Okay, good morning and welcome to the Public Utility Board meeting of Monday, July 14th, 2025. It is 9 a.m.
Do we have any presentations from members of the public?
Doesn't appear to be so, so we'll move right on to the consent agenda.
Would anyone like to pull any of these items? I'd like to pull A.
Okay.
I believe that's it. All right. Item A has been pulled. I'll entertain a motion for items B, C, and D.
We have a motion to approve from Mr. Nukus. I'll second. Second from Ms. Parker.
All those in favor, please say aye. Aye. Any opposed, sign the same. It passes unanimously.
All right, item A.
I just have a question on how did we come to the, I mean, I agree with doing the integrated
study instead, but how did we come to that decision?
So, so the particular item that for A is we originally had planned to have basically a peer review of
what we have been working on
initially. We
subsequently
decided to take a different approach.
And so the integrated resource plan recommendation actually dates back
to a management study that that we did back in 2018-2019.
And just internally we felt that that was probably the better approach, the more holistic approach.
And so, so that's kind of where, where that really came from.
Rather than us kind of do our own kind of resource planning internally,
we kind of felt that, you know, making a larger recommendation, more of a master plan
with a longer term horizon than
probably the five-year horizon that we would have looked like, looked at internally just made more sense.
And how far are we going to be going out, like 30 years? How far are we looking?
Minimum 15, I would prefer 20. But certainly I think
once we engage a consultant, which is what we plan to do, we can certainly have that conversation.
Certainly if the board thinks that a much longer horizon than 15 or 20 years is,
is preferable, certainly we would appreciate your feedback on that.
And we're still going to include all renewables and looking at battery storage and all that kind of stuff at the same time.
Absolutely. All resources will, will be on the table.
Okay. Thank you.
Yes, ma'am.
Yeah, I think, you know, we, we had this discussion in May regarding the, what was originally the
energy plan followed by the resource plan. And I think that, that first step of setting goals is really important.
You know, setting goals, public input, and then, then leading to what resources are we actually going to, to utilize to, to fulfill the plan.
So, I mean, I see in the, in the, in the agenda it said, you know, still planning to have public input and, and so forth.
I just want to make sure that we set goals before,
you know, identifying the plan.
Yeah. And in today's work session, we'll have a kind of more robust conversation. And certainly if there's additional feedback, we would appreciate it.
Okay.
I'll go ahead and move approval.
We have a motion for approval for item A.
Second.
We have a second. All those in favor, please say aye.
Aye.
Passes unanimously.
All right. Items for individual consideration. Consider approval. It's item A. Consider approval of the June 23, 2025 minutes.
So moved.
We have a motion to approve the minutes.
Second.
We have a second. All those in favor, please say aye.
Aye.
Any opposed?
It passes unanimously. Management reports item B.
As some members of the board, we do have one quick item. I'm going to ask Cassie to come up here.
This is our first time, so please take it easy on her.
I thought it'd be good for her to come up here and kind of let you know a little bit about some legislation that recently went through and what that ultimately means for the board.
So I'll just turn it over to her really quick. So Cassie, go ahead.
Administration manager, just a quick update on the new posting requirements in response to House Bill 1522.
The requirements are now that we post the agenda three business days in advance.
So you will now see the agenda on Tuesdays by the end of the day rather than Thursdays as it was previously.
We do plan to try to implement this as soon as possible just so that we're in compliance with this once it does hit that deadline.
But that is it for the update. And if y'all have any questions, feel free to let me know.
All right. So thank you for that.
And like Cassie said, you'll have even more time to review the agenda.
And certainly we're working with staff, which we tried to work through that a little bit earlier.
But going to the next item, which is the agenda items, again, we have budget presentation today.
And then on July 28th, the finance department will come back with the full budgets and rate ordinances
and ask that you make a recommendation to the council at that time.
And then finally, for new business, today we have a work session on the dispatchable generation that was requested at the last meeting.
Happy to go through that. But that's what we have for the mayor's report.
If you have any other questions or requests, just let us know.
Oh, we're not just regular work. OK. All right.
Thank you, Tony. I guess we're moving on to work session item A.
Budgets.
Well, good morning, Chair, members of the PUB, Matt Hamilton, ADF Finance,
here this morning to present the preliminary utility budgets for fiscal year twenty five, twenty six.
As part of this presentation, we will cover the budget process for the upcoming fiscal year, a change in the methodology that we've used.
And so we'll talk a little bit about that.
And then as we get into each of the departments, we've also included just an overview of where the fund ended the prior fiscal year,
where we anticipate it will end in the current fiscal year.
And then, of course, talk a little bit about the operating budgets for next fiscal year and the rates associated for each fund.
So talking a little bit about the budget process, the budget process hasn't changed from the prior year. So we did a kickoff in February of this year.
The departments worked very diligently to scrub and review their their budgets and submit that to the finance department.
Once we had those in March, we compiled everything and proceeded to meet with the city manager's office to review the budgets.
And here we are with you to present these preliminary budgets following our meetings.
We'll present the information to counsel.
We'll have a budget workshop that covers all the departments citywide on August 9th.
We'll have a few follow up meetings thereafter in August.
And then budget adoption is scheduled for September 17th.
So talking a little bit about the budget methodology, and this is different this year than it has been in prior years.
So in prior years, what the city did is it took the prior year's budget and assumed that that was the baseline
for the next fiscal year.
And what would happen is the departments would review their operational needs and submit what we called either baseline or supplemental requests.
Essentially, it was requests for new funding that would be added to the prior year's budget in order to create that new that new budget.
So this year, we decided to make a change and move towards something called zero base budget and zero base budgeting is a technique in which the budgets start from zero.
The departments did not have their prior year budgets rolled forward.
Essentially, the exercise was, you know, allocate resources, you know, where you need them rather than just simply rolling something over.
And so each of the budgets, not just within the utilities, but citywide, were built from the ground up this year.
And so it was a really great exercise for the city to ensure that every dollar is justified where it needs to be, that funding is allocated toward,
you know, the contracts that we have, our existing obligations.
And so it was a very labor intensive, but great exercise for for the city to go through.
So our funding priorities this year is to focus on existing employees.
As you'll see in the presentations, we're not proposing to add any new employees as well as a real focus on the existing projects that we have in our CIP rather than making a proposal to add, you know, a significant number of of new projects.
Now, some of the projects have been in, you know, design and such, and they're just starting to move forward now.
So you will see, you know, a couple of new ones.
But but by and large, we're very focused on completing the projects that we've already committed ourselves to.
Additionally, the departments have been asked to focus on what they believe to be their core services and aligning the resources accordingly.
So that really fell into that zero based budgeting methodology and then focusing on ways to save and reduce debt.
I'll say for, you know, the water wastewater utility in particular, we have some very large infrastructure projects that that we're just at the at the beginning phases of.
So we will see, you know, an increase in debt issuance associated with with that department.
But overall, broadly speaking, that's what we've really been been focused on.
Right sizing revenue and also diversifying revenue streams.
So as part of the zero based budgeting process, not only did we look on the expenditure side,
but we also looked on the revenue side and we evaluated where our rates are.
What are we charging? What are we not charging for that maybe we should be charging for?
And so it was a very comprehensive, comprehensive review.
I did want to mention that we have enhanced our financial reporting and so we do post monthly financials on the city's Web site on the finance page.
And we've also been very focused on updating financial policies throughout the city and fee schedules and proposing to update fee schedules to focus on on cost recovery.
So getting started with solid waste and recycling, just want to give a quick overview of their current organizational structure.
They currently have a total of one hundred and thirty FTEs.
And again, there's not a request to add any additional FTEs next year.
Taking a look at the current year and where the fund ended last year.
So twenty twenty four actuals solid waste ended down one hundred and twelve thousand dollars.
However, this was considerably better than the twenty four budget, which anticipated a two million dollar use of reserve.
So the use of reserve that that was utilized at the end of twenty four was only one hundred and twelve thousand.
The looking in the in the current fiscal year, we anticipate that solid waste will end positive one hundred and eighty four thousand.
One question that did come up from member Ryback prior to the meeting that I just wanted to address before we get into each of these departments,
because I think it applies to each is as we look at personnel services, you're going to notice a variance between the actuals and the budget.
So as we look at the twenty five budget for personnel and solid waste, the budget amount is fourteen point four million.
But the twenty five estimate is thirteen point eight million.
And I just wanted to let you know that primarily that's due to vacancies that have occurred throughout the year.
And so, you know, we have to budget a hundred percent of personnel as if everybody is going to be employed ten one through nine thirty.
But, of course, you know, due to turnover and position movements and things like that throughout the year, you know,
frequently you'll see the year end numbers less than than what that budget number is.
The other is sometimes labor is charged to, you know, maybe a specific project.
Maybe those expenses were reimbursed for one reason or another.
So that could also be another reason that it would be it would be lower.
So taking a look at solid waste for fiscal year twenty five, twenty six.
Overall, the budget expenditure budget increase four point two percent.
However, we are not recommending a base rate increase for fiscal year twenty twenty six.
You may recall last year when we made the budget presentations,
what we had forecasted for fiscal year twenty twenty six last year was a three percent rate increase for solid waste.
And so I just wanted to highlight that because, you know, that's a fruit of the labor of the department in the zero base budgeting exercise
to ensure that, you know, we are looking at reducing expenses where we can, containing the rate as best we can.
And so just wanted to to mention that to to the board.
So preliminary budget reductions for solid waste, the department identified nine hundred and eighty thousand in reductions.
Personnel two hundred and twelve thousand.
Currently, the department has two deputy director positions.
They have proposed to reduce that to one deputy director position, materials and supplies reduction of two hundred nine thousand.
This is a reduced expense for the alternative daily daily cover and odor control agents,
as well as some furniture expenses that they were able to to reduce.
Maintenance and repairs, seventeen thousand five hundred. This is reduced expense associated with the compressed natural gas operations.
Three hundred ninety seven thousand, which are reduced discretionary expenses, travel, training, equipment, rental.
And then one hundred and forty four thousand in fixed assets, which are the dumpsters and containers.
And I believe the department identified that they could refurbish some of the containers and such to reduce expense.
So taking a look at solid waste growth, growth projections, solid waste is very consistent, I'll say, year over year.
We're projecting three percent growth in residential customers, one percent or I'm sorry, one point seven percent growth in commercial front load, side load polls and three percent growth in landfill customers.
And as you can see on this chart, it it provides last year's actuals, the current year estimate and then the fiscal year twenty five, twenty six estimates based on those those growth assumptions.
So this is the fiscal year twenty five, twenty six preliminary performance. So the department is proposing forty five point three million in revenue and forty five point three million in expense.
One thing that I did want to point out, you'll notice the the fund balance in the future years does decrease. And that was intentional. And the reason is because the city sets a fund balance policy that provides a range, a low and a high.
