Transportation Advisory Board - Regular Meeting

Hello. This is Phil. Hello. This is Phil.

Hi Phil, we can hear you.

Oh, okay. All right. Hi everyone.

I'd like to call this meeting to order. Good afternoon. I would like to welcome you to the Thursday, May 29, special session Public Utilities Advisory Board meeting. This is our fourth meeting this year. My name is Lou Halkias, and I am the chair of this board and will be conducting the meeting today. Mayor, please roll call. Sure. Abbas Bikap Harawala. Yes.

Bhavani

Gallivarti. Present. Brandon Haft. Here. Present. Hans Roeder. Not here. James Valar. Here. Lou Halkias. Here. Who's here. Michelle Ackman. Right there. Nathan Williams, Wilson, I'm sorry, right there.

Hey, Matt.

And

Phil Schreiber. Phil Yes,

I'm here by phone.

Thank you.

Thank you. Our next order of business is public forum. Speakers will be called in the order that they signed up. If anyone was unable to sign up, they could speak at the end of the public forum. If you didn't sign up but would like to do so, please raise your hand so we can get your name and add it to the list.

Please call the first public forum speaker. Daniel Bouley. One minute.

Hello. Hi. My name is Dan Boley. First of all, I want to sincerely thank the board for voting to recommend to the city council to sign the IMEA contract. I've been involved in the green building and sustainability movements for twenty years.

I believe strongly in sustainability. I'm concerned about the fact that environmental sustainability is just one leg of a three legged stool. And as people plan it and and people plan it and money. All right? And the people part has been left out.

And that doesn't work well. I met with about a dozen residents last Friday. And we're looking into forming something called the Naperville Sustainability Project, to spread the word of what real sustainability is. For instance, a lot of people don't realize that even though Washington State is much more progressive than Illinois, if you look at the federal elections, and yet they overwhelmingly voted to keep natural gas. And if you look into it, you found that it was all the Democrats in Seattle that voted to do that.

It's not a partisan issue. It's about money and it's about people. And I would like to see the city of Naperville understand more about what real sustainability is. I did some calculations on the IMA contract. And really, what I'm asking to do is for the city to do their own calculations.

I would love to see projected rates in kilowatt hours. So in my projection and you also have to look at I did it a couple different ways. If you look at the fact that in two years, we're gonna lose two major peaker plants in 2027 in Illinois, the projected power load, increased load due to data centers across the country is gonna be four times the amount of power we have now. And the sad thing is that we don't people aren't gonna realize this till 2035 that we made a mistake. So I'm just some projections here.

In 2040, if we stay with the IEMEA, my calculations say the the rate will be 15¢ an hour, and without IEMEA, it'd be 19¢ an hour. You get up to $20.5.00 $18 an hour, IMEA. Dollars $0.03 8 an hour without IMEA. Now, these may not be things, but I would love to see some professional projections made on those so people can make an informed choice on this. Thank you very much.

Thank you. Before we do the next person, I've overlapped one thing. I don't want to liability wise for the group here. I didn't mention the rules of the public forum. Thank you, Dan, for staying within the rules. And you didn't need instruction. Not that the other people do also, but I think I'd better just to follow through with this. As we start the public forum, I'd like to remind everyone of the citizen participation rules in the city's municipal code for speaking at meetings. Speakers will be called on to speak in the order that they signed up on the sign up sheet. Each speaker will have three minutes to make their comments.

Speakers are asked to present their comments in a respectful and courteous manner. Speakers should stay on topic and be cognizant of their words. Personal attacks on board members, staff, other speakers, or members of the audience is not allowed. If inappropriate language or comments are expressed during this meeting, you will be asked immediately to stop commenting. Also for audience members, there's no cheering and no jeering. Actions such as applauding, cheering, or booing during or at the conclusion of any remarks made by any speaker are not allowed. Now that we've covered that, please

go forward. Thanks. I'm Joe Husson. I've been a resident for over twenty five years. And actually, I like Dan's idea of doing a financial projection, actually showing how the costs, what the MNO costs are, how are we getting to these numbers. So that sounds like a great idea. I have three points today. The first is the League of Women Voters described the PUAB selection process as disappointing and recommended a rigorous evaluation process that involved the community. The city's Environment and Sustainability Task Force requested the same thing. We want the city to follow its procurement code, so rule one-9B-four requires competitive bidding.

The community will never be satisfied by getting one proposal from one vendor that doesn't have any price information. The second point is, IME will likely come back with another limited time offer. When they do, we should ask them to include the information from their sales presentations in the contract. The sales presentation said they plan to clean up their act by buying more renewable power, but that's not in the contract. And I'm not naive.

IMEA knew we wanted cleaner power, and the reason that it isn't in the contract is they want the ability to continue to buy dirty assets. If we sign, we don't get to we'd have no say in this for the next thirty years. So while Naperville is their largest customer, we only get 3% of the vote at IMEA. So we don't have the voting power to require cleaner power after we sign the contract. Naperville ratepayers' money is already leaving our state to pay for dirty power in Kentucky.

With environmental laws like CEJA in Illinois, there's nothing in the contract to prevent IMEA from buying more dirty, out of state generating assets that send even more of our money and jobs out of state. And the third point is I appreciate the PUABs looking at retail rates. However, I don't want anyone to be confused that IMEA is cheaper. IMEA doesn't sell retail power. They sell generation and capacity.

To determine if IMEA is a good deal, we should compare it with other vendors that sell generation and capacity. By law, ComEd can't sell generation, so don't get confused by comparing ComEd with IMEA because they don't compete. Naperville tax dollars have reduced the distribution costs of our retail rates. You can ask the presenters if they included tax dollars that are used to bury distribution lines in the rate comparisons to see if this is actually an apples to apples comparison. In closing, the energy contract is worth billions of dollars, so we need to stop the one off presentations from whoever comes to this body, take this seriously, Conduct a competitive bid like businesses do when making major purchases.

Thank you.

Thank you.

That's it? No more public speeches.

No more. Okay. Thank you. So next will be old business. And we're going now to really new business, which would be in the section F, reports.

Chairman, I think you would want to approve the or at least review the last meeting minutes. Well, the minutes.

Well, was Okay. I guess I did miss the minutes here. Yes, I do want to. I'd like to approve the meeting's minutes from 04/08/2025. And I imagine by this point, all of the members have had an opportunity to review the minutes. Do I have a motion?

I make a motion.

And I have a second, okay. Is there a discussion regarding the minutes?

Yes. I have a quick question. So during the last meeting, there were some documents and I think like a presentation and some citizen comments that were like emails and stuff that weren't there. I just wanted to make sure that it showed within the record that those were submitted by individuals and that weren't necessarily representative of the whole, that we weren't involved necessarily in pulling that together concurrently.

Yes. Can you talk a little bit more to the microphone? Okay. So basically, the documents and letters that were received by the PUAB were from individuals? Is that what you're saying?

Well, I don't know that they were received by the they were received by the PUAB during the meeting, but they weren't provided in advance. And I just don't want it to, you know, I wasn't sure where they came from necessarily. I just didn't want it to be necessarily representative or reflective of, you know, that I went out and sought those out and, you know,

So I said where they came from at that meeting. And I said, I contacted people down there to see what their experience was with Prairie State and Trumbull County with those areas. And so I asked them for feedback as to what they felt. And so they submitted that feedback to me. And I said, those were the letters that I received. And I wanted to put those in the record to make sure that people had some input from the people down there. Because there was an impression that the people down there were suffering. And that's what was being put out. And the people told me something different. That's in the record.

Yeah, totally fair. I just wanted to make sure that it was tied to you as a board member rather than the entire board or you know, any other individuals on

the Yeah and nothing really was said that this is the board's work. Good. Any other questions?

Yeah, I was just wondering if we could actually get amended minutes to state that specifically that was what was submitted into the record was not submitted on behalf of the PUAB itself relative to the materials the board chairman had submitted?

Yes. Were just Daryl and I were just looking through the minutes that were attached. And we realized that those letters there was quite a few letters from the public that were also submitted as well. And our intention was to include them. So I think that an amended motion would be appropriate. We did have a statement that we were going to put on top of each one of them from our legal counsel related to that they were not in an opinion of the board and all of that. So I think an amended motion to approve with a statement on each one as to where they came from would be in order. And that's how then we would post those minutes going forward. Is that

Yeah, that would be great.

Perfect. Okay,

so can I have someone say that that is the amendment that they would like on as a result of our discussion?

Yes, so I motion to amend the minutes as Brian Quick. Please.

Quick, I can't vote on this, obviously. But, and I mean, my limited experience on counsel, it's, I don't want to say abnormal, but perhaps atypical. Like if a counsel person were bringing a letter from a resident, it would seem obvious that it was from the resident themselves and not counsel. So I've just never seen the case where minutes would be amended to in order to reflect that. So just my 2¢.

Obviously, can do what they want and vote on it. But that's just my experience. Thank you.

To clarify again, I introduced those letters. I said I asked those people for them. I didn't say in the name of the POAB was for me, because I wanted to find out what was going on down there besides the fact going down there and touring the area. So it's been noted, I think, to make sure that this is not something that the PUAB totally put out. So I think we can all agree on that. So any other discussion? Then I'm going to ask for a vote. Those in favor of approving the amended minutes, if you would say yes.

Yes. Yes.

Aye.

Okay. And those opposed? So that's unanimous that the minutes as amended are passed. Thank you. Okay, the next now are with the reports.

It was the meeting. The minutes were my first thing. Prior to the first report, which is to receive the PUAB year to date CIP report, prior to that, is there any public comment prior to this presentation? There's public comment, I'm assuming? I have to ask for each one of these.

No speakers have signed up.

No speakers. Thank you. So we will receive the PUAB year to end date CIP report. Yes.

Mr. Chairman, if I may, I'd like to do a summary of the reports because I know we have quite a few of them tonight in addition to the numerous presentations later in the agenda. I want to be respectful of your time. And of going through each one of these individually, I'd like to do a summary of the financials and then take any questions on the reports. I think that might speed things along and allow you guys to get to sort of the meat of the agenda quicker and hopefully give you some more time to discuss those issues

yes so are we talking about water only or

both water water at this time

okay so if you can identify those by their number then we'll be able to keep it straight So the first 12082. What I could

do is, if mayor could pull up the revenue overview dashboard. Yes. And mayor, if you could maybe zoom in a little bit on that, you possibly can. I'm a visual person. And I think these dashboards, if done correctly, can be quite useful. Perfect, Mayor. Thank you. Maybe center it a bit. Excellent, excellent. The good news is oh, first, my name is Daryl Blenis. I'm the director for the water utilities. Thank you for your time this evening. Like I said, I just want to hit the highlights of the revenue and expenses and to take any questions you may have on our various reports. That way we could kind of speed this along. But I will be respectful of your time.

If you have questions, just let me know. So first on the revenue side, we have really good news to report. Through April, our revenues are matching up with our projections. I think if you look at the year to date actual is $26,040,000 and the budget projections was $26,080,000 So we're pre dialed in, which gives me a good sense that our new rates and our demand forecasting is in alignment with reality. So I feel pretty good about that.

Also what's interesting is that our demand forecasting, we also factored in, like for example in April, the water demand in April was the third lowest we've had since 2008. So as you can see, we dialed in April as well. So I think our demand forecasting is much improved and hopefully remains consistent for the rest of the year. So I feel pretty good about where we're at on the revenue side. With that, our cash position is also doing quite well.

Our target balance per our policy is thirty days. And as of the publishing of the packet, our operating reserve is actually at 86. So we are exceeding our target balances. The total amount of that is I believe 16,800,000.0 in reserves for the water utility fund. Mayor if you could go to the expense overview I'd appreciate it.

Thank you, mayor. More good news on the expense side. We were also tracking quite well with our projections. If you look at the year to date projections versus the actuals, the one deviation you'll see is in capital outlay. But I would suggest that the year to date projections on a capital outlay is based on a linear pattern versus the seasonal nature of construction.

So we anticipate having a lot more construction during the summer months than we would have in the non warmer weather months. So as you can see throughout town, we are quite busy. I think we have a very visible project this year at Washington and Ogden with our water main replacement. That's going quite well. But the good news is all of our major projects have been awarded and are under construction.

And things are going well so far. We did receive bids today for our South plant upgrades and improvements, and that's one of our bigger projects. We budgeted over $50,000,000 this year, and the bids are currently under evaluation. So we're looking forward to getting that project awarded and under construction as well. So like I said, good news on the revenue and expense side. Things are lining up with our expectations so far. Mayor, if you could pull up the SADA report, please.

Which is the other report now we're going to?

The SADAI report. SADAI. Okay. That's the system average interruption duration index. I will note, if you look in the state eye top left corner box, has 7.92. It's in red, which means that we're in a worse position at this time of the year than we were last year. That actually makes sense based on our numbers to date. We've had 60 water main breaks this year through April. Last year through April we had 32. So we are trending higher on the water main breaks.

So that reflects reality. So I think that indication is showing what's happening out in the field. The good news is that we are ramping up our water main replacement. So hopefully we'll get rid of those bad water mains over time and improve that ZDi number going forward.

And Darrell, I remember you speaking about this a number of times over the last couple of years and that you've been systematically replacing water main, but also testing quite considerably to try to evaluate the pieces of water main that are most at risk.

Correct.

You know, maybe you can help us better understand that. Absolutely. Are these known and they're just breaking sooner than you thought?

So what

we do is each year we put together a five year capital plan. And we evaluate the water mains that we have in our list. What we do is we assign each section a water main or each stick of pipe actually has its own score. We call that our BRE score or business risk exposures score. And that factors in things as service history, water main breaks, age, material type, impacts to the public.

For example, if it serves a school or a hospital, obviously that water main is quite important. So we score each tick a pipe gets a score, and we tackle the worst performing or the worst scoring pipe as we can. And last year we actually, or two years ago we took out the water main on eleventh, And that was like the worst scoring pipe in the entire system. So we do have a method to scoring this. You know, it is buried infrastructure.

And water main pipe is difficult to get inside to do a condition assessment. So this is a tabletop exercise. But we are out there in the field, the condition of the pipe is quite bad. So we think our tabletop exercises are quite sufficient at this time. As the technology improves, we are going to be testing new technology next year that uses sound and to measure the wall thickness of the water main pipe as a way to determine its remaining useful life. So we're going to be investigating that. And as it becomes more cost effective, we'll be including that in our BRE index going forward.

Thank you. May I ask one more question? Just if the failure rates are kind of accelerating, let's not treat this as like just an anomaly for a year, but let's hope it's not a sign of more to come. When you look at your future budgeting and project timelines, is there a way or is there a need to increase replacement activity? Sure. So what we've

done over the next several years, and is included in the rate study projections as well, and make sure we have sufficient revenue, was we are increasing the miles of water main each year. So currently we're at just over four miles. And by the end of the rate study period, we'll be at six. And it's our goal with the next rate study to get to two miles. So we are ramping up each year.

Each additional year we're adding more miles. We did a condition assessment evaluation in 2021 that identified that we fell about 50 miles behind schedule on replacing water main. And we've identified that we need to get to 10 miles a year for a period of time to get caught up. And for a system of our size, the best practice would be around 1% or seven miles. So we need to get to 10 for a while to get caught up on that backlog.

