>> Okay, it's nine o'clock, and we do have a quorum.
So I'll call to order the Public Utilities Board for the City of Denton on Monday, November 18th, 2024.
We do have someone that wishes to speak this morning, Mr. Lee, and he's speaking in opposition, of course, scientific.
So Mr. Lee, you have the floor.
>> Yes, how are you doing?
Yes, my name is Charles Lee.
I live on, I live on North Elm Street, and I just want to say that me personally, myself,
I've been here for three years, and I'm actually using less energy than I ever had, and my bills keep skyrocketing.
And I have some questions, because, and a lot of people in the town have the same feelings as me.
But my thing is about this company, what is it, Core Scientific.
Now, I'm not personally against cryptocurrency, or data mining, or anything like that.
I have nothing against the industry at all.
I just have some questions.
I don't see how integrating a residential electric company,
and with this company that uses a tremendous amount of power, they use a lot of power, power of the whole cities, and stuff like that.
And I'm just very concerned about how this would benefit residential customers.
I think, really do think they should have their own infrastructure separate from residential customers,
because I just don't, I would like somebody to explain to me how this benefits residential customers in any type of way,
especially when they're getting all kind of tax breaks and incentives and things of that nature.
And it's basically just a question, and I would like somebody to explain this to me.
>> Thank you very much, and have a nice day.
>> Thank you.
All right, the next is the consent agenda.
And I know that Lee wanted to pull a few items.
That was an A, E, and F.
Does any other board members wish to pull any items?
All right, seeing none.
Do we have a motion to approve B, C, D, G, H, and I?
>> Yeah, move.
>> So moved.
>> Okay, Aaron moved, Devin seconds.
All in favor say aye.
>> Aye. >> Aye.
Okay, next item is item A.
>> Good morning, Randy Klingle, Treasury Manager.
And if you would like to pose your question, I will do my best to answer.
>> I just wanted to have you refresh our memories about the uses of this $300 million bonding.
>> Yes sir, I'd be happy to if you'll let me set the stage a little bit about the commercial paper program.
>> Please do. >> The city has two programs.
One for the voter geo approved programs for those 2019-2023 bond sales, that was the latest one.
And then the utility commercial paper program, it supports the utility system's capital projects only.
And so what that does, our intent when we created this in 2021 is to use it for contract appropriation authority.
So when we go into contracts, we must have all the funding sources identified and
the backing of this program helps us get to sign some of those contracts, even if we don't have all the cash in hand.
So the $300 million in very general banking terms is a line of credit.
We don't have the cash, it sits out there available for us, and we can get it any time.
Thankfully we had it in place during Storm Uri, because we did issue those notes that year.
Never really our intent, like I said, we only wanted contract appropriation, but we sure were blessed that we had it.
We were able to issue those funds, $140 million, and get those in place within 24 hours.
And what you have in front of you today is the actual refunding ordinance that comes in annually.
And so we have to re-up our authority.
If we do decide to issue notes, they have to be returned and paid back in full in 270 days.
So the refunding ordinance allows us to issue long-term debt for those and go put them in a bond sale for 20 or 30 years.
That is what this item here is for.
Okay, so this covers capital projects, which we're in theory mostly aware of what's coming through the design monies that we've already appropriated.
And this is just the rolling line of credit.
Correct, giving us the authority that if we do issue notes and grab the cash.
Just as we did during the wonderful event two years ago.
Yes.
Okay, well I just wanted to be reminded of what had happened with them, you know, I saw that much money and I went.
It's a large number.
I know it's for something, but what's it for?
Yes, sir.
Well, thank you. That's all I had.
All right, do we have a motion then to approve item A?
So moved.
In a second?
Second.
Second, all in favor say aye.
Aye.
Carries item E.
Good morning, Cody Tenorio, DME Engineering here for item E.
Yes, I just wanted to get a few more details about what had caused the increase in that budget.
Yes, sir, so only I asked there's three, four, five items that all had values next to them.
The riser pole termination that was caused to a manufacturing issue with the poles.
Since beta had to install things, beta's the contractor there, since beta had to install things on the pole and they were delayed,
it required a change order for lost time and production for the exploratory underground work.
Let's go back to the pole, you said they had to do some field modifications to the pole, so it wasn't manufactured incorrectly.
Yes, sir.
So do those costs go back to the manufacturer?
We are working with legal to recoup those costs, yes, sir.
But we do not yet know what share they're going to participate in?
I do not believe so.
OK, so you're asking essentially to have this money expended, whereas some of it may come back as a refund from the manufacturer?