And ideally, the fund balance is intended to stay within that range. So because the solid waste fund was about two million dollars over the high target range of their fund balance and was not currently revenue funding all of their vehicles.
What we've done is used some of that reserve in order to start revenue funding their their vehicle acquisitions each year, one hundred percent.
And that goes back to aligning with our goal of reducing debt. So the funds many years ago would revenue fund one hundred percent of their vehicles.
We had gotten away from that in the current year. It's about 50 percent. So this sets us back on track to get the fund balance within those policy limits and start revenue funding those vehicles again so that we can reduce debt issuance.
So solid waste five year capital plan. There's really two big items. One is the vehicle replacements and additions. And you'll again see in 26 about half of that three point four million is revenue funded.
But then in the future years, 27 and onward is one hundred percent revenue funded. And then for next year, the major project is the organics program infrastructure.
Any maybe I'll pause any questions on solid waste.
Right. Just a couple of I could so that I understand with the methodology when your existing employees said we're not going to be hiring anymore.
Would that be an layman's term. You're thinking of a freeze or what about attrition's that come through. Are they not going to be replaced and you're just not adding more.
So to two things. One is that there is not a request to add any new FTEs for the next fiscal year in regard to vacancies with the city has done in the current fiscal year is implemented a managed vacancy program where when vacancies do come come up.
Those are reviewed to ensure that that position is still needed that it's you know mission critical to hire if there were to be a position that was determined you know hey the workload of this position could be covered by an operational change or technology whatever it may be.
Then then that position may not end up being filled. So there is. Yeah. So then a question these projections for five years and such this existing employee on the verb is that looked at each individual year or is it.
In other words of this existing employee this year we won't be hiring anymore according whatever the terminology is. Are we looking at that. Then next year you're going to come back and say the same thing or is there going to be with the projections.
How do you how do you implement that. Right. So so the projections right now don't contemplate new employees but they do contemplate increases to existing employees personnel expenses so you know benefits and compensation and all that.
We will come back every year through the budget process and review.
You know the needs of the department and if it's appropriate to add FTEs we will.
And I read in the if I may Mr.
Oh good. So I read in the paper.
Some rather large number on the deficit that the council was looking at. Are we caught in that snare as well.
I mean that in particular related to the general funds and it particularly related to you know external funding tax rate implications and things from legislation.
So the short answer is no.
However the exercise to move towards zero base budgeting and review these budgets in a high level of detail was a good exercise to do across the city because with that prior methodology of just taking last year's budget and rolling forward over time
there's things that you know are there that aren't really needed anymore as the organization has evolved. So so the utility funds there is not a you know a deficit issue that we're dealing with.
I'm just saying it's not at risk as much as the rest of the department.
Correct. Yeah.
And one more question if I may Mr. Chairman on the fixed assets. I was intrigued on the reasoning. I mean we're talking about metal boxes already made outside of having land to store them.
Is there a time where we have 30 that are not being used or three of the five yard and whatever or I'm just a little I'm intrigued as to why they get the cut when I would think of anything they're easy to just keep stored for.
Are we not using them that many. Yeah. I'll ask solid waste to to address. I think they adjust your mind. I'm not quite as tall as he is.
Good morning Brenda Haney and the solid waste director and I think this is probably the first time I've introduced myself to all of you.
We do keep a bit of an inventory of dumpsters and roll off boxes. But we have been spending more over the last several years when we were implementing the commercial diversion program.
This year we've decided to pull that number back. We're in the final year of that implementation so we don't need to add as many. What we keep an inventory is really that routine one gets damaged.
One gets hit whatever and so we do that normal replacement of those that are that are hurt or damaged in the course of use.
And then what we do with our replacement is we can always go and just buy a new one but we can extend the life of those existing containers.
Let's say one of the side panels has been damaged the bottom is rusted out. We can we can well cut that out and weld a new one in and just extend the life of that otherwise fine dumpster. So that's what we'll do with those just to try to minimize the number of ones that we have to continue to replace.
So if I may thank you. So is it is it cheaper just to buy new ones versus keeping 30 on store.
Well we keep some on store but we make an annual purchase of additional ones to keep that inventory in our yard to replace those that are damaged just during the course of normal wear and tear.
So is it fair to say that that 30 number is just kind of buffer number that you use as a general rule. Yeah those are I think that's referring specifically to a size container without the small green ones what I was talking about.
So yeah we keep those little ones on side. Yes. So you keep as many as 30 and that's not unusual because it looked like you were going to cut 30 and that's why I was curious.
Yeah no we're going to keep keep a stock just a normal kind of as part of the base budgeting part of what we did was kind of look back and reflect on how many of these are we actually turning through year over year and making sure that we're maintaining an adequate number to take care of all of those actual replacements during the course of year. We don't want to set ourselves up where we don't have enough funds obviously to replace what we need during the course of the year.
But we also don't want to store them if we don't need them. That's a statement I was looking for. Thank you. You're welcome. Thank you. Nice to meet you.
So what is your your debt service coverage ratio goal. So the solid waste. Yeah so so the debt service coverage ratio is a calculation that looks at your total revenue over your debt service whatever you have and it's that you're right.
Sometimes how much more revenue do you have than than you're going to pay in debt service. The debt service coverage ratio is really only applicable to revenue bonds which the solid waste department doesn't currently have.
So the policy of the city is a coverage ratio of one point two five and when we issue debt for the utility system it's water wastewater and DME actually combined is what the rating agencies on the market look at.
So we do show it individually for each department. So this two point one five percent or two point one five ratio for solid waste is well above the one and a quarter that would be needed if they were to issue revenue bonds.
Okay. That was a lot of information for the question was debt service. What is your debt service coverage ratio for solid waste goal. What's the what's the normal goal for solid waste. Oh the goal. That's all I asked. Oh yeah. One and one and a quarter.
But you're keeping it higher because it kind of makes up some ground where the other ones might be lower I guess.
That's what I'm assuming because we tend to keep that higher. Of course it's a lower revenue. It's a lower budget process. Yeah. So that that ratio is going to be impacted by two things.
One is how much debt service we have which solid waste hasn't you know increase their debt service that much. And the second is the total revenues. And so essentially as debt service has remained relatively flat but revenues has increased that ratio has has gotten better.
So it is something that we consider in the budget process but it's not necessarily something that we adjust. OK. Yeah. Yeah.
Okay. Talking a little bit about D.M.E. So just a organizational structure hundred and eighty nine F.T.E.s again not proposing any additional F.T.E.s for fiscal year twenty six taking a look at where they ended fiscal year twenty twenty four.
So two hundred and ninety million in expense eighteen point eight million of use of reserve.
The budget was seventeen point seven million use of reserve. So just a little above the twenty four budget for the current fiscal year.
What we're estimating is three hundred and nineteen million in revenue and expense which includes one point seven million use of reserve.
The budgeted use of reserve is one point four million. So just a little bit above that number. However D.M.E. and you know water wastewater utilities are are highly dependent upon the fourth quarter in the summer months.
You know this could this could change pretty quickly over the next next two months.
So the overall budget change looking at fiscal year twenty six for D.M.E. is a thirty four point two percent increase. Nearly all of it is just due to purchase power forecasts. There's no base rate increase proposed for fiscal year twenty six.
However the E.C.A. and T.C.R.F. rates will adjust as needed as as they do for the E.C.A. quarterly and the T.C.R.F. annually.
We have made as you know some updates to the target balances over the last year most recently effective July 1st and that E.C.A. target balance is really there to help stabilize the E.C.A. rate.
We did implement the large load E.C.A. which I believe went into effect July 1st with a 20 million target balance that there again will help strengthen the department's financials.
Revenue projections for fiscal year twenty six five hundred and twenty six million expense projections of five hundred nine million leaving them in a in a net positive which we'll see on the on the next slide.
Preliminary budget reductions total three point three million two point three million is related to winter and summer outage insurance.
But we did want to note that contingency funding is remaining in their budget should that be needed for that purpose. The campus expansion was previously slated to be debt funded but is now revenue funded.
The design piece of it the beginning piece of it which will save nine hundred ninety thousand in debt service and then the focused advocacy contract of seventy two thousand.
Additionally BME in their review identified six vacancies that they anticipate to continue to hold through fiscal year twenty twenty six.
So taking a look at DME growth projections these are the forecasted sales in megawatt hours for fiscal year twenty twenty six combined between residential and general service.
We're seeing an eight percent increase and then the bar graph to the right is just a visual of the same data.
So taking a look at the DME is five year preliminary forecast. So again five hundred and twenty six million in revenue five hundred nine million in expense with a net income of seventeen million.
Again what you'll see is the purchase power forecast has increased over last year but again not recommending any rate increase.
The fund balance target you'll notice we are beneath the policy target until 2030 when we are above the target for the policy.
There's a five year window for us to raise the fund balance to within the fund policy limits and this is really driven by I believe it was in August of twenty three that unexpected financing the purchase power that we needed to make and financed over over five years.
And so once that falls off we'll be within those policy targets again.
And then I did just want to note since we talked about the debt service coverage ratio for for solid waste for DME it's currently projected for twenty six at one point seven four so above the one and a quarter as well.
This is an overview of DME's five year capital plan totaling sixty three point nine million of that sixty three point nine million fifty eight point four is anticipated to be debt funded one point four million revenue funded and four million in cost participation or developer contribution.
Questions on DME zero percent increase next year for base rate right yes.
Just clarifying.
Oh just the base rate.
Okay. Talking a little bit about customer service our customer service department currently reports up through DME and has sixty five and a half FTE's that will remain for next year as well.
The department also includes our three one one operation so ten of the sixty five FTE's are part of our three one one group.
Customer service ended last year about eight hundred thousand under budget and in the current year we anticipate that they'll be roughly about the same quite a bit of that as you'll notice in the personnel line is due to vacancies and turnover.
Within the department.
So before I get to the next slide as we looked at each of the department's budgets and we analyze customer service one of the largest expenses in customer services operations are the fees associated with processing credit cards.
And so the city currently pays one point three million in credit card in each processing fees annually related to utility bills.
The city does not currently recover this cost through any type of dedicated fee.
So just as a little bit of history the city did have a convenience fee prior to 2020 it was implemented in 2014 and it was a two point seven percent convenience fee only on commercial accounts.
When we went to renew our merchant service contract in 2020 the laws and regulations had changed surrounding convenience fees where you could no longer charge a percentage on a convenience fee.
It had to be a flat fee.
So at that time it was the board and council's direction to remove the fee. And since 2020 we have not had any type of fee associated with processing cards online.
So staff did look at what would a cost recovery option look like. And so one option is to implement the flat convenience fee. It would apply to Internet phone and kiosk payments.
It does not apply to any recurring payments. So if you were set up on auto pay for example it would not apply and it would not apply to point of sale where if you walked in to pay your bill it would not apply unless you used the kiosk.