And then once we get caught up, we'll go into a steady state mode and do around seven miles a year. So that's sort of the nutshell that I have for you. Just a kind of quick overview of the financials, the revenue and expenses, and our performance out in the field. We did include our CIP list for you. But like I said, so far that's tracking quite well. And we got all our major projects awarded and under construction. So I'd be happy to address any questions that you may have on these items or anything else in your packet.

Is there anything else that you, if you wanted to talk about the Springbrook Influent Report at the same time?

Well, like I said, there's nothing shocking in there. That's why I didn't want to call it out per se. But we are actually updating the Power BI dashboard that you usually get. So it may look a little differently. So we included the Influent pump station as opposed to the effluent. I've been working with a boss on some better visualizations for that dashboard And working with our data team on getting those implemented. But that takes a little bit of coding and a little bit of time. So we're kind of in the process of getting that done. So in the interim, I presented those other two reports to show the rainfall data and the Influen pump station at Springbrook. But point out, there's nothing abnormal going on there. Right.

And in the interest or in the spirit of what we're doing trying to get all of the water situation taken care of, did you kind of also cover the PUAB water financial packet at the last

Yes, did. I kind of summarized

You summarized that and with the also the water supply report?

Yeah, I mentioned the April flows were the third lowest since 2008. Once again, the revenue is tracking our water demand estimates. So on the water supply side, once again, they're in alignment with our projections. So we feel pretty good that our demand forecasting is on track. And the rates are producing the revenue that we were expecting.

And does that conclude your water reports?

It does, unless you have more questions. I'd happy to.

Yes, one moment. Yeah. Any questions? Any questions from the PUAB? When will you post voter quality report for 2024?

Could you say that again? I apologize.

When will you post on our website voter quality report for 2024?

Yes, yes. Yeah, it's on the website. And it also should be sent out to you in your, the link in your water bill as well.

Okay. Because some other villages are posting five year data. We post only one year data. That

is correct. But we also, you know, we can provide links to the previous documents as well. So that's something we could take a look at if you think it's worthy of doing that.

Any other questions from the PUAB for this? No? So what we're going to do is take the entire packet as one. Do I have a motion to accept these reports? So moved. Do I have a second? Second. Any discussion on these reports other than what we just had? All in favor of accepting these reports, say aye.

Aye.

Those opposed, nay. So those are all passed unanimously. The next area that we will be looking at is to receive the report of the Electric Utilities preliminary P04 twenty twenty five financial summary. Mr. Director.

Thank you very much, Mr. Chairman. Brian Growth, electric utility director. And I will, unless there's any questions at any time, I will just continue to move through our reports and take any questions that anyone has. The first one is we are about as of this report, we're about one third of the way through the year. No significant issues, as you can see, identified by our finance department. These documents are prepared by our finance department based on our financials at the time. We do continue to experience significant material supply chain inconsistencies. So we are receiving materials from POs from 2021, 2022, 2023. And this does affect cash flow, right?

So we are closely watching our cash position as well as what our in and outs are. Now, we do know that there are some projects in our engineering group which are being significantly delayed such as our large power transformers and so we continue to communicate this to our finance department so that they could be aware of you know effectively we're adding transformer deliveries that we procured many years ago that are now showing up, but we're also pushing out projects because of supplier issues as well. So in general, there's pretty much an offset here. But I just want to make that note. Then with Brian respect to our

question. I think we've talked about this quite a bit for the last three years since COVID there's been a backup. And I'm assuming you're going to get like you already are. They're catching up and then they're kind of inundating your budget. Just going forward, because we are a part of IMEA, don't think we ever, at least I don't recall, talked about leveraging the power of that group to purchase or even take assets that maybe we don't necessarily need I'm just wondering can you provide a little comment Terry on the buying strategy or power of IMEA and the collective municipalities to work together to kind of work through some of these issues

absolutely no I appreciate that opportunity so we do work with other members of IMEA primarily at the start of these supply chain issues to understand what their procurement for their assets are as well as to try and work across all of our member communities to standardize what we have, right? So the thought being that if we all are purchasing the same transformers and the same type of distribution transformers in the same configurations, we might be able to leverage and to either A, get a better position financially or to at least get material, right? There have been several instances where other members of IMEA have contacted the city asking if we have something that they need, right? For example, a 2,500 kVA transformer that might have failed at another town. We have been able to help some other towns.

We have not necessarily had the need to ask other towns to deliver materials. Nonetheless, how we've handled it is we've given what we've had because we have had a significant inventory and then those folks just deliver it when they get they get it back. Our warehouse has mins and maxes and we never go below the minimum number that we need to serve our community, right? So our priority is serving our community and if somebody needs something we're happy to give them a reel or cable or something as long as we have a defined timeline that it's gonna come back. On the standardization front what we found was we're all generally aligned on standards for distribution transformers overhead underground some other communities are more overhead than we are and so there's not necessarily a 100% alignment there and we also determined that the large investor owned utilities were actually going out and buying futures and basically reserving capacity at transformer factories that's not something that even as a whole collective IMEA community we thought was prudent nor was it prudent from a Naperville perspective.

We always were able to get what we needed when we needed it. I will say it has the costs have impacted our budget but not so much that we've had a significant issue. Did that answer your question?

Yeah, thank you.

I will say from this sheet here I will note that the renewable energy fund the $355,000 budgeted as of this morning I believe mayor ran the numbers and was about 28 spend so I'll ever I'll always take any opportunity I can to plug the renewable energy fund and the grants that are available to residents of the city of Naperville. You know, by this time last year, I believe we were out of funds. This year, we are not. So continue to turn in those grant applications and and we'll continue to process them as we have been the numbers for the financial report are there and if there's any questions I'm happy to take them other than the next item that I'd like to stop on is this one here I'd like to perhaps discuss what this is this is our capital budget where we stand for the year There was a comment that I feel should be addressed that it made in public forum that tax dollars are being used to subsidize the electric utility. This is our capital program.

As you saw in the other ones, the other spreadsheets those were our operations and maintenance these are all funded from utility dollars these are all in the rates in the rate study that was approved by council as well as the PUAB in the past. So as you can see some items here percent used is higher than others. We are going into our peak construction season so I will expect that the next time I report these back to you that we will have significantly higher spend and I think Phil Calderoni our engineering manager down at the end of this table here has lofty goals to get some construction done and is in progress right now.

So as you're going through these, you're going to go through your reports in one group. And then we'll be able to approve them at one time?

That the plan? That's correct.

Yeah. And so I just want to make sure that up to this point, we have covered twenty five-seven forty one, twenty five-seven forty two, July and seven well we're coming up to $7.44

that's correct mr. Chairman okay thank you

mr. Chairman may ask one more question about what was just being covered in

the budget yeah absolutely

yeah just Brian really quick we have this tollway substation reliability upgrade.

That's right.

That's a significant capital outlay. If I recall last time we talked, maybe it was two meetings ago, you had mentioned that a portion of this is our ability and responsibility to do this work just curious with the tollway system itself and kind of this the nature of our government at this point are there any reasons that you could foresee that that project would not go forward or be able to go forward this year?

No. So what we are seeing is a significant delay on transformers as well as the building. Is that correct, Mr. So we're seeing a delay in this. The tollway concept, so we have a substation along I-eighty 8 that's called tollway substation.

And so we are seeing delays in this project but we are not seeing the fact that it cannot go forward. We've taken a couple of different approaches based on cost trying to reduce cost right so we had we had originally thought we were going to use a prefabricated building and then those costs came back higher than we expected so then we decided to move towards a traditional type building. Consultants are working on that right now. We have two transformers on order. Some of those costs will be pushed into next year.

What the suppliers have, one of the inconsistencies in supply chains that we've seen is that terms and conditions of when suppliers would like to be paid are vastly different across suppliers. Some like heavy upfront costs to be paid, some like delayed costs. And so one of the issues that we are seeing is that a large payment for these two transformers will be moved to next year which actually helps our cash position not only because we're not spending it this year but also helps because we are seeing the transform the distribution transformers come in

okay and I and I appreciate that it just I think maybe more specifically it's just the tollway authority itself has no impact on your project and

that's correct it is it is in name only

okay that's what yes thanks

so your next report will be the received the electric utilities SADI report

That's correct. So the SADI report largely unchanged, right? Our goal is less than thirty minutes for a SADI index which is the amount of time that the average customer could expect to be out for the year. We've had some wildlife issues this year that have affected overhead portions of the town. We've also had our traditional cable faults, and I say traditional because we haven't seen anything outside the normal. A couple of vehicle accidents, vehicle versus our switch gears this year. But outside of those, there's nothing that really stands out here as a negative trend. These are all within standard deviations of where we've been.

Is that it for this report? So before we move, because I didn't ask specific questions from the PUAB for these, are there any other questions from the PUAB? I know there was a question before by one of the members here that was getting the SADI reports mixed up so is this the appropriate SADI report that you wanted to ask

yes mister chairman I would like to ask mister Grosse some questions about the it's not really about the SADI report about the issue of outages And I don't want to strike fear into everybody's heart but I did prepare some PowerPoint slides for this and I will I will get this done in a matter of a couple minutes. Next one. I was reading the NERC twenty twenty five summer reliability assessment that was just put out in May. Think this was put out a couple weeks ago. Next slide please.

And in that in that assessment, they highlighted a couple things talking about reliability and availability for power in in the near future and in the distant future. But of the things they said and this is MISO which we're not in we're in PJM but MISO is at an elevated risk of operating reserve shortfalls during periods of high demand or low resource output. The shift is driven by the decline in dispatchable generation and the increasing share that solar and wind resources have in meeting demand. Next slide. So when there is a table with a lot of data in it but I'd like to draw your attention to the two arrows off to the right.

This is their assessment of the MISO system and there's three columns there are the anticipated reserve margin which is the amount of extra capacity that MISO has over and above what they think they'll need which is 27% or 25%. The anticipated reserve margin with typical outages is only 9% but the far column that says anticipated reserve margin with higher demand outages and D rates in extreme conditions is a negative number, which basically means under that extreme scenario MISO is not going to have enough power to get through even this summer. Now PJM is the other red arrow and if you go to the far right they're anticipating a little bit of reserve margin. But as we've talked about before, these reserve margins are declining. So our both of our grids at PJM and MISO are under risk.

Next slide please. So last week only I was on my phone and I started seeing articles about this and you know they're pretty alarming. If you just look at the headlines, summer heat waves could be trouble for stressed grid. Next slide. Yeah.

So so that there's there's actually three of those slides like that. We don't have to go through them all. But then just last Sunday, there was a a large power outage in New Orleans where a 100,000 accounts lost power. And it wasn't because of weather. It wasn't because of a hurricane or anything. It was just a shortage of power. I think a power plant went down and that was it. A 100,000 accounts. Just to put that into perspective, Naperville has 60,000 accounts. This happened Sunday.

Next slide. So my question to director Groth and I really don't want like a long answer right now. I think just a summary today would be sufficient one or two minutes of what Naperville is ready to do in the event of a of a, you know, a loss of electricity supply either that you're warned about or you're not warned about. But I would also ask that perhaps that our next PUAB meeting, we get a more comprehensive, you know, outline of what Naperville is prepared to do with these impending shortages that these grids and ISOs are all predicting are coming down the pipe.

Please go ahead.

Thank you Mr. Chairman. Yes, so in few seconds I've had here, the electric utility and most departments, all departments within the city have a continuity of operations plan, right? A coup plan where we identify how we would handle certain types of emergencies, immediate contact information, things like that. We did receive, I would not say something similar to this, to the level that this is, but we did receive some notifications in December 2022, I believe, or 2023 that there was an impending shortage around Christmas Eve of that year and so we had some opportunity to at least dust these plans off and take a look at them.

We do that every year anyways. We do hold tabletop exercises within the electric utility and within the city as we did hold one last Friday for all directors in the city. But in general, the COOP plan identifies all of our feeders which are how we the lines that come out of our substations and how we serve the public, right? And so what we do is we look at our feeders, we look at what type of load is on those feeders. Is it a hospital?

Is it a nursing home? Is it just residential? And I say just residential because we have to prioritize. If we were to receive a call from PJM or from IMEA who's registered on our behalf to say that hey this is what we will need to curtail during these time periods we would go to our COOP plan we would look at our lowest priority feeders and how long that we have those identified to be out. I won't go into the very specifics of what those timelines look like, but we are prepared to receive a message from PJM or from IMEA who's registered on our behalf to say this is how we will meet whatever curtailment goal is delivered to us.

And that would likely be some turning off of feeder breakers and rolling blackouts based on priority right so we would like to leave the hospitals and schools and large public buildings up as long as we can and that's why we have the prioritized list

Okay Mr. Chairman could I ask that perhaps there are not maybe maybe the next one or one of the PUAB meetings down the road we receive at least a little bit of a more comprehensive assessment of what those plans might be.

Yes. Thank you, Mr. Director. Before we move on to the last report from the electric people, are there any other questions on the reports that we went through from the members here? Or on to anybody up here? No. Okay. So we have one more, 20 five-seven forty five, which is the Receive the Electric Utilities 2025 EE and REP dashboard report.

Thank you very much, Chairman. I'll walk through this quick as we've seen this dashboard several times in the past but nonetheless EV count where we tracked a number of EVs in the city of Naperville and the slope continues to be fairly similar to what it's been in the past. Another time to plug our energy efficiency both the IMEA which is more of the commercial side, the residential thermostat program, all of our energy efficiency programs across the city. I would ask that everybody review those on our city website and continue to apply for grants that we can get those dollars into the field. We are providing LED light bulbs still or do we still have a few?

So we still have a few LED light bulbs if anyone's interested in receiving them free of charge. I would ask them to reach out to Mayor Dieb. Yeah, please do. And then we also new this year, we also have smart switches. If you wanna talk a a few seconds about those.

Basically, will have, like, a remote control of everything that you plug in into the wall. You can download the app on your phone and you can turn on, turn off the load remotely. So just coming to the utility, we'll be more than happy to to give you some.

And those are provided through IMEA's energy efficiency program. We track the number of thermostat rebates. And then our conservation voltage reduction program, our two engineers, the two managers at the end of the table will be giving a little bit of a presentation not only about conservation voltage reduction but our more holistic approach to virtual power plants or also known as our distributed energy management system later on this evening so I will pause that conversation I wanted to remind everyone that our new solar net metering policy has gone into effect which removed all caps on installation up to one megawatt and so again there are no installation caps. There used to be a 10 kw or 13 kw cap depending on what you had in your home. But all of those caps have been removed and our permitting folks simply review on electrical characteristics as well as building characteristics at this time.

Thank you for that. That completes that report. Now before we go any further, are there any other questions from PUAB members? Go ahead, Michelle.

Mayor, can you remind me the number of EE awarded projects and annual KWH savings that I think it's up one more. That chart, is that both renewable energy program and IMEA combined? Residential and commercial?

That is correct. Are

you seeing I'm just curious some of the other measures. I'm particularly thinking heat pumps and how that if there's been a lot of customer uptake in that or how how that one's going?

