basis.

And the last one you've seen it uh from the dashboards uh that Tim published, but these are the major project dashboards and updates to those.

Uh ultimately the benchmark there is it's is it within scope?

Is it on budget and on schedule?

And if you look through the major uh project updates here, I won't read through them all, but uh they are all on target.

Uh next one is compliance.

Can't operate electric utility without compliance.

Uh multiple compliance areas here.

Uh, first one being safety.

Um always benchmark is going to be zero again uh in this category.

These are RPU benchmarks.

There's really no national benchmarks here.

Um, our benchmark will always be zero for safety.

And unfortunately, we had uh six recordable instances, instant incidences in 2025.

Uh so that one obviously is a red.

Um the last part down towards the bottom.

A lot of those are our critical infrastructure and protection things that we do with personnel training in our SIP world for SCADA security and cybersecurity, uh, instant response.

We always test our instrument response plan and make updates to them to make sure we're as hardened as we can against uh cybersecurity threats and then system patching, make sure our system is protected.

So obviously uh did perform very well there this year.

And the last one, and I think this is Tim's favorite one.

Uh the financial stability and performance.

Uh, this is kind of a mixed bag here with some yellows and greens, and we'll talk through some of these.

Uh as far as the benchmarks, there are benchmarks here that are published through APPA.

Uh that they publish their annual financial and operations ratios uh for public utilities.

So we wanted to make sure we were in uh up within 10% of the minimum's values of all published municipal utilities.

That's our benchmark that we set for ourselves.

So uh our revenue per kilowatt hour sales is red.

The benchmark is 13.6.

We were at 17.9.

Uh talks a little bit to our rates.

Um the next one, the yellow one is the power supply cost.

Um, the benchmark was 6.9, our par supply cost is 8.1.

The second yellow or second yellow down the debt ratio uh target was 3.93.

Our value was 3.36.

Then the last one is debt to asset ratio value is 32.2%.

We were at 34.

Unfortunately, if there's any questions on this section, I might have to phone a friend.

I'll just highlight uh preempt any questions.

The revenue per kilowatt hour considers the impact of the power cost adjustment in addition to our published rate structure.

And I think that's the largest impact that we've seen here.

We've seen a sustained two cent per kilowatt hour power cost adjustment that really stepped in in 2024.

That's a pass-through cost from our wholesale supplier.

And so that's the largest impact here related to our competitiveness here in the Midwest average.

No change to the Oatana public utilities um rate comparison.

We're still in line with regional rates, but this is comparing to a Midwest average.

That is a broader benchmark, not necessarily the peers that we have in the immediately adjacent uh region.

So kind of forge ahead from the from the KPIs and kind of highlight a couple of system details.

Uh so we added just under 500 customers last year, 499.

Uh, so our customer count at in December of 2025 was 61,242.

We have a total of 867.8 total circuit miles of distribution, and 67.2% of that distribution infrastructure is underground.

Um, kind of going back to that.

I'll have a graph uh here in a minute for the the 62 point uh 67.2% of underground.

Uh just the trend line for customers steadily uh uh raising our number of customers that we have year over year, um almost on a four to five hundred average.

And then from an underground circuit miles, we did uh see the upward trend there.

Uh, two main factors there.

Uh we do have do have some overhead to underground conversion projects that we do when the reliability impact is positive, generally around road projects or intersections.

But the biggest driver here is when new subdivisions go in, uh they generally are going underground.

So this really drives this number.

Um, and I think over two-thirds of our system is underground.

So that is fantastic.

Looking at our system peak, we're a little off on our system peak uh back in 2023 was when we set our historical average or historical peak at uh 294.8.

Uh, we were a little down last year in 2025, uh hitting a peak of just over uh 260 megawatts.

Um, minimum demand uh is very constant.

The average uh megawatt hour uh per residential customers is is trending a little bit lower.

It's not a very large slope on the downward end of it is trending downward.

I blame Patty for this and and Josh's group for the good job that they're doing in the marketing group on rebates.

Uh but we are seeing uh a downward trend uh in some of those uh uh megawatt hour uh sales because of even though we're we're offsetting basically our growth here uh with some of the rebates and and programs and efficiency programs that we're doing.

So this is our our daily uh max min and max uh load.

Uh so the top line is our maximum load, and then our our daily minimum load is the bottom curve, the maximum there uh happened on July 23rd, and it was 200 260.2 minimum was on uh October 19th at 87.3.

Again, kind of see that uh some very summer peaking model that we have down here in southern Minnesota.

Service territory, we have roughly our total of 62.79 square miles.

The original service terrain in 1974 was was 31.05.

So we've doubled more than doubled in size since 1974.

1974 is a great year.

That was the year I was born.

Don't do the math very quick there.

Uh so over time we've acquired just over uh 31.74 square miles of service territory from 1974 to December 31st of 2025.

Uh power resources, one of the things to highlight here as you're kind of looking through the the statistics, some of these are kind of a rehash of uh our yearly system data.

But if you look at the number of total system generation from 2025 from 2024, that is a 37 point 31.7% increase in total generation from uh in 2025 from 2024.

Uh kind of the simpa in RPU load graph, coincident peaks overlaid.

Uh a couple of things note here.

Obviously, we follow since ZIPA is roughly a lot of their customers are in southern Minnesota or are our summer peaking utilities.

So we follow a similar load curve.

Um, but maybe the thing to highlight here is is the dotted red line.

That is the 216 megawatt contract rate of delivery line or CROD.

So it really shows how many months uh we're above CROD.

And the trend there is we don't have this trended, but uh as you can see, we started hitting above CROD in May and fell below CROD in October.

Uh that line, that timeline is is extending uh for if you go back five, 10 years, that would have been June to August or maybe September.

So as our load is going up, we're above CROD uh more months uh over CROD.

We are supplying getting our own uh forecasting, getting our load, our own power supply from TEA being in the market and do real-time things.

So the number of of months that were above CROD is is expanding as our load is going up.

And the last one, I mean we need to phone a friend here as well.

Uh, but we kind of rehash some of the availability factors and the forced outage rates uh for gas turbine one and gas turbine number two uh kind of highlights here the net generation.

Uh see cast urban number one is relatively low because of the outage.

Uh gas turbine two is a little bit above 2024.

And then same for uh West.

With that any questions.

Well, thank you so much for that.

Um, are there any uh questions or comments on uh the informational agenda item six A.

I I have one it I mean, it looks like I don't know if I did my math right.

We increased by just under point 0.8% in terms of new connections.

And I'm thinking that we'll the same based on what I'm kind of hearing in the developments coming that we'll continue to do that.

And that was one of your yellow or red areas.

Okay.

Is there a plan?

Uh you know, what do you think?

How is that what do you how we you know?

I obviously I get its money, and but and but it look looks like it's gonna continue.

So is there so one of the things that we did in the budgeting cycle is we increase the new housing starts to go to wrap into the budget process and increased our uh distribution transformers and new services allocations to accommodate the city has a goal of a thousand lots per year.

Uh so we we ramped up to do that.

We're also tracking the dry utility installation.

We have a uh basically a list of all the utility or all the subdivisions that are coming in and where they are in either the community development or public works process, so we can see them coming up through the process until we would be installing dry utilities, and that spreadsheet is becoming very lengthy.

So we want to make sure the new housing starts and our budget assumptions were correct, and we uh adjusted the budget accordingly.

Okay, thank you.

Couple more points there as well.

Um, when our budgets were originally written, it was very early in the reaction to the bold forward and community expansion.

And so we took a maybe what wasn't a we a conservative approach of budgeting.

Uh we didn't want to um over budget for new housing starts, knowing that new housing starts have some level of self-sufficiency in line extension fees.

There is associated revenue through fees that come in with that.

So we took a conservative approach in these budgeting cycles.

That's one of the reasons we under shot.

I'll admit there was some level of internal skepticism as to is it going to be a thousand houses a year?

Um, but it wasn't gonna stay at the 300 per year.

That's been historic as well.

As you can see, it landed in about 500, and so it's somewhere in the middle of that.

And we used budget revision process last year to accommodate the additional budget necessary.

About half of new line extensions is covered by fees.

The other half is covered by 10 years of rates.

And so there is an overall rate impact to new housing starts if we undershoot that.

Uh, it puts a little bit of future rate pressure on us to accommodate that future growth.

And as Scott said, we're revising those estimates based off of what we now know of new plats, new lots coming in, and in line with what the trajectory of development in the housing side is.

Um, we also have to understand what percentages apartments versus single family houses.

And so we go into these having to procure transformers well ahead of time.

The type of transformers we buy matters related to what type of housing it is as well.

So we've reacted, even though we missed the initial budgetary estimates through budget revision processes.

And that's what the board saw last year with the budget revision and the transformer purchases.

So we're acting to that.

We intend to have more informed estimates going forward as we approach the 27 budget revision process that we're in the middle of right now.

The board will hear recommendations in August for that.

And then next year we'll be planning the 28, 29 process and allows us to improve those metrics on how we're doing on estimated versus actual.

