Mar 23, 2021 Public Utilities Board on 2021-03-23 11:30 AM (JOINT MEETING WITH THE CITY COUNCIL)

>> Good morning and welcome everyone to this joint meeting of the Denton City Council and Public Utilities Board. I'm Mayor Pro Tem Jesse Davis and at this time is 1132. I will formally open the meeting of the City Council and introduce Chair of the Public Utilities Board, Susan Parker. >> Good morning. It's 1132, so I will call the Public Utilities Board meeting open. >> Very good. Thank you, Chair Parker. And with that, I will move us to our one and only work session report, item 1A, ID21341, receive a report, hold a discussion and give staff direction regarding processes, impacts and results of service delivery during the February 2021 inclement weather event. By the following departments, we'll hear from Denton Municipal Electric and the water and wastewater utilities. And just for the members of the public, these are very in-depth reports we're about to receive. There are breaks built in for questions. So we'll be taking -- you'll see a slide come up that says breaks and questions. That's when you can expect your PUB and council members to be posing the questions. And Tony, are you up? >> Yes, sir. So Mayor Pro Tem, City Council members, members of the PUB, I appreciate your time today, and we certainly have a lengthy presentation, about 40 slides. We're going to try to go through those as efficiently as we can. Again, my name is Tony Puente. I'm the executive manager for utilities for the city and also serve as the DME general manager. Before I get started with the presentation, I just wanted to go through just a couple of items. Just wanted to -- first of all, I want to acknowledge, you know, the trying times that our customers faced during, you know, this winter storm. We know that, you know, many of them suffered through extreme, you know, low temperatures. And certainly some of our customers that are dependent on medical equipment, we understand that they went through some very anxious times trying to sort out how to take care of themselves and where to go. And so certainly want to just acknowledge our customers. I also want to assure our customers that, you know, that they were certainly at the forefront of our minds and our efforts throughout the storm. You know, their health and safety was certainly a top priority for our team at Den Municipal Electric, and we certainly worked with many of our partners across the city, especially our public safety folks, to be able to respond to calls and some of the information that we were getting. I also want to assure our customers -- excuse me -- that right from the very beginning, we initiated our rotating outage plans. We did not hold that back. We immediately put our plan into effect. We also made some adjustments to that plan, and so while we had some hard lines as we were getting phone calls from our customers and requests, we did make adjustments to that in order to be able to address certain things. One of the examples I've given before is that we increased the outage from 30 minutes to about 45 minutes just trying to make sure that we accommodated people so that they could have a little bit more time with electricity in their homes and be able to warm up their homes as best that they could. Again, I want to thank our public safety partners, and also just wanted to stipulate that as ERCOT was allowing us to add power back onto the system, we did that. We did not hold back on that power primarily, again, because of our concerns for the health and safety of our customers, and so even though we knew that we may be exposed to some financial challenges going forward, we did not hold that back. We continue to allow power back onto the system to be able to provide it to our customers. The second item that I wanted to just briefly just go through is just to thank our DME staff. As you can imagine, it was a very trying time for them as well. In my view, they acted very valiantly, including the fact that many of them left their own families and their own loved ones at home in the dark to be able to come in and provide the services to our customers that they've always been able to provide, and so I want to acknowledge their efforts and the work that they did and just thank them. I will tell you, just on a personal level, that I have not worked with people like this since, frankly, since I was a young 19-year-old Marine being deployed overseas during the first Gulf War. I'm honored to serve with these folks. They were very valiant. I will tell you that every single one of them stood their post, and they did not abandon their post. Our folks did everything that they could, and I wanted to thank them, and I truly believe that at the end of the day, their work and their effort saved people's lives. We have a number of examples where we worked with FEMA and dialysis centers and other areas of the community to try to give them at least some power, try to accommodate them as best we could, and so I truly believe that our efforts did save people's lives, and lastly, I'll just say that in my book, all these DMA employees and certainly all our employees across the city, certainly those that we partnered with, are heroes in my book, and I would hope that you would echo that as well. So with that, I appreciate your indulgence with that, and I'll go ahead and initiate this presentation. So just to go through the objectives, I'm going to quickly go through just a little bit about DME. Hopefully, we'll answer some questions that some of our customers and community members have. Then I'm going to turn it over to Chris Lutrick. He'll go through some of our division reports. We'll have a break for questions on that section, and then Terry Nolte will come up and present some additional division reports, and then at the end, we'll just have time for questions and just general questions that you may have for me or for either one of our team members. So just a little bit about DME. DME was established back in 1905. That's about 116 years of local power that's been provided that the citizens of Denton have chosen to have. Certainly, from our viewpoint, that provides the maximum local control. DME is the sixth largest municipally owned utility in Texas. We're one of about 72 MOEs in the state of Texas. We make up about a third of the total ERCOT market. So about two-thirds of the ERCOT market is made up of co-ops and private utilities, just to give you kind of the size of our participation in the ERCOT market. Our governing body is the city council. We certainly have an advisory board, public utilities board, that advises to council on all things related to utilities, including DME. And council does adopt our budget and rates on an annual basis. Over the last two years, our team has really tried to focus DME and to be in and recognizing that we're a department of the city. We're not a separate entity. And so we've driven this concept of one city, one organization. And I think our staff have certainly embraced that concept. DME also has a defined service territory. The main area is certainly the core of the city, but we do have extra jurisdictional or ETJ areas. And then there's also some small tracts in the city of Corinth that we also currently serve. So this includes single, dual, and triple certified areas. And we'll talk a little bit more in the next slide about that. So this is just a map for you on areas that we serve. I know we've had a lot of customers ask, well, why am I with co-serve or Encore? And this really kind of shows a picture of this green teal area is the single certified areas for DME, where we serve the majority of our customers. But in these outline areas, we do compete in those areas in dual and triple certified areas. In some cases, we're duly certified with co-serve or with Encore, or we're triply certified with those two entities primarily. And the way that that works is normally that starts at the development process when the developer wants to come into one of these dual and triply certified areas, they work with all three companies and they make a decision as to who's going to serve that particular area. I'll tell you that the vast majority of developers do choose DME. And so we anticipate, just like in Hunter and Coal Ranch as an example, we're going to serve the majority of those two developments that will continue to expand outside of the Encore city area. And just really quick, once that decision is made on who's going to serve that particular area, that dual or triple certification does not end. So that continues. But as you can imagine, it's very cost prohibitive for another provider to come into that area. Certainly there'll be restrictions related to available right away and such, and there'll be some additional expenses