May 19, 2025 Public Utilities Board on 2025-05-19 9:00 AM

Good morning. I'd like to welcome you and call to order the Public Utility Board meeting for the City of Denton of Monday, May 19th, 2025. Are there any presentation for members of the public? There does not appear to be any. We'll move straight on to the consent agenda. Would any member like to pull one of these items? I have a quick question on item A. Okay, let's pull item A, please. Any others? No. Then we'll entertain a motion for items B and C of the consent agenda. So moved. We have a motion. Second. We have a second. All those in favor, please say aye. Aye. Any opposed, sign the same. All right, it passes unanimously. Item A. What is your question, Mr. Taylor? So notice the majority of this contract is for that initial study, and then it has a small amount kind of for maintenance on the study. Does that mean that it'll provide annual cost of service updates for the five-year period? That's correct. The additional amount is for maintaining the model. So the upfront cost is to develop the model, and then the ongoing contract is for the maintenance. Okay. So then basically every year we'll have a new cost of service. Okay. Thank you. The update refreshed. Yeah. Move approval on item A. We have a motion to approve item A. Do we have a second? Second. Second. We got a second. All those in favor, please say aye. Aye. Any opposed, sign the same. It passes unanimously. Moving on to items for individual consideration. Consider approval of the minutes of April 28th. So moved. Move approval. Second. Second. All those in favor, please say aye. Aye. Passes unanimously. Item B. Consider approval of the May 5th minutes. So moved. We got a motion. Mr. Rainer, we got a second. Yes. Mr. Vermeer and over here, Newquist. All those in favor, please say aye. Aye. Any opposed, sign the same. Passes unanimously. Item C. Consider recommending adoption of an ordinance directing the publication of notice of intention to issue $46,535,000 in principal amounts of COs for the City of Denton. Good morning. I also need the next item called. I have one presentation. Oh, these two go together. It says that here. I'm sorry. No problem. This is items C and D also. So the items are PUB 25-039 and PUB 25-040. Good morning, Randy Klingle, Treasury Manager. I'm here for the Notice of Intent for this year's Certificates of Obligation, which as mentioned are both items for one presentation, but will be voted on separately, please. The Notice of Intent is required by state law for Certificates of Obligation only, and we will post the notices in the Denton Record Chronicle, which is required to be in a printed paper of local variety in your municipal government. I will also post it on the city's website for the length of the duration until the bond sale actually happens in the late summer. And then the bond ordinance cannot come to you or to the council until 46 days after that first posting in the local paper. So the majority of the information I have is also in your backup. It's in your AIS. It's a list of the projects, and I will not be going over the list of those projects, but if you have any questions, we probably have some friends here in the audience that will help us out on those details. But I will just go through the funds themselves and show you the totals that will be on the Notice of Intent. So the first fund is the Solid Waste Fund, which the Notice of Intent is at their reimbursement status, the same, nothing has changed, with $11.1 million. The water utility has a long list of projects, very detailed, as is normal for the utilities. And again, like I said, it's in the backup, and I won't go through all of these, but you will see the changes from the reimbursement ordinance that was in October. So for your water fund, we have $80,614,615. $80,614,615, I think I said that right. Wastewater, we also have two slides for this fund. The $77.1 million for the wastewater fund. And last, we have electric utility, $47,900,000 for the utility. For the solid waste, you have $11.1, you have the total utility system there at the $207,515, and some of those totals include the issuing cost and some price flexibility once we get to the bond sale in July. Our next steps is we'll go to council tomorrow for them to review this Notice of Intent after your recommendation today, and then we'll come back to PUB on June 23rd for the full bond ordinance. And July 15th, council members will review that as well. And then July 23rd, we'll have the bond sale and we should expect the funds in late August. Any questions? It doesn't appear to be any. Okay. Fantastic. I guess that's it. Go ahead. This is a substantial amount of debt, $250 million approximately. And of course, it represents a lot of necessary growth, you know, or necessary infrastructure to support the growth that is occurring in Denton. I have the Ray Roberts Water Treatment Plant expansion, up rate. That's I think if you total all of those $30 or $40 million total, the Milam Creek Wastewater Lift Station, you know, lots of expansion of landfill cells, you know, so these are all, a lot of this is related to the continued growth that we're experiencing as a city. And then there's also kind of mixed in just the maintenance, the replacing water lines that are 30 or 40 years old, replacing wastewater lines, you know, so it is a significant list of projects here, but, you know, I think we all know that they're all necessary. So with that, I will, do we need to call them? Do we need a motion yet for the note to publish the notice of intent? Each one. Yes. Yes. I guess I'll wait to see if there's any further discussion. Okay. I'll call it. Anybody? Doesn't appear to be any others, any other discussion. So we'll entertain a motion for item C for the notice of intent for $46,535,000 and COs. I move we recommend adoption of the ordinance for the COs. We have a motion for item C. Second. We have a second. All those in favor, please say aye. Aye. Any opposed, sign the same. Passes unanimously. Now entertain a motion for item D. I move. I have a motion. Second. We have a second. All those in favor, please say aye. Aye. Any opposed, sign the same. They both pass unanimously. Moving on to management reports. Good morning. Members of PEB, Stephen Gay, General Manager, Water Utilities and Street Operations. You have been provided in your packets the three memos. We have staff here if you have any questions. And then beyond that, I don't believe there's any future items and/or any new business. I think those were Lee questions. Yeah. But thank you for the memos. Thank you for the research. You're welcome. Anything else you got there? Future agenda items? No, sir. No. Anybody else got any future agenda items? Doesn't appear to be. New business action items? I guess you're passing on that, too. Yes, sir. We will move on to the work session. Item A. Receive a report, hold a discussion, give staff direction regarding updates to the Denton Renewable Resource Plan. Would you please ask someone who knows something to get up there and make the presentation, please? I'll try to find you someone. We've been knocking him down all morning. We should continue, I think. We'll let everybody clear out. So Mr. Chair, members of the PEB, Tony Puente, the DME General Manager. Appreciate your time this morning. I'm going to try to run through this presentation as efficiently as I can. I do want to kind of open up with a couple of things real quick for you. First of all, legislative session is still in the session. They still got about two more weeks. There are a number of bills that are under consideration that we're tracking. Certainly I referenced some of those within the confines of this presentation. Know that some of the requirements that may be coming down the pike may dictate for our community, for our utility, what must be done. So we certainly try to put this together within the context of what's happening at the state level, but also at the federal level as well. So we'll talk a little bit about that and about the availability of new renewable resources going forward in the state of Texas and frankly probably across the country. And then finally, locally, we continue to have some challenges that are related to our purchase power agreements, delivery of projects, uncertainty that's there as well. So we'll talk about that. The presentation overall recommends preservation of the 100 percent renewable goal that has been our mandate for a number of years now. We just try to define that, which based on an internal audit that was done, we found that there was not a very good definition of what that 100 percent renewable goal was. And so we try to define that here. I think going forward, it would be the definition that we certainly would recommend for our community going forward. So with that, this is a two-part presentation. The first part will be really an update to the renewable resource plan. I've outlined out here for you the objectives. We'll provide a staff recommendation in part one. Part two is related to what's called an integrated resource plan that is part of our recommendation. We'll cover regulatory market, some of our load forecasts, also provide recommendations. And then I'll wrap that up with a recap of the two recommendations that we're making today and would appreciate