Still have to understand where the market's going.

So if housing continues at its current pace, um, but there's also the chance that it could flatten out as well.

So part of this is just a forward projection and doing better as to predicting what the future is going to bring.

Thank you for that.

Any other questions or comments?

Councilmember Keene.

Yeah, a little bit of comment.

See if I can get a reaction.

I when I look at that uh peak demand and minimum, I think it's page 36.

Um it is you know astounding to think of the growth in Rochester and then that flat demand line.

And I think some of it can be explained through uh, you know, rebates and programs and LED lights.

But what kind of assumptions are we using for the next 10 years?

We still based our future projections based off of the econometric look back as well.

So a lot of it as far as how much energy a new home uses is pretty standard.

So we can predict that.

It's just a matter of predicting the right number of new homes being added.

So that element of predicting future residential growth is a matter of hitting the right future numbers there.

Um so the assumption underneath it is household usage will stay flat going into the coming years.

It's a factor of both number of households, and as the one chart shows average use per household is also a factor, and that's on a downward trajectory.

So new houses being new apartments, new houses being added are more efficient.

And so it's not just a times a multiplier.

We have to assume that the new houses are more efficient, better building codes, better appliances.

Okay.

That's on the residential side.

The commercial and industrial growth, we work very closely with our customers to work with them on what their future loads might be.

Um there has been business loss that has occurred here as well.

So commercial downturn has been a factor over the last 10 years as well.

Some of our larger accounts have either through efficiency or through different production means have improved their efficiencies.

So we have to balance housing residential projections also with what's happening in the business sector.

There are some structural changes that we're anticipating coming into this next budgetary period as well, just based off of some business and industrial use.

Overall, I think this is a good news story to tell because we've held community growth relatively flat on energy consumption, but it also comes with its own challenge because revenue requires charging per kilowatt hour.

So the that's one of the drivers of our rates going up is we're not we're not seeing any new load growth shared by uh additional customers.

Okay.

And again, it's just one of these things that I'm looking at that I didn't know, but the projection really is by that household.

I know I know the industrial sites differently, but the assumption of reduction per household extends into the like the next 10 years, as opposed to electrification's going to make the demand higher because we're moving away from some other things.

That's not coming into our that's not a planning assumption uh that we're using.

It is an assumption, but it's not have it doesn't yet have a material effect on the planning assumptions yet.

So we're watching the number of electric vehicle starts.

If you look back four years of what projections were of electric vehicle growth, we've realized about 25% of that actual growth.

And so those have been more moderate trajectories than earlier assumptions.

And those would be more on the bottom line there, that and the minimums because that's mostly hopefully they could also impact the top line of charging isn't at the right time.

But yes.

That's sort of the thing.

The other thing is an observation just is um it's amazing how stable the demands can be.

And I think that's just a function of scaling to 60,000 households, things like that.

But when you do see those sort of blurps, it I was looking for any sort of metric of where like 94% efficient on the energy we generate actually gets used as opposed to you know, we can't hit those kind of numbers because of demand going up and down, or it demand is if if when we say it's demand is you know, at 260, at that point, it does we don't just have it generate for that, and then it drops and we like generate energy that we don't use.

Demand is one of the more difficult, especially max demand is one of the more difficult things to predict because it is so highly weather dependent.

Um three days of hot weather in late July could swing our max demand in a year 30, 40 megawatts.

The difference between 23 when we hit our peak and last year 25 is really weather driven.

We had more houses, we just didn't have that hot, sticky third week of July, first week of August that we had back the day Mark Cochevar retired, that I will remember a date that goes into infamy.

It was just a hot, sticky Thursday after three days of heat.

So the upper end of the demand sets what our planning requirements are in the market.

It is highly weather dependent.

So the fact that it was lower, I think tells a better picture for us, at least in the short term.

We have less planning margin that we have to meet there for capacity, but we can still have a we could have this summer.

We could set a new peak just driven by air conditioning load as well.

So no, so that those things are impressive for me to see.

I appreciate seeing those kind of numbers.

I am still trying to on the financial one, that idea of like our 17.9 cents per kilowatt.

It's it's uh troublesome.

And I know, like you say, the cost adjustments is in there, but to see us that far off cost, I still really appreciate the offset with the reliability that we can bring there.

And I think those are things that are really appreciated of having the local control.

Thank you for that.

Any other questions or comments?

Hearing none, thank you so much.

Uh and we will move to the second informational item, uh, item 6B, the MISO annual capacity auction results for planning year 2026 and 27, which will be presented by the director of power resources, Mr.

Bill Bullock.

Good evening.

Um, we were talking about planning and uh demand.

We sort of have an imperfect um forecast tool, which is the uh MISO um planning resource auction, which they do once a year.

It only gives us one year of visibility, but it is uh it does give us the pricing signal we were looking for.

This is the second year um, and and they run this auction uh in April, they publish the results in May, and the prices go into effect in June.

Um they're using the methodology of uh what they call RDBC, uh reliability demand-based curve methodology, and that really is intended to improve the price signals to focus on uh reliability of supply.

Um and the the framework really allows the pricing to adjust to meet the supply and demand uh dynamics.

Um this last year resulted in net capacity additions of 4%.

There were 4% more capacity made available to the market.

Um, but there is an offset to that.

There were imports um uh as well as new capacity, and then there were lower accreditation on some assets and retirement of other assets that help balance that out.

Um, but capacity additions really need to continue to uh to to be added um given the expected growth from new large loads.

Um so this is the map of MISO, uh, where you know Minnesota and RPU are in zone one.

Um, we're in the northern um part of MISO, you can see that small area connecting the northern and the southern zones.

Um, and just the pricing for summer is really um, you know, the limit that showing where the limit is.

Although this is significantly lower, so almost 50% lower than the auction last year, which I think reflects that the prices were very high last year.

So it did attract a lot of new capacity into the market.

So the market is working.

Um that's what this shows.

And of course, the other seasons are um fall and winter were very similar to last year, but something strange happened in spring.

There was an over abundance of capacity, and the price is very low for the for the springtime.

Um, this is if you want to know what where the additions came from and where the um where we lost capacity.

Um last year, this is for the north central region.

The most leftmost column is a hundred megawatt, a hundred gigawatts.

That's what uh what the offers were in 2025.

Then adding to that, you can see the yellow, there is a big uh addition of solar energy uh into the market.

Um, and that would be in the north central region.

Uh the blue is gas.

Um, so there was significant amount of gas added.

Uh, and then the the red are battery projects that were added.

So you can see a lot of um uh in fact, in fact, the batteries are almost as large a contribution as as the gas plants were.

And then they had another one one gigawatt of imports from external resources, so that would be from the other um RTOs um uh sending the through the transmission grid.

Um, and then uh the increased accreditation each year they're accrediting um capacity for different resources.

And as you can see here, this year um solar actually gained accreditation for the summer, which makes a lot of sense.

Um so there was more um anyone with a solar plant got more credit for the capacity that they generate.

Um this had a significant impact.

Um, and then if you look at the the next column, that minus 1.7, that's assets that were decreased in their accreditation, and in that um grouping is you see, wind was hit pretty badly with which makes sense because there's less wind in the summer than there is uh in the other seasons.

Um coal was also lost significant amount of accredited capacity.

Um that um that that was relatively new, and even nuclear lost some of their uh accredited capacity.

So we could count on those resources less.

Those are traditionally base loaded assets, so um it it did make a pretty big impact.

Um, and then we also lost um from operations that mostly coal and gas that were retired or um suspended.

Um so net net we in the north central region gained about 3.1% um or 3.1 gigawatts.

Um which explains why the prices came down somewhat.

It's the same pattern if you look at the overall market, except there was uh a bit more capacity added to the other um the the other zones, um, meaning that uh that's why the prices were a bit lower there, but sort of the same dynamics, you know, solar gas, um same sort of narrative.

Um before we become too complacent, it's important to look at the so the green line shows like the historical load uh within MISO, and the dotted lines are showing what's forecast.

So as you can see, we've been seeing a lot of volatility in pricing, and the load has not increased so much, but we're we can see year over year the dark blue uh to the light blue shows uh 2023, 2024, and 2025.

So the the expectation is that we will have uh a significant amount uh increase in in load coming our way.

Uh more demand means we're need a lot more uh capacity.

So uh we can expect uh the um hopefully the the the prices that are currently showing up in the auction will continue to drive um the supply curve so that we get um more capacity online, but in order to meet these kind of projections for load growth, um, we're going to need a lot more capacity than we've had.

Um, and that's that's why you know we're making the investments we are in the capacity that we are because we do you can see that in 2030, right?

When Sherco is retiring, um, that's when a lot of this uh high um additions are going to come into the market.

And that's that's it.

I didn't mean to scare you or you know, but but it is uh, you know, I think uh the the market has shown to uh to work.

Uh it's attracted capacity, it'll need to continue to attract more in order to um to ensure price stability for us.

Well, thank you so much for that.

Are there any questions, comments, or discussions on the informational item 6B?

I have one.

Oh, go ahead, Wendy.