that may be incurred to be able to switch. But again, I wanted to just quickly just show that because I know we have a lot of customers that ask questions about, well, why are my lights off or my lights on? Some of the explanations that you may have been with a different provider and not the municipal electric. This is our current organizational structure. I'm not going to go through it in detail, just simply to say that you'll be hearing from Terry and myself again in our dual roles here. Terry does also oversee the water wastewater utilities as the interim director for water wastewater, but he serves as the assistant general manager for DME. And of course, I have a dual role as well in that we oversee the other city utilities, including the municipal electric. Over on the right-hand side, I did want to point out just quickly that over the last three years now, really starting in May of 2019, we've worked to right size, not only our budget, but certainly our staffing levels. We engaged an external party to help us go through and look at FTE counts and just our organization in general. And so over the last two years going into our 2021 budget, we did certainly see about a $9 million reduction in our operating budget. And we saw about 20 positions that we eliminated in the budget. And again, we did that very purposeful as part of just a wider right sizing of our budget and our organization. So with that, I'm gonna turn it over to Chris Lutrik to come in and cover his areas of responsibility. Thank you, Tony. Before I get started, I would just like to reiterate a few things that Tony said. I'd like to thank our customers for the patience they provided us during the winter event and just to reiterate what an honor it was to work next to all of our DME staff. It was very trying times. As you know, a lot of the work was done outside, very demanding conditions, and our guys just never back down. So this was an unprecedented event for us. We never knew what the next hour might hold, but our guys were always, guys and gals were always up to the task. They never back down and they did what they had to do to get the job done. So again, it was just an honor to work alongside them during the event. So I'm Chris Lutrik. I'm the executive manager of operations. I oversee the day-to-day electrical operations of the utility, and I will be covering our DME system response to the winter event. I'll start with talking about ERCOT's role during that week. As you know, that's an acronym that has received a lot of media attention over the last month, and the acronym stands for the Electric Reliability Council of Texas. They're a quasi-governmental organization that manages the electric power to about 24 million Texans, which represents about 90% of the state's electrical load and covers about 75% of the land. It is wholly contained within the borders of Texas, and I should state that ERCOT does not own or operate any equipment. They simply oversee the interconnection of the 17 transmission distribution service providers who do own and operate the equipment and are interconnected. Their main task are they coordinate the operation of more than 550 generation units. They're spread out over the state of Texas. They coordinate the operation of 46,500 circuit miles of high voltage transmission lines that are required to transport that power from the generators to the load centers. My colleague Terry Nalte will discuss this next bullet in detail in his presentation, but another function of ERCOT is they manage the financial settlement for the competitive wholesale bulk power market in Texas. Here's a fraction that will become important in my presentation. DME represents 0.5% of ERCOT. That allocation and obligation is assessed every year, and it's based on the peak summer load of the utilities, and ours currently stands at 375 megawatts. So now we'll get to the event, and again, we're talking about the event starting on Saturday, February 14th, and working our way towards Thursday. I think that's February 18th. So at that time, the grid was under a lot of strain. Loads were very high, and ERCOT at 1.20 a.m., the reserve margins had been compromised. At that time, they entered a load shed event. So as you see, the nominal frequency of the ERCOT grid is 60 hertz. Small deviations above and below that are normal, but when the frequency starts to vary either above or below 60 hertz, that's an indication that the grid is under stress. So as you see in this 30-minute or 40-minute snapshot here, a lot of things happen. So the first events here are there's generators are tripping offline. So we already were in a -- our capacity reserves were compromised. We have generators tripping offline. So as you'll see, the graph begins to trend downward. That means the frequency is moving away from 60 hertz. So right at about 1.43, you see the graph gets pretty steep. This is an indication that the grid is in trouble. ERCOT orders another load shed instruction. Then again, as you notice, three more generation outages occurred, and the graph gets really steep. This is the time when we were headed towards a blackout condition. If ERCOT did not take the proper steps to mitigate this frequency decay. So again, the first threshold was hit, the 59.4 hertz. At that point, the generators can only operate for nine minutes. At that point, they have protective devices called relays that would have then taken additional generation that was able to function offline to protect the equipment. During the event, so ERCOT ordered another big chunk of load shed that was 3,000 megawatts to try to mitigate that frequency decay. And we came close because if you notice on the graph, we were below that threshold for four minutes and 23 seconds before the frequency was able to start its recovery. And an important note on the bottom right-hand corner is the minimum frequency that was recorded was 59.302. That's an important number and I will further expand on that later in my presentation. Now on to DMEs to our part of this load shed event. At the time, the load shed began at 1.20 a.m. on Monday, February 15th, the city's net load was 275 megawatts. That probably was about 100 to 125 megawatts higher than your typical February evening. And actually the previous day, which would have been Sunday morning, we set our peak, our all-time winter peak of 304 megawatts. So to give you the context over the whole load shed event, ERCOT ultimately required operators to shed 20,000 megawatts of power from the grid. And to put that in context, at that time the total grid load was about 70,000. So nearly one-third of the load on the ERCOT grid was instructed to be shed. To break that down to our portion again, it's based on your obligation now and that's still the half a percent. So out of the 20,000 megawatts, we were required to shed 100 megawatts at the peak or about 36% of the city's net load. This event that I detailed on the previous slide that started at 1.20 a.m. on Monday persisted through, I believe it is 12.39 a.m. on Thursday morning. So a total event duration of about 59 hours. So how did we go about the load shed? We have a load shed plan. I'll start with this plan is confidential as it contains critical energy and electric infrastructure information. It has our hospitals, police departments, fire stations. They are identified in the plan as well as what circuit they're on. So if that information was to become public, bad actors would have a roadmap for doing the most sabotage or destruction to our infrastructure. Therefore those plans are confidential. So that being said, the plan is updated annually along with our ERCOT emergency operation plan. They're submitted to ERCOT and it contains two main components for shedding load. The first is under frequency load shed. It's a pretty fancy title there and I will explain that further on the next slide. And emergency load shed. That was the method that was utilized during this event by our operators. And I'll finish this slide by saying that DME is obligated to comply with ERCOT operating instructions. This is directed by NERC. NERC is the North American Electric Reliability Council. They're a federal entity that oversees the operation of electric utilities across the country. Our obligations are detailed in the ERCOT operating guides and protocols. So to detail the two different methods of load shed, I'll start with emergency load shed. That is a controlled rotating outage. During the event we saw a lot of social media that used the word blackout. ERCOT, that means something different. So to ERCOT, a blackout is if you were to go up in space and take a picture, the state of Texas would be dark. At that point the grid has failed. There is no transmission voltage and 24 million people are without power. So