The kiosk would be included. The fee would be disclosed as a charge for convenience with an opportunity for the resident to cancel the transaction if they didn't want to proceed.
To recover the full cost to process cards and checks based on the volume that we saw for the full fiscal year 2024 the city is estimated to need a $2.90 flat convenience fee per transaction.
There are a couple of tables here. The first is just to highlight that 97 percent of customer services utility billing transactions are on the Internet or over the phone which includes the IVR.
The IVR is the interactive voice kind of phone tree that you would go through to make a payment. Kiosks represent 0.2 percent and point of sale is 2.75 percent. So the vast majority of our transactions are occurring on the Internet.
If we look at two scenarios one is the implementation of a $1 flat fee that would and we back out any of the recurring or non eligible transactions it would recover $460,000 which would leave an expense of $880,000.
If we implemented the $2.90 flat fee we would recover $1.3 million and that remaining expense is $6,000 so nearly 100 percent of the card processing fees that we're incurring.
So taking a look at the customer service five-year PERFORMA this is an internal service fund and so the fund is the funds revenue comes from the departments who are utilizing its services so the implementation of a convenience fee would mean that the utility departments would be transferring less into this fund which would decrease their budgets.
And you can see just the breakout of what those transfers would look like. This preliminary view here does include the convenience fees as a separate line but DME pays the vast majority as well as water, wastewater and solid waste they're combined is the majority of the fund.
So for proposed 2026 $11.8 million in revenue including those transfers and convenience fees and then $11.8 million in expense and the fund balance would remain at $439,000.
The reason that there's any fund balance is just for an issue with the software, something unexpected within the customer service department that we would need some resources to deploy to remain functional.
Questions on customer service?
Let's go back to there, thank you.
Flat fee, yes. So that example that you're giving, that's not just commercial that's across the board.
It is, yes.
Are you all, we're at a stage where you're looking at do you want to do a flat fee $2.90 or not do anything, is that kind of the options, and are you all, is that coming back to us for us to then say yes, no, whatever?
Yeah, I think the feedback that we're really looking for is, is a fee of some kind to recover the expenses associated with processing, something that you would like staff to research, bring back options, or is it a non-starter, and you do not want, your recommendation would be that
we do not have a fee of any kind, and we leave it as is.
There are a couple different, the convenience fee is the best option, I think that we have, we have looked at some different things.
There's service fees, there's surcharges in the, in the merchant service world, they mean different things, and there's all these kind of niche regulations associated with them, but I really think our, what we're looking for is, at the end of the day, do we want to proceed with
looking into a convenience fee to implement at some point in the next fiscal year, we will bring it back to you, and we will present this to council for their feedback as well, but, but
we're not necessarily looking for a, we like the dollar better than the $2.90 or, I guess any, any feedback would be appreciated.
Why $2.90 instead of $3?
Well the reason, the reason is $2.90 is just kind of how the math shook out.
It's better than $3.
We certainly don't want to over recover and charge residents more than the actual fees that we're being charged, so, so that's why it's, yeah, $2.90.
So it looks like e-checks are cheap, like that comes out to like seven, 50,000 transactions, $3,000, it's like seven cents an e-check versus 400,000, like that's several dollars per credit card processing.
It seems like we would want to nudge people into the lower cost option.
So, is it possible to have two fees, like a 10 cent fee if you pay by e-check and a $2 fee if you pay by whatever, by card?
Because, because we would want to encourage customers to use the lowest cost option for their benefit in our, in the cities.
Yeah.
That's certainly something we can look into. I believe, and this is kind of where it gets into that regulation, you know, is they put both of those together.
They put the credit cards and the e-checks together under that convenience fee type of charge, so we would need to go back and see if we can differentiate within that different convenience fees, but I, we can look into, I don't know if it's possible.
Yeah, so that question there is just like, let's encourage people to use the lower cost option, it saves, it saves whoever, whoever it saves money, it either saves them or us or, you know, all the same money, so it saves somebody money.
The, the recurring, we're cutting those out just as a benefit for getting people to sign up for recurring, or we don't actually have to pay the transaction fee on a recurring?
Well, we, we do pay, however, the, you cannot charge a convenience fee on a recurring transaction, so that's part of that, the banking regulations as well, if you, if we were to choose to go with a convenience fee.
So, it would be one option, however, for residents not to pay a convenience fee is to be set up with a recurring payment.
And the other option, of course, is, is, is that point of sale to come in. Right, and I think, I mean, the point of sale, of course, is to drive across town, wait in line, you know, that's, that's a huge inconvenience, so it's definitely, people just grumble about their $3 fee.
I wonder, I want to, what I'm trying to understand is kind of rate impact and fairness here. If, if people who are paying month to month versus recurring payment are probably more likely to have to balance their finances week to week, so they're waiting until they can pay the utility bill.
If they set up auto pay, it's going to, you know, hurt them financially, where people who set up auto pay just don't care, like, you know, they've got the money in the bank, they're lease affected, they may have a higher utility bill, so they're actually causing a greater transaction cost, you know, or commercial accounts where a commercial account can set up auto pay, and they're auto paying thousands of dollars a month, and incurring $30 a month in charges where somebody's like struggling in their apartment to piece together their $80 payment.
Three bucks is three or 4% increase.
Yep.
So I wish.
I hate to kind of put the load on those that might be the most struggling.
And, you know, trying to come up with a way to make this this fair, and I almost wonder if not having a fee and having it just built into the, because then it will be spread evenly across all the utilities budgets.
Yeah, Mr. Teller, just let me point out that.
So DME pays, you know, almost 50% of that convenience fee.
That cost is born by all ratepayers right so so any rate payer which is the far bulk of our ratepayers that do not pay with credit cards that that use other forms of payment.
Those folks are carrying a portion of that cost in the base rate that we're charging them and so, so there's a level of subsidization that's happening here by us not charging the convenience fee on the folks that are actually driving those fees.
And I want to point that out as well I certainly understand. I'm not sure that we have a metrics to prove out that that the folks that you're saying are the ones that are actually doing that. I think we could make some assumptions about it, but I just want to point out that that cost, you know that one over $1 million is going to all ratepayers across the board for DME, but also for the other utilities.
And just to and just to clarify that are there additional transactions other than the Internet kiosk and point of sale.
Like cash, or just like, I guess a paper check mailed in is that like, we all the above we offer all forms of payments and that'd be the point of sale would be your probably checks and cash.
Yeah, and so, just looking at like 2% like so I mean really most things are some kind of the payment.
Yeah, so I would, I would lean toward it hides it, but it perhaps keeps it more evenly spread across by use.
Having it just in that base rate because that base rates based on kilowatt hours, or, you know, total bill.
So it might make it a little, a little more fair for everybody if it's just kind of spread across the entire rate base.
Yeah, and also just to give you some additional context. So if we're talking about about $1 million that DME is paying for these convenience fees, kind of the metric that we use about a 1% increase in base rates is about two and a half million dollars.
So you're talking about almost half a percent. Right. That's levied on on base rates.
As a result of this transaction, just to give you some additional context.
Susan, did you have something.
No, I'm just processing.
Okay.
Two things if they if they'll stay here, just trying to.
So the million dollars. In reality, we're not eating it, it's being paid over the spread of everybody correct.
Yes. So, I am and before
2020, we were able to the commercial was paying something but the residential was not correct.
Could we still have that kind of process, though there'll be a flat rate.
I would lean towards that for the purpose of there are people that, you know, four bucks is is a factor, a residential wise commercial.
They need to talk if that's if that's an issue for them. But I would I would like to see that type of concept where the residential since everybody's going to pay for it anyway. Okay. So that's in the hidden thing. But why have an additional cost as it were, in my mind, to the residential that could be hurting right now.
I would like to see them possibly get a pass and look and I'm not saying the commercial pays for the whole million dollars and such but but look at some kind of fee for the commercial but leave the residential alone.
Do we do we know how many commercial actually use a credit card.
I don't have the exact number but I do know that commercial business cards are more expensive because of the benefits and rewards than typical retail cards and so those are the more expensive transactions, which I believe was the reason prior to 2020 that I mean one of the reasons
it was applied to commercial is because they were the more expensive transactions to process that leads to a great question thought dovetail that if if they're doing the reoccurring in a sense the commercial could be slipping past that extra cost monthly by having reoccurring transaction.
Is that correct on a credit card. It, it would if it was recurring. Yeah, okay. Thank you. And they probably would do it that way. Well I would say money.
But at the same time, the cost is being met, and I think the residential is not carrying a heavy burden.
I think my most important, the most important thing to me would be to nudge people to each x, whatever, whatever we can do if we can separate that out to not charge a fee for that will eat the seven cents instead of incurring some other larger charge, you know.
But yeah, there's, there's a bunch of questions about the rate that it might be better just to keep it blended across or only charge certain, you know, larger transactions the rates but not charged for each x I really think is a safe thing if they're only seven cents.
I'm not into the numbers right now either. It's just the process.
I'm with you on those lines just and commercial pay residential not worry about the numbers will work that out, it'll come to itself.
You'll get it for us and then we'll say yes or something.
Where do online banking transactions fall in the volume.
Through my online banking to send it.
It would be in the, in the internet.
Just one more. So, this is not in the budget right now though, you're not assuming any savings in the budget in the, in the utility budgets.
We do not have this.
You just had, what was the.
Yeah, in this customer service pro forma, we are showing the line of the convenience fees. However, in the utility performance. We are not showing that savings currently.
Okay, so if the direction was, you know,
we'd like staff to, to look at implementing this.
We could go back and, you know, change the expense lines to show it what 40% of that's going to go to electric right.
Yeah, yeah, I would put out a couple things. So one convenience fees are pretty standard across all industries right so us actually not having a convenience fee kind of sets us apart from everywhere else our customers are used to paying right and so it's not
anything different.
The other thing that I'll mention is that, because where you may be going. So as we're looking at, at these expenditures and this is just one program of a number of expenditure reductions that we've that we've recommended in this budget right because of those
reductions, we were able to lower the assumed base rate increase that we had last year for 26, which was 5% down to zero. I remember, we don't reach our fund bound on fund balance until fiscal year 23 right.
So, if this is adopted, and you know, 40 50% of that comes to DME, it won't necessarily. We are recommendation would not be for you to lower the base rates, it would be hey that that could potentially get us to the minimum fund balance faster right and get us in a, in a much stronger financial
position so I would just, I just want to kind of point that out as well.
And you're right I mean, go to a restaurant and they bring you the little handheld look at your, look at your receipt. There's your processing fee right on your little receipt, so it's, it's what everybody's doing now.
And we know these are tough decisions but these are the questions that I think the board and others have had about DME looking at his programs and that's exactly what we're doing right and so if you say no to this, then what else are you going to say no to before you know it.
This little piece and the next piece adds up and now you're looking at a base rate increase. Yeah.