For our renewable energy or the IMEA one?

The residential heat pump one, is that under IMEA or is that under

The only one under IMEA is the the thermostat rebate and AC.

Yes. Yes. The AC heat pump.

Yeah. And the heat pumps.

Okay.

That's under IEMEA. And some of the other ones that you've seen here like, you know, solar and EV also is part of IEMEA.

So where is the AC one captured?

It's not. We are trying to collect as much data just to look at the calculation. So we really didn't have so many installations to collect the data that will have an impact on savings.

So not much uptake in the That

is correct. Yeah. But we are monitoring that with the heat pump as well.

Okay, thank you. Okay, thanks.

And just a question for either of you. You know, think this issue of blackout is concerning and I don't know if it's interesting to me that you received a notice in the wintertime. I wouldn't have expected that. Would assume that it would be in the summertime. Can you speak to how distributed solar in some ways can be a hedge against some of that, especially now that we can increase the capacity of solar installations in the city?

Solar generally does not reduce the city's peak as much as I would say folks think that it does. Right? So if you look at a solar production curve, it doesn't line up with the city's use curve per se, right? And so we had our rate study consultant take a look at this mostly from a financial perspective, right? Because when we were implementing our new net metering policy, we needed to come up with our avoided cost number that the kilowatt hours that are banked at the end of the year would be then paid out to the customers.

And really what you see in the curve from a city's load curve versus a solar production curve, the solar production curve is trailing off as this city's use curve is going up. And so when we look at the rolling blackout issue versus the concept of solar production, really is dependent upon, you know, the time of the day, the time of year and what solar is producing at that time. But in general, I would say that our derm solution where we will be able to control battery storage, control devices that customers will allow us to do, water heaters, things like that, right? And I understand here in the city most water heaters are gas. Other towns have more electrified water heaters and things like that.

But I would say that that's more of a hedge against those issues than solar is per se.

Thank you. And you did touch on it, the battery storage. I'm not sure, is that part of this plan that you review? And will that be available to the PUAB? Does is there any commentary on battery storage that's part of that plan

currently we do not have the ability as a utility to control battery storage and that includes electric vehicles or anything like that that would have a bidirectional charger. That's one of the goals and I don't want to steal their thunder but that's one of the goals of the Durham's project is to be able to control not only battery storage but also thermostats from one single pane of glass. So the long term vision is that and long term, I say three to four years is that our control room who is staffed 20 fourseven will be able to have all of these resources at their disposal to not only control peak but also to be able to from a regional perspective within the city say hey a transformer might have a little bit of a higher load than we'd like at this point in time because of an abnormal field switching condition hey, it would be great if we could discharge this set of batteries or if we could do x, y, and z, maybe raise the thermostat in the summer a little bit or lower the thermostat in the winter so that we could reduce peak demand whether it because of a transformer outage or a cable fault that we're seeing a high load on a substation transformer.

That's the long term vision of the germs platform that we're in the process of deploying right now.

And just one further question. When you say battery storage, do you mean like a megawatt type unit that the city owns and operates? Are you talking about somehow having a smart system where you're interacting with battery storage at the residential or commercial

level so both to be quite honest right the long term plan and we've talked to several battery manufacturers at this point we're also talking about perhaps doing a battery storage study of our own as an electric utility. But really, I think the fastest way to get to a point where we can leverage what's been installed, right? So from a permitting perspective, we know that there are about 40

About 43 battery installations in the city.

Right. Currently, right? So to leverage those, that would be our first low hanging fruit if you will let me you know, use that term. But we would be able to control those with our derm system.

Okay. Any other questions by the PUAB? Phil? I know you're there.

Phil? No questions. Thank you, though.

Okay. Thank you. Okay. So that took care of the EE and REP dashboard report. Are there any other electric utilities reports that we need to discuss in this group?

No. I think that should conclude the electric reports.

Okay, so that takes care of it. So do I have a motion to accept these reports as a group?

I motion to accept the electric utility reports.

Okay, is there a second?

I'll second that.

GREGORY Is there any discussion? If not, I'd like to have a vote. Those in favor of accepting the report say aye. Aye. Those opposed say no. Unanimous. Thank you very much. Thank you. Next will be the we will receive the presentations from Chris Townsend, energy law partner of CJ Energy Law, LLC, and Mark Pruitt, principal at the Power Bureau. Are there any public comments, mayor, for these?

Thank you. Thank you, gentlemen. I appreciate your time again coming here to Naperville to help us as we go through gathering information. And I think at this point, as I was mentioning earlier to Mr. Pruitt, I think I'm going to ask all the members here to hold questions until you're complete with your presentation. And then we'll ask our questions after you're finished.

Mr. Townsend, if you could turn your mic on.

As I was saying, thank you very much for having us back, Mr. Chairman, members of the board. We actually have two different presentations for you this evening. The first is to compare Naperville's rates to those of ComEd. And the second is an analysis of what it would look like for Naperville to purchase its electricity from a retail supplier. What I'd suggest with your indulgence, Mr. Chairman, is at the end of the first presentation, we'll take questions with regards to that. And then Mr. Pruitt will address the second presentation.

Absolutely.

Thank you very much.

Looks like we're doing the retail supplier one first. Great.

Thank you.

So again, just a quick agenda for us. We'll provide very brief introductions, explain what the assignment was that we were given for this analysis, talk about the approach that we took in order to be able to compare those rates, talk through the results then of what that analysis was, and then, again, an open discussion about what it is that we found and what it is that we see for the future as well. So again, at this point, you know both myself and Mr. Pruitt, our perspective is that from outside of the utilities, providing different types of services for entities other than the local utilities. Our assignment today for this presentation was to try to analyze Naperville's electric costs and compare them to ComEd?

JOSEPH Sure. So when we took a look at this and we thank staff. We made you chase down a bunch of data for us. So thank you. We actually decided to break this into two sub assignments. One was to take a look at the utilities' wholesale electricity rates. That's the price paid from loads to the wholesale market. And then the second was to take a look at how the retail electricity, how the average Naperville consumer stacks up from a cost standpoint. And we used ComEd as the comparison basis there.

So let's first talk about the wholesale rate. So sounds like a simple enough question, right? How do Naperville's rates compare to those of ComEd?

JAMES Right. So the first thing to think about, besides the pretty colors I selected for the graphs, is that these are four graphs. Each graph represents two years. And each two year period, it represents the hourly energy price for the eight thousand seven hundred and sixty hours in each of those years. So, part of the complication of an assignment like this is to say, okay, compared against what?

Right? The normal analysis stipulates some assumptions. One of those assumptions is that you would not be purchasing at the hourly energy price because most consumers don't want to tolerate that type of volatility. And I just point out just a few things. One is that, of course, we all see the extreme high prices.

I think the highest one here was towards the 2022, close to $4,000 a megawatt hour. That's in the green, all the way over to the right hand side of the green, color coded. But also note that there's a substantial number of negative priced hours. So prices in PJM can actually go negative. When there's too much power on the grid, the price swings from positive to negative. We can talk about those implications. Everyone would love to get the negative pricing. But in a real time pricing situation, you know, it's there for about that long. But this is just to give you some context. It's not to say, oh, woe is us. It just says, Okay, we have to put some parameters and some assumptions into this equation. DAY:

And I would say that from a utility director point of view, you're probably not getting a whole lot of calls from people saying thank you when the price goes negative. But I can guarantee that there will be plenty of calls each time you see a spike that goes up there. So what proxy did you use if you didn't use the hourly prices for ComEd?

Sure. So, you know, we identified the challenges. They're in the top here. And really, we had to say, okay, what would you know, but for your IEMEA contract, how would the city have hedged its purchases in the wholesale market? How much was hedged? When was it hedged? At what price? At what duration? Was it layered? You know, even the structure of the hedge can have an impact. We don't know what would have happened. So it's hard for us to know. You know, it could be anyone's guess. So, we took a proxy here. The candidate was the default portfolio at ComEd.

So, this is the portfolio that is secured by the Illinois Power Agency. It's a large portfolio, 21,000,000 megawatt hours a year. So, it's larger than your Naperville portfolio. It's shaped for daily and seasonal use patterns. So, it's not just an average price from the wholesale market. It does take into account higher summer consumption, lower winter consumption, and then peak and off peak consumption patterns from a day to day standpoint. So it actually does a pretty good job of that. It does include just wholesale transactions. There's no broker fees. It's an process that the IPA utilizes.

It has a layered hedging prospect where they can do one, two, and three year tranches. I think the majority of the portfolio right now is 50% is secured and 50% is left at index, meaning that they only lock in 50% of their volume and leave the other 50% at the market, right? Which is, again, that's how they do it. Not saying it's right or wrong. It's just it's a proxy.

And then it passes through energy transmission and other charges. So to me, it's a really good local reference because it is wholesale purchasing at scale and it's seasonally adjusted. So we thought, okay, let's use that as our basis of comparison that said, if the city was buying from the wholesale market itself, not IEMEA, would it have done something like this? I think, yeah. It's probably something close to that would have been the case.

JOSHUA Okay. So that's what we did in order to be able to understand the ComEd price that we're comparing. What about the IEMEA price? Can we just take the bottom of the bill from IEMEA and compare that to ComEd?

Well, just to be clear, the ComEd reference here really means PJM, right? So it's the ComEd portfolio, but it is based on the wholesale PJM price. So I just just to make that distinction. So we have a proxy there. And then we took a look at the IMEA charges. So when we look at the IMEA charge, we see a bill. We saw the monthly bills, and they're very detailed. And then, we were provided with this pie chart on the left that identifies, Okay, of that bill, what percentage goes to transmission? What percentage goes to capital funding? What percentage goes to purchase power?

Right? So, there's this entire portfolio approach. Something we noticed is you look over on the table on the right, you see I highlighted debt service. Okay. There is no debt service in the PJM market. You're simply buying energy, capacity, and transmission. Well, and ancillaries. So four things. The debt service that is here, that is embedded in your IMEA charges, is actually a payment for an asset. Okay?

It's separate from the energy capacity transmission and ancillaries that is delivered to you as energy supply. So if we another way to look at this is, even if you well, the analogy I use, because I try to keep things straight. The debt service is like a mortgage. You are making progress payments over time to purchase a portion of a power plant. At the end of that contract, you will have ownership of that asset.

That is opposed to renting, where you make a payment every month and you get to an end of the period and you don't own the asset, right? So to make the appropriate comparison of the PJM wholesale rates for energy capacity transmission to the IMEA equivalent, we identified that the debt service portion of those billings needed to come out of that equation.

JOSHUA All right. There is no corollary for that debt service with regards to those PJM assets, PJM price. There is not a at the end of the day, the ComEd rate payers don't end up owning an asset. At the end of the day, by you paying the debt service, you will own an asset. So what was the result of our analysis?

Lots of math. Well, arithmetic. So what we've done here is we reconstructed the monthly consumption from the IMEA billing, multiply that by the rates for that we came up for each discrete month since 2017 through the 2024 to come up with a cost of energy capacity transmission and ancillaries for PJM using the IPA proxy and the netted IMEA rate. So, IMEA billings minus debt service. And we came up with all those monthlies.

That made it for a very busy chart. So we consolidated down to annual volumes of total energy costs. And as you see in each of the years, we have a dark blue bar and then a lighter blue bar and then a green bar. The darker blue bar is the what we calculate as being the IMEA's net wholesale power cost in dollars. Next to that is what we calculated as the ComEd proxy for the PJM wholesale rate.

And then the green bar just shows the negative balance or the negative difference between the two. You see a few patterns here. One is that the for the most part, both rates are fairly stable. And that's to be expected, especially when we annualize the rates. We did see one major year of differentiation. That's 2023. That was the year of the start of the Ukraine war. Natural gas prices as well. And then in in response, electricity prices rose very dramatically during that year because only 50% of that ComEd proxy was hedged. 50% of the load experienced the price increase.

50% stayed at their hedged rate. Whereas for IMEA in the same year, 100% of your load was hedged. So it didn't move, right? So that's just the dynamic of the hedging decisions that need to be made in any wholesale power operation. But as you can see, are these dramatic numbers? I don't think so, given a utility of your size. But we do see some fairly consistent patterns here. And we see that, on balance, the cost of the IMEA service compares favorably to the proxy PJM rate that we adopted.

Okay. So that's the wholesale story and looking at that at the wholesale level. What about the retail rates? What do we do in order to be able to try to take those and look at the different types of customers for the residents of Naperville, the companies that are located here, as well as residents and companies inside of ComEd.

J. Sure. So the first step we did was we cracked into the rate book and we identified all the primary rates that are applied to businesses, residential customers within the Naperville municipal utility service territory. And those are listed in the rates box. Then we came to the volumes for the monthly consumption by rate class, monthly demand by rate class, and then number of consumers by rate class.

And what we're really trying to dig down into is rate times volume equals cost for every month from 2017 to 2024 for each of those rate classes. So, spreadsheets. Don't worry, we're not going to walk you through all the spreadsheets. That's terrible. It would be terrible.

So what data did you have to gather in order to be able to populate those spreadsheets?

JAMES Sure. So we gather data from, first and foremost, the Naperville Municipal Utility. Again, thanks to staff for being so responsive and helping us get through that. We also went through the Commonwealth Edison books, tariff books, since 2017. We pulled information from the Commerce Commission, the Illinois Power Agency, the PJM Independent Market Monitor, and Illinois Municipal Electric Agency. So everybody's got a little piece of data. We think that we have a more or less complete mosaic with the data that we collected. So that has to do with rates. When it comes to volumes, that was all exclusively coming from the Naperville Municipal Utility. We do note that some of the capacity values we use averaged on a multi month basis.

So we don't necessarily have discrete values for each and every month. But we do have A value. And we think that it's representative. And then there are some consumption volumes that are percent allocated. So for your small commercials, there's small, small commercial and then there's non small, small commercial. And there's just basically close to a 75, 25% split between those two. So we allocated that accordingly. If you wanted to get really into the weeds, you could do hourlies for each of those. That seemed to be a bit of overkill. So this seemed to be a very good approximation.

JOSHUA And we did provide the city with the models. So if there are additional inputs that you want to add into that, tweak different inputs, you certainly have the ability to do that now as well. So how did the different rate classes compare between Naperville and ComEd?

JOSEPH Sure. So ComEd's rates ComEd deals with a lot more and different customers than Naperville. So it has 20 some odd different rates. So we tried to pick the rate classes that were closest to the requirements and the data availability for City Of Naperville. So you see over here on the left hand side, those are the City Of Naperville rates. And then the equivalent ComEd rates are over on the right. And for the most part, they align pretty well. As you can see, residential to residential, outdoor metered lights to dust to dawn lighting, there's a lot of similarities there. So no real major gaps.

Though I would note that ComEd has a whole lot more rates than Naperville does. So does a bill for a ComEd customer look like a bill for a Naperville customer?