your direction. We do plan to present this to the Council on June 3rd. And so certainly, we want to be able to have enough time to provide them your feedback on these recommendations. So with that, the renewable resource plan, the current plan was adopted back in 2018. That goal was done through a study. And so some of the things that I'll kind of touch on here is that obtaining the goal really depended on how we accounted for certain resources that would have reached that goal by 2020 or 2024. The acquisition of diversified set of power purchase agreements, that was really the goal, right, is to not necessarily build our own renewable energy plant, but to acquire those two power purchase agreements. It did list out a number of objectives, one of those being the fact that always cognizant of the least cost supplies, right? And so certainly always be cognizant of what the ultimate impact is to rate payers. It did recognize that the debt and energy center was a cost hedge. And I think that is consistent with what we've communicated, certainly since I've been the general manager, but even before that time, of what the debt was intended to do. And we certainly believe that it's been successful in that. And acknowledge that the greatest challenge is balancing the supply portfolio around intermittent resources. And that's something that continues to be seen across the states, certainly in California. The infamous duck curve, if you're familiar with that, in that in the evening hours, between the hours of 6 and 10 during the summers, when you tend to see scarcity, right, when the wind doesn't show up and the sun is gone, that tends to be those hours of uncertainty or scarcity. In a winter, it's actually a double situation, because you also have the morning hours, around 8 o'clock to about 10 o'clock as well. And then finally, and we have implemented some hedge plan and strategies that have gone into trying to manage this portfolio. Do share with you here the current resources that we have. So we do have one resource at 150 megawatts, and then the remaining resources that we have under contract currently are solar. We have a total of 455 megawatts of capacity. I will just mention that the Yellow Viking, that is still not online. And we continue to work with them on that particular contract. And it just goes to some of the PPA challenges that we're seeing. In addition to that, we also have issued an RFP that we're currently evaluating for up to 300 megawatts of solar, wind, and battery. We are working through those proposals now and do plan to be in front of you in the coming weeks with some recommendations regarding some additional resources for your consideration. So this provides you just a timeline and some history of the evolution of this goal. I went back to 2009. 2009, the goal was 40 percent. And you can see here that in 2021, we achieved that goal. I do have an asterisk here for you because I do want to make sure that you understand how we've attained that. So back in 2021, we served a little bit over 1.5 million megawatt hours to our customers. The contracts that we had in place at the time actually generated 1.3 million megawatt hours of power. And then we were able to utilize 262,000 megawatt hours. So it's equivalent of 30 megawatts that was tied to one contract called the Whitetail contract. We did go to the Council at the time, also the PUB, and recommended that while the dead renewable resource plan and discussions at the time was that we were not to count recs towards this goal, we certainly believe that there was a misunderstanding of what a rec is. And certainly, I'll try to touch base a little bit today on what that is. So the Council did give us direction in 2020 to begin counting those 30 megawatts of recs towards our goal. And so in 2021, we actually were able to achieve that goal, actually exceeded it a little bit by 1 percent, 101 percent. And I've given you here, kind of since that time, what we've done. Certainly, in '22 and '23, we counted the 30 megawatts of renewable -- or recs from the Whitetail contract, but we actually had to buy additional recs out in the open market to attain that goal. And in 2024, the Whitetail contract did expire December 31st of 2023. And so in 2024, we bought 400 -- a little bit over 400,000 megawatt hours of recs in the open market to round out our goal of 100 percent. Just to rehash a little bit of what we communicated to the PV and the Council at the time was not counting the Whitetail recs would have cost the city an additional, you know, $5 million -- $5.1 million to go out there and acquire that renewable energy out in the open market with short-term contracts, along with recs, right? And so the Council decided, since we had already used -- had already paid for the 30 megawatts within the PPA contract that we had, to not spend that money, instead go ahead and utilize those recs. In 2024, again, you know, we anticipate that that energy that would have been equivalent to the 400,000 megawatts would have cost us about $2 million, right? Instead, we bought 400,000 megawatt hours of recs at about $1.50 a megawatt hour. So we spent about $600,000, right? So $600,000 versus $2.5 million is really a differential, right? And ultimately, what we did not spend on behalf of our ratepayers. Some of the challenges associated with the current plan, and certainly some of the findings that I'll cover from an internal audit that was done. We worked very closely with the city's internal auditor on this. But some of the challenges, right, is, you know, associated with counting a rec, right? So let me talk to you just a little bit about what's called the Texas Renewable Portfolio Standard. So that standard, RPS -- understand that RPSs exist throughout various states across the country, so this isn't anything that's new to just the state of Texas or DME. But that RPS program was established back in 1999, after deregulation, you know, the infamous SB7 that you may be familiar with. And it created this renewable energy credit program. The intent was to identify resources. So the plan identified a specific number of resources -- solar, wind, geothermal, hydroelectric, wind, tidal, and biomass -- as the types of facilities that would be counted as renewable in the state, and that would be awarded recs, right? And so the rec became kind of the supporting evidence or the evidentiary document that a megawatt hour of renewable energy from these resources was actually produced and generated. And the goals was to incentivize renewables in the state of Texas, and the goals were, at the time, you know, very high, lofty goals, right? 5,000 megawatts by 2015, 10,000 by 2025. And I'll tell you, the state has certainly built far more, right? So today -- and this is a little bit dated because I put this presentation in a couple months ago -- but at the time, wind -- there was over 39,000 megawatt hours of installed capacity, making Texas the leader in the nation for wind resources. Solar was at over 25,000 megawatts of installed capacity. And while Texas was slightly behind California from installed capacity, actually, instead of Texas, those resources actually generated more power than in California. And so certainly, Texas became a leader. For retail electric providers -- and understand that there's retail electric providers in the -- and the investor-owned and so the private -- the private utilities, DME, and all MOUs are also REPs, and then you have your cooperatives that are also REPs. But this particular standard and the requirements spelled out in the standard that mandated, right, that REPs, right, buy a certain amount of renewable energy credits, right? The state would tell them and allocate to them, this is the number that you have to go out there and buy to continue to incentivize renewable energy in the state. Again, DME was exempt from those requirements, along with all other MOUs that have not opted in, right? There's a fancy acronym called a NOE, right? It's a non-opt-in entity, right, and that describes DME and a lot of other 72 counterparts that we have across the state. And then, again, whether or not we count RECs towards our goal is certainly a local decision, but the RPS certainly provides some guidance as to how RECs are viewed, not just in the state of Texas, but really across the country. So what is a REC? So a REC is simply a title document, right, if you think about it like that. It's a property rights document that gives the owner of that document, whether or not you own the energy, the right to claim that you are renewable by that evidence, right? And so one REC is awarded for every one megawatt hour of energy that's actually generated from just those resources that I outlined for you in the RPS. And so, for example, rooftop solar locally does not get RECs, right, primarily because those tend to be behind the meter, right? So they're tied into our distribution system. There is no way for ARCOT to track that. Same thing with, to a large extent, from community solar. So if there was a community solar one megawatt installation, generally we would be looking at tying that into our distribution system, not into transmission. So it wouldn't necessarily be seen as a statewide resource. And so that would not also be, would not be eligible and receive a REC. RECs do have a three-year