Yes, sir.
OK, so can we look forward to a deductive change order in the future?
Yeah, I believe so, it will.
That's a possibility, not a probability?
Hopefully, probability.
OK, thank you.
Do you want me to go through the other ones too, sir?
Yeah, carry on.
Yes, sir.
CT installation on the riser poles and the removal of the 15 kV underground feeders.
Both of those items, it was just more efficient to have beta perform the work.
It was going to be work that needed to be done regardless, so those aren't a new cost.
They were going to happen anyway.
OK, well, you just said they were going to have to be done regardless.
Right.
So why weren't they in the costs?
We didn't, with the changes in schedule for the project and everything that's happened, it was just more efficient since beta was already on site.
At the beginning of the project, we didn't see the delays and everything, so having them there already decreased wait time.
So it decreased the wait time, but it increased their scope?
Yes, sir.
So were these funds going to originally come from somewhere else?
Yes, sir.
I mean, they were all going to be part of the Hickory project, the Hickory costs.
Would it have been a different contractor?
It would have been a different contractor, most likely, yes, ma'am.
OK, so this is covering the work another contractor was supposed to do, but they did not do.
We had plans to do that, but we didn't get around to getting another contractor to doing it since beta was already there.
OK.
And it was decided that they could do it.
I'm sorry, carry on.
Convenience store service, all the overhead facilities in that area are converted to underground, so that customer had to be reconnected.
That service is a three-phase service that wasn't in beta's contract or in their scope of work.
I'm sorry.
So we asked them to do it, which created--
Well, it was known that the client was going to have to be reconnected, yes?
Yes, sir.
OK.
Yeah.
And would that have been a different contractor again?
Possibly.
OK.
Most likely.
And the same for the next item, or is that the customer, the convenience store?
That was the convenience store, yes, sir.
Well, the reason I asked for it is I looked at all this, and I was like, well, does all this really belong to this contract?
And apparently, it did not.
Some of it belonged to other contracts who were not executed or because of delays.
Yes, it just wasn't in their scope.
It wasn't in beta's scope, yes, sir.
Well, it's over a million bucks.
It's on a $43 million project, I suppose, percentage-wise.
That's not a lot, but it caught my eye, and it might catch the council's eye.
So I think you should be prepared to answer these questions.
Yes, sir.
That's all I have.
Thank you.
All right, do we have a motion to approve item E?
It's all moved.
And a second?
Mr. Neuquist, second?
All in favor, say aye.
Aye.
Opposed?
Carries.
Thank you.
And the last item is item F.
Good morning, Madam Chair, PB members, Bill Sheppard, DME.
And I am here to address member Ryback's question on the invoice cloud, item F. All right,
so invoice cloud is our provider that allows customers to do self-service
and online payment transactions.
And when we issued that RFP back in '21, we had to estimate a certain uptake
of our customers to utilize those services.
And we estimated a little low, obviously,
because we have more customers using that than ever before.
Our credit card payment has increased from 44% to 64% of payments are now credit card payments.
The amount of transactions per year have gone up 175,000 transactions per year.
So that's really the core.
So the driver of this cost increase is customers using the system.
Yes, sir.
More than you had anticipated.
Correct.
It's not that we had a time of material service contract with the company to support this,
and we had this overrun of the use of their service.
Right. And we're going to be going back out to RFP here very soon.
And we're hoping to use the volumes that we are seeing now
to even leverage a lower cost in the future.
Okay. Well, I kind of misunderstood that from the information sheet, so thank you.
You're welcome.
Thank you.
All right.
Do we have a motion to approve item F, Mr. Ryback?
So moved.
And a second?
Second.
Devin seconds. All in favor say aye. Aye. Carries. Thank you.
Okay. The next item is approval of the October 28th, 2024 minutes.
Were there any changes or corrections?
Seeing none. Do we have a motion to approve?
Mr. Newquist moved approval. And a second?
Mr. Tape. Mr. Ryback.
All in favor say aye. Aye. Carries.
I think what we'll do is we'll skip down to management reports and then we'll go into closed session.
So, go ahead.
>> Yes ma'am, Madam Chair, members of the PUB, I have a few items for you today.
The first item that we provided to you is the PUB roster, right?
That way you know one who appointed you with seat you're in, just as a reminder,
the seat you're in corresponds with the council seat, whomever might be filling that.
And so we just wanted to provide that to you for informational purposes.
And then we've also have a follow up memo from the water department on a question that was brought up at the last meeting.
So I think Steven's here and his folks are here in case someone has any questions about that particular memo.