But let's remember this is electricity. This is going to McDonald's you got to have electricity, no matter what McDonald's you could cut back on. So this is this is an item that we're going to stay cool or be heated.
Electricity is got to be there so we've got to be very sensitive with that number I think more so than whatever one else is charging. That's just my opinion.
And along the same lines, we're going to keep the rate the same but we're going to add a fee, versus, we're going to have to have a half, half a percent rate increase and those, those come out in the wash like the same general cost so if we have a fee I just want to make sure it's, it's fair
and I'm like I said encourages the lowest cost option. So,
water wastewater and drainage, taking a look at the water utilities. The water utility department also includes streets as well. And in total there's 247 FTEs.
No change anticipated for fiscal year 26.
So taking a look specifically at water for fiscal year 2024 actuals 52.1 million in revenue 47.8 million in expense for a net change positive change of 4.2 million.
In the fiscal year 25 budget, or estimate in the current year, 54.4 million in revenue and 53.7 million in expense, resulting in a net income of 656,000.
Again I would just note, you know this is dependent on the way the summer ends up over the next two months.
Fiscal year 26 so an overall budget change of 6.3%.
We are proposing a 3% rate increase to residential and commercial.
This is in line with what we had forecasted last year for 20 as well as a 297% rate increase in the wholesale treated water rate, which has not been increased in an extremely long time.
Revenue projections of 59.1 million, expense projections of 62.7, so we are budgeting a use of reserve.
There are two vacancies that are anticipated to be held through fiscal year 2026.
We are in the middle of a retail rate study, wholesale rate study, and we also have included in the budget alternative financing sources, WIFIA, and the Texas Water Development Board.
WIFIA is a federal program through the EPA.
We've been looking at the alignment of our capital improvement plan to our investment portfolio, so from a cash management perspective we can ensure that we have the cash available when the construction expenses occur.
And also taking a look at affordability balanced with the construction and/or future growth of the city.
So the water five-year forecast proposed for fiscal year 26, as I had noted, was 59.1 million in revenue with 1.1 million, I'm sorry, 59.1 million in revenue and 62.7 million in expense with a use of reserve of 3.6 million.
This does include the 3% rate increase on residential and commercial base rates.
And that is primarily due to, I don't know if you can see it on the slide real well, but the increase in the debt service and that's associated with the capital projects.
The Water Fund, I will note, is above their fund balance target.
We anticipate in future years that will be drawn down again as the debt service increases as these projects continue.
But they are meeting the fund balance policy targets in each of the next five years.
And the debt service coverage ratio projected for 26 is 1.13, which is lower than the one and a quarter.
But as I mentioned earlier, when we go to issue utility bonds, revenue bonds, the utility system as a whole is combined.
So this would include water, wastewater, and DME.
So the Water Five-Year Capital Plan in total, 94.9 million.
Fifty-five point six of that is anticipated to be debt funded, which includes revenue bonds through Texas Water Development Board.
Thirty-seven point nine million in WIFIA funding and 1.3 million in revenue funding, which are the vehicle replacements.
And the water modeling.
Turning to, well, I guess I'll stop for questions on water.
Any questions on water specifically?
Have we adjusted all of our rates based on the recent weather or our budgets on the recent weather?
I mean, all the rain, cooling things off and giving us free water.
I can see three budgets.
I can say for DME, we are looking at our purchase power forecasts.
We plan to do that here in the next couple of weeks.
And probably by the time this budget comes back to you, we may have updated if things have moved.
Certainly, the weather's been a lot cooler than we had anticipated.
So that certainly has changed our forecast.
I can't speak to water.
Yeah.
So the way we currently forecast for future years is just an assumption of a, quote, unquote, normal year.
So not wet or dry.
Certainly, the weather in the current year will affect, you know, current year financials.
And we may see that -- I'll go back to that slide.
So we may see, depending on, you know, what happens with the weather, that $656,000 net income.
I mean, that may increase or decrease because the revenue isn't as high.
Not yet.
Okay.
But I will -- I mean, I will note that's really the reason that we keep and implement these fund balance targets
is because of that uncertainty, you know, with the weather and the utilities.
So as we experience, you know, plus or minus a million dollars in any of these funds,
it doesn't have a, you know, material effect on the rates when we have that reserve available.
Okay.
Turning to wastewater, fiscal year '24 actuals $36.7 million and $36.7 million in expense.
That included a use of reserve of $633,000, which was less than the budgeted use of reserve of $1.6 million.
So they ended '24 better than anticipated.
In fiscal year '25, the current fiscal year, $39.2 million is estimated in revenue,
which is slightly lower than the budget amount of $40 million and a net income of $197,000.
So the budget for fiscal year 2026, we're anticipating 12% increase.
Overall in the budget, an 11% rate increase, which was in line with the forecasted amount that we had last year for fiscal year 2026.
Revenue projections of $44.5 million and expense projections of $44.1 million.
And one vacancy is anticipated to be held through fiscal year 2026.
So again, 11% rate increase for residential and commercial. This is needed for the very large infrastructure projects that we're taking on.
With the rate increases, and you'll see that in future years, it steps down 9, 8, 7, 5.
Those, of course, are just preliminary based on how the actual financials work out.
But we do anticipate overall that the rates would decrease as we get moving on these projects.
We also do anticipate the use of impact fees to offset a rate impact to base rates.
And so that is also included in the budget for '26 as well.
How does the debt service transfers, you see them increasing, how are they in correlation to the rate decreases percentage wise?
Yeah, so a lot of that is due to an increase in the use of anticipated impact fees,
as well as some of the funding options that we have through WIFIA defers the payments five years after the completion of the construction
to allow for the growth to happen before those payments are starting to be made.
And those are, of course, projected so they could be fluctuating, and then we might see increases versus decreases on the residential rates to meet that, correct?
Right.
Yeah, okay, thanks.
So Wastewater Five-Year Capital Plan, in total it is $242 million, of which $141 million is anticipated to be debt funded.
$98 million is through WIFIA, and $2.8 million is revenue funded, which are the vehicles.
So again, $114 million you can see here is attributable to the plant, as well as I believe in the line replacement there's some fairly large projects there as well, which I have the list, I can take a look.
Yeah, so quite a large amount, but certainly leveraging WIFIA and the Texas Water Development Board is an important component of our financing plan.
So the 3% and 11% rate increases for water and wastewater, we wanted to provide a comparison of current residential rates as well as commercial rates and where Denton Falls, this selection of cities are the same cities that we had compared last year as well.
So Denton on the residential side, total water and wastewater rate is a little under, you know, half the comparison cities.
With the rate increase, we would remain relatively the same compared to our peer group. I will note that this does not include any anticipated rate increase for any of these cities because we don't know what those proposed rate increases are yet.
So we would anticipate that those cities would also increase their rates somewhat. On the commercial side, Denton is relatively in the middle.
And with the proposed commercial rate increase, we would be essentially right in line with McKinney, Plano, and Frisco.
Taking a look at drainage, drainage has 25 employees, no change for fiscal year 26. Watershed protection is also a function within drainage, but does report up through the Director of Environmental Services.
In the current fiscal year, sorry, ending fiscal year 24, $5.8 million in revenue, $4.5 million in expense with a net income of $1.3 million.
The drainage fund is a little unique in that we target a million dollars flat of reserve. That $1.3 million, we had intended to move it into a capital project for channel repairs and such in at the end of 24.
That didn't happen, so that balance is now in the fund balance of drainage. And so what you'll see on the next slide is that we're proposing to take that $1.3 million in fiscal year 26 and appropriate that transfer to get it into a project for it to be spent on channel rehab.
So overall, a 3.6% increase relative to the '25 budget. There's no proposed rate increase. Revenue projections of $7.1 million and the same on the expense projection side, but just remember that of that $7.1, $1.3 is that net income that we're pulling out of the reserve to put it into a job.
We also kicked off a cost of service study with Raftelis on June 27th, and so we're taking a look at drainage fees, which we will bring forward in the '26 budget process for implementation, potentially in 2027.
But we did want to provide just an overview of drainage history. So the current drainage rate was implemented in 2002. At the time, there was 3,300 inlets and 32 miles of infrastructure.
Flash forward to 2025, we have 9,218 inlets, 179% increase, and 320 miles of infrastructure, a 900% increase. And even though you don't see a big change in the budget, there's a lot of infrastructure out there that the city needs to repair and address and needs funding for.
So that was the purpose of kicking off the study, to identify what those needs are, what the rate should be in order to address those needs. But we just wanted to highlight that the rate hasn't changed in what will be 13 or 14 years.
That's 20, I'm sorry, 23, 24 years. So this is a drainage five-year PERFORMA. Again, fiscal year 2026, moving that $1.3 million into a project, and that will decrease the fund balance from $2.3 million to $1 million.
Looking at this, I apologize, in the out years, the beginning fund balance, starting in 2027, would revert back to $1 million with that transfer. So the policy target is $1 million. That's what we want to stick with. And again, no rate increases forecasted for next year.
So this is a general overview of the rate change summary. So in total, a $6.19 increase on the average residential bill and $9.43 on the commercial side.
I do want to note, on the electric average bill, we did pull the winter rates, not the summer rates in average. So it will be, as you look at the electric average bill there, we just want to note that the average bill is higher when you combine summer and winter rates.
We didn't catch that by the time this table was put together, but I did want to let you know. There is no rate change proposed for DME, but just the total bill. So the $6.19 is what we're approximating the additional increase would be for an average residential bill, which is water and wastewater.
I also just wanted to provide a history of rates. I think this is something that we had shown last year and perhaps the year before. So for a number of years, as you know, not only did we not increase rates, we actually decreased rates.
In 2014, in 2024, we increased electric and wastewater. In 2025, last year, we did increase all the utilities, with the exception of drainage. And then in 26, we're proposing only an increase to water and wastewater, which is essentially driven by their CIP.
Recommendations and next steps. What we're looking for today is just feedback in any direction that you have, thoughts you have on the preliminary rate increases for water and wastewater.
We already talked about it, but if there are any additional thoughts on the cost recovery option for online credit card or each utility payments and then looking ahead, July 28, we'll be back. So if there's any follow up that we can bring that you would like.
We'll go through any changes between now and then that have been made and then we'll be looking for a recommendation to council for the budgets and the rates. August 9th is the budget workshop with council.
Again, that's all the citywide departments. August 19th is a follow up a work session with council. And then September 16th. I think I'd actually said the 17th earlier in my comments but September 16th is the anticipated budget and tax rate hearing and adoption.
Miss Parker, could we get a bigger breakdown on the electric and the wastewater capital projects. Sure. I know that they're all kind of lumped together but be helpful to see that as possible. Thank you.
They're just a very big budget so yeah, sure. Yeah.
Yeah, I think this, you know, nobody likes a rate increase.
However, we have one and a half billion dollars in capital improvements plan just in the water side.