life. So whether they're produced on January 1st or December 31st, that's considered year one, and then it has two more years, right? And so RECs will either be retired, which is something that DME has not done, and it'll be part of our recommendations here today, or they just simply mature out, right? And so, but they do have a three-year life and there is a market in the wholesale market for those, something that we've tried to do. And it was part of the internal audit discussion was that when we buy RECs, we only buy RECs in the year, that are produced in the year in which we're going to count them, and so if we're 2024, we only bought RECs that were generated in 2024. We didn't buy RECs that were produced in 2022 or 2023, right? And I think that's just part of, part of my training, right? If you're familiar on the treasury side, there's, you know, new treasury issues, right, that are, that you don't have to go out and buy from broker. You can go to the treasury window, or you used to. I don't know if that's still even around, but that's what we kind of equated this to, right? And, and I think, I think it just holds more true to, I think what ultimately the community's goal has been. And then finally, I will also mention that certain solar resources actually also receive what's called compliance premiums, right? And that's just, that's just another document, another instrument that, that, that, that shows that that particular resource met certain requirements. In our view, for renewable resource that we have, if we get RECs and CP, while there is a CP market as well, we won't uncouple those, right? That's part of our recommendation that if, if we're going to retire the REC and we have a CP, a corresponding CP, we will retire that as well, right? And, and then finally, there is a guiding document that I provided to you in your backup that was produced by the, by the EPA and the Green Power Partnership that also explains what a REC is, right? And so much of the information that I'm providing to you, Dan, and I know I'm summarizing quite a bit, but you do, you did receive this particular document. I will mention to you that in this document, it does recognize that the RECs are legal property rights to the renewableness of a resource. It also verifies, I think, what the RPS said in that one REC equals one megawatt hour of renewable energy. And then electricity cannot be considered renewable without a REC to substantiate the renewableness of that, of that energy. Yes, sir. I'm curious with all of the discussions and votes and changes in Washington on the Green Power and such, is the EPA Green Power Partnership, is it affected by the ways and, and views and voting of Congress in Washington or is this, I'm just curious, is our guidelines stable all the way through regardless of what, who's in the offices? Yeah, I think, I think the way, what I would catch that with is it's, it's uncertain, you know, and so, yeah, and I mean, everything from, you know, 3000 percent tariffs on certain solar panels that are coming from, from Asia are certainly, and that goes to, to what's happening at the federal level that's, that's trickling down and, and frankly, already straining a supply chain that's, that's already, you know, several years behind in providing, you know, everything from, from raw materials to engines, right, that, that is also impacting development of new renewable resources across the country. So some of the other, you know, challenges, as I mentioned back in 2021, the internal auditor came in and some of the recommendations she made, some findings she had was one that the goal, the goal calculation was not defined within that 2018 study. We did work with her, and so how we count, how we account for that goal at the end of the year is something that was done in concert with the internal auditor. We provide annually an ISR, I think, I think we already provided, we're getting ready to send out the one for 2024 that spells out exactly how we do that. Basically it's an end of year calculation, right, what was our total load that was served, what was the total number of RECs that we had in our REC account at ERCOT, and then if we are, if we are short, then we try to then, then we go out in the open market and we acquire the differential and RECs to meet that gap. And that's basically the, the accounting. We certainly believe that that needs to be memorialized. And then no formal reporting of that goal, and so, so immediately after 2021 and 2022, we began to send out that ISR and we plan to continue to do that annual reporting back to the Council and the community of where we are with that goal. Certainly the need to update load increases and regulatory changes, we'll go through that and evaluate the cost benefits of RECs and CP retirements. And that there is a market for these RECs and these CPs. And so while we could monetize every single REC that we had, after we've counted it, we don't think that that certainly meets the spirit of what the community would want. And so part of our recommendation will be that once we count a REC towards that hundred percent renewable goal, that we retire it. Now if there are excess RECs, again, there is a market. And so if there is a situation where we have more, more RECs than we needed, then our recommendation would be to go out and monetize those on behalf of our ratepayers. And then finally, the large load issue, SB6 is currently at the legislature that will try to address a lot of issues regarding large loads. We're certainly working on some strategies and once SB6 is determined, whether it passes or not, then we're going to be brushing up some of the requirements and strategies for large loads. Currently we've targeted 5 megawatts as a large load. SB6, I think, has it a little bit higher, right? So we certainly want to make sure that we're in concert with SB6. But large loads do pose a risk to our ratepayers when it comes to not just potential bankruptcy and failures, but certainly when you've entered into a long-term contract, like a winter solar contract for 15 or 20 years, it does expose you to additional challenges, right, and that you may end up with very long position, more than you need. And so you're familiar with the City of Georgetown, that's part of the challenges that they had. They went out and procured over 200% more in renewable energy than they needed. Their forecast did not come in, so they were very long energy, and they're still trying to uncouple many of those contracts. And certainly we'd like to avoid that. And so taking a reasonable and prudent strategy when it comes to large loads is also part of the recommendation that we're going to make today. And so again, to kind of staff recommendations for part one, and then I'll certainly stop after that, see if you have any questions, we certainly believe that having a city policy that we'd like to call the renewable energy policy, that really outlines what the purpose is here. One that this is really an offset goal, right? Again, those resources, whether it's a winter solar resource or it's a thermal resource or whatever, all of those are interconnected into the ERCA grid. And so that power doesn't necessarily flow directly into our homes here in Denton, right? We're all part of one large pool. And so now if we have a local resource, community solar project, I think we can certainly make that argument that those just physically, right, that that energy flows to our homes just like rooftop solar on a business or a residence. And then we would also recommend that we tie the allowable resources that can be recognized within the city policy to those that are outlined within the RPS. And then we would like to also then outline the treatment of renewable energy credits, one that we will retire them, right? We're not going to be holding those to maturity. We'll not be monetizing those up to our 100% goal. Now, I understand that the possibility of that happening where we end up with excess recs from our PPAs and renewable resources is very unlikely unless we adopt a strategy like Georgetown where we're now going to have more than 100% or 200% more renewable energy than what we actually anticipate that we would need. But that if we are in a situation where we do have excess recs, that we'd be allowed to sell those on the open market and not to necessarily let those roll over, right? Again, our recommendation here is that we count recs that are generated in the same year in which we're counting it towards our goal. So now if I have a rollover rec from 2024 to 2025, now I've kind of violated that particular principle. But certainly, again, that is our recommendation. And then when needed to meet the 100% renewable goal that we go out there and we purchase recs with CP, depending on the resource, and only those that are generated in the same year that were counted. And then for large loads, our recommendation is that we take a reasonable, prudent approach, right? Not all these resources or these loads, certainly those that we're seeing and we continue to see interest in large loads wanting to come into the city. Some may be real, some may not be real. Some may be legitimate and backed by very large corporations, whether they be financial or business entities, they have very high ratings, or they may be very speculative, right? Let