>> I'm sorry to say, I think you all misunderstood my question.
>> Okay. >> Which is fine.
I was wanting to know more about the problem with the filters and
there was a discussion from the director about a change in the maintenance procedure.
And that is what I had wanted to ask about or get more information on.
>> Steven Gay, General Manager, Water Utilities.
>> So we haven't done any major maintenance on the existing filters at Lake Ray Roberts since they were installed.
So we have two projects going on right now, one's called a capacity improvement.
So part of that, we're actually replacing the filter media and we're changing it out from granular.
I think we're doing, we're at anthracite is what we're using right now, anthracite and sand.
And we're changing it out to granular activated carbon, which is a more effective filter media.
And then moving forward, we're implementing a filter surveillance program.
We'll be checking the filter, the quality of the filters.
Periodically, we'll annually, we'll be pulling samples and evaluating that.
Historically, what you'll do is you'll see some type of rotation on your filter media throughout the years.
In this case, we haven't done anything in 20 years.
>> Well, that's sad.
>> Yes, sir.
>> Well, I got the impression from your comments that you were going to get on to some kind of regular rotating.
>> Yeah. >> Maintenance program with that?
>> Yes, and then the filter media project or program will dictate that.
And so we'll be able to gauge the health and the efficiency of the filters.
And then based off of that data, we'll then either add media to it or change it out on a regular basis.
>> So do you anticipate- >> It'll be on a rotation.
>> Okay, so do you anticipate over some period of time that you'll be changing out all of the filter media?
>> Yes, we're going to start with this, the rerate project that we're doing right now, the capacity improvements.
We're going to be starting out with fresh media throughout the whole plan.
So all of our filters will be changed.
And then beginning with the new media, we'll start the filter surveillance program.
So in the future, we do foresee some type of rotation where we'll say, okay,
we probably need to change the media out on one filter a year for the next five years.
>> So how many filters are there to change the media again?
>> You'll have to get that exact number for you.
>> It's gotta be more than- >> Well, over Lake Louisville, we have 16 filters.
>> That makes more sense.
>> Yeah, Ray Roberts is a little bit, it's different.
I want to say it's around eight to ten, but don't quote me on that, I'll get back to you on that.
>> But just our general idea that there would be basins of filtration.
>> Multiple, yeah, because what we have to do is we have to backwash them.
So we have to clean them periodically.
And so we'll take them out of service while we're cleaning them.
We still need to treat water.
>> Right, so speaking of being out of service, we had this problem this past summer,
where we had the one, then we went to the next one, and we were down to one day a week.
And I know when it went on, but I was never notified when it went off.
So how long was that restriction in place?
>> That, I had to give you the exact date, but we did post it on our website.
And we sent out notification to the community.
So I apologize that you didn't receive anything.
>> If you notified our community, they didn't notify us, at least that I was aware of.
>> Yeah.
>> I knew, but I think maybe I saw it on the website.
>> Maybe, yeah.
But we got those, I have to look for the date, but we can follow up with you on the dates
of when it was restored.
>> That would be great, I'd appreciate it.
Thank you.
>> Thank you.
>> So the only other item that we have for you is the, I just want to point out to you
that we have one meeting left this year, which will be on December 9th.
And then the meeting after that won't be until January 13th, so part of the process that we established with the chair
was if we have certain items that are either going to bypass the PUB or there's a back to back kind of approval process.
We have some items today that will be considered by the council tomorrow.
We coordinate with the chair to make sure she's comfortable with that in her absence as the vice chair.
So there will be some items on the 9th that will be coming back to you retroactively through the management report.
And certainly we'll provide you all the backup and if there's questions we'll be answering those for you.
Same thing likely on the 13th.
I just want to give you the heads up on that particular process.
So with that, happy to answer any questions that you may have.
>> Questions?
All right, then I guess it's time to go into closed session.
So the public utilities board will now at 917 AM convene into a closed meeting to deliberate the closed meeting item.
Set forth on the agenda, which includes the following, PUB 24243,
deliberations regarding certain public power utilities competitive matters.
Under Texas government code section 551.086,
consultation with attorneys under Texas government code 551.071.
>> Okay, the Public Utility Board has now at 953 AM reconvened from closed session and no official action was taken.
He's back in the room, okay.
All right, we're going to call all items B, C, D, and E for the presentation, and then we'll vote on them individually.
So go ahead, Tony.
>> Hi, Chair. [INAUDIBLE]
It involves a number of agreements that the chair has just read, and we're happy to answer questions as we go, or if you want to wait till the end.
So just as a reminder, this is the existing facility that we have.