I was just gonna ask, you know, projected road load growth and why you what you're I mean, I think why you think well, I think most of that load growth is probably data center.

That's what I was thinking, um, which is all around the market.

Um so yes, I think uh I think that's the what's driving it.

Maybe a little EV addition.

Do they publish their assumptions why they think it's growing?

Is that what they're saying?

Yeah, so what they do is they require all of the load serving entities in MISO to submit what their load forecast is.

So we submit ours.

Um, all the other utilities submit theirs, and they aggregate all of that, and then they get the market view from that.

So that is based on actual um input from everyone that's serving a load in the in the market.

I got uh two quick questions.

One, um, so capacity remains the vital critical, scarce, scarce resource that's just critical for us at our size and scale.

Yeah.

And then second, did I see plus and minus on hydro?

I didn't.

I thought I saw, plus I'm colorblind.

I thought I saw a plus minus.

Oh, yeah.

So there would be probably some of the hydro was got accredited higher.

So they got a higher accreditation.

And then um, or they, you know, maybe um uh renovated the turbine so that they had more output.

Um, but then also some might have been um okay.

Which is more than I expected to see in our region.

So okay.

That's all I got.

Uh anyone else?

Just note there was another FERC level decision just last week.

They issued uh a show cause notice.

This is the federal agency telling every energy market out there, you must demonstrate that you will be able to meet resource adequacy within 60 days.

All energy markets have to respond.

So NURC and FERC are also are both taking pretty severe and aggressive actions to try and manage data center reliability and the ability for markets to respond to these new and growing loads.

That's a pretty out of character thing for FERC to take such an aggressive action.

Um and the initial notice periods are within 60 days for this as well.

One of the reasons for the more extensive write-ups and watch of what's happening in the regulatory space here is there's just a lot of things changing with large load additions happening right now.

Next up on our agenda is our board policy review.

Um this is uh item number 7A, and it concerns board policy number 32, financial policies.

And this will be presented by general manager McCullough and assistant general manager of administration, Mr.

Hogan.

I'll take the kickoff here from my seat.

Um, just wanted to highlight the why again we're bringing this forward to the board.

Um I'll move fairly quickly through some of these slides, but the intent here was to do a companion approach to the city finance policies.

If you've um read the city finance policies that were recently adopted, they share that they're inclusive of RPU, except as provided by charter.

There's a few charter differences where uh the RPU board has distinct financial authorities that are separate from the council, not not different or not independent, but separate from council.

And we want to highlight a few of these where we have drafted what we believe is in alignment with charter shared services is one of those, as we uh consider the opportunity to provide shared services across the entire city organization and some uh kind of new frameworks that we're proposing here on how to approach those issues.

Um the procurement side of things as well, as evidenced by the board's letting of a 600,000 plus dollar contract just earlier in this meeting.

The board has distinct uh charter authorities on procurement and kind of sole responsibilities to operate within the budget that required a companion approach.

The city policies share about how the general city process works for procurement that goes through city council.

Much procurement here goes through only the board.

Um, there are some charter reserved rights where city council has reserved roles, and this is drafted in a way we believe to respect those and bring clarity to how these processes should work as well.

Um the board is, I think, familiar with where the authorities are different and distinct between the two.

The common council reserves rights for operating and capital budget approval.

It's recommended by the board, but ultimately council must sign off on budgets that includes the rate, tariff, and fees, um, the head count, uh, authorized FTEs, any debt issuance, purchase or sale of real property.

We've dealt with these issues as a board.

I think on almost every one of those over the last few years in my tenure.

So I think those are well-established areas where there needs to be distinct treatment here as well.

Mayor signs all contracts, so we're not seeking to make any change here.

We're just seeking to provide clarity when the city policies say something needs to be approved by the city city administrator and council.

In the case of RPU, often that's general manager board, and in some cases it's council as well.

So just trying to provide that clarity here with the finance policies.

Um, not trying to establish any difference in what the board's authorities are.

That's defined by charter, what is and is not allowed there, what the board can and cannot do.

And then some of these changes that are being proposed are within what are the delegated authorities.

So you have to look at board policy six, that's delegation of authority from the board to the general manager as we get into the procurement section.

You'll see a couple proposals there to deal with some timely issues related to wholesale input procurement as well.

And we'll touch on those.

Section two on shared services, section 12 on purchasing, where we have a proposed policy change.

And then section 18.

Part of why we wanted to bring this forward now is to get some feedback from the full board related to the council's direction on changes to the payment in lieu of tax.

That's probably one of the larger changes that would require uh for alignment there, a rescission of one of the board policies, which is the current definition of payment in lieu of tax.

So looking for some board direction specifically on section 18, and we'll probably spend the most amount of time there within this policy review.

So with that, I will turn it over to Peter to walk through the specific policies.

Um, as you might have read in the board packet, any section in the draft policies where there's yellow highlighted text talks about where there are either one of these chapter changes, anything that's in just standard uh black and white is intended to document how things work and not make any change to charter authorities or um processes.

And in many sections, it just refers this is where city policy governs, don't look here, look there.

And in some cases, there might be a slight difference that says here's where there's a separate governance process, look here.

That citywide policy has a slightly different charter flavor for the RPU board.

So I'll leave it there, and I'm sure it will lead to some uh robust discussion.

Very good.

Thank you, Tim.

So that we will uh move into so this this first slide here is really talking to what Tim kind of already touched on, so we won't spend a lot of time here.

But I think the uh the key statement there went too far.

Okay.

I won't page in that.

Um so this is um section two, really talking about the budget, and we're really talking about here that the uh to highlight just a few things here.

The budget is uh you know prepared at the direction of the general manager, approved by the board, but then ultimately that the right to approve the budget is reserved by the city council.

But there is some nuances within that as far as the charter boundaries there.

The budget, when we send the operating budget, the city council is approving the entire budget.

So all the expenditures, which then allows us to move, you know, expenses around within the budget, and which that also happens at the city side.

On the projects, they're specifically identified.

So you'll see there's a whole process.

Uh, we do have a process where we do move like kind projects.

Uh so there's a whole bunch of line extensions in there.

It may or may not end up being that exact line extension that happens and may end up getting moved to a different one.

So there's an internal process for that as well.

And then uh the right tariff is is approved by the council as well.

And then the council also approves the total number of headcount, but how those uh positions are actually uh assigned is actually within the operation of the board and delegated to the general manager.

So that's that's a little bit different than some of the city uh functions there.

Uh we also work very closely, you know, across the city finance and and our PU finance team.

And there's there's quite a few examples here of areas where we kind of coordinate and work together.

And that's also a requirement of the charter as well.

That um the uh well the um RPU board is responsible for the operation and all the financial policies for the utility.

The we're also required through the charter to coordinate with the the city finance in order to coordinate um reporting for like the financial audits and budgets and things like that.

So we do a lot of work back and forth.

And on that whole big list of policies, you probably notice there's a number of them that said coordinate, like on investments.

We coordinate participate in an investment pool throughout the whole city with the funds.

There's also some funds that are not within that investment fund that are directly invested as well.

So we we do both.

We do the same thing with insurance where we're part of the you know, the citywide health insurance uh on the risk management side, some of our insurance policies uh direct and separate uh when you look at what we need to do and some of the impacts we've had with uh say generation coverage the last few years with the the costs, and I expect we'll get impacted with that with the GT1 claim in this last year as well.

So on the um this one here is really talking more about within those financial policies that it's delegated to the RPU board than within the um the the uh delegated through uh policy six to the general manager, and within that, this policy is delegating and or identifying who is responsible within the executive team essentially for different roles and responsibilities.

So we're identifying and and delegating, you know, who's the stewards that are responsible for specific areas within the operation there.

And that's kind of that middle section there where we're talking about the RPU director of finance, uh director of information systems, the assistant general manager on the operations side, assistant general manager on the administration side as well.

Yes.

Um are any of these that you're talking about right now in conflict with what the city's finance?

I think most of these ones here, especially where you see the charter boundaries is there's statements in the city policy that say something different.

So, like if you looked at the the um the stewards there, it would say that the city uh director of finance is responsible for that.

Well, actually in this domain, that's that's not true, yeah, because of the charter says it's the board and the board delegates to the general managers.

So there's uh there's a number of these ones here.

And I I think the biggest difference you're going to see between the city uh set of policies is there's a policy level statement, but then there's a whole bunch of procedures, and you'll see purposely within what I've written up here is I have tried not to include procedures because they can change their dynamic, then they change year over year.

Like the city one calls out you know the date that the tax levy is going to be set and things like that.

It's like those those are operational, you know, blocking and tackling things.

So you'll see some difference.

Uh, there's other parts of it where the where we specifically reference in the policy that we're adopting uh on the purchase one, the risk part of that or uh on conduit debt.

There's a several pages of description of how it's going to be evaluated.

And we're just saying we're just adopting that, you know, because it's there's no sense you know, rewriting stuff that's already in a policy.

So the intent here is to definitely to partner up and make these uh coordinate, basically.