me kind of equate them to the wildcatters, if you're familiar with the oil and gas industry. There's a number of speculators that go out there and enter into contracts for mineral rights with the hope that they're going to hit something, right? And so the same thing here, we're seeing data centers that want to come to Denton, want to build 100 megawatts, 300 megawatts, get me energized, and then I'll market it to people that may be interested. Those are very speculative. For us to go out there and enter into a 15-, 20-year contract on a speculative type of data center really poses a very big risk to the utility and to our ratepayers. And so our recommendation is to kind of take a prudent approach, let us evaluate each resource, and even if they're legitimate, maybe we don't do a long-term 15-, 20-year PPA. Maybe we do a short-term two- or three-year deal out in the open market that's also tied with renewable energy credits. And then within this policy, we would anticipate that we would spell out how that goal is supposed to be calculated, that there would be an annual reporting requirement back to the PAB and the council, and of course, a glossary of all the wonderful acronyms that we use in the industry. So I'm going to stop here and see if you have any questions on part one. So just want to review, could we go back to the slide that showed the 2021 to 2024? So we had 262,800 RECs coming from the Whitetail Wind Project, which we were buying physical power from, and then we were also buying RECs, additional RECs, tied to that physical facility. When did we buy the additional RECs in '22, '23, '24? We bought them in that particular year. Actually, we tend to buy them after the calendar year once we've reconciled, and if we're short, we go out in the open market and we buy those RECs, but we're making sure that they're RECs that were generated in that same year. So kind of like spring 2023, we would have bought the RECs in '24, '23? That's correct. That's correct. Okay. So in 2016, we had this 70% goal, and there was public outcry that it was a 70% goal and not 100% goal, and so in two years, less than two years, there was enough political will to change to 100% goal. And at the time, there were lots of concerns because solar was basically non-existent. We were looking at wind farms, and the discussion then was of buying RECs, and Denton actually had the Green Sense energy program where you could pay an extra 0.3 cents per kilowatt hour, and DME would green up that energy just like Green Mountain did or some of those other providers by purchasing RECs. And at the 100% goal discussions, the concept of just buying RECs was offered, and the alternative was that DME was going to have to generate 120% or 130% of the power needed for the city and then still run the deck or purchase from real-time market another 10% or 15%. And it was going to cost about one cent per kilowatt hour, that was 2018 discussions. And the city approved it, the voters elected council members who supported it and councils targeted that goal. When we get to 2021, 2020, the whitetail wind resources was just seen as like, oh, they've offered this opportunity to buy these RECs at a pretty low cost. And it was maybe the camel's nose in the tent on using RECs because up until that point, none of that 100% goal was REC-based. It was, we're going to overbuy power and we're going to have to sell some of that power back onto the system, and we're still going to have to have fossil fuels support us because there isn't yet long-term storage in our cot, but the city was committed to it. And then we started with, well, we have physical RECs tied to a physical generator that we're already buying power from, so we're still supporting this wind farm that we're also buying power from, and that was the camel's nose. And then it's like, oh, well, we need another 70,000 megawatts of RECs. We can buy them for a buck 50 on the market, and so we'll do that. And I feel like now we're, this document seems to be veering more and more toward, well, we can just spend a buck 50 a megawatt and buy RECs for everything, and large loads do present a risk. If we have a 300 megawatt load and that company closes up shop for any reason, moves down the road, ceases to exist, changes their technology and doesn't need the power, if we've bought 20 years of power for them, then we have to sell that power on the market and hope that prices stay at the level we purchased that power from. But what we found with our renewables is our renewables are cheaper than market prices. And I don't know if that's true this year, but I know last year y'all presented that our wind farm, our PPA, our solar PPAs were so-called in the money. They were cheaper than, on an annual basis, than buying real-time or long-term power. So I feel the same pessimism that was brought up in 2018 about how we're going to overbuy and we're going to be selling at a loss, and so it would be simpler if we just buy RECs. But that isn't what we've experienced. Now I know it's a lot harder to plan. It's much more complicated because you have to predict, and wind and solar, wind especially is not accurate until you're maybe 72 to 48 hours ahead, so you have to either purchase way too much energy and try and sell back the excess, or you have to be very responsive in your planning. And I would gladly support expanding an energy office to do that work, do that hard work above just buying RECs, because RECs are, every solar and wind project and hydro project in Texas just kind of dumps their excess RECs from last year. And they're $1.50 a megawatt, which is a tiny, tiny fraction of the value of the energy. You mentioned buying, if we hadn't bought $600,000 in RECs, we would have had to buy $5 million in energy. $2 million. Or $2 million, I'm sorry. But then we would have had $2 million in energy that we may not have needed to consume, but we then could have also, it would have had a value because it would have been sold. So maybe it wouldn't have netted out a profit, but it might have broken even. And so we could have been supporting, I think sticking with the citizen goal of supporting renewable energy in Texas by directly supporting a solar farm, a wind farm, a battery or hybrid or hydro installation. Yeah, so certainly a lot there, board member. We acknowledge that since 2018, a lot of things have evolved, right? And so while yes, you're right in that our current PPAs may very well be in the money. The reality is that when we're looking to serve our load and we're looking and planning for when do we need to mitigate the most risk to our repairs, the renewables just aren't sufficient and that's why they're considered intermittent resources. You don't control them. You don't push a button. You don't turn on an engine when you need it. It produces when it produces and you get what you get. The other thing, too, that I will tell you is that while those resources that we executed 10 years ago may be in the money, where we're seeing them today, where they're being priced, they're out of the money, right? And so to enter into a 15, 20 year wind and solar contract today means you're going to pay more, right? And again, I can't go into the proposals that we're seeing, but I can tell you that's what you're going to see, right? And so what the council, what the POB is going to have to decide is are we willing to pay more for those resources that may be in the money 10 years from today, but today we're paying more, right? In light of the fact that we've already raised rates for our customers, right, 25%, right, for the energy. So now you're going to be adding additional cost to our repairs. So the other thing, too, that I'll mention to you is that while we certainly understand and we've certainly been supportive of this renewable, 100% renewable goal, if the resources aren't there to contract with them, then the goal isn't, I mean, it's just a goal on paper, right? And we'll continue to not meet that goal. And that's what we're seeing today, both with PPAs that we already had in place that have been subjected to things like force majeure because they can't get panels or they can't get engines, right? So we're having to work with those resources, and in many cases they're looking to pass on additional costs back to us that then makes that PPA out of the money as well, right? And then the other thing that I'll mention to you is that, and I'll talk a little bit about it in a little bit when it comes to things like firming requirements, right? And so if these renewable resources are required to firm their energy, that additional cost will come back to us in a PPA. I mean, we're looking at a PPA today that's already telling us that we're going to be looking at probably an additional seven cents on top of the PPA contract that we had, right? That seven cents potentially makes that resource, takes that resource out of the money, right? And so that's also the reality, right, of what we're seeing. And we certainly understand kind of your position and what others are saying in the community, but if I can't go get those resources, then I'm never going to be at 100% renewable. Even if I tried to go out there and contract for 200% more, which I'll just be honest with you, that's not something that myself and my staff will be recommending to you. So we would