this is, I'll use the word outage or try to use the word outage for the rest of the presentation. Again, they're controlled. They are initiated by our system operations. They can be done remotely. And again, our obligation is 5% of the total ERCOT load. And so when we're issued a directive or an instruction from ERCOT, we get on a call with the other 16 TDSPs and as that graph showed, your load shed instruction is 1000 megawatts. And then that was acknowledged. And then that meant that 1000 became 5 megawatts for us. So everybody got the same instructions. They're done verbally over the phone. You acknowledge it. And then you're obligated to perform that load shed as soon as possible. Our plan we had in place utilizes feeders that do not contain critical loads. Those are 43 feeders that we identified. They're mainly residential and commercial loads. And they would be the first load that is shed when instructed by ERCOT. Our plan was tweaked after the 2011 event, winter event. I think that was during the Super Bowl. That was the last time that ERCOT had issued a load shed event. For that event, the duration was six hours, about six hours. And DME's portion of that event was 20 megawatts. So at that time in evaluating that, this is as bad as it can get. So we added 50% to that to bump that to 30 megawatts. And to roll 30 megawatts, we have to have two blocks, an A and a B. So when the A is on, the B would be off. So we had to identify 60 megawatts or twice your allotment for our plan. And our original plan, as Tony mentioned earlier, called for a 30 minute outage. That's what we entered in this event. That was our plan. The second load shed method is the under frequency load shed. As dictated here, this is the automatic non-rotating outages. All TDSPs in ERCOT are required to have a minimum of 25% of their load that are fed from circuits that have these protective relays on them that can sense the frequency of the grid. And what this is is the grid is under a lot of stress. And our relays, like the first one, the 59.3, the importance of that first number I told you was 59.302. We were two thousandths of a hertz away from this group of relays opening up across ERCOT. And at that point, automatically those feeders would have opened up and a minimum of 5% of the load would have been shed. Again, it's a built in feature to try to save the grid to avoid the blackout condition. There's three groups. So as the frequency continues to decay, the next group two would open up and then group three would open up. And I should note, if those relays were to open or to operate at that point, those circuits are under the control of ERCOT and you cannot restore power to those circuits until ERCOT issues the instruction. So again, those relays did not operate during this event and they have never operated on our system. They're a very rare occurrence, but they're a last ditch effort to shed load to save the grid. The next main component of the load shed plan is it requires you to prioritize your loads. So this takes all of your customer bases and you have to, it doesn't exactly tell you how you need to classify them. It just tells them that you do need to classify them. So classifying the critical load, that is established by the Texas Administrative Code done through the PUCT and it lists four categories of critical load customers. The first being the critical load public safety customer. As you can imagine, that's your major fire stations, police department, water treatment plants, sewage treatment plants, emergency operations centers, and your major hospitals. Critical load industrial customer. I don't think we have any of those on our system. They have to do with endangering public in retail establishments. And then the last two classes we do have on our system, those are the chronic condition residential customer and the critical care customer. These are programs that customers in ERCOT can apply. There's some qualifications for them, but they actually are basically notifying the utility, hey, I'm here. Here's my address. And I have some medical equipment that needs to be, you know, this operates off the electrical grid. But it should be noted at the bottom also in that code is a statement that says designation as a critical load customer, a critical care residential customer, or a chronic condition care customer does not guarantee the uninterrupted supply of electricity. That was one of the questions that was out, that was floating around. For load shed, at that point, you're trying to stabilize the grid. So those customers are not guaranteed. Actually, any customer is not guaranteed uninterrupted supply of electricity, either via mother nature with a storm or equipment failure or a rotating outage. But our load shed plan, we do take those into consideration. So we have four categories that are listed here and followed by basically our fifth category, which is our emergency load shed feeders. So category one is our critical load public safety customers from as described right above. These are our major hospitals, police department, fire stations, basically health and human services, so they can continue to provide those services for our residents. Categories two, three and four due to the size of this load shed event, they were in the rotation. So again, I have some graphs that will detail that out. Feeder utilization during load shed, just some information about our system. DME has 107 feeders that carry load. Just a quick tutorial there. A feeder is basically electrical circuit that originates at a substation circuit breaker and runs out into our territory to serve load. They're, they're generally pretty long, you know, three or four miles, three or four miles long, they're designed to carry a maximum of 13 megawatts. We tend to try to load to keep those balance at about eight so that we have some switching capabilities. The feeders are segmented by switches and other equipment that can allows us to intertie these circuits from one to the other. This gives us flexibility in balancing our load through the different seasons, responding to outages, maintenance activities. That's our flexibility. But I should say that's large sections of those circuits can be moved to another one. We cannot move individual customers from one circuit to another. That can be done, but it would be very expensive and you basically have to build the infrastructure to do that. So that being said, 17 of the feeders on our system serve the critical infrastructure load. That's the category one on the previous slide. That's your major hospitals, water, wastewater facilities, police and fire. These feeders did not experience any outages during the event. The remaining 90 feeders on our circuit, on our system were utilized to, to get us through the rotating outages. And to put that in context, at the peak on Monday evening, our load shed instruction was 100 megawatts. We had to take 230 megawatts off of our system to roll over to the next 100 megawatts of load shed. So once you're in a load shed condition, you cannot exceed that amount. So the load you have on, you actually have to take that off. So you have both blocks off before you bring the next one on. If not, you would actually be putting more load on the grid, which would, would defeat the purpose. But at that point, that 230 megawatts affected about 43,000 of our customers. So we had two thirds of our 60,000 customers were without power during these rotation periods. So back to our plan, we originally had 43 feeders identified for load shed. That would have accommodated a request of 30 megawatts. And it took an additional 47 feeders that did have critical service loads. We had to put them into the mix to maintain our goal of maintaining the rotating outages. This is a, this is a pretty angry looking graph, but it kind of details the, the, the, the rotation cycles that we did have. So it starts on the very left at 1 26 a.m. on Sunday. And I know that print's very small on Sunday. You just have to take my word for it. That's when we started. So we were at zero load shed. That graph I initially showed you of the situation where the system was about to collapse. That's the steep incline here in our load shed instruction. So ERCOT was able to use load shed to mitigate the frequency decay, stabilize the grid. And then the rest of this orange line is, is our portion of the load shed instruction throughout the, throughout the day. You know, during the day, the load, maybe some generators come on and off. At this point, the only way ERCOT was able to allow any extra load to come on the system as extra generation came on the system. So the orange line in the middle is our load shed requirement. Here on Monday evening, it peaked at 100 megawatts. So, and as you can see, the blue