So and where the city policy will say something that is in conflict with the charter, that's where we've tried to point out okay, this is this is where it's different, and this is how it's different.

And that's really the purpose of the RPU policy.

I wouldn't go to the extent to say they're in conflict with the city policies are uh this falls within the companion approach.

So there's areas of what RPU board is responsible for that require delegation to the general manager.

So if the city policy says the director of finance is responsible for accounting systems and definition, that's true for the full city, but there's a specific charter requirement that delegates that responsibility to the RPU board that except for the extent of integrating financial systems, it's the board's responsibility to do the audit, it's the board's responsibility to do the defining the accounting and financial systems.

So this is drafted in a way to be a companion, not in conflict, but to define that the city finance policies don't do anything more than stay except where charter says otherwise.

This is trying to make an attempt to say here's where some distinct charter authorities lie.

These are the these have been long established in how the board operates and the delegations to the GM.

So I wouldn't say they're in conflict.

Um there may be some differences as to what it means for the city director of finance to be responsible for the coordination of systems.

We would say yes, we always do.

We provide integration to the budget.

We have a requirement to submit by budget deadlines.

We've tried to recognize all of those targets that the council has adopted in policy to hit certain dates, but it's still the board's responsibility to develop the budget.

So where there is a distinction, we're trying to show where that definition is.

If you just read what's drafted now, it could lead to some confusion, and we're trying to provide clarity here as to where the responsibilities are.

I believe it's very important that the board's uh responsibilities to manage and control the business fall to the technology systems selected, the accounting systems that are selected, and so it's trying to make those same delegations here as they apply through the city charter.

Yes, clarifying just I um Ms.

McCullough's thing kind of changed.

I mean, the the policies we're dealing with right now conceptually is the this board talking to this management team.

Correct.

Okay.

It's not really set up for this admin this management team to talk to the city uh administration.

I'd say largely yes, but there's a couple areas where charter requires close coordination.

I understand, but again, I'm gonna review these finance policies as if this is our board communicating with our management team given directions on how to, you know, policy-wise, not and I really appreciate not operationally, but policy-wise.

Yeah.

Okay.

I generally agree with you on that statement.

Right, yeah, right.

Just clarifying.

Thank you.

There are probably areas where there needs to be dialogue where there are you know misalignments.

So and I think we'll touch on a few of those here.

I I do understand what you're saying.

Yep, but I'm not sure if that's this board should work with the city's administration then to resolve those, or this management team needs to work with that admin.

I mean, and that's we're all in the city cocoon here, but we're almost acting like we're this separate contractor and they and we're trying to work out the contracting things between us.

And I I'm gonna state it again.

I'm viewing this as your staff is helping us like pen these policies that it's our communication, this board's communication with dismanagement.

Yeah, this is your direction to us, absolutely.

Very good.

Yes.

So um looking at the the uh shared services uh section, uh this is a new section that went into uh into place on the the city side uh in 2026.

However, we've been doing this for a long time with public works.

So ever since I've been here, um the the utility has been doing the the billing, the collections, the customer service for both uh sanitary sewer and the storm water, and we have a whole process.

So a lot of what's being done at the city level here looks a lot like what we've been doing for 10 plus years.

So this isn't a big surprise.

Um, and then a lot of the work that we've done back and forth here is to you know help define that.

I think a couple of the key things that we wanted to identify here is uh, and I and I worked with uh the team at the public works site here, Aaron Luckstein, um, to develop uh memo of understanding to clearly document what is included and then also when there's changes.

Uh the you know, uh a good example of one in our case was when we decide to do advanced metering, it has a right impact on the on the uh sanitary sewer side.

So, you know, we kind of made that decision and really didn't include or have very much discussion with the with the public works team.

The former public works director being one of those that needed needed communication with.

So there's a paragraph in here that speaks to that.

And I think that's an important point to make, but it's it's true as we go further down this road on the shared services side.

So I think that's what we're um pointing to, you know, having a memo of understanding, giving some discretion to the general manager up to 175,000 to you know uh negotiate small contracts back and forth uh between departments.

However, when it gets to that larger amount, kind of using the the GM authorization as a threshold to say that needs to come back to the uh the board to say, yep, we're okay with that, and over the methodology of where you're going forward there.

So kind of respecting our governance as well, that we can't just go out and enter into uh agreements that without a limit then.

The purchasing contracts one here for the most part uh are very similar in both the the policy, you know, we're going to follow state bidding laws and things like that.

The different areas here that kind of stand out is in uh like the second uh point down there on the RPU policy.

Uh we uh we also have access to or have governance under section 453, which allows us in the generation and transmission area of the business to um be treated more like a an investor-owned uh utility.

So that means some of the the uh the public bidding is not required.

The public meetings are not even required in some of those cases.

So where you can uh actually negotiate that.

And we have used some of these uh things selectively when we built Westside.

We're currently doing that with Mount Simon uh with some of the wind generation contracts that we've done, have all been under that 453 uh provision.

The other one that's in there is uh public funds, uh use of public funds.

And this is a relatively small dollar one, but it's a it's a different, definitely a difference between uh on the city side and um and what the utility can do.

Um this was actually one of the first resolutions that I uh wrote when I started here back in 20.

Uh I started in uh September of 2014.

So this is one of my first board actions was actually this uh resolution.

And what it's allowing us to do is because of some of the conservation requirements, the utility can actually have funds where we support like an award at a science fair and stuff like that.

As long as we're promoting the the EGO Act and some of the regulatory requirements that we have.

Typically, in the public funds doctrine, you can't do that.

So we can't um get them contribute funds that way.

So that there's uh it's a narrow exception, but it's something that went through the board some time ago.

Um and we're working to incorporate that in here.

And then I think Tim already touched on the last part that all contracts are in the name of the city uh and signed by the mayor and witnessed by the clerk.

Yes.

Can I go back to the shared shared services?

Just I mean, I I appreciate you called out the ones where the public works and the billing system where RPU is providing services for another one, a document of understanding, whatever.

Do that's an example you did.

It's not, but it's another example how HR works, that there's an HR department in the city.

That's one that actually Brian and Brian, the city uh uh finance director and I are working on developing because they've kind of come up with a you know a methodology to allocate stuff, but there's no documented how we got there or what's in or what that process is going to be.

So I mean that we're working on that.

Yeah, that would be an example here where there is the different enterprise funds, but one HR service.

And then the other one, and again, I I'm just trying to make sure I understand that there's other things where RPU provides service back.

And I think this whole idea of the if if everybody were trying to do the billing, it's just ludicrous kind of kind of organizationally.

But the legal representation where the city has a city attorney who represents the city, and that's another example of like these are things they have long history of successfully operating a shared services.

Yep.

And this is this is not in conflict with that at all.

And it's recognizing that internal shared services that was really a change in the last budget cycle prior to 2025.

There were some transfers from the public utilities to the general fund for portion of the city attorney.

There's been arrangements for funding uh HR business partner that was a specific need.

What we did is we took in 25 through the budget proposal, we worked with administration on defining cost allocations.

So the entire HR department is I think 19 FTEs and includes that's okay.

I just wanted to establish that you know when you talk about shared services.

There are I I know you didn't call it, you just had an example in there, but I wanted to say if someone would say, like, no, that's a different organization.

So this is meant to address the same thing.

So what this policy change, it isn't really a change, but it's just creating definition around that.

It would ask us to write a memo of understanding to say, yeah, here's the allocation methodology, we're paying on a head count ratio, and establish that through a budget process so that we're working in concert as the budget's developed and goes toward towards the city council adoption.

It defines what's the transfer for internal services for HR for IT for uh city attorney.

And so it's it's in alignment with what we did in the last cycle for those internal services, attorney HR.

There are some areas where RPU has distinct uh departments, finance and IT being two of those, and those are not largely in the city finance uh in the city allocation.

So I understand, but I'm just trying to establish that when I as I'm still trying to understand, like that I believe I'm going looking at a finance uh policy changes as opposed to restatements or clarifications, and I'm trying to understand the difference between them.

I I do appreciate it was an example in there about the public works, but I wanted to get it stated.

Another good recent example has been the solar and public buildings.

So we have a detailed memo of understanding between the city and the utility because the utility is actually funding that.

It's about 2.6 million dollars coming out of the power resources um budget.

Um, and that's you know, because we needed to go out and procure solar as well.

So we're getting access to that, and there's a whole um there's state grant money involved.

There's going to be tax money that may or may not come through at different levels on things.

Okay.

And then there's a recovery point and an asset transfer at the end of the life of that.

And that's all written in the MOU.

So that it's like, okay, five years from now or 10 years from now, somebody's not out there guessing what should or could have happened here.

It's like up front, we're documenting that and getting that.

Very good.

Thank you.

Not to belabor a point.

I just wanted to make one key policy recommendation point here that we are bringing forward.

And this impacted our shared services on the one bill.

Formerly, we had a spreadsheet.

It defined square footage of offices and people allocated towards billing functions.

And it resulted in a number that public works, the sanitary sewer and the stormwater fund pay RPU for the billing services.