have to get that direction from you and the council to go out there and contract for more than 200% because that is going to be additional price risk, right, on our countries. Are you done? No, when you're done. So a question, as you talked about the renewable versus the rec, and we're buying these recs, and there's a concern you have on some of these renewables are lagging, whatever the reason is, is there a percentage that's in your head or on paper that if the renewables go to a certain level, then we're going to be buying these recs regardless? Because if we've made a commitment to the citizens, we need to, I think I need a little bit more verbiage to defend the recs versus the amount of recs that we're going to be buying, realizing there's just so much that you can pull on the renewables. But are the renewables in a situation that gives you grave concern that we need to be looking at additional recs than what we've been doing? Yeah, absolutely. I think across the state, the issue of reliability is a real issue, right? And so the ERCOT grid has to maintain a certain level of energy, right, 60 hertz, right? And so for you to be able to maintain that, you have to have resources that are not necessarily intermittent, but that you know you're going to be able to count on, right? And so as more and more of these resources have come into the market, that then has posed just physical, right? But I've got two engineers that are sitting right there that can come explain to you better than I can, right? But being able to maintain those 60 hertz and be able to keep the power on for all the state of Texas, right, is something that is very, very critical, right, and why the state is actually looking, right, one of the bills that they're looking at, as capping the amount of new generation going forward, right, that they would cap renewable resources to more than 50 percent of the total resources that come into, that are allowed to come into the market going forward, right? So there is a natural cap, because again, what the state is looking at and seeing is that these resources are, from a reliability standpoint, are making it difficult to continue to manage and maintain that grid at the 60 hertz, right? And so the other thing, too, is that as these resources continue to come into play -- and, Mr. Taylor, I -- you know, listen, we think storage is important, and we think there's a place for storage, and I think storage can certainly provide some of that reliability, some of that stability. But what's in the market today, really, and what's economical, is two-hour batteries. There are some four hours and there's some six hours, but, you know, the economics on those are just not there quite yet, right? And so two-hour battery, you know, for summer of '23, when we saw price spikes that lasted for four hours and we incurred, you know, $31 million, right, a two-hour battery would have cut that in half, right? And it's something that we're looking at, right, but again, those resources are just not fully developed and they continue to pose challenges. What I would tell you is that, you know, our recommendation is to really separate these goals out, right? So you have the 100 percent renewable goal that is predicated on renewable energy if it's available, if it's there, right, and then you meet the gap with RECs, but then there's this other conversation of, right, what is the right generation mix for our utility, right? And what I would tell you is I equate it to taking your entire life savings and putting it all in Coca-Cola stock, right? It poses a huge risk, right, to your future well-being, right? And what we've done here, right, what we tried to do here is to place our entire generation in one type, and that's all intermittent, it's all renewable, right? And so, yes, we have a power plant, 225 megawatts, that is woefully insufficient. And so looking at, you know, what is the right mix, right, to your point, you know, what is the right mix of renewable energy within our total portfolio, you know? I would tell you today, I don't believe it's 100 percent. You know, I also don't believe it's zero, right? And so part of the recommendation will be to go out there and do an integrated resource plan that will do that, will tell us what should that percentage be and what other resources should you have, right? And within those additional resources, there's an abundant number of resources, right? There's geothermal, you know, there's small modular reactors that are currently being prototyped, you know, there's nuclear as well, you know? And so there's a number of other resources out there that we really should be looking at and looking at how do we manage the generation needs, right, for this utility, not for the next five years, but for the next 20 or 30 years, right? A nuclear facility today, whether it's an – whether it's an SMR or it's a traditional nuke, right, a 10-year permitting process, right, just to get it permitted, and then you're looking at another 10 years to develop that, right? And let me tell you, nobody builds a traditional nuke by themselves, right? And so you generally have to be party with other people on a project like that, on top of the fact that today we don't have, even with our projected load, we don't have the load to substantiate a nuclear facility by ourselves, right? So it would – it would require us to partner with someone to do that. And let me tell you, today, while there's growing interest in nuclear in the state, there's nobody out there that said, "Yeah, we want to be the first ones out the gate," right? But looking for those opportunities is certainly something that we think we'll continue to need. And the other thing that I'll mention to you is that, you know, while we have a quickstart generation facility, and we think that that facility has been great for backing up when the wind doesn't – you know, blowing, the sun doesn't shine – I said I would never say that, but I just did – you know, the reality is that as our load continues to grow, even a quickstart generation facility will not be sufficient. We will be looking at and needing a base load unit, right, something that is on all the time, so. I don't know the rules. Sounds interesting. So does that fall in line with what you had mentioned earlier about having an electric oversee type office or administrators? It sounds like that that would create that type of need, or am I – have I missed that? Yeah. So we currently, I believe, have a – I don't know the exact name – Energy Trade – Energy Management Organization. Energy Management Organization, which has a group of folks that are – they're balancing the next three years and the next three months and the next, you know, week. And so, you know, and then three-year planning, one-year planning, you know, they're using different tools at all those depths, you know, and I think – and I don't know if they schedule the deck or if the deck is strictly ERCOT scheduled. No, the deck is scheduled by us, based on market signals. Yeah, so then – so they do everything from forecasting, you know, what all the intermittents are going to do to buying short and medium term, you know, in between and then turning on the power plant. You know, I think there's – there were a lot of ifs in what you brought up. If the legislature passes a bill, you know, and honestly, if the legislature passes a bill that makes it harder to build renewable, it'll – you know, a recent study came out of UT that said it's going to increase power costs by 50% to 70% in Texas, and anybody that owns a long-term PPA with renewables is going to be printing money, because they bought it at 30% and they're going to sell it at 50% to 70% higher than it is now. So until that law passes, you know, we won't know the impacts, but it won't actually – it wouldn't be a negative for owning renewable, it would be a negative for building future renewable. Well, I would just say it could be a negative, Mr. Taylor, in that, you know, the current iteration of that particular bill doesn't grandfather existing resources, and so even existing resources would have to firm up, right, and if they have to firm up, they will not be in the money any longer. Yeah, and I think there are, you know, a lot of other ifs about, like, if renewables are available. Well, there are 40,000 megawatts of wind and there's 25,000 megawatts of solar and there's 10,000 megawatts of battery. And you know, we're – well, we've got, like, 500 or something, 500 megawatts. And so now I think it's if they're available at a price we're willing to pay, you know, or if we think that's a competitive rate, you know, more than – like, I completely agree with we set a goal and then we try and execute the goal and we adjust as that goal goes forward. On the goal, I – you know, my understanding was 100% renewable was the goal and 100% renewable meant we were going to overpurchase and we still needed a quick start plan for financial backstop and we still – like, this was the 2018 goal. I don't know if the will of the people has changed or, you know, if council no longer thinks that's the goal. So I think if whatever we bring forward, moving forward, you know, we might need, you know, resident input or, you know, some way to make sure that if we think that they're like – that the goal has shifted that, you