spike was the 230 megawatts that it took for us to roll on the next 100 megawatt block. So as the situation improved over the 59 hours, you can see the line trending down. But this just shows one of our, one of our accomplishments that I, that I'll wrap up my presentation with. We never stopped rotating outages, regardless of what the load shed requirement was. Our next graph here is just that prioritization that I spoke of, of our load that this details that out. Our 17 feeders that serve our critical load, they were not rotated. So, and then as we prioritized our circuit, you see, we had to get right up to the, right up to those 17 circuits, but we were able to, to, to rotate the frequency. We were able to minimize the frequency rotation of our critical customers based on the amount of load shed instructions we had from ERCOT. And on the right is our load shed feeders that were originally designed. They carried the bulk of our rotating bulk of the, of the workload in meeting our load shed requirements for this event. So onto another type of outage. So systems really weren't meant to be rotated on and off as, as we were required to do. So especially with the temperatures that we were facing. So this graph details our, our fuse overload. So out on our system, we have some protective devices. They're usually saved for squirrel suicides. But basically they're, they're, they're a dumb protective device that's, that's meant to melt out at a certain power load. So it's like the old fuses you would have in your car or maybe a circuit breaker at your house. Their segment, the circuit out so that if there's a fault at one part, that fuse melts out and protects the rest of the circuit. At that point, we normally have an outage management system. We would know that we would roll a truck that replaced the fuses and the power comes back on. So I know, especially the PB talking about our reliability reports, we give you the bulk of those are our outages that are repaired in 35 to 45 minutes. Those are fuse replacements. But the issue we had during the rotating outages is if you can imagine your house and I'm sure everybody was setting through that when your power was out for an hour, you're setting there and then power is restored to your circuit. All of your electrical devices came on at once. So that's the same for your neighbors. That's the same for, for every one of our customers on our, on our circuits. Now while we were able to handle the neighborhoods that predominantly had gas heat, the electrical demand on those was much lower. Our neighborhoods that had a lot of electric heat, we struggled with that. So every time we would pick that circuit back up, the cold load pickup or the additional load of all of the electrical devices coming on at once was burning out our fuses. So this graph represents the 172 phone calls that we received because people were letting us know their power was out. We were able to verify that a lot of those, they were voicemails, that their power was just in a rotating outage and it came back on. But actually 47 of those calls were fuse burnouts and or transformers. And we rolled a service truck to get those, those customers back on. So now on to our field operations. These are the, our line and substation field crews. These are the men and women that, that replaced all of those fuses and replaced transformers. And, and so in knowing, we didn't foresee the rolling outages, but what we did foresee is the NOAA forecast that, that called for some freezing rain that would precede the snow that we're going to receive on Sunday. That's a very, that's a very treacherous travel condition for our staff. That, and also the freezing rain is, is, is, they're much like tornadoes are to, to the electric utility. They're very hard on your aerial equipment. The ice builds up and puts a substantial amount of weight on your, on your lines and your poles. So knowing that was coming, we actually brought some DME crews into Denton and we staged them in a hotel near, near our yard so that they could quickly respond to any outages. We placed, we told all field personnel were put on notice to be available for storm response. And due to the sub-zero temps and the forecasted windshields of minus 10 to minus 15, we canceled all non-outage operations. And finally, our winter storm event kicked off for us on Sunday evening. We had a piece of underground con or conductor fail that ended up tripping off a one of our substation power transformers. And this led to an outage in a subdivision that ended up being our most difficult to recover. And I'll speak about that a little later in the presentation. So the rolling outages, as I've mentioned, they commenced at 1 20 a.m. on Monday, February 15th. And as I just spoke, spoke, spoke to the rolling outages during the extreme low temperatures caused numerous equipment failures. That's the cold load pickup. And that's a topic that I'll keep talking about that caused us quite a bit of issue. So our effort from our, from our staff took 55, 55 of our staff coming from our maintenance, construction, substation and metering groups that began working Sunday evening around the clock and continued working in shifts up to 16 hours for the duration of the event. The primary work they performed was fuse and transformer replacement. After the rolling outages come back on, customers and notify us their power was out. We verify that and then we had to go get them back on. And again, our staff who did a wonderful job through this worked about 174 calls during the storm event. On to engineering. Our two systems, our transmission system, as you can imagine, performed quite well with the amount of load shed that was on the grid. The transmission system was not stressed at all. And our transmission voltage was maintained for the duration of the event. Our distribution system, we had two all electric subdivisions that were on individual feeders, the village of Carmel. That's the outage that kicked off the our response on Sunday evening. The circuit is primarily electric heat. So when we energize the circuit for both of these two subdivisions, we were unable to pick those circuits up. Our guys worked very diligently. We actually end up having to segment the circuit in the field and bring it on a little bit at a time. But once we did that, we could get some heat back in those houses. We could better manage that situation. 11 distribution transformers failed. Probable cause was overloading again for that cold load pickup, the sudden inrush of power when we were to energize the circuit. Engineering. So as you've seen, we had a plan for 30 megawatts for our load shed that quickly went out the window. So on the fly Monday morning, engineering developed tools for our system operators to manage to be able to allow to spread those rotating outages amongst our 90 remaining feeders. So that tool was invaluable. And that's what our operators used to get us through this event. They provided recommendations for load switching and subdivision load balancing again, primarily for those two subdivisions that I previously mentioned. We had an issue with the Lake Louisville water intake facility. So that's the raw water supply for the Lake Louisville water treatment plant. We actually it's down on the North shore of Lake Louisville down by the I-35 bridge. We actually power that from our system. So we have a circuit that runs all the way down by the DCTA through Corinth to the water treatment plant. We began noticing some phase imbalance measurements on our SCADA system. And so that that's an indication that something was not right. So while the the pumps were still running, we had a power quality issue. We worked with our colleagues at the at the water intake facility. We actually were able to take this facility offline, two brief moments to try to troubleshoot the transformer to try to figure out what the issue was. We weren't able to do that. We brought them back on. They ran the night and it sun up. One of our crews actually found a damaged switch. It's in a remote part of the circuit on Swisher Road down behind the QT. And that was causing our issue. We were able to quickly get a jumper on that and restore the the power quality to to the facility. And finally, engineering helped provide, as you can imagine, there was we generated a lot of rolling outage data through this event. And they they helped our system ops pull that into one one source. Our business services, as you could imagine, our key customers were really affected by this event, as our emergency load shed features are our primarily our residential and small commercial customers. Their their electrical equipment at their house is better suited for a rolling outage. So your house other than the code load pickup, most of your