No. It has dollar signs. And that's about it in terms of similarities. On the left are pretty much the billing determinants that we see on a monthly Naperville bill. Now, we did not calculate state tax because state tax is going to be roughly equal between the two. Local taxes, we didn't do those because we don't have a point of reference. So these are largely consumption driven and fee driven itemizations. And as you see on the left, Naperville has a customer charge, an energy charge, and a demand charge. On the Commonwealth Edison side, the bill is broken into three separate parts the supply, delivery, and taxes and fees. That's in bold.

And then in each of those categories are different charges. And what we just show here are the cumulative billings for the residential rate classes rates residential rate classes applied to the Naperville customer base for December 2024. And we see that for the, under the Naperville rate, those customers would have been billed something around $5,000,000 at an average rate of 13.2¢. And then for ComEd, the billables would have been about $6,800,000 with an average rate of 17.9018 a kilowatt hour.

Okay. So ComEd has all of those additional taxes and fees. What do those look like in terms of the impact on the bills for the customers?

For the most part, the fees are established either through legislation or through regulation. And really they are orders for the utility to collect this amount of money for this purpose, right? So, Fija and CJA are our most recent legislative examples of collections for specific purposes. So the zero emission standard, the carbon free resource adjustment, all of those types of things, energy trans transition assistance. Those are usually fees that that that get placed on the bill.

Again, they're at the bottom of the bill. And they are typically additive to the energy supply cost. But every consumer pays them. Normally, we see fees as additive in cost. However, one of these fees, the carbon free energy resource adjustment in black, actually swung into being a credit for the first several months of its inauguration after CEJA. We'll talk a little bit more about this further on in the presentation. But that is the one anomaly. And it was of such a credit that it overwhelmed all the other charges and turned into be a net overall

credit GREEN:

for ComEd consumers, during those months where you see the bars dropping below the horizontal line.

Okay. Well, that'll be an interesting story for us to talk about later on. But on a bottom line impact, can you walk through rate class by rate class, the way in which the rates generally compared from Naperville's retail rates to ComEd's retail rates?

Sure. And I'll be a good consultant and start by saying it depends, right? So we have different rates are going to have different impacts. But when we compare the Naperville residential rate with the ComEd residential rate, we get this monthly price pattern. In red is the ComEd rate, and then blue is City of Naperville rate. And the pattern that I discern here are two things. One is the City Of Naperville rate, fairly steady. The variance is largely driven by monthly variations in actual consumption, right? So if you use more, you pay more. You use less, you pay less.

Pretty simple, but more or less horizontal if we were to drive the average line. And over for the better part of the test period, somewhat higher than the ComEd rates. Up until about 2022, at which time you see the big dip in the ComEd rates. That's where the CFRA, the Carbon Free Resource Adjustment, kicked in, drew down those costs. And ever since that point, they've been going up. And they continue to go up all the way over to the right hand side. So it seems that the price advantage for being a ComEd residential customer has flipped. And we don't know if that trend continues. Time will tell. But it's a decided change in the pattern.

So you've got a little box down at the bottom of this that talks about volatility index and inflation SHERMAN: index. What are those?

Yeah. So price patterns are nice. But the level of price is one thing. The volatility, the amount of movement of that price is something that can be concerning to consumers. Right? People can take good news. They can take bad news. They just can't take surprises. So, volatility is always a surprise. So, we like to measure rates with regard to their stability. So volatility index is really just a standard deviation measurement. And the higher the number, the more volatile the price. So you see here the city of Naperville volatility index, pretty tame at point five roughly. Commonwealth Edison at 2.3. And most of that volatility coming in the past year.

The inflation index is merely a measure of what is the rate of the annualized rate of increase between the start of the study and the end of the study. And it just, again, shows that over this time period, the city of Naperville rates have been relatively flat and the Commonwealth Edison have risen.

Okay. So that's the story for residential customers. What about small commercial customers?

JOSHUA Small commercial customers? It is almost the same, with the exception that over the immediate history, going back to 2017, those rates were actually pretty competitive. If you were a small commercial customer served by Naperville versus a small commercial customer served by ComEd, you were paying about the same thing. But then again, 2022 occurs, massive credits in ComEd. They reverse. And then the cost settles at a rate higher than where it was before.

And again, the volatility index and the inflation index seem to show the same type of results. Yes. And what about large commercial big companies?

They're about the same. I would say even though there looks like to be a lot of noise in this graph, that actually means that they're pretty congruent. And you see that, you know, it looks statistically, wow, there's still quite a bit more volatility in the comment. Yes, it is. And that's largely because the wholesale market has been very volatile. And that wholesale market volatility doesn't feed through to the Naperville rates because the Naperville rates are hedged.

Makes sense. Outdoor lighting, street lights.

Hard to explain. I would just say that this is, you know, rate was set in 2017 for Naperville and it stayed there. It's not representative of, doesn't have any relationship at all to variance in consumption or variance in market rates. The ComEd rates, as you can see, they bump around a little bit more. ComEd street lighting rates have typically been very low because they are not assessed a charge for capacity. And they are typically not charged anything but off peak energy rates. So they tend to pay the very lowest rates available in the ComEd system.

So what's primary service? And how does that compare?

Primary service is larger energy user that is taking service at higher voltage. So, you know, it's a big, you know, probably like a process user, manufacturer, something along those lines. We didn't get the names of all your customers. We just got data files showing consumption. So it's hard for me to say.

But I would say that in this case, the issue that I would be looking at from an advisory standpoint is take a look at the delta between the municipal rate and then those kind of peaky periods towards the right hand side of the entire graph for ComEd. And you see that the distance, when it gets high, it is really high. You're talking a difference between 10¢ and 17¢ a kilowatt hour. So that's roughly $70 a megawatt hour. That's a material swing.

And that's being driven by the market volatility. So again, it just speaks to is something hedged or not hedged? Is there value? And sometimes say in the middle of the chart, yeah, hedging, that didn't do you any good. But like a life jacket, a hedge is only valuable when you need it. So

And it looks That's how it works. Like the ComEd customers would have benefited greatly by having that hedge and that the Naperville customers benefit by the fact that Naperville already has that hedge in place.

I think that is a point, yes.

So with regards to the transmission service customers, Naperville only has one currently taking service underneath that rate. So out of an abundance of caution, we didn't want to present any customer data. We have not presented that result here. Suffice to say that it wasn't anything that would be shocking to you in terms of the overall presentation here. So we've talked a little bit about that carbon free resource adjustment and how that has impacted rates. Can you explain what that is and how that works and what the impact that that has had upon ComEd's customers.

JOSEPH Sure. So the CFRA was created under the Climate and Equitable Jobs Act. And it was a process it's called a contract for differences between the utilities and Exelon, the owner of the nuclear power plants. And what it sought to do was establish a minimum amount of earnings for three nuclear power plants for a period of, I think it was seven years? Until 2028.

Okay. Ten. Yep. So the way it works is if every year there's a new benchmark price, a minimum revenue price for power plants. If market earnings come in above that minimum rate, Exelon must rebate back everything above that minimum value back to the utility.

And then the utility pushes that credit to the consumers. If market revenues for the power plants comes in below that minimum threshold, then utilities collect extra monies from the customers and then pays that excess over to the Exelon utilities. And it's just a way to guarantee their revenue, right? So, okay, that's great. It was presented as something of a hedge to consumers as well.

It says, look, when prices in the market go way up, we're going to get credits back from the nuclear power plants. And you get the benefit. You will get a rebate when that occurs. Terrific. When market prices are low, we're going to have to ask you to kick in a little bit more to keep those nuclear power plants operating to maintain reliability. That was the trade off.

So essentially, Exelon had gone to the legislature and said, we think that there are going to be low power prices coming up. And because of that, the plants aren't going to be profitable. We're going to have to shut them down. And what the general assembly said was, well, we're not just going to give you money to make it profitable. If you really believe that the prices are going to be low, then we'll give you the subsidy in order to be able to make it even for you.

However, if power prices go up, we want to be able to share in essentially the profits that Exelon is getting at the time. So the price will go down to consumers. As market price goes up, the charge goes down or becomes a credit. As market prices drop, you end up getting a charge as a consumer. And that's the way that that hedge works within the ComEd system or the way it's supposed to work.

J. Right. Unfortunately, when ComEd kicked off the CFRA in 2022, they miscalculated and ended up crediting back to consumers an extra $1,100,000,000 So you see on the graph that the credits are really low on the left hand side. Shouldn't have been maybe half at far down on the axis. Once it was discovered, ComEd said, oh, our mistake.

We're going to have to get that billion dollars back from consumers plus interest. So what was supposed to be a pretty clean hedge is a little muddled right now. We don't know what happens with the CFRA with power prices going up starting in June? We don't know.

CHIEF Again, this has evened out a little bit now, but it went through volatile swings when it was first introduced. First, because the amount of the refund was too much, and then as they immediately tried to recoup those dollars. What about market prices?

Well, markets do what markets do. They go up and down. And this is just a tracking of the wholesale energy price in PJM. You you get a war here and there or a hurricane here and there or some type of constraint in the natural gas system, and it will immediately feed through to spot prices in electricity in the PJM market. That's just how it works.

The price for electricity is reflective of the inputs. The primary input is energy or fuel rather. So as fuel costs go up due to interruption, perceived risk, etcetera, you're going to see a resulting and sometimes accelerated increase in prices for electricity. So I don't know how you get around this unless you hedge.

So there are a couple of other charges that are included in that ComEd bill that we had walked through and the various charges that are continuing to go up. Can you talk a little bit about the renewable portfolio standard charge and the energy efficiency charges that are included in the ComEd retail rate.

Sure. So the renewable portfolio charge, or RPS charge, is a set of dollars that are collected from every ComEd customer that are then embargoed by the utility for the purpose of purchasing renewable energy credits from providers that are selected by the Illinois Power Agency and approved by the Illinois Commerce Commission. That used to be $1.89 a megawatt hour or $0.00189 a kilowatt hour. And that's the flat portion of the blue line that you see there. Eventually, the RPS was has always been subject to a cost cap.

That cost cap was raised by legislation. And that's why you see the line going up. Currently, the IPA identifies that the RPS is $2,000,000,000 shy of funding to meet its procurement goals. So we would expect that cap to be raised over time. So we think that that trend continues.

Energy efficiency programs used to be kind of just a pass through from ComEd. But then that's the the red you see over on the left. And then it dropped to a credit. That's when the old energy efficiency program ended and the new energy efficiency program started. The new energy efficiency program allows ComEd to use a combination of debt and equity from ComEd to fund the energy efficiency programs and then earn a return on those programs.

So as a rate based charge, every year when they spend money, they're actually going to increase the cost of the program because they have all the past capital to recover, plus the returns, plus the current year capital recover. So it layers in cost recovery over a ten, twenty, thirty year period.

Essentially, the energy efficiency programs have been put on a credit card, if you will, the ComEd credit card. And so not only are you paying the fees for those, but you're also paying the interest on the prior expenses that have been incurred for energy efficiency. So you've given us a good view of what the current situation is and looking at the past. Do we have any insights into what we're looking at for the future? What have policymakers, What are they seeing as the next steps out there in the energy industry in Illinois?

Right. So this is a chart that was put out by the Illinois Commerce Commission in the last cycle of the Renewable Energy Access Plan. And there's a lot going on here. But essentially, it is trying to identify on the layers where does energy come from or where could energy come from in Illinois. So starting down at the bottom, you've got the existing renewable procurements, the RPS purchases. Then the light green are those are purchases that are necessary to meet the RPS goal. Right? They have not yet been purchased. Then you see the dark blue, which is ZEC payments. Those are zero emissions credit payments paid to three nuclear power plants in Illinois.

Those end in 2027, 2028. Then you've got the clean

CHIEF J. Those are the CFRA payments.

JOSEPH Yeah, the CFRA. I forgot what CMC stood for in this nomenclature. But that's the CFRA subsidy. And you see that those drop off as well. And you see the dotted line kind of moving, the black dotted line going forward.

Those are all nuclear generation that is expected to need to be continued to be supported in order to keep those plants operating in Illinois. Above that, you start to see the potential for new demand. And, you know, what you're what you really want to focus on is the two red lines. The total Illinois electricity demand line is the top red line. That's what we must have in order to be able to self supply, right?

And as you see, we're getting closer and closer and closer to hitting that ceiling. And that the ceiling might lift in the beige. You see the potential for new demand. So that's data centers, EVs, the like. So in this, the way to look at it from a policymaker perspective is, Okay, which direction are things going? Well, first thing is the renewable incentives are likely going to have to increase dramatically in order to fill that light green gap.

Right. Those are purchases that haven't been made yet. Those aren't included yet in the ComEd bill.

That's right. Then there's probably going to be a need to continue the nuclear incentives to ensure that those assets continue to operate. Now, there's a lot of argument and pushing and shoving around this. I'm not making a value decision. But you'll hear a lot of discussion in Springfield about are the nuclear plants actually losing money or are they just not making as much money as the owners would like to see.

That's a value judgment. All I'm saying is that if they went away, that would be a pretty big portion of the generating capacity in market disappearing. And then lastly, the low growth. You know, data centers and then all the incentives for these things, the electrification, the EVs, they all lead towards greater and greater demand for electricity. And when you increase supply in any type of a market or you increase demand in any type of market, unless you have a commensurate increase in supply, you're going to see increases in price.

So that's the view of the future. We're prepared to answer questions that the board may have regarding this. But thank you again for your time and attention.

Thank you.

Thank you very much. I think at this point, do we have, while it's fresh with people, do you have any questions regarding this part of the presentation? Okay, there's a Okay, so go ahead, Michelle.

Thank you. Well, first of all, you so much for putting this together. I know especially trying to do like an apples to apples comparison and the data crunching, I can't even imagine the level of involvement that that took. So thank you. I did think it was worth noting on slide 11, I think that one kind of has a nice breakout of those taxes and fees.

And I think it's just worth mentioning, and please let me know if you agree or disagree, that looking at those taxes and fees, I mean, lot of those you talked a lot about the energy efficiency program. I mean, there's also demand response in there. So those additional riders or charges, ComEd customers are getting a lot of services and programs and such out of those that, for example, the city of Naperville doesn't offer. Not saying that we should. I'm just saying, in some cases, I kind of feel like those customers, because of the scale of the utility and the volume, they're kind of it's a little bit you get what you pay for.

I mean, have, like, massive low income programs, electrification, demand response, hourly pricing. They have a whole R and D and innovation department that those charges are funding that are, you know, we don't have necessarily, you know, even close to that scale in the city. If I mean, for energy efficiency, we have mayor and you're doing a fantastic job. But it's one of you compared to, like, you know, that one EE rider line item is funding hundreds and hundreds of jobs. So I just I know apples to apples is so hard. I just think that that's worth noting for folks. Do you guys agree with that? I mean, do you

Yeah, that's an arithmetic question. And what's in and out of the equation is completely up to the user. My understanding is that under the IMEA program that there are some energy efficiency programs and there are some renewable energy purchases. And those were not backed out when we kind of massaged the numbers here. So I think from a quantitative standpoint, yeah, we could make further adjustments.

From a qualitative standpoint, that's going to be in the eye of the beholder. Is the IMEA energy efficiency program of a scale and value that is equivalent to, say, the ComEd? And that's something that I think only the utility staff can speak to, or you as the leadership.