And that has been a long established transfer and it's a good framework on like defensible allocation methodologies.

But what we're suggesting here is that the board ask us to write down in a memo so that we can remember five years down the road.

What is that we agreed to and have memos that define that?

Because we have found a couple places where there's a handshake agreement, where there's an agreement between two teammates that neither of which are here, and then there's a transfer.

So we're trying to create better definition around these shared services arrangements.

So they sustain through budget cycles and we can do proper budget planning around those as well.

Obligating ourselves not to make changes that might impact others without talking to them and requiring that before we commit to do a new shared service that we bring it back to the board and it comes through a normal budget process or some type of because it has cost implications there.

And the board's responsible for the budget there.

And we did that through the internal services.

We brought that through the 2526 or the 2627 budget process, and we're stepping into a pretty significant cost allocation for HR and city attorney.

And we're just trying to write down how we did that so that we can remember it 10 years down the road when names are different.

Yeah.

I think there's different ways of doing that stuff, but that's helpful.

Very good.

So the next topic here is a new one.

This one's kind of more general.

The next page is going to be more the uh a policy uh change that we're requesting.

So on the purchasing side here, this is uh talking a little bit to the emergency purchasing uh when when something happens.

I think the the winter storm phone is the one that kind of brought this to our attention earlier in the year uh at the end of February.

But um basically the the uh the mayor can declare an emergency, and there's uh there's certain like bidding things that are uh are um you don't have to adhere to during that emergency.

Um, however, there's some follow-up things here, and then we're really talking about you know, being able to go out and make purchases, which I think really fits into the next slide more talking about the wholesale side that in an in an emergency, and and again, this came back to the windstorm phone where we needed to buy nearly 500,000 worth of fuel oil.

Well, that was above the general manager's um uh you know authorization at 175.

We actually didn't really have a good mechanism for it.

Now we went ahead and purchased it and came back to the board afterwards for uh for approval.

But what we're asking for here is to say on the wholesale supply side, provided that it's under the um approved budget in total, uh, that the general manager has the authority to go and uh procure those um those resources on the wholesale side.

We essentially already have that in a number of our participation agreements with MISO, the energy authority, SEMPA, where we already have a take all, you know, uh, you know, and and pay for uh take and pay type of a contract there.

So on a lot of the large uh power supply sides for the electric side, we already have that.

The fuel oil was one that jumped out, and then we're also looking at that on the water side as well to say, okay, there's there's some electric and chemical things like that that you could have some emergency situations.

So this is a specific um, you know, uh delegation of authority that doesn't exist today that we're asking for.

And it's specific to commodities that aren't covered in one of these long-term council approved contracts.

So this would be the fuel oil clause that would, as long as it fits within total budget and we're earning a margin on the power generation, there's revenues to support it.

It's pre-authorization to buy fuel if needed.

That's the effective policy change here that would have handled the winter storm fern situation that happened back in January as well.

A point that the board may not be uh conversational on is when we do a budget proposal, we estimate what our loads are going to be.

If our loads are 5% higher than they are, we would exceed our total budget by 5%.

We don't come back through the board or council to ask for 5% more to buy more energy from SIMPA.

We consider those wholesale supply contracts as pre-approved under council's 40-year contracting authority.

And so this is just recognizing that there's certain long-term supply contracts that we will procure and we don't need the board's authorization to come back.

We take energy, we have to pay for it.

Myso, we don't come back in a month where we have a budget variance and say we need more money.

We're considering those pre-approved.

So it's just documenting the practice of that.

So it's clear from a financial authority perspective that the team has the ability to act under the board's authority and council's authority to do that.

So to keep track of that, we also keep track of then of all of the approved budget below the gross margin.

And so we're watching that in total to go, you know, we've got this many dollars to work with.

Are we staying within them?

So there's this that above, you know, the gross margin where it's wholesale power and retail revenues is managed differently than the rest of the budget.

So payment or tax.

This is the last section, but it's a it's a meaty section.

So uh the payment in lieu of tax, um the current uh policy is governed by the RPU board policy number 27 and is really based on uh the commodities being sold.

So the kilowatt hours and CCF.

So the the amount of the payment in lieu of tax is included in our um rates and is recovered through the charges for energy and for the volumetric on water.

So that's where that's actually being collected right now.

The city policy is recommending going to a six and a half percent uh retail sale, or six and a half percent of retail sales as their preferred or recommended, or actually it's adopted policy on the city side.

So obviously there's a difference between the the two.

So um in talking with the uh city administration and uh uh Brian on the finance side, they're looking at a five-year phase in period.

They're not anticipating any change in 26-27 because that's already an approved budget.

So then we'd be uh working towards that uh going further.

There's a few key things down the bottom there on the goals, obviously, is uh consistency um where all of the enterprise funds are being uh, you know, the the payment law of taxes being assessed in a similar manner.

Uh we're wanting to also work on creating uh uh better rate transparency.

It's kind of to what Scott talked about a little bit about benchmarking that rate.

We're gonna talk about that a little bit in uh in one of these future slides here, as to a lot of these um things like payment and law of tax for us are in our rates, whereas for an Excel, they're not.

So that we'll we'll get to talk a little bit about that as we go through here.

So the the key in in changing from a volume metric over to revenue is to define what is revenue and our the definition in the the city policy says retail revenue.

Um retail revenue can be affected by a number of different things, and we'll touch on this in more detail on another slide too.

But the power cost adjustment can turn out to be a pass-through expense, especially if there's wholesale activity going on where we've entered into wind contracts and we're saying for a nominal number, we're paying $50 a megawatt hour for a wind contract and we're selling into the market at 25, because until 2030, we have to buy all of our uh load requirements from SEMPA.

So we're exposed to the market.

And so there's there's some significant numbers there.

Those end up going through the power cost adjustment and end up in retail revenue.

So that's that's where we have to kind of we have to be a lot more detailed in defining what retail revenue really is.

We're suggesting what should be included there.

And then most of the standard charges, customer charge, energy, uh, water, uh, volumetric CCF, standby charges, those would all be part of retail revenue.

And there's a lot of other, as you can see, fees, whether it's contribution, aid or construction and stuff like that.

There's other sources of revenue.

Uh the shared services fee, that's you know, it's over a million dollars a year, but in public works pays for the electric utility for the services.

So we're basically saying all of those would be, you know, they wouldn't be subject to a an additional uh payment law of tax on any of those kinds of items.

So I think Tim had this in his write-up as well, but there's about four or five kind of specific questions that we'd love to get the board's thoughts and input on here.

Uh one is we will need to do a cost of service because we're going from that volume metric to now all of a sudden it's a you know percent of retail sales.

So essentially now the that percentage will be on customer charge and it'll be on demand charges as well as kilowatt hours, whereas now all of it is in kilowatt hours.

So if you're a high kilowatt hour user, you're actually paying more of the pilot than if you're a low kilowatt hour user.

So that's that's how it's structured right now and has been for a long time.

Based on 2023's cost of service that we did, I just took retail and and all the commercials.

And based on that, that it's about a 423,000 dollar cost shift from commercial to residential, just based on 2023 numbers in the cost of service.

Um that represents about $7.50 a customer per year.

So like I said, it'll be different numbers when we do the custom service here next year.

But uh just to give you an idea of just some of the things that are moving there.

If you if you look at just the kilowatt hour rate that Scott was sharing earlier, about a cent of that kilowatt hour rate is the payment low of tax.

So that's just that's uh and we'll we'll get to that one here in a little bit.

Peter, I might suggest that we just take these recommendations one at a time and get some feedback from the board.

So one of the in the implementation and five phasing of this, we're in support of aligning to the council policy of going to six and a half of total retail revenues, but on a phased approach.

So the first thing that we're recommending is we don't do so any earlier than accomplishing our cost of service studies because it has an impact on rate components.

We have a scheduled cost of service study in 2027 for water and 2028 for electric.

And so for those reasons, we would recommend no earlier implementation.

And then through those future cost of service studies, we would do the work to understand how we would have to readjust the rate components.

So if there's any objections to that, we could consider revisions to the policy.

But that's the first big one is as we respond to the city council's policy direction through future budgets.

One of those would be let's get cost of service done first, because it's an important component of that.

Um that recommendation or timing.

Would there be any?

I don't believe there's any pushback.

And I think they talked about a five-year thing.

So I have no concern with that.

I I don't believe there is.

And that was stated in the uh presentation to the council that recognized that there's kind of a delayed implementation that might be necessary here.

So that's one of the things we're putting into the policy so that we have clear direction on as we approach the next cost of service studies.

As Peter pointed out, there is kind of a rate class shift that'll happen here.

And if it's strong enough, we might recommend phasing that in over a couple years, moving a half million dollars of revenue requirement between two different rate classes for payment in lieu of tax implications uh may want to be phased in.

So we'll address that at the time.

So um there's two kind of companion ones here.

First, we're talking a little bit about the electric utility uh transition.

Um what we're looking at here, uh, Scott, I appreciate Scott's drafts this evening, you know, where he was showing over the red line how much of the time we're above that.