appliances are not affected by this. Whereas you have sensitive electronics, you have large motors, they just cannot work through a rotating power outage. So our customers started calling. We contacted them. They contacted us. Many of these customers were notated were notified that they would have gas curtailment was a possibility. So these customers shown here, they let us know that they were not going to be a full operation or any operation during the duration of this event. So what that did was basically a demand response load shed that helped that helped the grid by keeping these customers or our large portion of our load. I should also note that's not on here, but the target distribution center out by the airport is 100% automated facility. So we were getting calls from them, our load, our rotating outages were giving them fits. So there they were basically bringing their operation to a standstill. And they actually proposed an idea if we could come cut them loose from the grid, they could run on their generators and, and provide minimal service, minimum business function for their facility. So we accommodated them, we went out, we disconnected the transformer, they ran on their generator towards the end of the event, they gave us a call, we, we hooked them back up. We've since had some meetings with them to see how, if this was to ever happen again, how we could better work together through that situation. Customer outreach, we utilize the social media, both the DME, Twitter and the city social media accounts to communicate the request for conservation. This was prior to the event, and to relay ERCOT's current emergency levels. We also began we have some canned messages that we began sending out the week before any any winter storm saying, you know, take precautions, have water ready, that sort of stuff. So we got that information out. And another thing is that that kind of evolved during the event is a lot of people use Twitter. So we were able to be notified of a lot of power outages via Twitter, which took some stress off of our utility dispatchers who are in unindated with phone calls, as you can imagine. The last issue here is the energy management back office. As Terry will detail here a little bit later. That's the the function where they settle our collateral invoice payments with ERCOT. As Terry will mention ERCOT is kind of like a prepay system. So nobody's extended any credit. You have to have the money in place before you actually use the electricity. So they were very busy working with DME management and city finance during these unprecedented times to make sure that we we met all of our ERCOT obligations. Regulatory and compliance, our main issues were system reliability and cybersecurity. And I'll start with here that this this next bullet point is transmission operators, requirement five of the NERC. Again, that's National Electric Rock North American Electric Reliability Council. Rule five states that each transmission operator, generator operator, and distribution provider shall comply with each operating instruction issued by its balancing authority. And in this case, the balancing authority for the Texas grid is ERCOT. So we were all three of those. And we were by this requirement, we were obligated to comply with those instructions. Our operators did. We complied with all ERCOT load shed instructions, both to add load and to remove load during the duration of the event. And therefore, with the excellent performance of our system operators, there were no observable violations of the NERC requirements. And again, thank you for the patience. This is the last slide. So just giving giving you a heads up. So challenges, communications were a big challenge for us. Our utility dispatchers and system operators filled at almost 9000 phone calls the week of February the 13th. Our normal monthly call volume is about 2100 calls. So they were on the phone constantly, you know, customers looking for information. When is this outage going to end? Why is it going on? Just a lot of questions that that we couldn't ask. So communications with our customers and from our customers was a challenge. And also the this event also brought to light that a lot of our customers that had sensitive electrical needs were they probably needed on interruptible electricity did not have backup generators. So therefore, they solely relied on grid power. And we weren't able to provide that around the clock. Critical infrastructure and customer identification process, we identified some of our critical infrastructure customers by them giving us a call saying, Hey, why'd you cut my power off? We didn't know you were there. So that was a a that was a learning curve for us. And I'll get to how we dealt with that on on the success side. The extreme cold temperatures provided a very harsh work environment for our staff, as well as our equipment. The majority of our equipment is diesel powered and it's tough to get diesel engine started at five below our outage processing technology. That is our outage management system that our system operators use to manage the grid. When we initiated the rolling outages, it was not designed for that and it crashed. So during the remainder of the of the storm event, we utilize legal pads, pins and sticky notes. That's how we managed the outage. And again, I'll skip down the load shed feeder and load tracking. Our skater system was functional the whole time. But as I mentioned, we have 107 feeders. So knowing the status of any of those feeders at any one time, it's a daunting task. So we've had operators working 12 hours, who have, you know, done 12 or 14 of these rotating outages. When we handed that off to the the next shift operators, we we dropped a couple circuits. So we made a mistake. Those circuits experience outages longer than they needed. But we were able to identify our error and we actually came up with an audit system pretty quickly so that the the shift that was coming on could audit the previous the previous load shed and identify the status of all feeders. And we eliminated that we eliminated that error. And again, I think I've mentioned that five times a cold load pickup was a was it was a struggle for us. Successes. I bolded the first two statements. The first is, we maintain the ERCOT interconnect. I cannot overemphasize the misery that would have bestowed all 24 million Texans if the if the grid would have failed. As I mentioned, you know, you're looking at some of the coldest temperatures ever recorded in Texas, all the way down to South Padre. And I'm definitely sure we would not have gotten the power back on for those five days that the extreme cold temperatures were here. So we were a part of that. We did our part as well as our other our colleagues that operate the grid. So that was one of our bigger successes. On a more local success note, we maintain the rotating outages as the aftermath of this says has been discussed. As far as I know, we're the largest, we're the only utility of our size or larger that maintain rotating outages for the duration of the event. Now, this was a major inconvenience for our customers. But what it did do was allow us to keep heat in these houses by taking whatever power we had allocated for us. And we're able to spread that amongst all of our customers. I'm fortunate enough not to have DME power, I have Encore, I did not have power for 90 hours. So it's it's a, that's a big, that's a big deal. It took a lot of creative thinking. And it took a lot of hard work by our staff to be able to maintain those rotating outages. And I'm very proud that we were able to do that. As Tony mentioned earlier, we provided some affected critical care customers that weren't prepared. So we answered phone calls, an elderly gentleman, he did not want 911. He did not want to go to the warming center. But he had some equipment that he says wasn't charging correctly. Our lineman grabbed a small generator and extension cord, drove to his house, plugged his equipment in and charged it. So there's lots of there's lots of stories about that. That's what I said, I never knew what the next hour was going to, to was going to have in, in, in, in store for us. But but we just tackled those as they came along. We had a couple customers had some equipment, hey, can you give us an extra rotation cycle, and I think we'll be good. So we were able to accommodate those type of requests through the duration of the event kind of on a one off basis. One of our success stories is as we identified, as Tony mentioned, a dialysis clinic that we didn't know was there. Doctor left us a message we gave him a call. Hey, I have 50 patients that have to have this treatment. If not, they have to go into the hospital. Is there anything you can do? I don't have