I would note that at the last presentation that we had, we talked a little bit about the renewable portfolio standard that they have, the goals that they have associated with that, and their failure to meet those goals to date. And again, as we indicated, those are likely to be additional costs as well. It seems that you have a different way to be able to access renewable energy. And those paths that you have are included within the rates that we compare.

Thank you.

Any other questions?

Yeah, I just had a quick question. I might be out of my league here, so just stop me if I am. On slide six and I think I understand this, so just help me if I'm not tracking it correctly. The 28.7% debt service, the mortgage payment that was being spoken of, that was essentially carved out so that you could look at apples to apples as close as possible?

Correct. So for every dollar of IMEA billables, we would count 71.2¢ to essentially back out that 28.7¢ that that is represents the debt portion of that dollar.

Right. And I think from the mortgage analogy standpoint and the benefit to I'm in members is that at some point that price would sunset because the asset would be paid for, right?

That's my our understanding of your contract but I haven't reviewed your contract

yeah I'm just working off this trying to understand sure because I think that it's really important to understand that part of that relative to this apples to apples comparison because while it looks like a benefit right it actually becomes a liability in the terms of the larger yellow pie chart piece there for the O and M operating of the assets that the IME members will actually own, correct? Like that price theoretically would go up as a plant gets older. Theoretically? And as things are paid down. So what I'm trying to understand here is just that piece is kind of left out of this kind of analysis that you all did, right?

Just how does this reduction of the debt for the assets change this equation? How does the O and M costs that go up change the equation? You know, I took an accounting class in college. I know that a lot of these assets are depreciated every year. Power plants depreciated over thirty years. This one's been going for thirteen years. So we've only got, what, seventeen years left to depreciate the asset, which definitely affects the price, the delivered price, right? From an I would guess from an accounting standpoint.

Well, we're we're not doing a forensic accounting practice here. What we're comparing is rates. So what goes into the rates, I think, can be dissected and and interpreted. And if I heard you correctly, it seems that you're also looking for some type of forward view. We're not providing the forward view. Our task is to compare the rates and the results of those rates in terms of total cost on an annualized or monthly and then annualized basis. So I think the questions are fair, but I just wanted to be clear, that wasn't the task that was assigned for this activity.

Okay. Yeah. And I'm just making the point, just so that I think it's being raised, that it's great to look at the cost today in dollars. But we're comparing an open market that doesn't have assets versus an organization that does have assets. And it would just be I don't know if that's something you guys can actually look into where you can help us better understand something about how the cost of those assets affects the price over time. But I just think that would be helpful.

Sure. And I think that those type of capitalization of physical assets, you identified the cost side. Then you need to factor that for the benefit side, which is what's the value of that asset in the market conditions in the future. So if you can come to an agreement from a modeling standpoint in terms of what you think the rate for capacity will be, rate for energy, etcetera, and your ability to be a price taker in that environment, then I think you can get both sides of that equation figured out. And then I think that gets you to where you're driving, which is what is the ultimate value of that asset after the monetization of the debt period is expired.

Right. Yeah. And I just think that would be helpful, too. The other question or point that I would just make is I think you alluded to it. And I don't know what kind of subsidies different utilities or power producers get from the state or federal governments but those can change too and I assume that's a huge risk or potential benefit in this case depending on what that looks like but because we're being asked to evaluate a contract that would take place in 2035 I think again these these factors are so up in the air it's hard to compare rates right, with today's information. Is that fair to say?

Well, think that that can be. And I try not to make very many should statements. But I think that this type of analysis is good for establishing a benchmark of understanding of, Okay, what have we done in the past? Then you can identify within that model, Okay, there's some tweaks here, some things that maybe we disagree around. But, you know, we have a general consensus view of how things have worked so far.

Then I think that allows you a better platform for looking forward. And I think that that's an absolutely valid approach that we see amongst a number of asset owners. This is really kind of that threshold analysis. And then building onto that is usually what you see come next.

Okay. Thank you.

And again, the city will have the models. So if they want to put in different assumptions going forward on all of those different inputs, you'll have the ability to do that.

Thank you on that. And I think what you both have brought to us at this point before I go any further, any other questions? Go ahead.

Yes. I have several questions. And I'll just kind of go through the slide in particular and if you could go to slide your slide 11 which is the left hand right hand side thing. Yeah. Last time you were here we spoke briefly about the possible legislation that's working its way through Springfield for batteries.

And when we spoke last time I think the numbers were 18,000 megawatts of batteries. You and your report priced that out at $50,000,000,000 and we did some simple math and came up with that's worth $10,000 per account holder of battery costs moving forward. We just divided the two numbers out. Maybe that battery build out has been lowered recently. I don't know. I've been paying attention to it. But if there is legislation to charge utility customers for this battery build out, is that going to be another line on this right hand side in your view? Or how is that going to get paid for?

It would likely be another line item under the taxes and fees category. And I believe that the current number is 6,000, not the 18,000 that we studied. All

right. So that can be brought down proportionally. But in my former life as procuring power for a large industrial, I used to approve the ComEd invoices that came in starting like fifteen years ago. And the old ComEd invoices that I used to approve literally was only the delivery section and then some taxes literally were state taxes that we paid. And then as I progressed in my career, all of these items got added on added on added on added on and your your your next chart kinda shows that progression, the next bar chart.

So the issue that I have regarding Naperville is that it seems to me there's gonna be a lot of money that's gonna be added on in the future for these line items to support all these, you know, programs that the state would like to have. We're already supporting windmills and solar farms. We're already supporting a nuclear fleet. We're gonna they're gonna have to the combat customers are gonna have to support the battery build out. Is there discussion in Springfield about moving some of these costs that are on the right hand side over to municipal utilities on the left hand side.

In other words, there's a big pot of money out there that I would assume that the legislatures would like to get their hands on, which is Naperville consumers contributing to these items that are on the right hand side. Is that is that being discussed in Springfield at all right now? I don't want to plant the seed, but it seems like that's that'd be kinda out there for discussion already.

You let the cat out of the bag. I know that the issue has been raised in the past. I don't know if it's currently being discussed. My understanding is that the only issue relative to municipal utilities has been discussion around requirement for publication of an integrated resource plan by the municipal utilities and cooperatives of the power sector. I'm not aware of any other more specific inclusion efforts to bring those public power entities into the regime that's applied to the investor owned utilities.

But I'm not in Springfield all the time anymore.

I'm little So an integrated resource plan could be a foot in the door towards that possibly down the road?

It could be the other way around. My understanding is that the municipalities probably procure more renewable energy per capita than the investor owned utilities right now. So that might be a defense. I don't know.

Thank you. Then my next question is on slide 13. Yeah, that one. I'm not quite sure what date this slide on the right hand side, the red graph on the right hand side ends. Do you know the exact date?

Yeah, that goes through for the red line. It goes all the way through '20 It's got to be end of December 2025. Is that right? You mean twenty twenty twenty twenty four. I'm sorry.

Okay. So as we all know and we've discussed in this in these meetings before that there was a huge capacity price increase that came through actually it starts Tuesday or something like that June 1 where capacity prices in PJM were raised 800%. So I'm presuming that because this ended in December 2025 this red chart or excuse me, 2024, isn't even as bad as we know today with this capacity increase that just occurred in PJM, right?

CHRISTOPHER believe it will go up about another $04 a kilowatt hour, according to what ComEd has published.

There is one consideration you have to take in. You need to think about looking at the overall impact of that, though, is that, again, when you've got an increase in that power price, you're also going to have a decrease in the CFRA. So that is a there is going to be it isn't going to be just a straight pass through of those capacity charges. There is going to be a small thing. It isn't going to be one for one, But it is going to be recognized as a reduction

in the CFRA. CFRA is based upon energy prices plus capacity prices?

That's correct.

Okay. There'll be an offset due to CFRA.

Correct. Okay. Might not be one for one, though. It's, think that's

I believe, in the range of 65 BERNANDEZ: percent.

Okay. All right. So this, I think it's safe to say this red dot ending in December '24, the red graph ending, it's worse now because of this capacity. It's a known increase. It's not speculative. Correct. Okay. And I don't know if this is probably a question for director Groth, but this chart shows the residential customers paying more than ComEd, know theoretical ComEd supplying Naperville but the small commercial seemed pretty even, large commercial seemed pretty even. What percentage of Naperville's load is residential

I'll defer to mayor Dieb he is out he has the number he wants to say it

forty five percent Forty five?

Correct.

Is residential. Okay. So this applies to about half of Naperville's consumption. Okay. And then in your in your discussions, when you described why the blue line is fairly flat, you kept using the word hedge. Neighborhood has a hedge. Neighborhood has a hedge. All those charts, Naperville is fairly flat. When you say Naperville has a hedge, are you truly are you actually referring to the fact that Naperville buys most of its power from some thermal units in Southern Illinois and Kentucky whose prices just generally haven't gone up over the years? Is hedge equal to thermal plants in Europe?

CHRISTOPHER Yes, there are CHRISTOPHER you're looking

at things here?

CHRISTOPHER There's typically two types of hedges. One is a financial hedge. That's a power purchase agreement. And the other is a physical hedge. The primary hedges that impact the IMEA portfolio and therefore Naperville are your physical hedges that are held on your behalf through IEMEA from your ownership interest in the Prairie State as well as the assets in Kentucky.

Okay. So just recapping, that flat curve can be pretty much attributable to IMEA owning thermal plants. As we discussed before, you know, at Prairie State, they own the coal in the ground. They don't to buy coal. We went through all that.

So that's a reason for those flat curves. Okay. And then my second to last question I think is on page 19, which is the carbon free resource adjustment. And I think you said it but I'm not sure I heard it correctly that that has a termination date correctly or correct right now right

that's right 2028

but the charts that you show at the very end the multicolored graphs indicates that there's going to be these nukes aren't subsidizing the nukes isn't going to end, think is what you're saying. And the CFRA is actually a subsidy for a nuke, are the zero emission credits. So it doesn't seem to me, all the speculation, that those line items on the right hand side of that Naperville versus ComEd bill is going to go away, even though it has a termination date.

Again, that's our policymakers seem to generally accept the fact that there is going to have to be something done in order to be able to ensure that the nuclear units are still there for Illinois consumers.

Okay. One more question and then I'll be done. But as we know, the current administration is looking to terminate IRA, Inflation Reduction Act, subsidies that solar and wind get these days, investment tax credits, production tax credits, various other subsidies through the federal government, through the tax system of the federal government, it's not even on a ComEd bill. If those subsidies go away, just just from a qualitative point of view, what direction is solar and wind prices going to go for those that may need to buy that out in the future? Are they gonna go down or are they gonna go up because of the loss of subsidies?

Well

Like a PPA agreement, for example, for a solar farm or a windmill.

So it seems to me that the federal tax benefits support a very large portion of the development cost of assets. So I would say that for new assets, the cost of a new PPA will go up because the cash has to come from somewhere. Now that could be offset somewhat by technology, supply chain, and the like. But I think it's material increase in cost to buy the same project in that environment. In terms of purchasing from an existing resource, well, that resource is going to sell at market.

So I don't know that the tax policy necessarily has an impact there that is a direct line. There may be an indirect inference of cost impact. But I think that's more localized to the regional balance of supply and demand. Meaning that in a tight market, it could cause a material increase in overall cost. In a in a supply rich market, it might not have an impact at all.

So the other alternative to the price of solar and wind going up due to tax subsidies being eliminated is that there's less solar and wind built. And if there's less solar and wind built, the supply demand crunch that is already predicted is only going to get worse. In a situation where the supply demand balance gets worse, prices only go up. So for those entities that are buying at the market, one could construe that prices are only going up in the market. But as we discussed, Naperville has a hedge against that and that hedge is that Naperville is a part owner and directly through two thermal plants that it owns in Southern Illinois and Kentucky whose costs are almost fixed.

You can you can almost predict what they're going to be today, tomorrow and ten years from now. So and on top of all that, we've got all of these subsidies that are being layered on ComEd and customers which you're saying there's no current legislation to move those costs to municipal utilities but there's no guarantee of that either. You know when the legislators start getting hungry for money they go wherever the money is. So I guess the point I'm trying to make here is that Naperville is facing multiple well, then we've got the issue of brownouts and blackouts. You know there's there's all of these things that are kind of in the mix here.

Naperville is facing a layer cake of issues and problems coming up. Not only is there the decision to re up this contract with I'm here or not, we got rising prices. We've got you know, the potential for brownouts and blackouts to deal with. And for those that don't have this hedge, it's even worse. So I guess that's the point that I'd like to leave this discussion at right now.

Any other questions? Nick?

Not necessarily a question for you guys on this bit, but just to, I guess, sort of add on to the point there that Jim was making, I had previously commented on the fact that we're, for wind and solar in this case, but in general, when there's a subsidy getting through federal government or somebody else, it's not a true market. If Jim is giving if I'm trying to sell plant strawberries and sell them, but Jim is giving me $2 and without him giving me $2 anymore, I can't do that. It's not really a market. I didn't exist without him helping me. And then me being out of business, now prices would go up because there's less supply.

On top of the fact that when, as you guys know, as others know, when these are subsidized, it doesn't show up on our income taxes. The federal government just prints money, which results in monetary inflation as opposed to price inflation, which eventually gets reflected in prices going up one way or another. And then as we've seen over the past five years, the federal government continues to spend money. It's not taxed. It's printed or borrowed. So and the result of of that is everybody pays for more for their goods and services. Thank you.

Thank you. I'm just wondering if we've been going for two hours right now. And I know you're in the middle of your second presentation or starting the second part of your presentation. Do we want to take a recess, a short recess, or we want to keep on going? Okay, we'll keep on going. Thank you.

Thank you.

We're going to make this high speed, low drag for you. Separate topic. This was an examination of what are the options to select a retail supplier or power marketer to replace the functions of the membership in IMEA. So full disclosure, I've been in procurement for a large part of my professional life. And so a good portion of this is drawn by my experience.

But feel free to push back on anything that needs clarifications. So the wholesale market starts with power plants. The power from the power plants goes through transformers up to the transmission lines. Those are high towers that run along the highways. Then those transmission lines connect to a large substation where there's a step down transformers that bring that electricity to a voltage that can be distributed at the local utility level.

And then the utility delivers that to the meter and from the meter to the plug for the consumer. So right now, as a municipal utility, you operate within the red box, right? You've probably got some transformers. You've got well, starting on the left. I'm starting on the right. You've got the end users. You've got the transformers in your local system. You've got your local distribution lines. You may even own some of the transformers that connect you to the interstate transmission system, right? PJM is the wholesale market.

They're the ones that manage the power plants and the transmission lines and the access to those transmission lines. So that's the difference between the two. To operate in the wholesale market, that means buying electricity from a power plant and then selling it to a retail customer means that you have to be a wholesale market participant. You're a load serving entity, an LSE, right? So to meet those obligations in this part of the world, you had to be a member of PJM.