know, then we need to make sure that that's correct. Now I do agree separating the goal from – because then there's this tactical thing of, well, this year there's some crazy, you know, thing at the legislature. This year solar panels from wherever have, you know, a tariff or this year gas turbines, you know, plant shut down in Brazil or whatever. So I think we separate the goal from the implementation. I think that actually is your next part of your presentation. So the 2018 plan actually had three options. The first option was to go out there and secure additional solar contracts, right, immediately to reach that goal by 2020, right? That was kind of option one. Option two was to reach the goal by 2024 with what the plan identified as coastal wind, right? And we attempted to do that. It just was not available, right? And so you could have gotten coastal wind and reached that goal by 2024 or option two B was utilize the recs, right? Now in a final decision by this board, obviously a different board, and by the council was to not count those recs, right? As myself and Terry Nolte at the time, you know, came to DME and started looking at that entire discussion. We had a discussion with the consultants and they agreed that maybe the information that had gone to the council, to the PAV hadn't been 100 percent accurate, right, or as clear, right? That's why I've attached to you a letter, right, that I attached in your backup from the consultants, right, making clear that counting recs is a viable option, right? And it is a standard option, right, that companies out there, entities utilize, right? So counting, using recs to count towards 100 percent renewable goals is actually the standard and not the exception, right? There was, I think, within some in our community, that the goal was going to be achieved with energy only, right? But there was still a misunderstanding that those energy contracts, the evidence behind that energy isn't the energy, it is the rec, right? It is the rec that we count, right, as the evidence that that was produced, right? And so if a rec is the evidence for the energy for our PPAs, it's also the evidence for other generation of renewable energy in other places where we don't have PPAs, right? So it's the same thing, right? You just don't own the energy and you're not paying for the energy you're paying for the recs. I appreciate the education for the explanation because it, sometimes I look at this almost as in recs are credit cards and cash is what we're getting from the renewables and we just have a balance which you have a good grasp on and I appreciate that and, you know, Las Vegas is our next stop because, like you say, everything is uncertain, isn't it? I think if we were able to buy all renewables, we'd be buying all renewables. When we're able, like what does able mean? I mean, they're for sale. Yeah, but, okay, just give me two million, I'm only going to use a million. Right, so, and that's the balance, it's a cost risk balance. It's not like they're unavailable at any cost, you know, it's more like it is a cost risk balance. Absolutely. Yeah. Yeah, that's, I think that's... So sometimes when you say they're not available, that makes it sound like you can't buy, like nuclear is not available, like we can't buy nuclear at any dollar amount. Yeah, we don't have the psychic ability to make them available at the time that we need them. Okay. And then cut it off. Yeah. That may be better for the, and I'm, you know, remember, I'm all about renewable, I think most people are, it's just the reality of trying to get it exact is just, is the difficult part, right? I mean... And here's the other reality, right? The other reality is that, and again, I don't want to over dramatize this, but this is the reality, this was certainly our experience during Winter Storm Uri when there was few little renewables, right? The phone calls that I got in my cell phone, right, at home at night, nobody ever said I want the power, but only if it's wind and solar, right? And so certainly I think that Winter Storm Uri, I'll talk a little about the Texas Energy Fund that was overwhelmingly approved across the state and even here, right, is that people recognize that while we might want renewables, we also need reliability, right, and we need that power to be there when we need it, whether I'm a, you know, a homeowner or whether I'm a business, right? I need that power there to continue to operate and to continue to live. And so, unfortunately, renewables have introduced this intermittency, right, that you don't know when it's going to hit you. Yep. I mean, we have some very, you know, we have some very good people in the EMO that have some very good predictive models, right, on everything from weather to cloud cover to, you know, is there going to be a solar flutter day or not, right, that could have an impact on the market, right, and they're trying to react to it. What I will tell you, Mr. Kelly, too, is that we currently have five vacancies in that particular EMO. It continues to be a challenge, right, with all the different uncertainty and changes in the market, individuals that do that work are in high, high demand, right? And so, certainly, recruitment and even retention of these individuals is a challenge as well, right? I think they do a fantastic job. You know, we're moving forward with filling those five FTEs. We're hopeful that we're going to be able to attract some good people, maybe some people internally into the operation. We think that that gets us what we need for the time being, but remember, I will point out that the QSE, right, this Qualifying Scheduling Entity, which is what the EMO is officially known as, was started in 2013. In 2013, they were managing about $50 million of power. Today, actually, let me say, in three years, they're going to be managing $400 million of power, pretty much the same number of people, right? So, again, so creativity is not something that those individuals lack. They do. They're professional. They're creative. They're doing a fantastic job for us. What I'm hearing from them is, "Hey, it's going to get very, very hard here, and you're going to continue to see a bump up in your energy costs," right? We're at $0.046. Let's call it $0.05 is our ECA today. We're looking at power prices in the future, and we're looking at $0.06, $0.07, right? So yeah, that's one component of three components within a customer's bill, but it could easily be the largest component before too long. So, unless you have any questions, can I move to part two? Okay, so part two is, you know, our recommendation here is going to be to create what's called an integrated resource plan. Actually, in 2018, we had a consultant, did a management study, and actually made that recommendation. At the time, we felt that the debt and renewable resource plan, again, given the context of everything at the time, really kind of met that definition. We don't believe it meets that today, and certainly our recommendation, right, is to create an integrated resource plan. So what is it? It's basically just a strategy document that considers your total future electric demand, and also looks at the supply side, right? And options like potentially building new generation resources, and it could be a variety of those resources. There's not just natural gas, there's geothermal, certainly there's nuclear, hydrogen is probably not too far off, there's small modular reactors, there's a number of things that we can look at. For some context, Austin Energy just did this very thing. And they opted to build a geothermal facility. It is five megawatts. Their peak load is 2,000 megawatts, right? So it's a very, very small portion. Their plan is to build that in Nacogdoches, Texas. And I'll tell you, there's folks in Nacogdoches today that aren't very supportive, because they think that that facility is going to create earthquakes in their community, right? And so again, no resource is going to be without its detractors, or folks that may not be supportive of it. Really this plan is really a longitudinal plan that will look at what are the needs at 15 to 20 years. I will tell you, I woke up one morning, I was here now 25 years with the city, it goes by quick, right? 