And based on amendment three to the PPA, where CORE has had proposed and
was approved to build out the north side, which we're calling phase three,
as a high performance computing facility, no longer crypto mining within this facility.
If you remember when CORE went into bankruptcy, this particular phase had not been developed.
There are some shell buildings out there, but that was, again, already approved to conversion to HPC.
And then the south side, which is really two phases, phase one and phase two, this continues to operate as crypto mining.
And so these phases, phase two, is still partially being developed,
but would anticipate that they will continue to develop that, barring some approval in today's agreements.
So what is being proposed?
So what CORE is actually proposing is to move away completely from crypto mining on this site.
I just want to be clear that by moving away from crypto mining,
we're converting what is a variable load that is very price sensitive to a firm load.
And so being a firm load, that will be a constant load that would stay.
We'll talk a little bit about what the impacts are from a load shed standpoint,
in the event that ERCOT called for power reductions or cuts in our area.
So phases one and phases two, which again are currently crypto mining, would be shut down and converted.
They would anticipate that that would take about a nine to 10 month time frame,
where no energy would be flowing through that facility or minimal energy,
but that they would shut that down to convert that all to high performance computing, which is artificial intelligence.
The north side, as I already mentioned, was already approved for HPC conversion and they're actually beginning some work in that area.
Additionally, they do plan to put in an additional phase four that would also be HPC.
And so then all this entire facility would be all high power computing, high performance computing, excuse me, no longer crypto mining.
They would also build an office complex.
They would anticipate 130 to 300 full time employees on this site to operate this site.
In addition, there's some additional land that they also are proposing to lease from the city.
We'll talk a little bit about that.
That lease is predominantly DME owned or what we call DEC facility land that was purchased when the DEC was constructed.
There's an additional 6.7 acres of solid waste property that will also be incorporated into this property, into this facility.
And we'll talk a little bit about that here shortly.
Phase four will only be constructed once DME goes through a process with RCOP to build some transmission system improvements and upgrades.
We did find that once this facility comes online, there will be some system overloads that need to be corrected.
And so core understands that that was probably going to take us two to three years to go through that process and construct them.
This phase four will not come online until all of that is completed.
So that's the proposal, what the future state would be.
It's going to take a couple of years to a few years to get there.
But certainly, core is ready to start mobilizing some people to get that done.
There's also some temporary construction easements in this particular development where there are going to be staging equipment, personnel, that sort of thing.
It's a short term, 48 month period that they anticipate that we need that particular property.
So of that, you mentioned they're expanding the lease.
Is it all of the hashed area?
It is, yeah.
So this entire hashed area all the way around the DEC and back around will all be one perimeter.
It will be all fenced off with security around that particular site.
Certainly, as part of the process, we'll have access to our assets that are there, both the DEC, two substations or two substation sites.
Encore also has a facility there as well.
So there'll be ample ability for them to service those locations.
But this site will all be contiguous and controlled by core scientific.
And then there will be a fair amount of extra land there that is not currently planned for development, that they will lease.
Yeah, so there's some temporary easement areas.
I think it's about 12 acres that they're going to be leasing.
So, yeah.
Now, just understand that there's additional property that DME owns that's to the west of what eventually will be loop 288 that's going to come through here, right?
Currently, there are no plans for that site other than a future city service center annex that that's currently under proposal.
But still, again, we're talking about a number of years before that gets developed.
So in this in this PPA for this phase four number of provisions that I wanted to go through really quick.
So all of the the rates that are being charged are based on cost of service.
We've worked journal consultant to help us develop that all the energy that that's purchased will be recovered through the energy cost adjustment.
That's based on the current existing rate that we have or whatever the rate is that's in the ordinance.
As we bring that back to you on a quarterly basis, we'll be making adjustments to incorporate core within the recovery of that through that energy cost adjustment.
Currently, it's at five point one five, although you recently approved a slight decrease of that that the council will be considering tomorrow.
And then transmission related costs will also be passed through through our transmission cost recovery factor.
That's also another rate that the PCT the PB reviews, as you might recall, that's actually going to go up a little bit.
The net if impact to a residential customer from an ECA decrease, TCRF increase is about a one percent decrease.
But again, we'll be passing this those same costs on to to core.
And then there'll also be a base rate component that's that's proposed.
Currently, that's part of the PPA. So it's confidential.
But once we develop that as a normal tariff, that will be applicable not just for core, but any other large users.
Currently, we're looking at at about a 20 megawatt or higher type of rate structure.
But again, we're working with our consultant to bring that to you.