And some of that is replacements and maintenance, but most of that is treatment expansion growth, it's, it's new drinkable water, and it's new wastewater treatment to to meet the growth needs that you know that Denton is the growth that Denton is experiencing.
And so, you know, I appreciate that all the work that's been done to look for Texas Water Development Board with via funding these these funding options that have the lowest cost and the best terms for the city.
You know, and I know impact fees are always a challenge, because some folks are fighting them as much as possible but that's that is a way to keep long term residents from paying for new growth.
You don't know when the impact fees are going to show up that developments going to come in two years or five years or 20 years.
You know, and I know we've worked really hard, the city especially has worked really hard to try and, you know, implement those fairly so I think that it looks like these rate, these rate increases are inevitable to meet the growing needs of the city.
I also wanted to just make a comment, you showed all those cities, the comparison cities, and the ones that are cheaper than us are the ones that are have no like they're completely landlocked, they have not, they're not building new water treatment plants
they're not growing. Right. And so they have the lowest capital cost, they're maintaining infrastructure not building billions of dollars in new infrastructure.
So we're, we're in between we've got a lot of existing infrastructure, but we've got quite a bit of growth coming to.
Yeah, absolutely.
I guess we're moving along then. Thank you. Is that your presentation. Thank you very much.
We'll move on to item B. Is that correct.
Just a second I got the wrong presentation.
Oh,
I'm sorry about that. I had the wrong presentation up here.
Thank you for your time today.
I just fair warning this is a pretty long presentation so so kind of stand by.
Before I get started, just want to kind of open it up with a couple things. One, I think just to allude what you said earlier, the weather has been much different. I do want to acknowledge you know Jose Gaitan and, and Tony Roybal and the rest of our energy management group with the work that they've been doing and certainly I think, you know, they do a fantastic job and helping kind of keep keep rates low.
They manage all the purchase power costs for the utility right and and do get very creative and have a lot of information at the disposable to a disposal to be able to make good decisions of when to buy when not to buy went to lock in and and those are sort of things I think certainly with the budget that you've seen is really to a large extent attributable to the work that those folks do.
Second, you know, I know you've, you've heard probably a lot about this particular topic over the last couple of weeks appreciate member Rainer to requesting for it to come here we've had eventually planned to come here but certainly he got a little bit ahead of me but but I appreciate that.
A lot has changed over the last few weeks just to be honest with you, mainly driven, not just at the state level but certainly at the federal level.
At the EPA, those federal agencies aren't quite what they used to be right. And so, the economics of plants, not just in Texas but across the country, both for natural gas fired and coal fired plants.
Things just changed right and I think from from our perspective, what could have potentially meant a particular particular deal that that could be made on the market.
I think the economics of likely changed, including the fact that since making the presentation. We've, we've, we've had folks reaching out to us right about kind of what our plans are.
Okay, so I just wanted to kind of kind of preface that we counsel they give us direction I'll kind of mentioned to you what, what they said when we presented this to them but certainly we'll, we'll dig right into into the presentation so just a few items here that will that will cover today,
again, pretty long presentation.
So, just to kind of start off. Yeah, this is one of the questions that we have was, you know, kind of how does DME work. So we wanted to kind of explain this I mean this is kind of a typical summer day that we see and so certainly isn't always quite the case.
And, and the blue line across this is, this is really how our load works. And so this is our low profile. Generally, our peak load is about, you know, between four or 430 in the afternoon certainly based on our four CP.
That's when we kind of tend to see it. And that's normally what what the planning processes for our folks of how they're planning to, to use and leverage not just the deck but certainly renewable resources, how they're forecasting what that load maybe and then kind
of the normal process of doing the forecasting, certainly if weather changes demand changes summer 23 is a perfect example where the man just stayed high because temperature stay high even, even later on into the afternoons and so, again, that was not
something that was easily forecasted and so that gap between what we had covered, and the exposure that we had to to what's called you know the, the same day market right, you know really forces to acquire additional power at much, much higher prices
so. So this is, you know, and we'll talk a little bit I'll talk a little bit about the duck curve I'm not going to show the picture of the duck. I think a lot of you are familiar with that.
But you can see here, you know, this time at one o'clock in the morning, you know when you know starts to die down and, you know, usually around seven o'clock in the morning.
It starts to come up and so this is kind of our, our, our renewables solar renewable and you know they tend to peak, kind of in this area, certainly a cloudy day, you know, a stormy day.
And certainly there's congestion that happens in the transmission system that also kind of, you know, causes issues where maybe not all the solars there and, and so there's curtailment as well that happens and that happens across not just the PPAs that we have but really across all the various renewable resources.
So in the afternoon about meal seven o'clock sun just comes down and it's pretty precipitous right it happens, you know, almost instantaneous right and so if wind doesn't begin to pick up.
Those are kind of really the the hours we call kind of the scarcity period really ranges from about you know for about five, no excuse me, about seven to 10 o'clock in the afternoon and so that's normally your kind of your typical
summer day winter. It's actually a two scarcity period certainly we have the afternoon during the winter but but also, especially during the winter we see start to see that here as well.
You know if if certainly if wind dies down and the sun doesn't begin to shine. You start seeing some scarcity periods here in the early morning hours as well you know seven to 10 o'clock in the morning.
You know winter makes for a lot of anxiety at DME as we're managing these resources.
You know generally during the day during this period of time when when the sun is shining and certainly want to say that you know when the solar resources certainly during the day and even even at night.
We have kept prices low right and not not a whole lot of a demand that's in that up that's really driving that price. I will say data center development certainly by way of artificial intelligence is starting to eat up a lot of those cheap
priced hours right and so so what we're seeing it was being forecasted is that as those data centers you know start to come online, they start eating up a lot of that cheap power, the price of power is projected to continue to increase.
And just to just to kind of remind you know I've said this, we've said this over the last couple of years.
10 gigawatts that's 10 gigawatts of projected data center load in the DFW area alone.
And just for some context that 10 gigawatts is the same amount that was projected to be incentivized to the Texas Energy Fund, which that 10 gigawatts was really to replace retiring assets right.
And not to scare you but in the entire state of Texas, 80 gigawatts of data center load is what ERCOT is projecting right 80 gigawatts that's almost the entire generation fleet in entire ERCOT market right so so certainly a lot of a lot of pressure that that we're seeing
coming down down the pike. Certainly, things like like tariffs haven't been helpful. Other other decisions at the federal level. Certainly when it when it comes to renewables disincentivizing getting away from tax credits we'll talk a little bit about that as well.
Certainly, projected to cause power to the cost of power to increase.
For example, you kind of were looking at us like, what do you mean you're projecting zero. Well that's on the base rate side right on the energy side that's something that will be looking at on a quarterly basis with you and I think that's where you'll kind of begin to see that.
August of 23.
You know certainly we incurred $31 million worth of debt.
The debt will point out the debt price strike price is about $35. So, so I will tell you that the deck is based on economics right and so. So once we get above that strike price prices start to climb above $35 the deck begins to run.
And that's what you see right here right so around noon, kind of a typical day, the deck begins to run and it's there, and then it goes up pretty steady right. And so winds up happening is so as the deck continues to cover, you know, quite a bit of our load.
It doesn't cover our entire load member we have 225 megawatts is what the deck covers our peak load is 400. And so there's a, you know, a shortage there about 185.
And so now, as long as those renewables perform, we're pretty well covered right and then we're doing some financial transactions physical transactions to try to cover some of these gaps as well.
Both in the afternoons and certainly during, during the morning hours, the deck, you know, at night tends to run as well, but not quite as much wind seems to be a little bit more reliable in the evenings, then, then, then sometimes solar in the afternoon so, but that's generally how, how we work and that's just really a typical day.
I can say that not every day is the same. Right. And so our folks are continuously monitoring and watching you know both the weather and a number of other issues across the state.
They monitor the transmission system, looking at what's going on with, with other resources across the state so it only takes one very large generator generator to fail to cause some some hiccups and some, some issues for us on a price standpoint.
And so, again, you know, it's really, you know, these, these scarcity periods that we're looking at, just as a reminder, during winter storm URI, the scarcity cap was $9,000 a megawatt hour.
And if you remember for URI, it stayed at 9,000 for almost four days right and we incurred over $200 million worth of purchase power expense.
That did change after URI dropped down to $5,000 right so but even at $5,000 what we saw in '23 that we incurred just for a few days, $31 million worth of debt.
Certainly if that had been 9,000, it would have been, you know, much larger than that.
I will say that at, at the state there's, there's continual discussion about that scarcity cap and how to incentivize additional generation.
There are some that would like for that scarcity cap to be moved back up to 9,000, but there's some on the private side that want that cap completely removed.
And they believe that, you know, if you charge whatever the market will bear, that will send enough signals into, into that, that industry to build additional generation but again we'll, we'll see kind of where that goes today.
It's $5,000.
And so, and so these are all numbers that we've shown before in various presentations, certainly as we've talked to the board and the council about the data center.
But today as I mentioned, peak load is about 400 megawatts.
So we stand at about 180 megawatts short from a dispatchable generation standpoint.
Just a reminder, and I mentioned to you when we talked about the then renewable resource plan. While you know disaster was somewhat averted this last legislative session.
There's continued to be interest, and there was certainly movement to have all load serving entities like DME in the state of Texas to back up its entire peak load with dispatchable generation.
But at this point, that at the state level when they talk about dispatchable generation, that doesn't include wind and solar resources, and it does not even include battery storage right and so it was very clear.
You know, I know, you know, remember, remember, I had the same kind of kind of perspective but that's the view at the state level internally.
The legislature creates these bills and the PCT sets the rules. That is kind of where they're going right. I'm not saying that I like it or I agree with it. I'm just kind of giving you the facts.
So, so that was certainly averted other efforts there as well to, to require all existing wind and solar renewable projects or resources to have a backup firm dispatchable generation that did not pass but I want to be clear that the 88th legislature
did pass HB 1500 that will require all new renewable resources after 2027 to have to be backed up with dispatchable generation again, and dispatchable generation is not battery right and so again all those efforts are still there and so kind of, you know, this is the context that we're operating on.
Certainly we believe that by 2023, that peak load will will certainly reach over 600 megawatts increasing that shortage to look a little bit over 300 megawatts.
By 20 to 2044, that peak load will be anticipated to be at 900 with 675 megawatts. And so, you know, as we talk with a little bit about kind of the recommendations we're making certainly those are the basis I will point out that native load growth is projected to grow 100 megawatts by 2036.
And, and then our forecast that we've provided to you does not include any additional large load or large loads coming in into the city, but I will point out that we continue to have prospects and interest in folks wanting to locate right here in Denton.
And again, I'll just remind you 10,000 gigawatts in the DFW area and for the last time I looked at the map we were, we were part of that area right so certainly goes to to show the the continued interest here as well.