It represents a very small amount of our um our power sales that we're um directly going to MISO as opposed to SAMPA.

So the vast majority in the 98% range of our power costs that are going um to SAMP.

So that that's that contract you know expires in April of 2030.

So until then, our power supply under the 216, um, we have to um buy that through SAMPA.

So that that's um you know one of the elements.

And to the extent that we're bringing in um other contracts, as you see, there the capacity contracts win solar and batteries to some degree, although the batteries don't actually generate, so a little bit different there.

Uh so there will be some of these costs that compound, and we expect uh that there's market exposure there.

Uh that that number in the budget last year, I believe we had a number in the $15 million range.

Does that sound right?

Or 28 and 29.

Um, with the wind contracts getting moved back a year, we're probably only looking at 29 in the beginning of 2030 uh with that exposure.

But that there's definitely this potential of a of a rate exposure there.

Uh that we wouldn't want that to you know end up paying uh uh even a law of tax.

So a key here in this this one is going to be uh defining what uh the power cost adjustment is and what's that standard rate.

Um it kind of goes back to what Tim was saying earlier that there's there was a shift of about two cents a kilowatt hour a couple of years ago.

Um we probably need to move the standard rate to reflect that over time here.

And that that would be another move that we would have to do probably in the 28-29 time frame to reflect that and and kind of true this up at the same time.

So in impact of uh a total retail revenue policy if it includes power cost adjustment.

In January, we had a pretty strong energy cost adjustment that passed through to our customers.

Um it was about a million dollars to RPU from Simpa, roughly.

The way the current formula works, there was no additional pilot charged on that million dollars because that goes through the PCA on the bill, not the kilowatt hour rate.

This policy change would we we would have to answer the question do we want to charge pilot on that additional million dollars of wholesale fluctuations without any definition it would apply.

And so we're suggesting that we take a strong look at the power cost adjustment components and define in concert with city administration that it's intended to apply there or not.

So part of our concern is with our early investment in wind, we might have some duplication of power supply cost.

And if we make this transition and do it total revenue, we have 30 million of additional renewable expense in a year, and we apply pilot on that.

It it generates more pilot revenue, but it has more customer impact as well.

So it adds an extra six and a half percent on wholesale fluctuations that the current formula doesn't really have any impact on.

So I wanted to get some board feedback about the timing of that and the power cost adjustments um, whether it should apply or shouldn't, or if we should make a case around that.

I think that makes sense if I can just try to state it in a different way.

So what you're saying is if for that example of the power cost adjustment adds a million dollars of cost to our customers.

We don't we're not what you're proposing is that we don't see that as a revenue.

We're just saying that's an additional cost to the customers, and let's not add pilot on top of that cost to the customers.

I'm not making a case one way or other, just pointing out that if it's just defined as total retail revenue, then the additional cost of the million dollars of power cost would be a million plus six and a half percent as well.

Thank you.

The current formula only matters on how much kilowatt hours we sell to our customers.

It's really insulated from wholesale cost impacts.

And on the electric enterprise, it's two-thirds of our expenses that end up on the retail bill.

And so in an average year, it's probably we we've tracked very closely to a stable percentage of total revenue impact, but in this transition period where we might have duplication or higher costs, it would have a ratepayer impact on this as well.

So that's something that just wanted to state out loud that we there is an opportunity, I think, to define wholesale non-load serving retail revenues versus what is directly serving load as we define where those revenues lie.

Yeah.

Yeah, I think that I think that approach makes sense to not not add on to the um, you know, to not have the calculation, you know, kind of inadvertently adding on that extra six and a half percent.

If I might, I'm I'm just trying to think this through that the old, I mean, you guys made the the case that the old thing was just on like the energy cost and not the all the other ones, and so there is a policy statement there that the city's coming and says we're gonna do this on, I believe it not it's the retail revenue, not retail customers, but the retail and not transmission and not other things.

So is this is this really part of a RPU policy discussion, or is this we have to iron out the details of how pilot will work on these unique circumstances?

Because I don't feel like we're gonna solve those kind of problems with policy statements.

First, they don't need to be solved today because we're talking about a phased implementation for the future.

But before that steps in in the future, we do need to have a conversation with council administration on what the intent of the policy is.

Total retail revenue is it seems clear, but should we apply it on developer charges?

Yeah, yeah.

I mean I don't I don't want to be argumentative on this.

I'm trying to say, like, why am I as a RPU board member trying to work on this as opposed to um the the RPU administration having these discussions with finance and saying, here's what you're trying to do.

You I mean, they started this out by saying, here's what we're collecting right now from RPU.

We want to model this new one to follow that um and have growth with it.

So if it didn't work right, change the formula a little bit.

I I don't I I'm struggling why I'm sitting here because I sat through the thing on January uh or June 8th, um, and kind of brought up issues with that with their thing, but now I I feel like you guys are loading us up to say they made some mistakes and here's what we're gonna have to do to fix them.

And I don't think we can do that on like policy, this board giving you direction to do that.

I think it's gotta be you guys working that out with and I mean, if I mean I asked specifically, where'd the six and a half percent come from?

It came from looking at what the pilot payment is right now from RPU electric because that's 70% of what the city collects on it.

So yeah, you're making fair points, Patrick, and I'm not trying to be argumentative as well.

I think there's a few policy direction items that we are seeking from the board.

One is support on the phasing and timing because the board's responsible for cost of service budget recommendations, trying to get clear policy directions on the on what we're recommending to administration on phasing in the approach, just to make sure we're on the same page there.

There's probably a lot more detail in here than is absolutely necessary.

But we wanted, as we had the discussion with the ad hoc group that was reviewing this policy.

There's a couple key policy things that wanted to be brought to the full board's consideration here.

Not trying to belabor this one.

The the definition of retail revenues is one really that I would agree we need to work out with administration.

The policy level statements here are really stating what we believe the policies should be.

They could be removed from the policy here and be left for our work between administration on how this would be uh applied.

So it if that's the direction from the the board at I'm just one uh we're trying to just see some definition or alignment that it's not intending to go after other other not go after it's not intended to apply towards cell tower lease revenue that reduces the cost to our water customers, but I don't think it's the policy intent to charge pilot on cell tower lease revenue.

That's not what we would consider retail revenue.

So we're trying to make some policy level interpretation of what retail revenue means and get alignment from the board on it.

So that I don't think we're trying to help we're not kind of looking for a board correction here on that because we don't want to go make representations that you don't agree with either as well.

I mean, I should let other people speak.

I mean, I mean, I think this idea, this is new in there, and maybe you guys being closer to it are finding flaws, and we should work that out with with the uh city financing.

The I'll say it again that you know, the whole thing of just being six and a half percent, uh, that really was based on looking at what RPU electric was paying right now, even with the current formula only based on electric use, it was paying those sort of rates.

So this would be aligning it to be very similar in 27, 20, you know, when when it's gets in, but over time things will change.

It'll be, you know, the different usage will change.

I imagine there's flaws with just charging on power and not on all the other serv the services we provide.

Any system's gonna have someone's gonna be able to come at it and say, this is unfair to me because um, so I think we need to work those out.

But I have difficult time thinking the RPU policies should work that out because I feel I feel that's a thing between the two administrations.

I would agree with you generally.

And the intent of writing this much detail and pilot is not directed towards administration particularly.

It's directed at the board five years from now when we go to implement and rescind the board policy to outline here's how we need to think about the implementation of pilot and having that in a place that sustains it's gonna be a different board in five years.

And so we're trying to collect the policy level direction here on how to implement that and the timing because we have to go through cost of service.

Well, we're recommending going through cost of service and some other elements here as well.

Right.

So um kind of trying to do what you were just saying.

That's the history right there.

So the um the electric one had a history of about 5.96% uh in 2024.

We went back and made an adjustment to the um the uh consumer price index uh where we hadn't done an increase in years when there was zero rate increase.

And we went back about 10 years and restated that back in 2024.

That's where you see the bump up to 6.3 there.

And and again, because yeah, volumes are relatively and this this small growth, but it's it's like one percent.

Uh you you see that kind of constant there, and you see similar things on the on the water side there.

The difference here is that water is going to be looking at to get to that six and a half percent is a three percent rate increase, basically.

So what I hope the board will see in that is the current formula is a pretty stable proxy for percent of total revenue.

So if we don't change for five years, we've effectively aligned towards the policy direction because it it works like a percent of total revenue generally, and it's pretty stable there.

So this is just looking at if we were to make the adjustment on in 2028 to get to six and a half.

So this doesn't take into account phasing in or anything like that.

And uh gonna thank Patrick for pointing out the original copy that I put together, had 2026 at uh six percent, which was before we made all the adjustments at the end.

So I appreciate your uh attention to detail on that.

Tim and I are both like how we both miss that.

So I was just gonna comment on I would think that it would be you're gonna be like I like you know, Patrick's idea of kind of working with admin city admin, but I would also think that for 29 and 30 when we're there's sort of this duplicate thing that that would be a good discussion to say, okay, how do we deal with these years that are yeah, that's what this is trying to point out.