a generator backup. We were able to work with the doctor so that he we could give him a time slot allocated during the day that we would not rotate his circuits. He could get all of his patients their their treatment. And then that circuit would roll in over the night hours back into the rotation. So again, that was we were able to get those those patients their their needed treatment. We and we maintained our critical services for our citizens. So again, I stated a couple times the hospitals, Fire Department, Police Department utilities did not lose electricity. And finally, as we started out our original plan of 30 minutes, through some feedback from our customers, it was not adequate. They were their houses were getting colder beach rotation. So we're able to adjust that to 45 minutes, which seemed to seem to alleviate those, those cooling of those houses. So with that, I made it to the end and I'd be glad to answer any questions. Thank you, Chris, if you could pull the slide down for us. And council members and board members, what I'll do, I'll just kind of remind us real quickly of the topics that Chris covered. We have quite a few topics left to be covered by other presenters. So be careful just to contain our questions to what Chris just covered for us. There'll be lots of time to ask questions later about other items. He told us about utility dispatch and operations, field operations, engineering and customer relations, and regulatory compliance. And then folks who are just turning tuning in now, if you don't hear questions on other topics right away, that's because we're going to get to those topics in just a little while. Also, if y'all have more than say three questions, if you could hold on to those, I'll ask you to ask maybe your first three questions for each presenter. And then we'll kind of go through the rotation and we'll come back around for anything after that just to make sure everybody has a chance. So I see Mr. Ryback has a hand up. Lee, if you could go ahead and ask your questions. - Yes, sir. I just wanted to get clarification from Chris about this duration of the event of the 59.3 Hertz. I know that was just a small data point and everything you've covered. Could you clarify a little bit more about that particular trough, if you will, and the performance of the grid? - Yes, sir. So at that point, that was the 59.4 that the generators can only operate below that frequency for nine minutes. So I believe the duration that that trough represents was four minutes and 23 seconds. So if you'll notice in there, there was a big load shed block of about 3000 megawatts that seemed to do the trick and turn the tide. And as the frequency began to recover and exited that 59.4 and began to recover at that point. - Thank you. - Yes, sir. - Other questions? Council Member Meltzer. I've commented repeatedly prior to this meeting about how outstanding DME staff was. Thank you for giving people greater insight into that. I have a kind of a hypothetical question I'm asking on behalf of some members of the public who wonder about this. Some people believe because they were told by city officials at that time, mostly people who are not with the city, that the deck was meant to cover us when renewable power wasn't adequate. And that I'll actually quote from a Renewable Denton presentation, "We need to secure reliable source of dispatchable on-demand power, something that can ramp up and down quickly in response to renewable variability." So not in response to ERCOT prices. I mean ERCOT grid was mentioned probably very hard to explain to the public, but a lot of people believe that our plant should have protected so we wouldn't have had to do rolling blackouts. I'm just, the hypothetical is if in a world that we don't live in, the plant was functioning the way people were led to believe and just serving Denton, given that we had our own outage, would we have avoided rolling blackouts or what would the consequence have been if we were just responding to our own outage rather than the broad state of energy supply in Texas. Yes, sir. Council Member Meltzer, thank you for the question. And Mr. Terry Nalti is going to hop on here and provide you an answer. Yes. Can you hear me? Yeah. Okay. Council Member Meltzer, so with regard to the Denton Energy Center being available to serve the load of the city of Denton, I think while I understand your concern and perhaps that was a message that was delivered at some point in the past, what's curious to me is that all during the discussions of the Denton Energy Center, Denton and the ERCOT market existed. And in that market paradigm, there is no way that a single unit can be used to serve a load of an individual city. It must be injected into the market and you must purchase your energy from the market. And as I'll get into in my presentation later, the mechanics of the market are set up that way so that as a member of ERCOT, we're able to use the transmission grid to move power from remote power facilities to serve the load of the rest of the market at the lowest cost. And so I would just say that if that was a statement, then it was probably incorrect. It was incorrect. And that potential never existed. Secondly, local outages are dealt with the same way as a large outage as we just experienced in that when we have a local outage, Chris's crews are dispatched to go out and make changes to the distribution or transmission system in the locality around Denton in order to try to remedy that outage. ERCOT does not have employees that are dispatched out to make repairs to the grid. Each of the members of ERCOT provide those services for their own transmission system and for their own distribution system. Does that answer your question, sir? Well, partly. I mean, first of all, I think it's helpful that we're just because we need the public to trust us on so many things, especially on this topic. There's a lot that they've had to just endure and there's more to come. So the public needs to know that we're dealing as openly and forthrightly as possible. So I think acknowledging that the tech wasn't presented in a way that mirrors the reality at the time even is important. But I'm really asking for help responding to questions I get to say, well, even though you and I both know it's counterfactual, you can't have the plant just support us. It doesn't work that way. We're backed up by the grid. But the question that I get is, but if it could, would that have worked? Would we have not had outages? And I think the fact of the matter is we had an outage ourselves. So in that hypothetical world, that would have had some consequences, too. And I was looking for an opinion on what would that have been? And just before you try to respond, if you can, I accept on just logic that we're more secure backed up, except in this one week. Theoretically, we're more secure being backed up by all the production in Texas than by being backed up by just one plant. So I'm not questioning that. But some people do. So I'm looking for your opinion of if that were the case, it did function the way we know it couldn't, wouldn't there have been consequences too? Yes, sir. So the Denton Energy Center, as you know, is a 225 megawatt facility and had it been available to run and assuming that hypothetically, it was only connected to the load of Denton, it would have been able to serve up to 225 megawatts of load. And as Chris has indicated, the peak load was 325 megawatts. So we would still have had outages in the market in in the Denton area. And as you properly point out, when we lost gas pressure at the facility, and it went away, we would have had no power at all zero power for the community. Okay, thanks. I appreciate that. Thanks for clarifying all that. Just a quick little follow up on that before we take the next question. I just want to clarify for folks watching and anyone here on the panel that no one that's presenting to us today was or the personnel who are presenting the deck, the Denton Energy Center back in 2016. And also point out Councilmember Meltzer, I'm looking at the slide you just read from slide number two of the renewable Denton slides. And there's nothing in the statement you read that says this plant will be for Denton. It speaks in a very broad terms, it speaks in renewable energy, broadly, whether or not someone interpreted that way, or whether or not in another conversation, even a private conversation, it was presented that way. In just the statement that you read, there's nothing in that statement that says to ramp up specifically Denton or to supplement specifically Denton's renewables. No, I mean, if you'll allow me to respond, this is not it's not that productive for us to talk about, you know, too long for about what was said several years