15, 20 years will go by quick, right? And so that is a 15 or 20 year plan that you set the day, and then every five years you're revamping it, you're adding additional timeframes, right? And it's just a living document that continues to set your generation needs going forward as the community continues to evolve, right? And so whether it's data centers, or it's additional residential, or commercial development, that will continue to put pressure on their utility. So let me go through a little bit of the regulatory market, and we've kind of peppered through this. But here's the good news, right? We have not had any forced outages in ERCOT since 2021, right? Have we gotten close? Yeah, absolutely. There's been a few days in the winter and summer that I've been sweating bullets, right? Because I'm not sure if we're going to have to start doing rolling brownouts, right? And so certainly I would categorize the market as uncertain. Since yearly, the scarcity cap, the highest price at which energy could go was basically cut in half. It went from 9,000 to 5,000. And even though my AMO guys tell me, well, Tony, that's not exactly right, here's the way I look at it. Had the scarcity price has been 5,000 during winter storm Uri, instead of $140 million worth the debt, it would have been 70 million, right? And that's the difference, right? Likewise, in 2023, when the cap was 5,000, and we incurred $31 million in the summer of '23, had it been 9,000, we would have been looking at $60 million, right? And so certainly we think that reducing the cap has been a good thing. I would tell you there's some in the market, some especially on the private side, private generators that are saying, hey, that scarcity cap really needs to go back up to 9,000. And there's some generators that are saying it should be completely uncapped. And that will then send the right signals to the market on the private equity side to come into the state of Texas and build the generation that's needed. And what we're talking about, the generation that they would build, right, it would not be renewable resources. It would be dispatchable generation, very likely natural gas, right? Since that time, there's now been a fifth ANSLE service, and I could probably talk to you for a couple hours about ANSLE services. But certainly ANSLE services, you know, number six was this ERCOT contingency reserve. There's an independent market monitor that monitors what ERCOT does and reports back to the PUCT. And they estimated that that ANSLE service alone added an additional $8 to $10 billion of cost to rate payers in the state of Texas. Now, the DEC is eligible for that ANSLE services. We're eligible for all five ANSLE services today, and we are active in the market in selling those services and making ourselves available. One interesting thing about the ECRS that's been reported is that the ECRS has actually sidelined the newer, more efficient generation, and so now the market is even more dependent on some of the older, dirtier generation, right? And again, because it's far more lucrative for these newer generators to stand the sidelines and collect ANSLE service dollars and preserve their facility, right, and extend the life of their facility. FFFSS, that is a real acronym, Firm Fuel Supply Service is another one that's added $51 million into the market. The DEC is not eligible. As you guys know, we don't have a firm fuel contract for the DEC, so we're not eligible for that. And then in November of '23, voters approved, I think it was Proposition 7 or 9, but they approved a proposition to create what's called the Texas Energy Fund. This fund allocated $7.2 billion in ERCOT for loans and completion bonus grants to build 10,000 megawatts of dispatchable generation, with 100 megawatts as the minimum. A number of projects submitted in its first tranche of applications, DME did not submit an application, and we did not submit an application because the primary requirement is that you had to have a shovel-ready project to submit. And so those are being reviewed today. Only two have been awarded up to this point. A large number of them have actually dropped out of the program, but there is growing interest in the completion bonus, again, because there is no red tape for -- red tape, I'm probably sorry about this, red tape, but there's a lot of requirements, right? What I will tell you is that the interest cost of that loan that's backed by the state is about 3%, you know, and I think based on our credit ratings, I think we're pretty competitive to that. I think a lot of MOUs -- there's only one MOU, that's Kerrville, that submitted an application, and they're still going through the process -- excuse me -- there was a legal issue that came up, and we think the legislature is going to solve that particular issue when it comes to MOUs being eligible for this loan program. Had to do with subordinate liens and a whole bunch of other stuff that we probably don't have time to talk about today. And then the other issue is that 10,000 megawatts is actually -- it's actually 20,000 megawatts, so it's up to 10,000 megawatts on the loan program and 10,000 megawatts on the grant program. I'm hopeful that that particular legislation will get through to make that clarification, because under the current guidelines from the PECT, it's 10,000 megawatts total between loans and grants, right? And so, again, it certainly would expand the availability of those. There was another billion dollars for -- believe it or not, ERCAD does not cover all of the state of Texas, and so there's a billion dollars for outside of the state of Texas. Outside of ERCAD, you have two additional ISOs. One is SPP. Don't ask me what that means today, because I've forgotten. And then there's MISO, as well, on the east side, SPP, Southwest Power Pool, excuse me, on the west side, and then MISO, mid something or other, on the east side. And then -- a lot of information here. And then $1.8 billion is available, PECT still going through all the requirements for backup power package. Matter of fact, that's something that Stephen and I have had a lot of conversation about, especially for his water plants and some of his other critical infrastructure, that I think he would be certainly eligible. I were hopeful that he would be eligible for those. And it just keeps going and going, right? So again, proliferation of renewables, you know, more and more renewables continues to create additional scarcity periods, both in the summer evening hours, winter, morning and evening hours. One phenomena that we're certainly looking at and our EMOs is paying close attention to is as some of these very large loads are coming online that are 24/7, right, they are soaking up a lot of the cheap energy during the day, which is mainly solar, and at night, which is mainly wind. And so what we're seeing, future prices, those prices are now starting to climb up, right? And so additional risk to the entire market from those large loads. Yes, sir. Could you give me an example of the 24-hour, which you just referred to? Yeah, an AI data center, like the one we have that's being constructed here and then. So those will continue to soak up some of those low-cost power hours, and again, it's a supply and demand, so we're going to see those prices continue to climb up. So a specialty type of use versus like a university or something of that magnitude, they're the ones that draw the great deal of the power then? Yeah, by and large, what we call our native load, right, you know, our non-data center load is pretty variable, you know, but yeah, but these data centers, they're 24/7. That's why they have backup generation, because they cannot go down. So while power can be cut to them, they have to have a backup source to at least keep them on for a couple hours. Yes, thank you. Yes, sir. And then a number of other items that I won't necessarily go through, but everything from a sixth answerly service, this DRRS, to real-time co-optimization, Jose could probably spend three hours talking to you about that, how that interplays with batteries and renewable resources. Just so long as you have more pages of acronyms, I would... You would like some more? You've gone all day. Yeah, yeah, yeah. I can do these all day. Yeah. So I'll go with other, right? So there's, again, both at the state and federal level, lots of regulatory market issues. And then let me talk to you a little bit about our load. And so this is something that you've seen now a couple of times. And so currently, our load is... Our peak load, which we achieved in the summer of '23, was 408 megawatts, right? That is, in essence, backed up by 225 megawatts from our deck, leaving a shortage of 183. So in a situation where the state requires that we firm our load, right? We believe that this 183 megawatts today is what we would either have to, one, build, two, contract for, or three, what's being discussed is buying some type of credit, whether it's a dispatchable credit or it's a performance credit. So if you remember, the PCT was looking at creating what's called a performance credit mechanism that has been shelled, right? They're waiting to see what the legislature does with the dispatchable credit system. If that doesn't happen, likelihood the PCT is gonna go back and revive the PCM, right? And so based on our load, what we're seeing here, as you can see, our load growth, right? We anticipate our native load to continue to grow from 400 to 500, getting near to 600 by 2044. This large load is a number of projects that we have out there. And so the total load, we believe, that by 2044, we will be in excess of 900 megawatts. And so, again, to look at long-term basis, certainly what we're looking at somewhere in the 600 to 700 megawatts of additional generation, and let me just be clear, that is dispatchable generation, not renewable generation, again, that will continue to meet requirements if they come through fruition. Please understand that this forecast does not assume any additional large loads. And just like others across the state, we continue to have interest. One of the challenges that we have from a transmission system is that we've identified these overloads, right? And we believe it's gonna take us two to three years to resolve those system overloads. Once that's done, then we will have plenty of transmission capacity to support just about any large load that would be interested