That this is assuming that we would put the pilot formula, the new formula in place in 28.

You can see there's very little difference in 28 on the electric fund because we're only off by 0.2%.

But then the pro-cyclical or duplication of wholesale impact show up in 29 and 30.

And this would be the effect of what our rate payers would feel on the bottom line, is it would feel kind of like an additional half a percent if it's done on a total retail revenue basis.

So it's just trying to show forward if you make the switch what its future impact is there as well.

So we have uh similar, and actually the the last slide I have talks about kind of what we'd like to be the go for with.

So to some of the questions you were just asking on timing of this.

Um the water has a similar transition um with doing the comprehensive, uh, the long-term comprehensive plan right now.

We're not expecting to see the impacts of that until probably 2028 and 2029 from a right standpoint.

So there's definitely some you know pressures there.

Um we have a similar kind of um item there.

And the next one we're gonna touch on the last one there about water transmission, that's potentially internally, but it could also be if we ended up uh serving more regional water supply, that'd be uh supplying water outside the city as well that could uh impact how pilot is applied.

So that this is this one's a lot more dramatic because we're going from that three and a half percent that we pointed out earlier up to a six and a half percent in 2028.

Again, I don't anticipate we would do this.

I anticipate that this would be phased in over time and maybe going up one percentage a year in 28, 2930.

And I really look at the rate of collection and the methodology for collection as two separate things.

So, you know, we could go in and uh take a board action in policy 27 to change the mill rate to start stepping into the um into the the overall rate in as we work towards 2030 and then do the rate conversion um to uh to a percentage of sales, you know, after we get through all these other uh pieces.

So I think there's a way to get there with that and and meet everybody's needs.

Uh the the next I I think I don't think we had a question on the last one, right?

But so the next one here is talking about the bill presentment and on the on the bill presentment side, uh what we're recommending is that we would have so we actually do billing for four different enterprise funds.

And what we would do is you know, we'd come down to uh here's the subtotal for the the retail revenues for the you know, whatever you know, sanitary store or water or electric, and then we'd apply the six and a half percent and come up with the number, and then it would roll to the uh one line on the on the summary of the the bill on the front.

To do that, we'd effectively have to go up into the kilowatt hour rate of every single rate and peel that out, which we'd do through the cost of service process and take it out of there so that that overall headline rate then that Scott was sharing earlier, that would go down by that one cent.

And then, you know, the number would show up and it would have no, it's just shifting to where it shows up on the bill and how it's reported as uh as revenue basically.

Um but it also makes that's kind of the issue with our bond rating agencies and when we get compared in these industry standards, we have all these things in that rate.

And a lot of our people that we're being benchmarked against do not have them in that rate.

So this is um this is this is one that I do have concern in Tim.

I've spoken to Tim up for.

So generally going through this, I mean, I think uh the the idea of establishing these financial policies is a good way, and these lead to these discussions that we need to have about this kind of stuff.

Um, some of the staff were at the city one back in June 8th and and there were some things that were brought up there that I viewed as like why don't you just work within the city and see if you can get these things worked out and there's things like about the shared services.

And I brought them up there, and I try I think I don't know what came back from work from, but I but I feel like I'm seeing some of that same stuff here that these policies are being established to help this management team have a little bit of an upper hand on the administration.

And I just feel like we're not working well enough as a city yet.

I I mean, I respect the city charter where it defines RPU as a separate enterprise from the city, and that is important, and there's really good regulatory and other reasons for that.

But at the end of the day, we are one enter, one organization, the city of Rochester, that does these different services, but the customers at the other end, the ratepayers and the levy people are the same people.

And I want us to work harder at sort of treating them as like what's best for them as opposed to what's best for RPU or what's best for this.

Yeah, on this page 74, we're explaining why we have to separate pilot on our utility bill, but I don't see any strong logic or reason for calling out one type of business expense and not every other type of expense we have and trying to say this is what we spend on fleet and this is what we spend on something else.

But we somehow really, really want to tell them we're paying this as a tax to the city.

Um, where I've, if I get an uh uh XL bill, it doesn't say here's my property tax that I had to pay and you need to pay a percent of it.

And they just don't do that.

Um, I I'm not gonna vote to approve a policy that tells RPU management to deconstruct pilot fees down to the monthly bill and then communicate that to the residents uh and then collect that.

And I, you know, what would be the the purpose of doing that?

Telling the board that that uh the motivation is transparency just doesn't feel accurate to me right now.

And I'm again, I'm I've suffered this one.

I've struggled with these discussions on the side.

I still think we're I feel like I'm watching a little bit of a battle here, and I think we just need to do better across the two to two groups.

And um, so I I won't be supporting something like this that ends up deconstructing pilot down and trying to communicate it as if we were Minnesota Energy and we're not part of the city, and they're asking us for these fees, which they can do as a franchise fee.

And now for the city to be doing that within the city, I I just don't want to support it.

I don't want to come down.

I mean, I've got the side on the city, and then I'm in the RPU.

I'm not trying to say this one's right and this one's wrong.

I'm just saying, let's do better.

I could not support this more.

Um, I think that this is uh speaks to transparency um and clarity in billing.

And in a world where already our rates are higher than our neighbors because of the growth we have, because of the important transition we're doing.

Um, I think also the chance to lower the real rate when we look at our comparisons will help us in our discussions on borrowing.

And um I I happily I think this is well thought out.

I think it's thoughtful.

Um, and I could not support this more.

And as Tim knows, I I am struggling with this as well because I I feel like it's sending a message that we're not working together at the city, and that's where I'm struggling.

If there's some really good reasons, again, have the discussion at the admin level and sort out, you know, okay, here's why we want to do it.

It's going to save us money, whatever it all is, right?

I again, it just it doesn't feel good.

And as a as a citizen of Rochester, I think I want to see that the two entities work together.

Why would it not feel what are reasons it would not feel good?

Because it it see it it exists.

It was approved and deemed proper by the city to set the pilot rate.

The disclosure of it is what we're talking about.

We're not, you know, we agree with the rate.

We would love the phase in, but I don't understand how clarity in billing setting that that line item is somehow in conflict with the city.

I think it it our highest our duty is to our ratepayers and our citizens.

And I think clarity in billing would be a virtuous thing that we would want a clear bill that accurately shows everything, doesn't co-mingle items.

And I just I think that's a reasonable and goal to aspire to, uh at least the way I see it.

I'm I'm curious.

We're we're not the only public utility in the area.

Or is there any examples from other, you know, Oatana public utilities, other utilities, how they approach this?

I think there are a few examples that I will name uh Oatana and Austin as kind of the two more near large municipal utilities, do not display it separately on the bill.

They have uh either an in-kind transfer that equates to somewhere in the range of two and a half to four percent.

They do it on a different basis, a different methodology.

Oatana doesn't charge the city for electricity and the commodities they purchase up to four percent.

And it's effectively a two and a half percent value to the city.

I believe Austin's is a defined percentage of total revenue.

I do not think it's displayed on the bill.

If you look at a lake city, just to our north, another SIMPA member, it's displayed as a line item on the bill.

So it everyone does it a different way.

This is a change from this this recommendation is one that I don't bring lightly.

I recognize that it's controversial.

And uh this one is not uh directed at any policy change of administration.

I believe there's a few strategic reasons for the board to consider this.

And if you just give me a moment to outline those, and I recognize it's controversial.

And one of the reasons that I wanted to bring it to this level because there wasn't clarity at the ad hoc group level as well.

There was kind of a uh varying perspectives.

First one is just simplicity.

As it is today, the way we administer pilot only affects one billing rate component.

And going to total revenue means we, as staff, and we can do this, go into the billing system, and we have to change about a hundred different rate components and apply the percentages correctly.

So just ease of future administration.

It's easier to apply it akin to a sales tax.

One line item, it applies to all rate components.

It's simple, it's easier, but that's not necessarily the only reason to make it a line item.

We do hard things because they're required sometimes, and that in of itself isn't a compelling reason in it by itself.

The rate competitiveness one, I think is a compelling reason.

If you look at our rates up against people's energy, Excel energy, and that's who we are compared to when you look at bond rating agencies and others, they're looking at our average rate compared to others.

We're we are including our pilot city transfer as a part of our headline rate, and others aren't.

So it makes our rates appear six and a half percent higher in comparison.

And our own uh financial advisor that presented earlier showed that rate competitiveness over time is a uh could have a factor in our bond rating and our financial stability.

So the ability to implement uh a policy change like this and pull pilot to the line item would effectively lower our rates.

That doesn't change to the customer's perspective.

They still pay the same, but moving it out of the headline rate makes our rate more comparable and competitive in comparison, even though um the line item at the bottom of the bill doesn't change how bond rating agencies look at us.

It it does have a positive impact.

There are a few people's energy customers that are right next door inside the city limits to RPU customers, and the franchise fee, which is exactly our pilot rate, is shown on their bill at the bottom.

So two houses next to each other, one looks different than the other.

So there are some comparison reasons there.