Now PJM has different types of members. So you see end use customers in the upper right hand corner. Those are consumer advocates, very large users like aluminum smelters and the like. Move counterclockwise to the generation owners. That's all the power plants. They have to be members of PJM. They have contractual obligations and performance requirements to be part of PJM. Otherwise, their power isn't allowed onto the transmission system. The transmission asset owners must also have agreements with PJM to provide non biased or non discriminatory access to their transmission lines. Then there's other suppliers.

So these can be retail energy suppliers. These can be banks. They can be hedging organizations and the like. And the last one here, electric distributors. People who buy from the wholesale market and then sell to the retail customer. That's where you would need to be. And then as such, would then likely become a voting member of PJM if you were to do that. Now, all of this right now, as I understand things, is all managed on your behalf by IMEA. If you did not have IMEA and you wanted to go it alone or go it with some other municipalities, that's fine. But ultimately, you're gonna have to solve for how do we interact with PJM.

There must be some type of membership activity, right? I'm a can do it because it's a joint action agency. If you didn't have that, you would each have to be a member on your own. So what does it mean to be a load serving entity within PJM? Well, I'm not going read all this to you. But you've got a number of categories, number of buckets of requirements here. So to be a member, you need to apply. You need to sign agreements, all that type of thing. You know, there's the paperwork. Then there's the market operations.

That's where you are scheduling and getting your electricity scheduled and delivered, measured and metered. And you have to take into account all of the activities around managing that activity through your load management. Then you've got your general planning. You need to tell PJM what you think your load is going to be in the next one, five, and ten years. There's legal activities, lots of compliance. Lots and lots of compliance. Because PJM is a federal entity. It receives its charter from Federal Energy Regulatory Commission. So as Federal Energy Regulatory Commission issues orders that impact PJM, PJM changes its rules. To change its rules, PJM needs to go to its members to get those rules approved.

So it's like the Attorney Full Employment Act. Then to the general transactions. You need to run your own procurement, your own hedging, and purchasing your own environmental attributes. Now, the red box is what IMEA does for you. As a member of IMEA, you and all the other members, you get those services provided to you through the General Joint Action Agency. There was a question that said, Okay, well, of all those things, what's really a 20 fourseven obligation? What has to be done every hour of every day? And that's in the purple box. That's that load management. All the rest of it is a lot of paper, a lot of meetings, and a lot of compliance.

The load management, I think, is where people wanted to get a sense of, okay, what's the moment by moment activity that has to be managed? And that's the trading desk or the transmission desk. Transmission scheduler is the other name for it that we typically see in load serving entities. So, can an individual municipality operate independently in PJM? Yes. But very few choose to. You know, I mentioned to Chris when this issue came up. I said, Well, yeah, you can cut your own hair, too. But most people don't do that, right? It's because there's someone else who could do it.

And as a group, you can share the burden, right? So this was a list of all of the municipal utilities who are listed on the PGM website as a member. But when we take a closer and it looks like, oh, well, these are all independent members. Well, when you dig a little bit closer, starting with the city of Dover in Delaware, that's actually part of a larger group that handles a lot of their activity, just like IMEA. Batavia, Rochelle, and city of Geneva, also on that list.

And you say, Oh, well, they manage things on their own. They don't. They're part of Nimpa. And they also receive services from an outside entity called Avant Energy that handles a lot of this activity for them. I wasn't able to dig in and find out the story on the Indiana and Maryland municipals, but we'll continue to look.

New Jersey, all of those entities that are listed as individual members for PJM, they are also part of the New Jersey Public Power Authority, right? They're pooling their purchases and management. They're taking all these costs and tasks, pooling them together, and then achieving some economies of scale. So, I put hot links on there so you can see where I got the information on that. So, the problem statement that was presented to me was, Mark, could city of Naperville engage an alternative provider, a retail energy supplier or some other like entity, to meet its needs?

And I'd say, well, they can meet part of your needs. And the needs that a retail entity is most likely to be able to fulfill for you are in the red box, market operations and load management. And admittedly, those are critical. But again, as a load serving entity, you need to tag all the bases, right? All those things have to happen. So you could contract out load management and market operations with a counterparty. Right? And there's different kinds. And a lot of them would be interested in your load. Obviously, you're a big load.

Right? They'll be very interested in talking to you about it. But in effect, you would still need to take on the membership requirements, general planning, legal activities, and general transactions on your side of the desk, right? You need to find another provider or do them internally. We had a request to define some power marketing terms.

I'm not going to read all this to you. But I think that part of the challenge of operating in this arena is just that the language is somewhat duplicative. I would just maybe the most valuable part of this table is figuring out what is a power marketer. So a power marketer generally, as a category title, is an entity that sells or facilitates the sale of energy between parties. Could be wholesale parties. Could be retail parties. Right? That's a general category. So Constellation, Shell, MC Squared. Those are all power marketers.

A reseller is a power marketer that takes title to energy, meaning that they buy it, and then they sell it to another entity. Right? That taking of title means that they're taking on the market risk. And they're very sophisticated entities. And again, Constellation, Shell, MC squared, those are all examples of resellers. A service bureau is a little bit different. That's a power marketer that won't take title to the energy for you. They'll tell you they'll help you set up your agreements with your counterparties. They'll do your scheduling with you. But ultimately, you need to sign your own credit, your own contracts, and provide your own credit.

So Aces and American Power Net are examples of that. And then a retail energy supplier. That's a reseller that takes title to energy and then sells the energy to another party who is a retail customer. So might seem like too nuanced, the definitions, but this is, you know, the vocabulary that we use. One other issue that might have come up that you may have heard about is something called a subaccount.

So when a power marketer is a member of PJM, they have a PJM account. And it's through that account that they communicate their buying and selling and scheduling, right? That entity can create a subaccount. So I have, you know, Mark Pruitt, retail energy supplier. I can have my primary account and I can create a subaccount that I can manage separately from my primary account.

If I have a very large customer, I can put them exclusively in one sub account. This is usually what we see with large retail customers. So universities, hospitals, and the like. They typically do this because they want to make their own purchasing decisions and they will post their own credit. This is typically not something that you see in the wholesale entities using the sub account approach because wholesale entities are wholesale entities and they're obliged to operate as a primary account, not as a sub account.

And then, when I say terms like going to market, that means putting on a bid. You know, that's what I've done for most of my life. So, if an alternative provider can't do everything for you, would you need to staff up or would you need to contract out? I put together a little list going back on some of the studies for wholesale market participation strategies that we've looked at. When I was in the cogeneration business, we went through this activity every time we sold a cogen plant.

And that was, should this co generation plant be a wholesale asset? Right? We took a look at this every time. We took a look at this when I was at the University of Illinois and we were managing electricity purchasing for all the state agencies. University of Illinois is a wholesale market participant, right?

So we drew off of their example to see what operating within PJM was about. We looked at it when I was at the state to see if the Illinois Power Agency should be a wholesale market participant like the Long Island Power Authority. Ultimately, decided not to do that. And since being in consulting, we've looked at wholesale market participation for a number of large entities factories, hospitals, colleges, universities. And, you know, we look at this, it seems like with regularity, every one to two years.

And in every case, they ask, well, could you come up with a staffing plan? And this is pretty representative of a staffing plan that I think would be reasonable for a mid sized utility to operate. You see some job tasks. There's a wholesale energy manager, some energy analysts, because they're going to be living in spreadsheets and doing a lot of projections. You've got an energy policy analyst, somebody who needs to keep up with what's happening in FERC as well as the state. You're going to need some clerical support. You need a regulatory attorney because you just can't nothing against counsel. But I don't know if you want to become a regulatory expert. It's a lot. And then a lobbyist.

You may already have a lobbyist. That's great. Some of these are internal. Some of them are external. All I'm saying is that to get across the line of meeting all your obligations as a PJM market participant, even if you bring in a power provider, right, like a Constellation or someone credible like that, you're still going to have these types of costs. And it's these types of costs that lead most municipalities to group together to share the expense. Because the expense for managing the load for one utility is going to be pretty close to managing the load for four or five similar sized utilities. So you get economies of scale. So if you wanted to bid out or go to market, what would you need to do? You need to define what you're buying.

It's supply capacity transmission. You need those deliveries to start in 2035. And you're going to need some services as well. So you get that package. That's good. Then you need to work through a series of decisions. What's your schedule for deliveries? Do you want grid? Do you want unit contingent? You know, what's the source that you want? What resource types? What product types? You want a financial hedge. You want a physical hedge. What are your objectives in the hedge? What's your selection criteria? Right? If you get a really low price from a fossil fuel plant, is that gonna be how are you gonna grade that for a financial hedge from JPMorgan? You know, does it matter? You need to decide that going out the door.

And then you need to have terms for post selection contract renegotiations because getting up it's going to be very difficult to get a price today for energy delivery in 2035 because there's a lot of unknowns. So, here are some of the unknowns, also called risks in this table. For the bidders, what are they facing? Well, if I give you a price, you the municipality a price today, it might be too low come delivery time. I could say, Oh, I'll sell you electricity at $50 a megawatt hour, but the market price for electricity in 2035 could be $90 They'd be out of the money.

What do they do? Do they honor their $50 offer? Or do they terminate the contract and pay a penalty? Can they contract to can they enter into an agreement today not knowing what the regulatory obligations are going be ten years from now? That's going to be an item that is out of their control. And then they're going to ask, that's great you had every intention of being a municipal utility in ten years, but what if you're not here anymore? What if something changes and you get out of the utility business? What happens to this contract? So the bidder is going to try to mitigate those risks. They're going to increase their price offer.

They might simply offer an indicative price today that they reserve the right to bid tomorrow. And we see this a lot, not just in power, but I don't know the last time your city bought a fire truck. But usually you buy a huge piece of equipment like that several years in advance. You get an indicative price today. And then that price can be changed as you get closer to delivery point two and three years down the road. Same thing would happen here. It could be ten years down the road. So a price today is not something that is necessarily gonna be held for ten years. Or they might not bid. Your risks.

You might accept a price today that's too high. You might lock in at 90, and for whatever reason, market price for power ten years from now is 50. Now, you're really above market. You're committing to contract terms that, you know, you don't know what the regulatory environment's going to be. Are you going to have obligations to the state? Are you going to have different obligations to FERC? Are you going to have minimum take or pay provisions on transmission? Will your counterparty be there in ten years? These are all private companies. And we know that companies change and merge and go out of business.

And then they change their business. What if you entered into an agreement today with an NRG, only to find out that, like a couple weeks ago, NRG bought, I think it was a dozen natural gas power plants from LS Power. Now they're in the gas business. Is that somebody that you want to be transacting with, right, that you get your reputational risk? So you've got mitigations as well.

And it just means that your procurement process is not as simple as posting a bid, taking in prices, ranking them according to price, and then executing a contract. There's a lot of planning, a lot of preparation, and a lot of guesswork that's going to be done in this. So in a conclusion, slide, replacing IEMEA is going to require the utility to engage as a PJM member, one way or the other, right? That's a step up. And I'm not saying you can't do it. I'm saying you just don't do it right now. So it's additive. I'm sure it can get done. Obviously, it can get done. But there's very few, if any, one stop shop solutions that we've identified.

In all the municipalities that we reviewed, we didn't see evidence that a utility of similar size or a municipality similar size was simply operating their utility with only an alternative provider, right? There's always someone else in the mix providing those additional services. This ten year runway before delivery is really a challenge. And I don't envy you. This is tough.

Part of it's because wholesale energy markets are not liquid beyond, say, we used to say thirty six months. I would argue it's probably closer to twenty four months. So if you've got a price today, you don't from a vendor for delivery of energy in ten years, you don't have anything to validate whether that price is good or bad, right? It becomes a real challenge. And then, you know, usually when we've done these analyses before, what we were trying to do is to gain economies of scale or be able to sell our resource at a better price.

Right? That's co gen plans. It's the state portfolio of purchases. Those are the normal drivers that we see. Because there's a cost associated with this. Time and treasure has to go into this investment to be able to operate this way. And you don't have those here. So it's really a challenge to say, Yeah, go ahead. Cut your own hair. Very risky because I don't know what benefit you're seeking to achieve through this activity.

So I would, you know, my words of encouragement are, of course, you can do whatever you need to do. You're fully capable of doing it. I just think that it's going to be advisable to have a very clear vision of what are we going to accomplish in doing this. Because the road is going to be long and it's going to be challenging. So you're going to need to have a goal, well defined goal, to be able to justify the investment of time and material and money to get this done. So I appreciate your patience. I know it's been a long meeting. You've heard enough from me. I'm happy to respond to any questions. But thank you for your patience.

JOSEPH Thank you very much for your presentation. And at this point, do any of the UAB members have a question? At this point?

Yes. Yeah, this is Phil Schrader. Go

ahead.

I'm sorry. No? Oh, Phil. I didn't see him. Yes, Phil, please go ahead.

Sorry, know you can't see me. But yes, I have a question for Mark. Thank you for all the information. This question might stretch a little bit out of the nature of what you were asked to look at. But if we simplify and go beyond, like, what the solutions are to buy power in the future, because clearly, are many different ways to do that and to structure it and through different entities, wholesale, whatever.

If you simplify this down to the simple decision factor is around price, I think what you said is that we have no certainty on price beyond, like, the 24 month mark. I don't think we have any certainty on price from IMEA in their contract or what they've proposed. And somebody correct me if I'm off on that. So if the dimension is to try to make a decision today about buying power in the future simply based on price, but we don't have any certainty about what the price will be in a PGM market or through IMEA. How do you advise us to try to rationalize the decision process around that as well as the timing?

Because I don't if you take any other city, like Boston or Philadelphia, are they in a similar state right now where they're struggling with how to try to hedge the cost for their consumers fifteen plus years from now?

Well, think that for those cities you mentioned, they are served by investor owned utilities. So for those entities, I think their options are a little bit different. They can enter into virtual power purchase agreements. They can serve as a long term hedge. We've seen that quite a bit.

And they take some number of years to move forward with, right? They're not built overnight. So I would say that for those entities that are served by investor owned utilities, that's probably one way that they can start to set hedges going into the future and then arrange their energy purchases, discrete physical energy purchases in shorter term periods going forward. As it relates to your position in IMEA, yeah, your question's a bit outside of what we're looking at. But I think that most entities, when they're faced with this type of a question, it's probably very similar to the analysis that, say, a large industrial would undertake when they're deciding, do we keep operating the current steel mill or do we move to build a new steel mill?

So they look at a production cost modeling process. And that gets fairly involved because what you're trying to do is say, what's my best guess of cost of operations for option A? And then what's my best guess for cost of operations in option B? And I'm just trying to unify my assumptions across both of those scenarios. So that might not give you the comfort that you were looking for, Phil, but that's where I think, and I think we touched on this a little bit earlier, that that type of analysis, I think, can be done.

And it's usually what entities do once they've come to grips with, okay, this is our history. This is where we're at right now. Here are our options. How do they stack up? And I think that what you're talking about and what was addressed earlier is that next step, okay? How do they stack up? You know, the options.

Was that good, Phil?

Yeah, thank you.

I'd like to add that with the options that everybody has, all people, all cities, all municipalities looking for sources of energy, there's always going to be a certain amount of risk and volatility. I think the history has the history not shown us from what you've shown us today that there's less volatility going with IMEA and that there's less risk from your previous presentation? Because we're talking about risk. And we're talking about whether or not they have a source of thermal fuel that provides a stability that guarantees less volatility.