And then we'll talk a little bit about the about this duck curve right you know there in the summer, you know, six o'clock to 10pm in the winter it's kind of a to to peak time 7am to 9am roughly 6pm to 10pm in the afternoon so just for some context normally that scarcity period in
the afternoons is about a four hour type of period and I'll talk a little bit about some of the conversations we've had about battery storage within the context of that for our period that sometimes can extend to five hours and even even six hours in some time.
As I already mentioned, the scarcity pricing. I will say that when the solar generation, certainly from a DME perspective, does not meet the need that we've identified battery storage may be marginally viable and we'll talk a little bit about the economics
and the technology and certainly there's some things that are coming that are think that I think are exciting and, and there might be some future planning for us to do in that particular case.
I would also point out the fact that, you know, as we look at some more sister utilities, certainly on the on the public side.
There's really no investment going on on on battery storage. They tend, they tend to do exactly what we're doing and that's looking at power purchase agreements.
We are currently working through that particular instance that we do plan to come back to you and talk to you about a particular resource that we've been that we've been negotiating with and we're hoping that in the next few weeks, will be in front of you to talk, talk about that.
Talk about the economics and get your recommendation on whether to proceed or not.
I talked a little bit about winter storm. You're very well aware, you know, hundred and forty million dollars of net cost that we financed over 30 years that will not pay off until twenty fifty one.
And in summer of twenty three that thirty one million dollars we financed that over over five years and the payoff on that is twenty twenty nine on that kind of alluded to that and you can kind of see that in in the forecast as well.
And just for some context, winter storm Uri, that's about seven million dollars of annual debt service that we're paying for summer of twenty three.
It's about seven million dollars. Right. And so, again, you know, those are just the cost that we've incurred primary needs of consideration.
Certainly we believe that dispatchable quick start generation continues to add that to post value compared to other resources. Certainly as we're looking at what other MOUs are doing, I will point out that and I'll show you in a chart here.
Kerrville Public Utility Board in the city of Kerrville did recently receive approval through the Texas Energy Fund for a quick start generation facility.
They are they were the only MOU that applied and they were the first very first resource that was approved here not too long ago to to build that facility.
But other other MOUs like CPS Energy, Austin Energy, Greenville right down the road where our very own Bill Shepard will now be the GM.
They're investing in quick start generation, Brownsville, Bryan, Texas Utilities. And so as we're looking at what others are doing, certainly quick start generation is is what's kind of on on the menu, if you will.
And what those utilities are deeming very similar to the recommendation that we're making here about what we need kind of long term.
And then the only and there might be the conversation today is going to be about the possibility of acquiring an existing generation facility.
And we'll talk about what may be available out there. But we certainly think that when we're looking at delivery of turbines or combustion engines, the delivery projected delivery, if you ordered them.
And I say today, really, you should have been in line probably a year ago, two years ago. You're talking 20, 20, 30, 20, 31 before you get delivery of those. Right.
And so so certainly the longer that we take and making the decision receiving direction, if that's ultimately what what the board and the council decides, we're looking at much longer than that.
And so, again, that just continues to pose additional price risk for for our repairs. So the thought was, you know, it could there potentially be an existing facility out there that might be worthwhile looking at and potentially acquiring as a way to speed up getting some additional.
I'm not going to say I'm going to say it right, but not necessarily steel on the ground, but be able to get the generation faster than waiting until we build kind of a greenfield development again.
I think the economics of that potentially has changed, but certainly may still be worthwhile exploring a couple of things that I'll point out as we're kind of looking at, you know, geographically, what makes sense, what may be available in our kind.
We'll talk a little bit more about that. We certainly believe that that not putting something or not buying something within the city, then makes a whole lot of sense.
One, there's really not other options within the city. There is one additional facility, the Spencer station that's right there right next door to us that's owned by the city of Garland, but that certainly wouldn't meet meet our needs.
But again, wouldn't want something else in the city that would be a competing resource to our existing generation facility and then an acquisition of an existing facility could potentially pose kind of a net zero impact from an environmental standpoint.
It's a facility that already exists.
As an example, CPS Energy did buy recently, well within the last year, two coal plants. Those were existing coal plants. They do plan to continue to operate them, but the ultimate plan is to convert them from gas to cleaner natural gas and also then kind of get some of the benefits of the environmental impacts that are there.
A couple of other things that we think might be possible, you know, potentially there could be opportunities for some type of public-public type of relationship or partnership and then also public-private partnership.
You know, you may have heard in the media and other places that, you know, data centers are looking to build their own generation and in some states are being required to be co-located with generations.
So you may have read that there was a large data center in the East Coast that bought an old nuclear plant and they're refurbishing that.
And so I think there might be some possibilities there as well.
Again, nothing that we've explored, but certainly as we're kind of thinking through what might be out there, I think those opportunities certainly, you know, create economies of scale and then certainly, you know, cost sharing for our ratepayers.
You know, as we're looking at what that gap is in generation to our load, you know, kind of the general rule of thumb is that until you need about 1,200 megawatts, you're really not looking at some type of base load unit.
Really, that's kind of the magic number I think that's in the industry is once you need about 1,200 megawatts, now you're talking about some type of base load unit.
And, you know, the difference between a base load unit and a quick start generation is quick start generation only runs when it's needed.
A base load unit, because of the ramp schedule, has to stay on pretty constant and then you still have a delay to kind of ramp that up.
And so again, the economics are a little bit different, but certainly as you're looking at growth in DME and the load, certainly I think a base load unit at some point might be worthwhile.
For some context, so Austin Energy today has a peak load of about 6,000 megawatts.
Remember, ours, we're at 400, right?
There's 6,000, right?
Now, they have a million customers, right, compared to our little bit over 70,000 customers.
They have over 8,000 megawatts of dispatchable generation now, so they're 2,000 megawatts long, but they're anticipating that that load will continue to grow, right?
So then we'll eat up that 2,000 in the coming years.
In the short run, what they're doing is they're selling that power forward, right, into the market or they're entering into power purchase agreements, right?
And just to be clear, you know, those are the types of things that we're doing because we don't have dispatchable generation.
Certainly we're doing financial transactions, but some of those financial transactions are physical energy, right?
And so that physical energy is being contracted through these other types of resources that exist out in the market today.
So I want to be clear about kind of what's going on in the market there.
And then as a market participant, certainly something that we want to be clear is that, you know, we are, you know, roughly 1% today of total ERCOT market.
We are as responsible for reliability of the grid as anyone else, right?
We're in a commingled grid that has to maintain a certain level of frequency, right, that's 60 hertz.
I'm not an engineer, but I have plenty of engineers here that can come up here and talk your ear off about that.
But from a reliability standpoint, right, we're all in the same boat, right, to make sure that the grid stays stable and stays reliable.
And so I think it is incumbent upon us to also be looking at how do we continue to share in that as well.
So certainly there's the financial component, but then there's also the reliability component as well.
And then finally, just to clarify further about the DEC.
So I just want to be clear that the DEC, nor our renewable resources, nor any other resource that may come online, all those resources feed into the same grid, right?
They do not provide power directly to our customers.
That's certainly, you know, and I know that Steven here can tell you that, you know, water takes the path of least resistance.
Well, you know what?
Energy is the same way, right?
And so from a physics standpoint, certainly I think that the power that the DEC generates certainly stays in this region, right?
But it does not necessarily flow directly into our customers.
Certainly we cannot disconnect from the grid.
Now, physically, we could, but as a market participant, there'd be some pretty heavy fines for us to do that, right?
So some questions that have come up and as also, you know, so, well, how has the DEC performed?
The DEC is a money loser.
The DEC has a stranded resource and a number of other things.
And I'll tell you, you know, in my past life working in the finance department, I will tell you that, you know,
this isn't necessarily in keeping with governmental standards, right, accounting standards.
And it's not how we present the DEC in our financial statements.
But I think for just as a picture for you, Mo and DME or all its resources, whether it's generation or transmission,
we're a fully integrated income statement, right?
And so this isn't how the income statement really looks.
But just for some context, if it was a separate entity, this is how it would likely look.
And so over these number of years since we began operations 2018,
we certainly believe that the DEC, based on our financials, has earned a little bit over almost $260 million of gross income or also a gross margin.
So what is gross margin?
Gross margin is the revenue that we get minus fuel and some variable expenses, right?
That doesn't include our normal operating expenses for personnel.
It doesn't include debt, right?
So now when you start including all of the fixed expenses and personnel, certainly you look at, you know, the debt that we're paying for the DEC.
That's about $18 million is what we're paying on those revenue bonds.
And then you layer in here as well, you know, winter storm yearly, you layer in here summer of '23.
That was a request that we made.
At that point, now you're talking about net income of about a little bit over $100 million, right?
So again, certainly, you know, the DEC has generated quite a bit of income.
And also for your information, so that gross margin that's reflected on here on an annual basis,
that gross margin, if you remember how we calculate the ECA, so the ECA, right,
is really our purchase power costs, right, franchise fees, RRIs that are paid, right?
And then the first thing that we net off of that is the gross margin from the DEC.
And then the net cost of energy is what we pass on to our customers by way of ECA.
And so then that roughly $60 million a year in revenue that we're getting from the DEC is going there to pay for that, right?
If the DEC was not there, that's $60 million.
And it would likely be even more, right, because we would lose that hedge.
We'd have to go out there and do other physical energy.
We strongly believe that that cost would be even more, right?
Now you wouldn't have that $60 million there to offset, you know, what you're charging to your customers.
And so certainly you can kind of see how the numbers would flow.
And again, currently, you know, a quick start generation facility, you know, is covering about $60 million, roughly.
If it wasn't there, you know, kind of stated that.
And so as we're looking at the economics of another particular generation facility, certainly at a $300, $600,
we're looking at how that can continue to offset the purchase power costs that we have.
And it will eventually pass on to our customers.
So a little bit about -- a little more about the kind of just, you know, power trends in the market.
This is just a random day that I picked.
It was -- there's not any particular magic other than this particular day, you know, there was quite a bit of sun, right?
So as you see here, right, you know, I mentioned to you previously around 7 o'clock in the morning, the sun comes up.
And it's going to stay pretty high in the sky and cover pretty good and then just kind of begins to drop off precipitously, right?
Here in the yellow, I mean, you still have, you know, two nuclear facilities that are pretty constant.
You now have kind of coal, still constant, but certainly is starting to diminish in the market.
You certainly have quite a bit of natural gas that even when solar is producing quite a bit,
you still have as much as, you know, 40, 50 percent in some cases of natural gas generation that's happening.
And then you have certainly -- you have wind that drops off right during the day.
It ramps up, you know, as well.
And in this little red, you know, piece here, that's kind of the battery storage, right, that's out there in the market.
And that continues to develop and it continues to grow.
Certainly, we think that, you know, there might be opportunities there for that.