ago. But I assure you, you will not find even the mention of the existence of a grid or ERCOT. I don't think that that concept was was explained. So it's the really the only, you know, reasonable conclusion to the general public. But you know, I'm satisfied that we've, you know, brought up the point. And it is a source of why members of the public are confused. And hopefully now we've addressed that. Sure, I think that's I think that's a fair enough point. Just when we get to the next portion when Terry presents, I think it's important to keep the full context of that conversation in mind, what public perception was, what the actual message conveyed was, they very well may have been two different things. Other questions for Chris's portion of the presentation. Councilmember Ryan. Thank you. Just for for public knowledge, a lot of people think that if they didn't lose power during the storm, it's because they were on a hospital circuit. And we have a lot of water and wastewater infrastructure throughout the city that if we've got 107 feeders, on average, Chris, how many homes would that look like? For per circuit? Well, we can do some quick math there, Councilmember Ryan, as we looked at our data through the through the winter event here, our all electric homes, we were averaging about 157 homes or customers per megawatt. For our gas heat areas, that number was close to 250 homes per megawatt. So if you look at 200, and we have eight megawatts per feeder, you're talking about 1600, roughly 1600 homes per feeder, just customers per feeder would be a ballpark. And I bring that up simply because I had a couple of people who live close to a lift station that thought that they were on a hospital circuit when they were four miles away from a hospital. So there are other items that are out there that we did keep on that are necessary to, you know, lift stations, you definitely don't want going down during that type of a storm, either. Yes, sir, that that's correct. And as again, that that mentioned that plan is confidential, but there's 17 17 feeders out there that supply that that infrastructure, and we have two major hospitals. So as you can see, there's there's there's a handful of circuits that aren't connected to the hospital that aren't providing power to other critical loads. And as I mentioned, we can't pick and choose which customers on a circuit that we can, that can we can remove power from. So yeah, we have some, you know, some customers that maybe as as one side of the street is one circuit, the other side of the street is the other circuit. And I know that was a point of contention was they might have been on a critical circuit, and they're powered and go off, whereas across the street was a different circuit. So that that that kind of explains that. But yes, there are other facilities, fire stations, the water treatment plants that were that were on that critical list that they they remained on during the event. Okay, any other questions for Chris? I just go ahead. I see. Do I hear somebody? Councilmember Johnson's at you? Yeah, good. Go ahead. I heard him say that during the during that time, there was a target was called out called them out, and they were released from the grid, because they had generators to back them up for a certain amount of time. Is that possibly something that we could all different places could consider that would make it a lighter for the load that perhaps if we were in this situation again, I mean, customer Johnson, they had specialized equipment and the way they were set up is if their their switches detected grid power, that their generator generators would not come on. There are there are facilities in in in Denton that have backup generators, where they fell over, they lose power and that generator automatically automatically comes on. So that technology is out there. That was a very unique situation to disconnect someone from the utility grid. But that was the only way the way their system was designed. That's the only way they could run solely off of their generators was to remove the our source of power from their facility. Okay, other questions for Chris? Chris, I've just got a couple myself. Is it possible for someone to know, you know, the big joke kind of going around social media after this was used to want to know if the house you're buying was in a good school zone or not. Now you want to know if you're on a hospital feeder or not. Is it possible, given the confidentiality of some of the stuff you described for us, for people to know if they're on a lift station feeder, if they're on a hospital feeder or something like that? No, sir, there is not that again, that that plan is confidential. Probably got a lot of just real real world knowledge during this event. But one thing that I have to stress is our grid is is it's not static, it's dynamic. So I mentioned those connection points. So just because you're on this circuit, you know, at this point doesn't mean you're going to be on there. Next year, we may have a configuration change. There may be a new development come in that's outside of you that we have to rework things. So it doesn't necessarily mean you stay on the same circuit. But but generally, I think, speaking the hypothetically, if your power did not go out during this outage, as I noted that every circuit on our system other than our critical circuits were rotated, that could probably give those those customers an idea if they're on one of those circuits or not as of today. Okay. And I know you described for some of the challenges in in rotating those outages and keeping track of which circuits have been hit and which ones hadn't. Can you tell us anything about the the criteria you use to make those decisions? We know that that load shed plan is confidential and confidential for a reason. But can you tell us a little bit about some of the criteria that went into those decisions? As far as when we rotated or how we rotated the circuits? Sure, you know, I think there are probably a lot of folks who incorrectly believe you're just throwing darts at a map, you know, and that's the circuit that goes out next. Can you tell us just a little bit more detail? Besides just, you know, we tried not to cut the critical circuits. And there were some that we you told us about the doctor's dialysis clinic that you scheduled. Can you tell us a little bit more about what some of our residential customers were experiencing? Yes, sir, I can. So what our operators were tasked with doing is, as I mentioned, we had two blocks. So we had an A and a B. So when we initially started the load shed event, we were when we were in our plan. And at that point, you would have had those circuits would have had 30 minutes on and then theoretically 30 minutes off. Now, there was a transition. It takes about 15 minutes for our operators to actually remove the the the load that is on and replace it with the with the next block. So that was our criteria is we is to alternate an on cycle with an off cycle for our for our feeders. And then that was determined. So operators will go with the hundred the hundred megawatt load shed. So ERCOT calls in and says who you're instructed to shed one hundred megawatts of your load. Now you acknowledge that at that point, whatever your system load is at that point, you must remove one hundred megawatts. So as I mentioned, our feeders tend to have, you know, five megawatts to eight megawatts on it. So we had to identify as close as we could the feeders that totaled one hundred megawatts. We remove those from the system. So now they're in there. They're in their outage cycle. And while we were doing that, we had to identify the next grouping of circuits that totaled one hundred megawatts. So at that point, we didn't look at at neighborhoods or locations or anything. The circuits became solely a megawatt value. And it was like a puzzle you had to put together. What what you could shed or which combination of circuits that were available. So the one that was just had their power off, they're back on, they're not available now. So then it left. That's the tool that I spoke to that engineering was able to make for us is, hey, these these available circuits are what I have to choose from. And let's total up what our load shed requirement is. And then another part of the struggle was if we had a circuit and we take its five megawatts and we take that circuit off and it's now out of power for an hour and we bring it back on, that five megawatts is now seven megawatts. So to bring that circuit back on, we had to count it as three because when we energize that circuit is actually going to be a higher value. So basically and this was a manual process, tried tried to spread out the rotations amongst all the feeders in a very systematic