But ultimately, that that actual rate that will be charged to core will be part of our of our published tariffs.
So you mentioned if this project goes forward, transmission TCRF rates,
which is kind of half of our everybody's bill in Denton, is going to decline per per KWH.
That's likely what will happen again.
There'll be additional transmission cost to us because right now our load ratio share of transmission costs across the ERCOT market is about point four seven, about half a percent.
By converting this facility to a firm load, we anticipate that that would go to about one percent.
So there'll be additional costs. But again, all of those costs are based on usage.
So the more you use, the more you pay.
And so we would anticipate that that core would take the lion's share of those increased costs.
So basically, the transmission costs, DME pays goes up some.
But core, because they're using so many kilowatt hours, they are paying more of that portion.
So, like, assuming all those things come true, the average residents, home residents, TCRF line, as opposed to the ECA line, will be reduced by some amount.
That's what we would anticipate, yes, sir.
So core responsibilities here that we wanted to point out, there are any investments that need to be made, improvements that need to be made, transmission related within the site.
There's two substations, some additional relocations and lines.
Core has agreed through our contract to pay for those 100 percent.
There are additional costs that may be needed to resolve those system overloads.
Those costs have to go through a process, both from a selection of what project we will be doing and will be done, because it may not be DME.
It could be one of these other utilities, whether it's TNPA, Encore, CoServe, so that will be subject to ARCOT approval.
Those transmission investments are socialized through what's called the transmission cost of service filing.
So then those are socialized across the entire ARCOT system.
So the next thing is phase four can only be powered.
So there is a phase four component.
That phase four can only be powered once those system overloads are resolved through those investments that we would anticipate would take probably two to three years to go through the approval process, construction and/or connection.
And so it'll take some time before that phase four component comes online.
We would anticipate that that would be 2027 at the earliest, 2029 at the latest, again, subject to approval by ARCOT.
DME implications, certainly we need to modify the purchase power agreement.
Once converted to APTC, we would anticipate bringing a new tariff rate that would be applicable not just to core,
but other large load facilities that may not necessarily be data centers.
And so I just want to be clear that that particular rate will apply based on the amount of energy that's proposed to be used, very similar to the GS small, large and medium that we have today.
So it would work the same.
I want to point out that because this will be a firm load, we anticipate that there will be an impact.
It was called the four coincident peak load.
So in other words, our pro rata share, our load ratio share of the total ARCOT transmission system would go from roughly half a percent to about one percent as a firm load.
It is going to be subject to to mandated load shed.
And so, you know, if there is a call from ARCOT, just like Yuri and since that time, other events core will be treated like every other customer in the city.
Now, core is anticipating to have some backup generation, some small battery storage on site as well that will help them try to weather some of those outages when and if we were to shut them down.
Yes, sir. You had mentioned there had been some other incidents or situations where ARCOT had required some mandated shutdowns or pullbacks.
How many of those have there been since the big winter storm, typically one or two a year?
No, I think it's been less than that.
I think since Yuri, we've probably had probably two.
Now, we've had we've had a couple of instances where we've been we've been close both on both during the summer and in the winter, but they've not resulted in any mandated load shed events.
Thank you. Yes, sir.
So from a renewable standpoint, we do anticipate to continue to meet 100 percent renewable mandate because this is such a large load that's coming out so quickly.
We will not have time to have actual PPA contracts with wind and solar installations, but we do anticipate to issue our fees to to back that load up through that process that we have.
In the meantime, we do anticipate to do what we've been doing now with core, and that's buying renewable energy credits to meet that ongoing goal.
And in long term, long term, we'll be having conversations with the PB and also with the city council about the data and renewable resource plan and some of the regulatory challenges that we're seeing that that may require some firming of of the total city load with dispatchable generation.
So here's kind of what what our load currently looks like and what we would anticipate that we would look like when this facility comes online.
So currently, we're about 400 or so megawatts, and this is what we call our native load.
That's everybody else other than than any data center project that we have out there.
Then we have we anticipate that that would grow by 2044 a little bit over 500 megawatts.
That's just normal residential commercial development that's coming.
Certainly, we believe that that additional 100 megawatts of load is conservative.
We are in a very high growth area.
And so certainly native the native load could certainly outpace what we projected here, but that's what we forecast at this point.
With with this data center and other data centers that have already been approved,
we would anticipate that our peak load would climb probably north of of 800 megawatts.
And then by 2044, total load would be in excess of 900 megawatts that we'd be looking at.
I want to point out that while that is a 73 percent increase in load,
just want to point out that there have been additional there's been additional interest from other data centers to interconnect into DME's grid.