Um and then the other strategic region isn't so much for now, but it's for the future.

As we approach the conversation about water supply plan, how we apply pilot inside the jurisdiction of the city and outside of the jurisdiction of the city, I think matters.

There's city code that uh doesn't allow any cheaper rate to be charged outside the city than inside the city for water.

Um, and I think there's a valid question to be asked if we're pursuing a regional water solution towards our water supply plan.

A strategic reason is to consider the jurisdictional treatment of do customers that we serve outside the city should they pay the same pilot rate as customers inside the city.

Um, and so that's for those reasons.

I think it I'm not gonna die on the sword on this recommendation one way or the other, but I wanted to at least pose it to the board to get perspectives on there as well.

And this isn't focus at administration.

This is more of a policy recommendation that I'm bringing forward to have this exact conversation here.

I get that there's discomfort, Patrick.

You're you're expressing strong discomfort towards this one as well.

It's a it's a big policy diversion from the past.

Um I think there's some varied perspectives on it as well.

So I'm I'm not hearing a consensus right now on this specific element on billing treatment.

Willing to retract re uh retract that as part of the policy recommendation here, but I do think it is a choice of the the board and a policy level direction of how the bill should be presented here as well.

So just wanted to make that case.

It's not I I wouldn't agree with the this is directed at administration or not.

This is really a policy recommendation that I brought forward because I think there's a few compelling reasons to at least consider changing the billing treatment.

This is the last slide.

So uh this one is really just kind of doing an overview of um what what we're um suggesting would be uh move forward here.

Uh we're not expecting any change in 26, 27 based on the budget uh that are already approved.

Uh working with the city on a five year transition.

Um what I'm anticipating is in the uh water side in particular that's starting 28, we would be adding one percent a year, 28, 29, 30 to get up to that six and a half, which is really the you know, waiting until after some of these sample transitions, the the water um comprehensive study and the transitions in that area.

We can do if we know we're going there in 2030 basically to be 2031, uh is when we would show up in January 2031 is when it show up on a on a bill differently.

Um the or it would change the rights and impact everything differently.

Um then that would be you know, it would allow us to get through the cost of service for both utilities, uh, the electric and the water ones.

It would allow us to do a lot of the there'll be system configuration changes that we will have to uh make to uh to calculate this differently.

So that that there will be system things.

We want to get through the ERP and some of these other projects first before we bite off another good size project like that.

We also do have a system upgrade in in Kyanta that we need to do.

Uh again, that one, if we weren't doing an ERP, we would have been doing it already.

So that one's getting pushed off behind uh this project currently as well.

So that that's kind of the quick snapshot of what we're um proposing would be you know uh a move forward uh process.

Yeah.

A lot of questions and comments.

Do you mind hitting your mic?

We've had a lot of questions and comments.

Any other further questions and comments on the presentation?

Let me summarize just so we have clarity and consensus from the board.

I'm hearing that there's not consensus on specifically the billing treatment of pilot as a separate line item with that removed.

I'm hearing that uh some acknowledgement of consensus that the policies could be ready to move forward.

I don't want to speak for everyone here, but it would be our intent to make any revisions that the board sees fit.

Um if the ad hoc members might just speak to the level of review from their perspective if there's support as well with that one change, we would want to um bring something forward at some point in the future, if not the next meeting.

As one of the members, I would be supportive.

I think some of the things that Patrick mentioned about you know working out more of the details with admin, but otherwise, yeah.

And I appreciate uh Brent's input too, with the idea of like benchmarking and um and even the numbers you mentioned, the four and different percents, because uh this really was the the way this thing started out was looking at what RPU is and trying to make it consistent.

Now, that policy decision at the city level, why it should be consistent across enterprises could be challenged.

Why would it have to be the same across them?

But there's differing things.

Unfortunately, pilot from my perspective has always been set up to um replace the property tax that would happen with an investor-owned utility and not the income tax.

But unfortunately, everybody works it out on an income tax basis, which makes it uh it doesn't map as well as it should.

Yeah, okay.

I have a question that is uh so the percentage didn't change, but there was a change in what that's applied to in that it yeah, the the formula basis is recommended to be changed by the city council and that policy change.

And we're aligning our recommendation to this board to that to phase in a pilot uh formula change over the next five years with these considerations in there, except for billing treatment.

I think that's one area that needs further discussion.

We can park that for a future conversation because it wouldn't have to be done until that implementation is done down the road anyway.

So we can leave that out as clear policy direction of where to go and leave it for us to work with administration through future budget cycles of when is the right timing.

I don't think it's 26, 27.

I think everyone's aligned on that.

I don't think it's 28 or 29 because there's some big things happening in that time frame with debt issuance.

There's a good reason to avoid any changes ahead of that.

I think getting to the tail end of the uh transition on the power supply is also so compelling.

So within five years, aligning to it, knowing that we have to make some rate adjustments, those would be done through future budget conversations.

We're just trying to get policy direction here.

I think I received what is needed to make any revisions here on the pilot section specifically.

And I just want to reiterate it is our recommendation to align to the council policy um direction that's there.

I do think it's the council reserve right to make those policy directions, and it's the board's um uh in the budget recommendation to follow through those and and take that policy direction from the city council as well.

So with that change, I'm hearing consensus on the billing treatment piece of that.

Yes.

Yep.

Well, I am flexed that council and city staff would oppose that specific line item, which I think is transparent and enhances transparency of billing.

Um defer to uh the general manager and um whichever you come forward and recommend with.

But overall, I think this is exceptionally well done.

I think it is thoughtful, and I think it is just an appropriate to formalize, it's more professional to formalize reserve and define the clear rights this board has under charter.

And so I think this is a wonderful document thoughtfully put together, and I'm so grateful to all the time and energy that went into compiling it.

So um nice job to everyone who carefully wrote it out and and put it together.

Thank you.

I appreciate everyone's feedback.

Truly do.

Thank you.

Okay, now we move to the general manager's report, item number eight.

Uh, and I will turn this over to General Manager McCullough.

I think I'll handle this on an exception only basis if there's any questions for my report from the board.

If I could just take a moment, uh we're needing to take steps on the next policy review after financial policies.

We still have worker safety out that we will bring back within the next two months to the ad hoc group.

The next one that we would like to talk about or I'm recommending is board organization.

I have a couple policy proposals looking for a third quarter review.

And so I would uh ask for maybe an ad hoc assignment to start working with an ad hoc group on board organization.

Do we have any volunteers for the Q3 next policy?

I'll volunteer.

Oh, thank you, Kelsey.

And and I'm always willing, but I've been on a lot.

So if somebody else wants to say I can I can volunteer and uh thank you, sir.

Yep, I've been on too many as well.

So give me a give you a question.

Well, I'll set this one out.

So perfect.

Uh Kelsey and Brett will be on that, and good luck.

So moving next to division reports and and uh metrics.

Are there any questions or discussions from the board on the division reports and metrics for June 2026?

Hearing none, uh, we move to item 10.

Is there any other business to come before the board at this time?

Just indicate some new news that came through today.

We received favorable um generator interconnection uh treatment from MISO.

Uh I did touch on this on my GM report, but there may be a reason to call a special meeting between now and our next meeting.

So we have an interconnection agreement that we need to finalize, uh, have a legal review, has to be reviewed um by FERC ultimately, but there's a future board decision needed that might be timely.

I just wanted to indicate there might be a reason to call a special meeting in the middle of July to hit a MISO deadline.

We're trying to get clarity around that.

If we don't need a special meeting, we'll just bring it forward in July.

But to summarize, we had budgeted 20 million dollars for potential interconnection costs for Mount Simon station.

We believe there's going to be zero dollars in that category of outside system upgrades.

So it's a very positive point of news.

Overall, Mount Simon station is coming in another 20 million below that what we had anticipated, less bond issuance.

So it's good news item.

And I think if we need to do it on an accelerated timeline, there's a good reason to call a special meeting to hit those timelines.

So if needed, we're thinking uh the seventh or the second or third Tuesday, the 7th of July actually fits the timeline that there's a July 8th kind of approval.

If we don't need it, we'll just do it in July if we can delay that a little bit.

So we might be calling a special meeting for July 7th, just to be a very quick meeting for the approval of that and ask for treatment of the board.

Thank you.

Negative 20 million on every meeting would be awesome.

Um other business.

Uh hearing none, I'll entertain a motion and a second to adjourn the regular meeting and convene to close session pursuant to Minnesota State Statute Section 13D.05 subdivision 3C3 to consider offers for the purchase or sale of real property and Minnesota statute section 13d.05 subsection 3b to discuss a potential litigation matter related to a worker's compensation claim.

Um do I have a motion and a second?

For we motion, I will recuse myself from 11A, but participate in 11B.

Thank you for that.

Um do we have a motion and a second to adjourn this meeting and move into closed session?

I'll move to that approvaling that motion.

All second.

Thank you.

Uh moved and seconded.

All in favor say aye.

Aye.

Aye.

Any opposed?

This meeting of the RPU Board of Directors is adjourned, and we'll move to closed session.