Certainly, at some point, they will reach a competitive point where it may not be economical for them.
And again, this is just kind of the mixture today.
So here in this particular day, at noon, solar made up about 39 percent of the total generation at that particular point.
So this is kind of right at noon.
But even at that point, though, if you look at natural gas, natural gas was still over 31 percent in that particular moment.
Here at 8 o'clock, so this, you know, 20, 100 hour, this is where you see battery storage.
So battery storage at that point was 940 megawatts, not a small amount.
But it only made up about 1 percent, a little bit over 1 percent of the total generation that was needed there of 74,000 megawatts.
So again, this is all in a perfect scenario, right?
Sun's shining, plenty of sun, wind's showing up.
It's when those things don't show up or there's some other factor that all of a sudden this fleet of natural gas is there to kind of back up all those resources.
Question. Yes, sir. So battery storage, is that the only power storage option that's on that graph?
There's no other stored hydro or anything like that.
There are. You know, you could see here, kind of at that time, you know, here's hydro was a fraction, right? It was 207, so very small.
There's some other smaller types of generation out there as well.
Austin Energy is an example, is looking at a geothermal facility.
You know, for some context, it's a five megawatt geothermal facility that they're going to plan to do in Nacogdoches, Texas.
Their peak load is 2,700, right?
So just some context, you know, five megawatts doesn't do a whole lot.
And I can tell you, in talking to my counterparts in Austin Energy, the folks in Nacogdoches aren't very excited about a facility that might, in their view, may cause earthquakes, right?
So again, there's a number of proponents and opponents to whatever type of facility that you engage in.
So does that answer your question? And there is no pumped storage in Texas.
And I will also point out, just to talk to my folks, the battery storage that you're seeing out there in ERCOT today is you're talking about one hour duration battery, one and a half hour duration battery, two hour duration battery.
While there is talk about some four hour duration, the six hour, that technology is not there, nor the economics.
Now you're seeing some out in other parts of the country, but normally it's about a two hour duration.
So you take a 300 megawatt, you know, battery farm that's a two hour.
What they're doing is they're actually splitting that in half, right?
And so it's really you make it a four hour battery.
Now it's 150 megawatts facility, right? Instead of a 300 megawatt facility.
Again, those are things that they're doing really from an arbitrage standpoint, right? And I'll talk a little about kind of some of the arbitrage games that some of these battery facilities are doing in the answerly services market, right?
And versus necessarily taking that price arbitrage. So certainly arbitraging on the answerly services side.
And then two particular days, just to show you the differences, and this is something, all these graphs are graphs that are available on the ERCOT website, right?
You can just go to dashboards and you can see all these at any point in time. You know, they're constantly up on our computers and we're monitoring these.
But on this particular day, you can see the dotted line was kind of the price formation that ERCOT had anticipated the day before, what would materialize.
And in the solid line is the actual price formation. And so for the most part, it followed quite along.
I think ERCOT does a good job of projecting this. But then in the afternoon, something happened.
And all of a sudden, when they thought prices were going to be about $100 a megawatt hour, they shot up to a little bit over 150, right?
And remember, this can shoot up all the way to 5000, right? And in this particular day, on June 11, two days later, again, you could see the dotted line of what was projected.
And I didn't get what it ultimately ended up in. But I wanted just to point out that even in the morning, something could happen, right?
That all of a sudden, prices here were going to be below $40, and all of a sudden, they shot up about $75, $80.
And again, all of this can go up all the way to $5000, right?
So if we've not locked in enough, if we've not forecasted our load and all those things miss, then certainly now we're exposed to that.
And we don't have enough generation to just push a button, right?
At the same time that I'm buying power at $100, at $5000, I'm not selling power for that same amount to kind of offset that, right?
That's what the quick start generation allows you to do, right? Because again, within five minutes of us sending a signal to the engines, assuming that we have fuel and then mechanically the facility, right?
It is, in a day, it's a mechanical piece of equipment no different than your car, right?
Within five minutes, it's pumping out power, right? And we're selling power at the same time that we're buying power, right?
And so no other resource out there really can give you that.
Certainly, wind and solar, you know, it produces when it's producing, right?
So just talk a little bit about, you know, Matt alluded to this as well, kind of what I've shown here.
He showed the summer. This is the winter. If you're on the residential side, we have a summer rate and we have a winter rate.
And so this is the winter, excuse me, the summer rate, which tends to be the higher rate because at that point on a base rate side, which is where we have this bifurcation.
During the summer, months of April through October, that rate is roughly six cents a kilowatt hour, and that's for all of your energy, right?
In the winter, it's bifurcated for $600, it's six cents, and then anything above that is that four cents, right?
So I just wanted to clarify that here. So on average, you know, per kilowatt hour, our current rate is about 14.2 cents.
We believe that without the DEC, that rate would probably go up to about 15 cents.
We think that with additional generation investment, we could keep that rate pretty stable at about 14 cents.
Without the additional generation, you know, we think that rates will potentially continue to climb up to 15.
And it's something that, you know, that we hear from our customers.
And just to be clear, you know, I've heard more from our customers about our rate increases than about, you know, whether or not we have sufficient renewable resources.
But so there's a website you can go to at the PCT called The Power to Choose. I haven't updated this, so this is a little bit dated.
But at the time that I looked at it, kind of the average in the IOU market, right?
So if you were in a deregulated area and you could pick your own provider for a 12-month contract, you're looking at a little bit over 15 cents per kilowatt hour.
About the 24 months, now you're looking at 15.8 cents, something that I would just point out, this was called the polar rate of the provider of last resort.
Generally, if you're in a competitive market and your retail electric provider, your REP, goes out of business, you generally go to what's called the provider of last resort.
In this area would be TXU Energy. And until you get a contract with them, you pay what's called the polar rate.
That polar rate is about 19.8 cents, right?
And now, again, these are the averages, but generally speaking, you enter into a 12-month contract, 24-month contract.
If you don't renew that contract, your REP then transfers you to the highest rate that they have, right?
And so for customers that, you know, life happens, they forget, but managing that brings another level of complexity.
In the city of Denton, we don't do that, right?
In the city of Denton, you pay a fixed rate, albeit a different rate during the summer and one during the winter, but you don't have to worry about, you know, oh, I've got to renew that 12-month contract, the 12-month contract.
Or is there a special deal? Certainly, there's some gimmicks, some marketing gimmicks that are played by some of these REPs.
As an example, one that I looked at, they offer a very lucrative 11 cents per kilowatt hour rate, but only if you meet very specific, you know, requirements.
And if you don't, you don't get that $90 bill credit, and then your rate goes up to roughly 20 cents per kilowatt hour, right?
So then, you know, to the level of sophistication has to be there, and also tension as well, that poses just some economic challenges for our customers.
But again, from a comparison standpoint, we certainly believe that the rate that we offer our customers is very competitive, both from an IOU comparison, but also even when we look across other MOUs.
And for some context, too, here's just what the current rates are for our commercial customers. Those are broken out into currently we have three classes, the general service small and general service medium.
I won't read all that here to you. And in general service large, we are also currently looking at an additional category that we're going to lovingly call and creatively call the general services extra large, right?
Which would just be for large loads, right? And so very similar to what we've recommended on the ECA, we're certainly looking at that from a standard tariff standpoint.
At that point, large loads go to that tariff and wouldn't necessarily be a need for a PPA, unless there's some special circumstances.
We'll also be looking at that on the TCRF side as well that will be coming to you before too long.
So as we think about the possibility of acquiring an existing facility, certainly just to be clear, I think there's limitations here of what we're talking about.
But certainly geographic location is something that we want to look at. It certainly has to be something in ARCOT.
And I'll show you a map to show you that not everybody in the state of Texas is in ARCOT, right? About 98 percent, but not everybody.
You know, certainly there's a preference that it be in the north load zones. I'll show you kind of what do you mean by load zones?
I'll show you what that is. And then certainly not in the city of Denton. Generation type, I think, would also be important.
I think nuclear, you're talking about currently two nuclear facilities, although there continues to be growing interest in nuclear, not just in the state of Texas, but certainly across the country.
But I think at this point it would probably be unlikely, but from a cost perspective, but really there's only just two.
Coal and lignite, certainly those continue to be out there. I think there's probably more uncertainty on that. Certainly there's concerns about environmental remediation and issues.
Yeah, move on.
And then design, you know, baseload versus quick start, and then capacity. Those are some criteria, I think, that we've kind of thrown out there that we may be interested in looking at.
So this is a map of the state of Texas. Everything in color is ARCOT. You got SPP out here on the panhandle. On west Texas you got WEC, and then you got MISO here kind of on the east side.
This in blue is the north load zone, and so I think ideally we would be looking at something really in this area, I think from a management standpoint makes sense, but certainly anything in ARCOT could potentially be at play.
Just the history of kind of what generation types have been in the state, you know, going back to 2021, the one thing that I want to point out here is that, you know, coal and lignite just continues to drop off.
Certainly, you know, that may change here pretty quickly, right, as efforts at the federal level are going into play.
And then, yeah, even though I think natural gas has been pretty steady, you know, some of these peaks, excuse me, some of these peaks have started to come down as wind and solar generation has come online.
But again, I think all that may be changing as well.
And then just kind of quick accounting of what's out there, 4,700 megawatts of nuclear, 1,600 megawatts of coal and lignite, 12 facilities, natural gas, there's about 100 facilities, and about 6,500 megawatts.
And I did provide in your backup kind of a listing from the most reliable source out there called Wikipedia, right?
The only place I could find a single place where everything was identified, so kind of, you know, take that with a grain of salt.
And then for the Texas Energy Fund, these are the facilities that applied initially to the Texas Energy Fund.
Just a reminder, that was approved by voters in November of '23.
It was up to $10 billion, about $7 billion of that would go to spur about 10,000 megawatts of generation.
And that's what kind of this number kind of approximates.
Everything within Asterix are projects that have now fallen off.
They've withdrawn from that, right?
But I think our viewpoint is, right, a couple of things that were required.
One, you had to have site control, and two, you had to have a design, right?
And so even those facilities with the Asterix, hey, at some point that particular company or those entities had site control, had, you know, a design somewhere on the shelf, right?
So we think that, you know, those could be potential areas that we could also look at, at trying to acquire.
And the vast majority of these were quick start generation facilities.
And here's Kerrville.
The other non-IOU is Rayburn Electric Cooperative that submitted.
And then just as an update, those that dropped off, there was replacements, right?
So this is just an updated.
As I mentioned already, Kerrville has recently been approved, the first one that was approved.
And so just to wrap up here, kind of the options that we discussed with Council, certainly here today was option one, is to explore opportunities for future acquisition of approximately 300 megawatts of generation.
We think that if we're able to do the battery storage, that that could, you know, buy us some additional time before we would have to add an additional 300 megawatts.
Option two would be 600 megawatts.