But I would just point out that that's happening not only across the state of Texas,
but really across the country where there's been huge developments of data centers from everything from crypto mining to these tier three artificial intelligence,
high performance computing to an assortment of data centers in between the line there.
And so it's not anything that's not happening in other parts of the system, certainly not unique to DME.
But but certainly there's been interest here for context.
Currently, we serve about one point eight megawatt hours.
That's what our current load is that we serve.
We anticipate that that would grow to four point eight million, so certainly a substantial increase in load.
And so for some context, currently we have the dead energy center that's producing about 225 megawatts.
That's capacity of dispatchable generation that we have.
So in the event that we would be mandated to to firm our load,
then we would be required to have that additional roughly 600 megawatts of of of load that we're serving backed up by some type of dispatchable generation,
either through it being contracted, owned.
There will also be performance credit mechanisms potentially that may be available that are also going to be generated by those same types of dispatchable generations.
We did talk a little bit about the importance of a demand side program that could also be tied into some of the strategies along with an assortment of other things that we're looking at that we'll be bringing forward to you
through the update to the then renewable resource plan and we'll call our integrated resource plan.
So just talking a little bit about the load shed implications already mentioned that we would anticipate that we would go from roughly half a percent to about one percent would be our total share.
Right. And while load shed events are infrequent and they do vary in both the amount that's being requested for us to to power down and the duration.
And so again, not not not every event is exactly the same.
We we we do see possibilities during the summer in the late afternoon hours between six and ten o'clock.
But during the winter, we also see kind of this this double type of of potential event that may happen, not just in the evening as the sun comes down, but certainly early in the morning as as the wind starts blowing that there's possibilities there.
But again, since Yuri, we've had I think maybe one or two very short duration events that have happened.
So again, not every event is the same. We do have a load shed plan that is filed with with our cop that is confidential that we lay out our plan for any type of event.
But again, just like during Yuri, we are able to modify that as the need arises.
One thing that I want to be clear is that we will never jeopardize or prioritize public health and safety of our customers in those events.
So they're certainly always on our mind as we're looking at that load shed requirement.
But but again, it will this this project being converted from a variable load to a firm load will now be part of our load shed plan and will be subject to to load shed events are caught.
Excuse me. Core is very well aware of that. That's why they've invested in some generation and some battery storage in their facility to try to weather some of those events if they were to happen. I think you just answered my question.
So they're going to invest in their own generation in the event of a mandated outage. That's correct there for that reason.
But these types of facilities require that type of of generation backup, which again, the load is has to be constant. Right. And so so they put that in in the event that there's some type of system outage or forced outage that they can rely on variation in the quality of the load power delivered and deviation in the quality of delivered power.
Absolutely. Absolutely. It's what we call the ride through. So, yes, sir. Thank you, sir.
So so the example that I wanted to give just really quick just to make sure we're clear here in the event that are covered to call us in the example I have just to try to make the math easy for myself.
Right. Is that if the aircraft wants a 10,000 megawatt, 10,000 megawatt reduction, our share currently would be about 50 megawatts. So we'd be looking at 50 megawatts to start rotating within our circuits. Just to be clear, if that stays longer than, let's say, an hour, right.
Our low chip plan duration, about 30 to 45 minutes. Right. So if that goes on longer than that, what we're going to do is we're going to we're going to shut down another 50. So at a given point, you have 100 megawatts that are out.
Once that 50 is that new 50 is out, then we bring on the other 50. Right. And so then that 50 stays for another 30, 40 minutes. And then we do the same thing again, again, depending on how that how that flows through by going to going to a one percent.
Now we're looking at 100 megawatts. Right. And so and again, it's the same type of of scenario and we have those circuits identified and that we're working through just like we did during during Yuri.
And I would just point out that while we understand the impact that that they had on our customers, we're very proud of the fact that we had zero deaths in our community as a result of those outages.
I thought we did a really good job of managing them, hurt our customers. We initially started with a 30 minute kind of rotation, hurt our customers saying that was enough time to get them to reheat.
So we increased that that duration to about 45 minutes to give people that had the power back on time to reheat their homes and and do what they need to do.
And in addition, we were able to work with a number of critical facilities that we didn't know were in town that we were able to to work with them to keep them powered to service their customers.
And in particular, Dallas Center that that that we've built a really good relationship with.
And so anyway, so the next thing that yes, sir, just while we're on that topic, I want to keep beating my drum on large industrial customers and their ability to demand respond.