Well, that's true during the study period. It's also true that there's a cost to a hedge, right? There's going to be sometimes when the price you pay for commodity plus the hedge value is going to be above what's available in the market today. And sometimes it's momentary. Sometimes it's a duration.

So I think that when you're talking about hedging, at least when I speak about hedging, what I'm talking about is not saving money. I'm talking about how do I prevent something unexpected from happening, either to the upside or the downside. So in that case, the hedge that you currently have in place for IMEA, at least from the data that we have, has performed pretty well. The hedge that goes on to the ComEd wholesale price for consumers, it's a different hedge. It's a fiftyfifty split.

Half is left on the market. Half is secured through short term contracts, not the twenty, thirty, forty year contracts that you get from power plant ownership or a virtual power purchase agreement. So they're different. And therefore, they have different results.

I'm just trying to follow through with that thought here. They're different. But the result is that one has performance in the past that shows less risk and more stability. And that thermal fuel is there, is going to be there for this extended future time frame that we're talking about compared to what PJM is looking at, where it's a little bit more of a mix?

I think that's true. I think that the counterpoint, just to be fair, I think the counterpoint is you're putting all your chips on kind of coal, right? And there's the market characteristic, the cost of that coal, converting that coal into electricity. But there's also a regulatory risk premium. There's also other elements that can go into that equation. So I think you're right. Yeah, from a pricing standpoint, which was the nature of our assessment, yeah, you got a lot of stability in that. And I think it's worked pretty well, right? And when I say well, I'm not saying it just worked as according to plan, right? That's what it was intended to do.

I think that part of your policy conversation is, what are the metrics that we're going to measure to get success? And that's a robust conversation that I'm sure you're in the midst of on an ongoing basis.

GREGORY Right. And so it comes down to, if IMEA was only coal, that'd be one thing. But they're adjusting to the renewable environment also. So as the coal diminishes, the renewable increases. So the hedge is adjusting to the future. When you said, we don't know what the future is going hold because of regulatory requirements. The regulatory requirements we know are going to are established so that IMEA, has to address that and meet that requirement.

That's correct.

In the meantime, while they're doing this transition, they have the stability of the thermal source as they adjust and transition into the renewable. Is that They

have access. Yeah, they have access to a resource that others in the market do not.

Mean, but isn't that a significant issue point?

It would be if I was responsible for a

P and L. It would be if you're responsible. Okay. So are there any other questions or anything? Yes. Go ahead, Michelle. Michelle.

Yeah, Mark. One of the advantages of having a YouTube celebrity here like yourself is we can watch your YouTube videos wherever you chose to get them recorded. And some of us, maybe not all of us, were interested in your presentation to Winnetka. Winnetka's a fellow IMEA members that's struggling with the exact same situation we are. So it's been instructive to watch what they're doing with your help.

And I actually learned some things about Naperville following the Winnetka situation. So a couple of meetings ago, I expressed the concern that Naperville is between a rock and a hard place. The rock is that IMEA has given us a deadline to either join either join or not join. And actually we've we've passed that deadline already. It was April 30 April 30 But they're gonna meet in a board meeting in June to decide whether we have until August 21 to accept their offer or not. That's the rock.

Hello? I think we had lost Phil maybe, he's coming back. That's what it sounds like.

Now, just a little history. I think it was back in 2007, Naperville agreed to the current contract that we have with IMEA, started taking production from the coal, Prairie State coal plant in 2011 and in fact because Naperville decided to go with IMEA supply that's why they bought into Prairie State. So it's kind of ironic that we're here right now with this. But one of the things that happened back then and I don't know if I'm characterizing it correctly or not but Naperville was late to the game in joining IMEA and choosing to have them be a supplier of power. As a result of being late to the game, Naperville has incurred a price penalty that we're paying to this day.

Believe it or not, we're paying a price penalty to this day for joining late in 2011. I asked director Groth to add up with that, and this was in a Winnetka report, believe it or not. I didn't know it. I read the Winnetka report and they're talking about Naperville. And this total dollar amount that we will end up paying through the end of this year is about $50,000,000.

So Naperville's rate payers have suffered by the tune of $50,000,000 because of the indecisiveness of the city fourteen years ago to enter IMA or not. So IMA has given us possibly this August 21 deadline and the August 21 deadline means either we're in or out, or it could mean, Naperville, we're gonna let you back in, but here's the price you're gonna have to pay for the next, you know, or starting in twenty years starting in 2035. So that was a $50,000,000 miss from back then. So there's proponents for us to go out and bid this this power out. And that's the hard place because if we bid the power out, director Gross said that's gonna take six months to get out the door.

God knows how long it would take to evaluate. You you showed all the complications of what it means to go out and bid. But the the piece from the Winnetka presentation that I I witnessed you make was you actually contacted roughly a dozen wholesale suppliers that we could go bid out to, for example. And I and I think what you said was that none none of the ones that at least would speak to you about it said that they would give you a price starting in 2,035. Is that correct?

That's correct.

So this concept of Naperville bidding out their power source to make sure we've covered all our bases is this rock and hard place thing where if we wait a year to do the bidding process to learn what you've already learned that nobody will give us a price starting in 2035, or it would be a price that comes with all the risks. It's too high, regulatory risk, blah blah blah, all the things that could happen. This is where we are right now. This is what our city council is going to have to face. And I don't we're not asking you to answer the question, you know, what should we do?

But I think you're finding at Winnetka is very revealing that there's nobody out there that's probably going to give us a price that would satisfy requirements that we would think would be a safe contract to put together. So I just like to make that point. And I guess I have a bunch more questions. But this thing's gone on long enough, and I'm done. I'll conclude my questions with that.

Well, it is you almost got to see, boy. I mean, I was listening like, what's the answer to the question? So when you went out, you, in effect, did not find anybody that would give you that bid ten years out.

Right. We had a number of what I consider to be qualified providers, all PJM members and like. And they would not It would state that their governance generally was the reason that they cited that they would not have a way of providing a committed price that they could offer today for delivery in 2035. They did say we could give indicative. We could maybe work on a formula.

Like I said, there's a lot of interest. This is new load for those folks, and that's the business they're in. They all expressed, We definitely would like to work on it. But, Mark, if the expectation is 30 megawatts of capacity starting in 2035, we can't perform on that. We're flying blind for all the reasons that were noted. And I don't think that they're holding back. Think it's just a risk issue. SHARFSTEIN:

Oh, absolutely. And I think we've heard risk so many times in several presentations. So really, that's not an option. DELL: That's not a viable option.

Well, as was mentioned in that meeting and tell me if that's wrong. I mean, there is the other side of the coin that says, well, you got ten years to figure it out. That's true.

In a more volatile environment.

Also true. So the hard spot just got harder, You know?

It's Right. Just It's not going to get any better as we go along. Thank you both. Any other? Yes, Michelle.

Thank you. I guess I'll be totally clear then with my perspective. I guess I am one of the I am the one of the proponents for for going out to bid for this. I mean, my my main concern, it's not it's not a coal fired power plant. That's not kinda my perspective.

It's the prudency and transparency of going through the formal process. I just cannot wrap my head around sole sourcing something of of this size, and I understand the risks. And looking at slide 13, you do a really great job detailing those risks. And I guess a point I would make is that you could replace the header of this bidding out the city's electrical load to sole sourcing with IMEA the city's electrical load. I mean, the risk, I guess one big difference on the municipality side to city of Naperville is, well, IMEA won't even give us a price to accept.

And it sounds like neither will these bidders. But I'm not seeing anything in that risk to Naperville category that doesn't also apply to sole sourcing with IEMEA. I know we've also talked about how, I think what was it slide nine where you outlined all the member requirements this is really helpful I think in documenting like yes this is what's involved in providing electricity to our residents and to our businesses it's a huge huge undertaking and there are plenty of providers who you know want to take a bite at the part in the red and you know, I think it's pretty clear there's not one, you've made it pretty clear, think we know, there's not one company that's going to provide all of this. But we don't necessarily need a one stop shop. I mean, I think there are plenty of companies that would be happy to partner or subcontract with each other to provide these services to us.

And if one of the concerns could possibly be like, oh, well, I don't want to have to deal with several different companies. That's fine. Let's set up a contract where we have a prime identified and just make it really clear that we only wanted one nectaring for all contracting purposes. I mean, just feel like there lots there's an opportunity here. And for those reasons, I'm still a proponent of putting this out to bid.

I'd just like to support what Michelle is saying. I think just because someone or something is making us make a decision quickly doesn't mean that we should do it. And I would also add that just because we've spent $50,000,000 over that period of time because we took our time we don't know what things we evaluated that we missed in terms of things that could have gone wrong. So you know $50,000,000 is a big sum of money But going through the process, that's the cost. And it's unfortunate that this organization we're part of is penalizing us.

I think that's something we should really think about moving forward. Because when you talk about controlling cost and making sure everything's going to work out in the future an organization that's been putting an extra cost on us for all these years needs to really be considered and to that point Ryan if I may ask is there an appetite within this NIMPA group for additional members? Have you talked to them about the ability for this city to do what's in its best interest, which is evaluating all of its options including joining other groups

we have not researched joining another joint action agency if you remember there were some comments from CES in the past about joining potentially AMP or anything like that which is another joint action agency in this area actually not in Illinois but outside of Illinois certainly there's there's that possibility. I will remind everyone that Nimpa is 100 a project based organization that is 100% invested in Prairie State, right?

So, I

I don't know if that necessarily moves the needle. And then as Mr. Pruitt just talked about, how they handle their hedges and things like that is all through Avant Energy as I understand it. I'm not versed in other joint action agencies and things like that. But maybe perhaps it would be helpful to discuss a little bit about Nimba if you have a little more knowledge. Project based organization does all of their energy sales through Avant Energy. So only fulfills a portion of that piece. Right.

I don't have a deep operating understanding of Nimpa outside of the Nimpa organization. Has a One of their primary drivers is to facilitate the ownership interest that those municipalities have in the Prairie State project. So that's the primary charter issue of NIMPA. And they all have different it's very similar type agreement, slightly different, but similar to what you're looking at now. And that they do split some of their responsibilities.

They handle in their own silo. The city will do this, but collectively will do that. And then they have also worked with Avant to do some of their scheduling. So it is, as you mentioned, it's a mixed bag. And for them, it works.

To an outsider, it appears to work. I can't make a qualitative statement of it. But as we saw on the list, it's just not uncommon to try to find other like entities to share the burden with. Because if you can do it for $1 $1 you could probably do it for $4 for $1.1 right? It's like that in this business. There's a surprising amount of fixed price or fixed cost that goes into energy operations. But once you get there, the incremental cost is pretty small.

One more question. Do you know with that group how their rates compare to ours?

I believe they're a bit more volatile. There is a report that's published annually and maybe mayor has a little bit more insight. I know he's looked

at that. I mean, will share with the group the latest report that compares Naperville to Nimpah and Calmette.

Thank you.

I have a quick question for Brian that some of these comments just made me think of. So has we talked at all with the other communities that haven't signed it? Like I'm thinking, for example, Winnetka, maybe we do a combined procurement process with them. And it's two totally separate contracts. But just saying, hey, you're going to be providing the same exact group of services. Could we somehow leverage that for better pricing? I mean, could that be a possibility? Like, have there been conversations between, you know, staff at the other municipalities that haven't yet signed?

The concept has been discussed at a high level. I'm not sure that the economies of scale get there, right? I mean, we are the largest energy procurer from IMEA. Wernetke and St. Charles are substantially smaller than us. Maybe perhaps, Mark, you would talk about economies of scale and where that type of load would fit in the market. I think that might be helpful.

JOSEPH Sure. I can't really speak to St. Charles. I'm not deeply familiar with them. But Winnetka's peak load is about 30 megawatts. So they're about 10% the size of Naperville. Still a good size, right? I would say a large retail customer for an MC squared or a Dyna G is two megawatts. So 30 is pretty good. 300 is kind of an order of magnitude more.

I would say that, you know, to join together with other municipalities, you're gonna have to work through the governance process. You know, the procurement angle, I think, is manageable, right? It's a different number. It's a different schedule. You can break things out. You have same terms and conditions and different prices. We see this on the municipal level with buying road salt through the state contract, right? So obviously, there's a model there. I would say that based on my experience of working with municipalities, the heavy lift is probably on the governance side, right? How can a multi municipal entity operate from a voting standpoint?

How do you prevent cross subsidization on energy pricing and or services pricing? There's just some value driven questions that need to be pinned down. And again, not to say it can't be done. There are joint action agencies for water. In Georgia, we see a lot of co ops joining together for natural gas. So it's been done. But my sense and experience is that it's on the governance side, the planning side, where most of the effort has to go. The procurement is largely a mechanical issue. The governance is a value issue. So that tends to be where most of the effort is expended.

Yeah, that makes sense. Thank you. I guess I was thinking mostly just the procurement side and kind of peeling off before the governance part comes in. But yeah, knowing that we're, it sounds like it would largely benefit the other communities more so than us.

Thank you for that. I have one oh, you have another question? I have another. Phil, how are you doing?

I do have one more question, but I can wait after you.

Yes, go ahead. Go ahead.

Okay. Guess I'll direct this towards Mark, but it might be for others to respond as well. If the city of Naperville chose not to renew with INEA today, it kind of sounds like it's based on comments that people have made that it's implied that we need to go to market and get a competitive bid or that we should go get a competitive bid at this point in time. But if we chose not to go with I'm EA today, what is the risk to the city of Naperville of just sitting in the market for five years without doing anything?

Right. And that was the point I was trying to make with reference to the counterpoint to having ten years before your procurement volumes start to show up. Well, that's a long road to be able to support planning, right? So I would say that if you want that road, you would have some risks in that. I think the most obvious are going to be in terms of securing at what point can you enter the market to start setting hedges to protect you from upside price motion, right?

So that might be some years down the road before you can get to a financial hedge, like an energy a grid sourced energy PPA. It might take you some time, but you could, during that period of time, secure virtual power purchase agreements. Again, that can operate very similarly to a hedge. The challenge with all of these is it's you would be best served if you had some sense of your forward view of the market and really get into a very aggressive risk management program where you are finding various hedging options as soon as they're available and assessing them and then either executing or not executing. We've seen some large industrials that can't get long term electricity contracts that would give them price stability.

We've seen them turn to using synthetic hedges, using natural gas, which has more liquidity going into the future. But that's a very high level of sophistication to start operating in that arena. So I think your first risk is the market could run away from you. And by the time you're able to transact, you're already in that high price environment. That's one risk.

I guess you could argue that prices could go down and you're not going to be hurt. That's a probability assessment you'll have to make. I think there's also some risk in terms of just continuing to work through who are going to be your counterparties. What type of reputational risks or limits are you going to put on your counterparties that minimize the maximal number of counterparties that you could work with? Say you don't like financial hedges, Okay, fine.