Coupled with the battery storage, we may be a little long, but certainly, if you remember what I mentioned about our load forecast, that load forecast is somewhat conservative, right?
So just like we're short today with the deck, even if we add 600, we could very well be short come 2036 or 2044, right?
And so certainly, taking a longer position may not necessarily be a bad place.
We certainly believe we can get that monetized.
And then option three would be to do nothing, right?
And, you know, you previously, you and the Council previously gave us the go-ahead on the development of an integrated resource plan.
We think that that process would take 18 to 24 months.
We would, in essence, wait until that's done.
We certainly think that at that point, if there is going to be new dispatchable generation, at that point, we're likely looking at a new greenfield development versus acquiring an existing facility.
And then on June 17th, when I presented this to the Council, the direction that we certainly believe that the Council gave us was for us to explore options for 300 to 600 megawatts of dispatchable generation.
We've not yet kick-started that process, but certainly, it's something that we do plan to begin.
There was some direction from the Council to try to get or to give the public an opportunity to weigh in on that.
And so certainly, we're thinking about how best to do that and manage that going forward.
So with that, happy to answer any questions or get your direction.
Anybody got any comments?
Mr. Rayner.
So on the quick start generation, is that what I used to call cold start, primarily, such as the Spencer plant, so that's a gas operated?
And is it raw water type of, is that used in there as well or no?
No, there's no water required at the deck.
You know, certainly we have, you know, the engines that we have there, the Wurzel engines are reciprocating engines.
There's these jet turbines that are also available.
I think that likelihood we would be recommending at some point.
Both of these facilities now can be coupled with some battery storage as well.
And it changes the emissions profile.
Certainly, there's a cost to it.
But what happens is that today when you cold start the engines, they're cold started with natural gas.
So when you couple them with the battery, it's the battery that actually gets the engine started.
And so you limit some use of natural gas to just change some of the emissions profile of some of those facilities.
But then the other thing that I would point out, too, is that while the deck could be a dual fuel to convert it to some other type of fuel,
in the case of the deck, it would be diesel, would take some time.
And so I think as we're looking at future technology, having a better way, a faster way to be able to convert that,
certainly if hydrogen becomes viable, that could be something that we could look at, right?
So you could easily convert from natural gas to hydrogen without too much delay and too much shutdown time.
And we're looking at is the council also giving you the prerogative to look at a private public combination for a plant?
Or are we looking more or less or what are the options?
Just potential, if it's out there, potential purchasing outright or maybe a public private public type of joint venture.
Is that available? I mean, are you looking at that? Is that available?
Is that something we can talk about right now?
Yeah, I think the short answer is I think all of those things are on the table.
As I already mentioned, other MOUs are already interested in additional generation.
There could be a partnership with someone there to acquire a facility.
Maybe if it's a larger type facility that won't necessarily meet just our needs, it can meet their needs.
That could be some partnership.
I've already mentioned to you that there's data centers and others out there on the private side and even IOUs.
They're looking at the possibility of additional generation.
Again, we've not engaged anyone at this point, but those are just kind of the large realm of possibilities of what might be out there that we could potentially explore.
Would it be advantageous to stay within, not in the city limits of Denton, but surrounding area?
I mean, you looked at the map of Urquhart from Panhandle Down or whatever.
The further away something like that is purchased for our benefit, is there a disadvantage to that?
Well, just as a reminder, and I'll just say that even this is still in question, but the DFW area is a non-untainment area.
The deck, because of the emissions that exist in this area, the pollution, there's a limitation in our permit and how much emissions.
It limits the run hours of the deck, in theory. Now, the deck has never reached those limits.
Any facility in this area currently would fall under some type of permit limitation.
I think ideally you would want that where there is no limitation and then you could run that facility for its full economic benefit.
And so, as we're looking at facilities in the DFW area, I think that's one limitation that doesn't make putting something or buying something in this area attractive.
Now, all that could change, right? That whole non-untainment area could completely go away as we're understanding what the EPA is currently looking at based on various directives at the federal level.
You addressed what I was going to ask, so thank you.
And again, I'm just giving you the facts. I'm not weighing in on whether I agree or disagree with those.
So it's a fluid situation, obviously, and the government's going to EPA and it always gives us a lot of sleepless nights, I'm sure.
So are the Texas Energy Fund projects, are they in real estate mine, are they potential targets of purchases?
Absolutely.
Okay. Because they're already more or less beginning there, they're well beyond the concrete port and such.
Yeah, as I showed to you, the vast majority of those resources are all private investors, right?
And so what's important to those private entities is rate of return, right? And the quicker you can get a rate of return, the quicker you can turn around and do something else, right?
And so I think there's opportunities. Certainly, we believe that acquiring an existing facility will likely come at a premium compared to a greenfield development.
But again, the benefit of that is we get that onto our portfolio and we continue to give our ratepayers a little bit more rate stability. Thank you.
The other thing that I'll point out is, again, remember, these are private entities in many cases. They're publicly traded.
So at some point, if we do engage, likely we'll be doing NDAs and confidentiality agreements.
And so I know that from a community standpoint, sometimes transparency becomes an issue, but that's just the way kind of business is transacted.
Yeah. No green lights? Okay.
So I have two concerns in what was represented in the presentation.
One is that I feel like we might be aiming to solve the problems of 2021, not the current ERCOT.
And ERCOT's changed a lot in the last five years. You know, solar is now 35,000 megawatts or during the year it was like 10,000 megawatts.
There are more than 10,000 megawatts of solar scheduled to be integrated in the next 12 months.
So there's going to be 45 gigawatts of solar this time next year in ERCOT.
So the idea that we're going to have 100 hours of market cap prices.
Well, half the peak load in ERCOT is going to be met during sunny hours just from solar.
So we're not likely to experience a multi-day event like that unless it's transmission.
So I feel like we might be designing to solve for the next URI where we can have 100 hours of generation today.
Now, the next development after solar is battery. There were no batteries in URI.
There were effectively no batteries three years ago.
There were five gigawatts of batteries last year. There's 14 gigawatts of batteries today.
That's nine gigawatts in the last 10 months have gotten built by private investors in ERCOT because they think it's going to make a lot of money.
There's 12 more gigawatts of battery scheduled in the next 12 months.
So it's a gigawatt a month of private investors building batteries.
If you look at gas generation in the next 12 months, there are four facilities in ERCOT's queue.
Three of them are TEF recipients. So it's basically the TEF program is probably driving a good chunk of that queue, which is very small, tiny.
Four of those versus 80 batteries and I don't know, dozens and dozens of solar farms.
And so that's all private investment. That's companies seeking a profit.
And they think it's going to be profitable to build solar and batteries way more than it's going to be profitable to build gas generation.
And I understand, like, if we build a gap like the deck, it costs 30 million dollars a year in mortgage.
But it offsets 60 million dollars a year in energy purchase right now because forward prices are really high.
And so it saves us money just having it sitting there, even if we never turn it on, because we didn't have to sign a contract for 12 months of power with whoever with whatever vendor.
But that's that's a it's a it's a long term solution for potentially a short term problem.
We're going to have a 30 year mortgage on whatever we buy.
And in in five or 10 years, the market is going to be different than it is now guaranteed.
So I worry that we're looking at the last five or 10 years and not all of the changes that are happening and are going to happen.
And we learned this. We felt this with TMPA.
We built a lignite coal plant kind of at the end of the wave of all the municipalities building lignite coal plants.
We were underwater on it the last five years. We wrote it off at a loss.
It wasn't really running because it was because it was unprofitable. It was it was a thing that DME ratepayers were paying for when it was when we didn't want it the last five or 10 years.
I can't imagine a gas generator being the the technology of 2060.
That's how long this thing is going to going to exist if we build it today. So I really want to.
I think it's great to get cost estimates and kind of see what's out there and is like what's available in one year, what's available in five years.
But I think before we make a decision on a purchase, we really need to look at.
What the real financial risks are hour to hour in Urquhart in the next few years and then and then what the long term what we expect Urquhart to look like in 15 or 20.
Every forecast is going to be wrong, but we need to like we know which direction it's headed.
I'm exceptionally concerned about our projected energy needs.
I'm in an AI business and the energy needs in AI dwarf cryptocurrency by many, many, many multiples.
It is my largest expenditure over salaries. So I think we're being very conservative.
So I think we need to do whatever we need to do to get as much energy as possible.
If we're going to be in the market and I think Texas should be in the market for AI, we need to have as much energy as possible.
And I don't know if natural gas is the answer, but we need to be looking at everything, nuclear, everything.
It's not going to get any less energy intensive and it's only going to get worse.
So I think we need everything for everything on the table, even if it seems unreasonable to look at nuclear.
I think we need to look at nuclear. I agree. Thank you.
That was a very good input. Thank you very much.
Do you need a direction on this board right now or you just need a conversation?
I mean, you've already got direction from the council.
So we got direction from the council, you know, and we're certainly going to pursue with that.
But I think if there's some some level of agreement here and really, I think, as as Devin has pointed out, you know,
one, whether or not there's a deal out there or not, we don't know. Right.
And if there is, you know, let's let's look at what the possibilities might be.
I really think that as we're looking at this and we're going in parallel on this IRP, listen, I'm not going to bring a deal to you tomorrow.
I promise you that, you know, I don't contrary to popular belief, I don't have a deal in some back room ready to go.
I really don't. You know, I'm a really bad liar.
So but but I think if those opportunities come up, you know, we will certainly bring those to the board, to the council.
And ultimately, if there's a deal to be made and there's agreement, then then we will go forward and make a deal.
And then we still have this other project to go forward.
And I will tell you, you know, we're we're bullish on on small modular nuclear reactors.
You know, I think there's a lot of promise.
But the one that's in the state that they're looking at, not not the prototype and Abilene, but the one that is being forecasted in in cause station is one megawatt.
You know, and so again, one megawatt doesn't give us what we need. Could it be a component of a of a very diverse portfolio of generation?
That's not just wind and solar intermittent resources, potentially.
Also, what I'll mention to you is that in this last RFP that we did for battery storage, unlike other times that we've done it, we had 60 proposals.
You know, kind of raise the radar a little bit for us. Why are all these all of a sudden showing up?
And I get what you're saying, but I think there's the potential that there could be a flood, an oversaturation of battery that then changes the economics.
Now, at that point, it could create opportunities for us, right? Because again, we're not driven by that rate of return. We're being driven by that stability in pricing that we have for our different.
It's a different calculation, different calculus for us.
But yeah, so I think Mr. Chair, if there is some some agreement here on what we need to pursue, I think that will certainly bolster I think what the potential with the council has directed us.
Okay, I think that was really good discussion.
I would disagree with you on the TMPA. I thought our timing was pretty good. Maybe you should have quit spending money on it about 10 years ago, but we ran that we rode that horse till it died.
With that, unless there's anything more.
We are adjourned.
Thank you very much.