If whether it's core or Peter Biltz or Tetra Pak or any other large customer can can respond during that time, you know, that that if they if somebody can turn off 50 megawatts in their single customer,
then that's less the rest of the grid has to do or the rest of DME has to respond.
So that's where some kind of demand response or agreements to pay pay for that value or split the benefit between DME and the customer.
If it's got a value to reduce that load or anything like that, those are those are really good opportunities and for demand response program.
So I just keep beating that drum that I know you all you all have been talking about it for a while, but I think it's got a ton of potential value. And I would just say that relationships do matter.
And so so we worked very closely during that time with both both universities and also then ISD.
And so much of their load actually disappeared during year as well.
Now, certainly, you know, they couldn't have students on there. And so so it was natural. But again, how they reacted to that was really in concert with us and the relationship that we have with those institutions.
So but you're exactly right. Next time I want to just cover real quick is you are going to be considering changes to the lease agreement.
This would be amendment number three to the lease agreement.
The initial lease agreement that we had with core back when they first came in was for thirty one acres.
We did amend amend that in amendment number two, we added additional five point five, six acres for a total of thirty six point five acres that they were leasing with this agreement here.
That actually jumps up for an additional forty two point nine acres that encompasses six point seven acres of solid waste property for a total of about seventy nine point four acres, almost eighty acres that are being leased to core.
There is a fair market value payment that they were making for that lease agreement.
That's about a little bit over almost fifty four thousand dollars per month, so a little bit over six hundred thousand dollars a year that they would be paying for for leasing that property.
The majority of the property, seventy seventy two, almost seventy three acres are previously DME owned property and in the six point seven acres of land from solid waste.
And just to be clear, this property was purchased, the solid waste property was purchased for a solid waste transfer station.
We've worked with Brian Warner and his team.
They will have to redesign that transfer station as a result of this particular usage change.
But that transfer station will remain functional.
No changes or impacts short or long term to that facility as they develop other than they have to reengineering.
But we'll talk a little bit about an additional agreement concession that that core is made as a result of that particular change.
So the other agreement that you have is what's being called a value loss consideration agreement.
Core has agreed to pay the city a little bit in excess of five million dollars.
This money is a result of some additional negotiation that that fell through.
And so in consideration of that not happening, core has agreed to pay the city a little bit over five million dollars that would be used for any general government purpose.
So that money will be going to the general fund and it'll be a one time payment of sixty thousand dollars, which represents the engineering cost that that solid waste had made on the initial property development for the transfer station.
This gives them back to sixty thousand so they can start all over again and then have no impact on on the solid waste fund.
In addition to to this lease, there there's also a little bit over twelve and a half acres of property, also a fair market value, almost fifty two hundred dollars per month for some temporary construction easements is pretty standard in the construction world.
It's about it's a 48 month term.
They're using that property for staging equipment, personnel, that sort of thing, normal construction as they as they develop the property.
Standard terms and conditions apply that's pretty standard on our contracts.
Community impacts just shortly.
And this will just have one more slide after this.
So bear with me, community impacts cores anticipating that they would have one hundred and thirty to three hundred full time personnel on site.
That's, of course, contingent upon full development of all the phases, including phase four average salary.
They anticipate seventy to seventy five thousand plus plus benefits.
They do anticipate to work closely with U.N.T. and T.W.U. on some programs to to shore up that labor force.
Matter of fact, there's a number of U.N.T. students there now that have been working with course since the beginning.
And then they anticipate a little bit over two hundred spin off jobs with the average salary about thirty seven thousand.
These are construction type jobs, folks that will be there as they're constructing and servicing the facility.
Total real property investment. It's about four billion dollars.
So it's a significant investment that's being made on this facility.
That's about one hundred ninety four million of property taxes to the city over over the first 10 years of the agreement.
And I'll be clear here that through this process, there have been no economic incentives offered to core provided to core as part of this agreement.
They are seeking some incentives and abatements to the state of Texas.
But that's certainly something that's that's separate and that the economic development department is helping facilitate.
But no chapter 380 agreements or abatements that are that are being offered as part of this agreement.
And so the request that we have to for you today is staff recommends approval of amendment four to the purchase power agreement.
Amendment number three to the lease agreement, approval of a vast value loss consideration agreement and also an agreement for some temporary construction easements.
So with that, we'll be happy to answer any questions you may have for the questions.
I think we asked them all here. You're present. Oh, no, I have one.
He has one. Procedurally, may we move to approve B, C, D and E in one motion?
No, we have one at a time.
We do. Yeah, very well.
Thank you. All right.