in coming into our service territory. But that is the one barrier that we have today. But I will tell you that the prospects that we're talking to are not at all afraid of two to three years. They're saying, "Hey, what can you give me today? Can you give me five megawatts? Let me get started. Give me 20 megawatts, let me get started, and I'll wait two to three years for you to build it," right? And again, they're all across the spectrum, right? Some that I would categorize as very sophisticated, well-backed, and others that are more speculative. But we are having...continue to have those conversations, none of that is forecasted within this. Again, it's not real until we have...frankly, we have a PPA with them or some type of negotiated contract with them. So our staff recommendation when it comes to this is that we go out and we create integrated resource plan, preferably for 20 years, that would evaluate a number of different resources out there to create what we need within the context of that policy that we've outlined for you on the renewable side that looks at what the short-term needs might be and risks, incorporate as well any local demand-side management programs. I know we've been talking about that for some time, and there's certainly been a number of challenges for us to be able to bring that to fruition. Understand too that I just participated in a webinar on Friday, the state is actually looking at a residential demand-side program, and we're certainly advocating that our customers be eligible and be able to participate in that. Again, it's still in its infancy, but we certainly believe that ERCOT is interested in rolling out additional demand-side programs to continue to manage that load for the entire ERCOT grid. And also that this plan be cognizant of the climate action plan goals that the council has approved. And then we would recommend that we hire an external firm to help us do this. Again, the two models that we have, both CPS Energy in San Antonio and Austin Energy in Austin followed these processes and we like them. One of the things that's central to this process is that there be a stakeholder engagement process as well. So that we go out there and talk to the community, hear their concerns, share information with them as best we can, certainly there's confidential information that we won't be able to share with them. But again, to try to be as transparent as possible, get their feedback, be able to come back to the PB with that feedback and to the council and enroll out that program. We anticipate that that would take us 18 to 24 months to do that. Understand that even if the council, even the PB recommended that we go forward to build another generation facility, and let's say it's a natural gas facility, we're looking at probably 2030, 2031 based on the supply chain for engines and other material. Certainly we continue to have supply chain challenges on the transformer side. And so again, at best we think if we got started today, it would be 2030, 2031 before we got to build anything. If you add an additional 18 to 24 months there, now you're talking probably seven years from today that we would actually have some type of dispatchable generation on the ground operational. So during that time, we're going to continue to have to manage our portfolio the best we can. And if there is need for price increases, rate increases, then we'll certainly be coming to you with that. So and then just to recap here, again, our recommendation is to create a city renewable energy policy. Anticipate that would take us six to nine months as our internal process for that, and then create a long-term integrated resource plan that would take 18 to 24 months. So with that, that is my presentation. Happy to answer any other questions you may have. This was getting good there for a while, and now you guys are not doing it. Mr. Chair, I would say too that the plan is that we would make this same presentation to the council on June 3rd, and so I'm asking for your recommendation to submit to the council. So I think splitting these two, the goal, the city renewable energy policy, which would be probably our stated goals and defining those well and making them like Audit pointed out, they weren't well defined, and we weren't necessarily measuring them, at least not until 2020. We waited four years to start measuring them, and even then the definitions were always, were not super precise. So I think that makes sense. I noticed the IRP, you do have community engagement to get citizen input and stakeholder input. I think that we need the same in the goal part in the renewable energy policy as well. This is, it's complicated, you're talking about wind and solar driving down energy prices and data centers are soaking up and driving up the prices, and which one's going to win out who's like, renewable energy projects cost more than they did, and they look like they wouldn't be in the money now, but then future power prices are going from an average of $40 a megawatt to an average of $70 a megawatt, and there are a whole lot of REPs in the deregulated areas that are 30 or 40 or 50% more expensive than DME right now, because they have no long term power, they maybe have two years worth of power purchased, and they've been facing those higher prices now for a few years, and balancing it all, it's big and complicated and ever changing. I think these two plans, these are a good way to do it, and I think the key is community buy-in. Yeah? Yeah. Very good. All right. Do you need anything from us other than just the conversation and actual-- I mean, I know Mr. Taylor introduced the possibility of some type of community engagement with the policy, if the recommendation is to move forward with these two, do we add, because it's not-- I mean, it's contemplated there in the sense that it's going to come here to the PUB for consideration, and certainly the public is eligible to come here. Same thing with the council. If there's any other recommendation that you would want, I would anticipate that both for the PUB and for the council, likely that policy will be put on the agenda as an individual consideration item, and not necessarily consent agenda item, so again, that would afford the public additional opportunities to provide feedback, but if there's more than that, certainly we need that direction from you today as a recommendation to the council. I like the idea. I know you guys don't, it's okay, but I mean, if the people that want to have a discussion about this in a public format, and that might be me too, I think you might invite the PUB members to something like that. I mean, I know it's the deciding vote in this city, but if we're going to bring up the discussion, and we would like a discussion amongst our neighbors, then we could get involved with that. I bet Devin would. I think the magnitude of it would require it, and I appreciate you volunteering, Mr. Chairman. Well, I think I just said that Devin would do it. So hear that, and if you want to have more discussion of this on where to go with that, I think that's fine. Yeah, I think I would. Are you talking about some type of town hall meeting? Are you talking about, hey, we're okay with you putting in an IC, or are you talking about a public hearing that the council would have? Yeah, help me flesh that out a little bit more. So the six months process. So first, I mean, this is the plan to make a plan right now, it's what we had today. Yes. Yeah, so taking that to city council, obviously, but then in that six month period, it would seem like town hall would be, if you bring a final recommendation to a public hearing without any citizen input along the way, some views may get overlooked, and you also might lead to a really contentious hearing where a lot of people don't feel heard and show up angry at a public hearing when that isn't necessarily the intent. So if it was possible in the six to nine month period to have some kind of town hall or some kind of meeting, and city council might have a stronger opinion about the format of it, to get that input early and get those options early, you know, bringing a menu of options and what's supported and what's not, and what the likely risk and cost of each of those would be to council might be a better way to go. I know that complicates when you're writing a plan, writing 10 sections of a plan and trying to piece together how they would interact, I don't know, or maybe that's not appropriate, but I think somewhere in that six month process, having citizen input as opposed to just at the end in a public hearing. Okay. So I think the important thing to get across is that we, I think some of us would like to see some more public discussion about this and love to be invited, I guess everybody would be, if every citizen would be, red payer. We can try to communicate with the council and get their direction. Yeah. I mean, that's all we can do. You know, a few years ago we did that, and council asked PUB members to show up because we had the long discussions about it, but anyway, I think, I think that's good. Anybody got anything else? Do you need a motion? No. I think I have direction. Yeah, I was just discussing. I didn't quite catch that. Yeah. Thank you. Yeah. Okay. All right. Next we stand adjourned. All right. Thank you, Tony. Thank you.