You're going to take all the banks off the table. If you don't like anybody who has a power generation fleet of their own, Okay, well, that many fewer bidders that can work with you in the market. So I think that that second risk is something you need to watch out for as well and that it wouldn't be detrimental. I mean, in the end, you're going to get delivery of your electricity through PJM. It's just at what price? Right? You'll be at hourly. Okay. Fine. If you can live with that, then you have no risk.

But I think it's primarily that. It's your price and then what's the pool of parties that you're willing to transact with. I think those are your primary risks of what you'll have to manage over the next ten years.

I think Okay.

Thank you.

Is that good?

Yes. Thanks.

Yeah. Thank you.

So Hey, Lou. This is Nate. I'm still on. I had to step out because of child care.

Okay.

I I had a quick question just to kinda follow-up point on that for Mark. Would if that's okay, Lou.

Yes. Absolutely. Go ahead, please.

Thanks. Mark, would would you since since our hedge in this case is a is a physical asset, and we know that I shouldn't say we know, but the the likelihood of prices increasing in the future, at least in the in the near term, are are gonna go up. Do you see the cost decisions here being being the same? Do we do we run into the same issues, I guess you could say, going to the market as opposed to using IMEA as we are now?

If I understand your question, I would say that having ownership of a physical asset today is a very strong hedge that protects you against upside price movement. However, it has the mirror effect of perhaps landing you at a higher or above market rate, you know, should market prices fall. So, if you were to try to model this out, you would probably run two models, rising market price, or three models, rising market price, flat market price, falling market price. You see how your physical hedge operates in each of those scenarios. And then you would assign a probability to each of the scenarios to come up with a blended risk profile.

And at that point, you would say, Okay, I see my risk in each of these scenarios. What are my additional hedging or countervailing measures that I can take to offload that risk if the rising flat or falling market starts to materialize? I know that sounds like a lot of happy consultant talk, but that's what we do a lot of for large power buyers, right, that are looking ten years down the road is Sure. We're trying to make an educated guess. So I I is that responsive to your question?

Yeah. Yeah. That that makes sense. And, mean, I guess in the case of, like, our our previous contract, for example, I mean, just in in this is an obviously very generalized statement here, but, you know, if if two parties get into a contract together and one gets in too late into a contract late or wants to exit early, there there's typically a fee associated with that contract. Is that would that be a correct statement?

Yeah. I I think it's usually called a break fee or a a a break premium.

Sure. That makes sense. That's all I have, Lou. Thank you.

Thank you, Nate. Any other questions? Okay.

So Mark, we have an existing contract with IMEA. We know exactly what that is. And we have a proposed contract with IMEA. We know exactly what that is. So we kind of know where we are right now, and we know where we would be if we re upped with them.

You laid out all the things that could go wrong if you sign with another provider of electricity too far in the future. What's your assessment of the risk of signing with somebody completely new? I don't think we would do that like next year because it's too far in the future. But even if it's five years from now, sign a contract with somebody that's brand new. We've done all our homework. We've gone out and RFP and all that, and we've settled on some supplier.

Mhmm.

What's the even if we did that five years from now, say it's two thousand and thirty and we put a deal together with somebody to start supplying us in 2035, what do you feel the market volatility will be in 2030, such that when we're doing a deal with somebody like that, there wouldn't be a contract loaded with contingencies even even going out just five years. Because I see a state of chaos in this market right now, this electricity market. It's like the wild wild west out there in my view. There's so much uncertainty. I don't see it going away in five years, you know, these bigger plants you talked about that LS Power just sold, they're supposed to shut down in 2030.

There's just this high degree of complexity and chaos in this electricity market now that if we signed a contract even five years from now for supply five years in the future, how would you compare the risk that Naperville would be taking against that scenario versus the lural contract we have in our hand with IEMEA, should we sign it?

Good question. Good framing. A couple of thoughts come to mind. And this might not be cogent, so reel me back in if I go too far afield. I think what I'd be looking at if I were making that comparison would be two things. One is, okay, look, what's my best guess on a levelized plane of what I think I'm going to get out of either option, right? What's my forward view of the market? We can come up with a cone around prices. And Okay, we can make a good guess. You're right.

It is a very challenging market. So we're going have to put some work in on that. What I would probably encourage a municipality to do is, Okay, get comfortable with those forward views. But then take a look at what type of mitigating options you have in each of those hedging situations, the provider, the alternative provider, or IEMEA. If the alternative provider fails on you in your five years and one day, they just say, I'm out. I can't do what I said I was going to do. That's kind of the failure to launch. That's the maximal level of risk. What are your options then? Well, you could go find a financial hedge, limp through, and try to regroup and re approach the market at a later date.

Okay. How disruptive is that? What does that present you in terms of risk? So that's your that's your mitigation effort. What would your risk be on the IEMEA side? Is, I'm assuming, market prices just tank and and go down, you know, dramatically. And now you're at a cost of production that's above the the market price of power. Okay. What can you do around that in terms of your contract? Right?

Where's the backdoor, I think, is where I'd be looking in that type of analysis. Because if there is no backdoor, then that actually presents a lot of risk. If there's no backdoor, if there's no way to unwind whatever circumstance you find yourself in, that's something you really need to think through. Because it's akin to going down with the ship. You need to understand what is the potential for that risk and what is the extent of the risk.

And then do you have any options to mitigate that risk? Those are some questions I would be asking. And I'm not saying that any of these providers that we spoke to can't perform. They perform very well. But there are no guarantees.

We've had a number of presentations to this board showing us the potential and probability of volatility in the future and prices going up. I didn't see one presentation that showed that prices are going down. And demand is going up. City of Naperville has a data center that would like to come here. And I listened to the city council people.

And well, that's a lot of electricity. I mean, it's like they only have so much electricity and they don't want to lose it. Which makes me think, maybe if a source is not consistent, maybe that's the way we should think. And maybe Naperville should forget about the 88 Corridor because of the fact that we don't have electricity for any of that just to let it go. So probability of volatility and cost is going up, increasing and going up. I don't see any option. You give us some it could go down, but anything could happen. But I don't see that. The probability, if I'm a betting man, it's going up and it's going to be more volatile.

And I would double, yeah, I would agree. However, my job when I represent my clients is to look at all possibilities.

Absolutely. Absolutely. No one's asking that. But we have to make a decision. So when we talk about probability, volatility, and costs, and to keep on hearing, but it could happen. I mean, yes. I mean, that is. But the probability, the term sets for itself, more than likely, things are going up. And it's going to be more volatile. And there's more demand. There are going to be places that are required. If they don't go to Naperville, they're going somewhere else in PJM. And that electricity is going over there and whatever. I'm not arguing for a data center or anything. I'm just saying options for the city, number one.

And I've heard a colleague say they don't want to have they feel they don't like the fact that Naperville uses a percentage of coal or thermal in its mix. And I don't know if Director Groff has this or if you have an idea of this. What is the PJM energy makeup?

I believe you can look. The place to look is called the Environmental Disclosure Form for Commonwealth Edison. It's filed with the Illinois Commerce Commission on a quarterly basis. So you can see it over time. I believe that I'm guessing, so don't wrap my knuckles if I get this wrong. But I think that, oh.

And we could also look at if you're looking at the real time, I got real time up as well.

JOSHUA Sweet. Looks like the generational fuel mix is about just under 50% is gas. Looks like about 12.5% to 15% is coal. Oil is surprisingly a little bit better than a quarter. And then hydro I'm sorry. That's nuclear. I'm sorry. Not oil. Oil is a sliver. That makes more sense, say 1%.

Nuclear is about a third. So I'll run that back. Gas, about 50%. Nuclear, about a third. Coal, about 15%. And then the remainder is wind, storage, solar, other renewables, oil, hydro.

So when you look at the makeup of where anybody's going to get their power at this point during this transition time. There's no idea of who's transitioning that's in the PJM network, so to speak, supplying network. We do know IMEA is transitioning according to the laws of the state of Illinois. So when you come down to transition time and what's less risk because of the volatility in the future, it seems that IMEA really still is the best option for Naperville with the least risk and the best cost. Because your charts that you showed us show that the Commonwealth Edison costs are going up compared to Naperville's IMEA that we saw earlier.

So we'd all like to do something different. We'd all like to have totally clean. But the reality is that we have to have time as a city to transition. And I think that IMEA gives us that time while they also transition and while they give us stability and a mix, almost the same mix, if you want to compare fossil fuel to fossil fuel, as PJM. Isn't it?

I mean, it's pretty close. So it's how good do you want to feel at what expense for the city of Naperville? Say, I don't like having fossil fuel. Except we all it's transitioning, is what you're telling us. We're all transitioning, except we will not transition as fast if we don't go with MIEA.

MIEA. If stick we with them, our costs, extra costs, are going to go to other organizations that we're going to have to partner up with to do the same thing that IEMEA is doing for us right now at a set cost that we know. And the penalty that we're paying is, as you said, not unusual for cities or organizations that come late to the game that everybody else has put into and that has had a cost to. And they're saying, well, if you're going to come in later, you have to kind of catch up with us because we've already put our money in here or investment, which is what that is. So all of that's true,

I guess.

I believe that's correct.

Right. Can I

ask question? Thank you. Go ahead. Yeah.

Brian, I think maybe one of the sticking points that I was thinking about is really the issue of flexibility. At least initially when I was thinking about this, we're looking at these contracts that are super long. And to me, it wasn't as much about the energy mix as it was really about flexibility. Have they provided any options for us to evaluate IMEA where if we were to sign in for five years, ten years, fifteen years, twenty years, what the pricing structure would look like? Or is it only like an all or none twenty year contract?

At this time, it's an all or nothing twenty year contract. And I'll have this a little bit later in the report, but 27 of the 32 have signed that contract.

Can I ask a question?

Is there any chance, I probably know the answer, that we could find a pricing structure that gave more kind of flexibility in terms of the length of a contract? And maybe we pay a premium at a five year commitment versus a twenty year commitment

that has not been discussed at the board level and it has not been discussed with IMEA staff The contract length was twenty years and that coincided with PPAs that they were trying to provide to procure, right? And so that that the real issue that that IMEA has is that without contract extensions, did not ex they did not exist and thus no one wanted to become a counterparty to them if they did not exist and have the revenue to back up any PPAs or any other contracts they might enter into. So the twenty year length was devised to match up with the standard PPA length of twenty years.

So when we talk about, say, be hollow going to a transition period, how long did it take from beginning to end to do Be Hollow?

I believe IMEA, when they were here, talked about a nine year runway for the Be Hollow project from concept to build, which will become live in 2026.

So we saw with some other presentations that that's not unusual and that the time is getting longer from development to end, which is why AMEA came to us because that was part of what they said when they came here, saying it takes that long for us to have a business model to know what we're going to do.

I know that the development life cycles are fairly long. Even for projects within the city of Naperville. For example, the project that they did down at the Springbrook Water Reclamation Project, that was a several year lead time and that was considered behind the meter so that didn't have to go through the PJM project interconnection queue or anything like that and that was still a lengthy process. Know even the city had some issues with you know aggregating all of the parcels of land and things like that and then getting the geotechnical surveys so that basically no one will build a project like that in a floodplain and things like that. So even without PJM interconnection queues, these projects take some time.

And perhaps Mark or Chris, who are more versed in this than I am, would talk a little bit about project queues if you'd like. Sure.

Please. So the question is how long does it take to get a new solar wind farm think

was from concept to completion. I think that was the question, Chairman, was generally what does that look like for behind the meter project which is local in Naperville? And then what does it look like for a grid scale project?

I have a bit more experience with grid scale projects. And we can send you the most recent Lawrence Berkeley Lab study on interconnection activities for the renewable energy or I'm sorry, for all generation to the ISOs, PJM, MISO, etcetera. A few of the findings that come top to mind is that over the past ten years, only 15% of the capacity proposed for interconnection actually gets built in PJM. And that the time from first engagement with PJM for a study, so not taking into account the pre development. I think that they only look at development time from the first point of contact with PJM to deployment.

I think that's gone from four years. I think it's now seven, maybe seven and a half years. So fewer are getting through and the time to get to that decision is getting longer. And the dynamic here from a developer standpoint is that the longer it takes to develop, higher the costs are for a project that's not generating revenue. So it's more likely the longer the interconnection period that more of those projects get dropped.

So it's a there's a related function in there. With behind the meter, I think it's far more variable. Depends mostly on the interconnection capability of the local utility and what type of interconnection standards are maintained. So I've seen projects in ComEd and Ameren operate and get up and operational in a year. I've also seen them take four.

And I think that's a fair assumption or a fair and accurate assessment based on what we saw with the IMEA project. A lot of those timelines were on the city, right? And I think in that instance where we built the project within the city and the gentleman to my right here had a lot to do with that project. We had the land, right? And that's one of my concerns in doing this is land acquisition, right? That project was about seven or eight acres. And so land acquisition was not a part of those couple of years of development.

So it comes down to we'd all like to be at carbon free or wherever. However, the reality is that we all need trans and Naperville needs transition time. And the most economical transition time. And IMEA is transitioning. And if we leave IMEA, our resources, after five years or ten years, will be for probably total power acquiring because of all the things we're going to have to we're going to have to pay someone for that job.

It may not be IMEA, but it'll be someone. And there's going to be a cost. And then there's going to be other risks. And we're not going to have our own source like we do right now to keep the volatility and consistency. And the fact that we still have thermal for another ten years helps us in that transition. Because it's going down like everybody else. And again, we just heard PJM has a pretty close percentage of fossil fuel in it. So again, I'm thinking we just have to look at the reality. It's great to what you want to do. But I think what's within our parameters, I think, is definitely it. Are there any other questions?

Yeah. This is probably a question that Brian can answer better. But I think there's been hinting at this meeting or prior utility board meetings that IMEA might cut Naperville a special deal that we're not happy with the one that we have or that's proposed right now that they'll amend that projects or that that proposal somehow to satisfy Naperville. I think when Troy Fodor was here their general counsel I think he told us that this contract that's out there is the same contract being offered to everybody right

That's correct. The same contract that 27 members have signed.

Yeah. So 27 people have accepted the contract proposal as is. I know you can't speak for IMEA, but you're on the IMEA board, so you're the best person here. What would be the probability of IMEA cutting Naperville a special deal to satisfy some provision that we might find acceptable enough to go forward with them?

I don't think there's a high probability in that happening.

Okay.

Any other questions?

Just really quick. I think you touched on this very briefly last time, but have you seen Muni or any other organization sign a contract ten years in advance of the start date with the twenty year or plus or minus?

I have not.

So this situation that we're in is kind of unprecedented. It's unique. It's usually closer instead of a ten year out window. What is it typically closer to?

Right. I would say that if you were to determine I want to enter into a contract with a wind farm, I would probably give myself a good seven, maybe more years for that to be developed and deployed. I think that when you're dealing with the physical assets, it's just that's what you're stuck with is that timeline.

So I guess my question then is that, well, at this point, we made a recommendation at our last meeting. We've gotten, I guess, the next thing would be a motion to accept the presentation. Mean, guess what's next? Because we've kind of made our recommendation to city council. So I guess what happens next? I know we're kind of discussing and still

I don't understand what you mean, accept the recommendation, vote to accept the recommendation.

We did that at our last meeting.

Yes, we But