So then the first item is P.U.B. 24-244, a temporary construction easement between the city and Core Scientific.
Do we have a motion to approve?
Mr. Rybak motions. Mr. Taylor second.
All in favor say aye. Aye. Opposed?
Okay. Next item is P.U.B. 24-245.
Consider adopting an ordinance authorizing the city manager to execute a third amendment to the lease agreement between the city and Core Scientific.
Do we have a motion to approve?
Yes, I would like to. So I would like to run down for for Mr. Lee's questions, and I'm really sure this is going to get a lot of attention.
You know, this is a big financial deal. So I just wanted to run through what I understand the financial risks and benefits.
Sure. Do you want to do it here? Well, I figure may as well do it here. Go ahead. Yep. No.
We there's obviously the lease land, small amount of income to the city, the the a new business of 100 to 300 employees moving into town with tax base and jobs and all of those those type of economic development benefits.
But as it applies to D.M.E., this will the increased and steady load will.
Core Scientific will actually lower the average per kilowatt hour bill of all other meters in tech in in in D.M.E., because they will be carrying a portion of our transmission cost.
There are some, you know, what are the financial risks? Well, there's building out infrastructure.
Core pays for all of the infrastructure on their site and then deeds it to D.M.E.
So that we don't have to take out a loan to build a few million dollars in wires.
We have to do off site improvements, but those are reimbursed through the transmission cost of service program.
And those are already those improvements are things that D.M.E. has identified just from natural growth will eventually be needed.
They just get needed sooner if this project gets built.
The and then like temporary construction easements and end in the value loss agreement kind of offsetting the the expected revenue from the Bitcoin mining.
I think those are those are all the I believe the direct benefits to D.M.E.
But D.M.E. also does collect an ROI return on investment.
So a portion of the revenue D.M.E. has gets paid back to the city because the city put forth the original capital and effort to create the power company.
So just like a for profit company would have investors making money and a co-op the cooperative would be collecting an ROI and paying it back to the members.
D.M.E. pays it to the city.
So if D.M.E.'s revenues increase, that actually provides a transfer in funds to the city, lowering the total taxes needed by the city.
So for all these reasons, there's not there's I think the biggest risk I can see.
Two biggest risks I can see are if we get used to the revenue and core scientific, you know, ceases to exist or moves, you know, that would be the same as a loss of a Peter built or a large another large industrial tech repack.
Or, you know, one of those, you know, it would it would it would be a hole in our community for employment and and benefit.
But, you know, we can't we can't control that much.
And if anything, I feel like the high performance computing is probably a little more consistent than the Bitcoin mining from a long term perspective.
And it has potential for more employees.
Yeah. And furthermore, there's more investment in the community.
High performance computing is the wave of the future.
It was just going to be more and more and more of it.
So you have to get used to it because we all want these things to respond when we talk to them.
Yeah. And I think that the other risk, which is a risk that DME has just in load, is we need to manage purchasing that load and forward.
And, you know, I think that's already you already have staff that that's their job.
And so I think they, you know, they'll be adjusting all of their plans and their risk models and so forth to include this.
I do have one concern is we are already not at our 100 percent renewable right now per the Denton Renewable Resource Plan.
We're in the 90 percent, somewhere below 100 percent currently renewable.
And this will add a large new load, which would push us to maybe 50 percent renewable.
And, you know, that was a hard fought mandate from the citizens.
And so I want to move us back there and we could start.
You know, you have a plan, short term, medium term, long term.
You know, I just want to make sure that we don't that we keep that plan moving forward as load growth.
We don't we don't have to fall below 100 percent to start planning for three years from now to buy more, you know, renewable energy.
With all that, I think this is a really good opportunity for DME and for the city and for the residents.
Very well said.
I move approve. So I move approval of item C.
All right. Do we have a second, Mr. Newquist?
All in favor, say aye.
Aye.
Carries. OK, P.U.B. 24246.
Consider recommending the adoption of an ordinance to execute an amendment number four for the purchase power agreement between the city and Core Scientific.
Do we have a motion to approve?
Mr. Ryback's motion and Mr. Taylor's second. All in favor, say aye. Aye.
Carries. P.U.B. 24247.
Consider recommending the adoption of an ordinance authorizing the city manager to execute an agreement for value loss consideration with Core Scientific.
Mr. Newquist moved. Mr. Ryback seconded.
All in favor, say aye. Aye. Carries.
That that is it. All right.
We're on to concluding items.
Does any board member wish to make a comment to the public or have something put on a future agenda item?
Seeing none, it's ten twenty nine.
We're adjourned.