manner. But basically it was driven by the load shed instruction and the feeders that were available that totaled that load shed instruction. Thank you. And I think I might have seen board member Davini's hand just a moment ago. I have a sort of rookie question that has to do with the target as member Johnson's asked. If a large a large customer like Target can disconnect from the grid, is there a way for an individual customer to disconnect from the grid if they have rooftop solar? I have a bunch of friends with rooftop solar whose solar did nothing because the grid was was shut down. Is there a way of for people to generate their own electricity if they have and if you've got an acre of land, you can also have your own wind turbine. So is there a way for individuals to generate other than with a, you know, a diesel generator or something like that? Well, thank you for the question. It's a very good question. As of now, there is not. So our our solar rooftop solar customers, the 600 or so we have on our system, they are interconnected to the grid by an IEEE standard. So that's an electrical trade association that kind of sets the rules. So the reason that that's in place is for the safety of our linemen. So if the power is disconnected, those solar panels are interconnected to the grid. And if they were to produce excess, excess electricity that was not utilized by the resident, that power would flow through the transformer and would energize the line. So as of now for rooftop solar, that is not an option. I have tasked our engineering department to take a look at that. Is there something out there that could basically is called islanding would island the the the solar the the solar generation for that resident and only provide power to that to that resident? I don't believe that's that's what you're speaking. Now we do have quite a few customers on our grid that have generators that can run in a called a standalone mode where they can power the house while connected to the to the grid. So we were looking at that. I was pretty sure that was going to be a question. But as of now, the interconnection standard for that is no. And the reason is because those customers have the ability to sell or push that power back on to the grid by design, whereas people have backup generators are not looking to sell that power. They're looking to power their their home and during a power outage. That's kind of the separation in those those two situations. But we are looking into it. Thank you, Chair Parker. First of all, I think you did a tremendous job with that 59 hours is miserable for all of us. But could you tell us hypothetically if we did not perform the way we did with the rolling outages, what could have been the outcome from NERC and ERCOT? The fine there's a monetary fine that could be imposed for not following the instructions. I think I've heard the it's it's capped at a million dollars a day. Could it could be the fine that would be imposed on you by not only NERC, but ERCOT. But but there was a again, there was a moral obligation for us to comply. So the bigger picture was we had the inconvenience a lot of our customers with the rotating outage. And, you know, you saw that fraction were half a percent. Encore is 35%. So of that 20,000 megawatts, they had 7000 megawatts, if they would have said now, we're not going to answer the call to ERCOT, we're not going to shed that load. The grid would have crashed, there would have been a blackout situation. And again, then all 24 million Texans would have been without power. So there was both the the regulatory reasons and then it was the right thing to do is to comply with those ERCOT instructions. Councilmember Armitage. Yeah, to speak to what you just said, I mean, a fine of million dollars a day would have been a savings for the city of that were the only consequence. But like you said, it was nowhere part of a network that holds up the whole state of Texas. So I have two related questions. One about battery storage. And these are forward looking questions. And another about the the national grid versus ERCOT. If we had had, you know, utility scale battery storage for our generating facility, would that or to what extent, you know, would that have helped both the the city and the grid in a crisis like that? I realize it would not solve the problem. But I'm wondering kind of how that works when you've got battery municipal battery storage, how that works as far as low load shedding demands in a situation like that. And secondly, you know, as a lot of people are asking, if it's my understanding that we're we're Texas, you know, or an individual city hooked up to the national grid that this would not have been an issue because of, you know, just as Denton has back up through the grid, through ERCOT, the national grid provides an even even greater backup system that's also more heavily regulated. So I was wondering if you could just, you know, you don't have to go into length of that. I realize that there are a number of factors that would complicate individual cities getting on the grid. But if you could just, you know, confirm that latter point about the national grid and, you know, give whatever specifics you can moving forward about municipal utility scale battery storage. Thanks. Thank you, Councilmember Armitage. I can speak to your second question a little more confidently than I can the first one. I believe if there say there was out at the deck facility, we have some utility scale, which you would be talking megawatt hour battery storage, I believe that would be considered a generating asset. So that those those that electricity would be generated that would be put onto the grid from that batteries would be treated just like it came from the deck. So it'd be part of that market. So I think it would have would have if you had theoretically had enough of it, any extra generation that would have been put on the grid would have been additional load shed that would have not been required. So if you can think of that at that point, secondly, personal batteries. So if you would have had a say you had a battery in your home, that storage, that capacity, that's not the same thing. So that would have helped with the rotating outages for the individual customers that had a battery storage at their at their at their residence. So if I think if that answers the question, I'm going to let Mr. Nalty tackle the your first question. Thank you. Yes, thank you. So first, battery storage, just a little bit more on what Chris said, you know, typically battery storage is a is a short duration resource. And this event lasted five days. So the longest batteries would be four hours of storage and would have only provided backup or additional generation, if you will, for about a four hour period. And I think as you Councilmember armature recall from the last time we we brought such a proposal in front of you, the economics of batteries at this point are not they just aren't cost effective relative to to others. Now, maybe this event might change that a little bit, but we'll have to see. With regard to your question about interconnecting to the other grid, so there are two additional grids that ERCOT could interconnect with. One is the Western Energy wholesale market, and the other is the Midwest ISO. It's actually a third the SPP. In, in the event that an individual city wanted to interconnect with one of those, we would have to physically build a line from our system to that system. And for us in Denton, it would the closest would be into Oklahoma somewhere. That process would take at least 10 years to do because of all of the Federal Energy Regulatory Commission regulations as well as the siting of the line and permitting. You would never want to have a single point of interconnection, you'd always want to have two. So you'd have to run not just one, but two lines to two desperate, disparate points in the grid to interconnect with to have the level of reliability that you would want to have. And then just wanted to follow up on your question about the fines. You know, you think about the fines at a million dollars a day. That million dollars a day would be on top of the adverse economic consequences that we suffered as a result of the loss of the deck. And then as you'll see the underperformance of our renewable assets. So to think that we would be able to actually mitigate damages as a result of paying fines, I think is is a little far fetched. And I'd be careful to try to make sure that the public doesn't believe that that's something from a from a from a just from a behavioral perspective as being a participant in ERCOT and understanding that we as a as a member of ERCOT have an obligation to follow the rules because we do get the benefits of the marketplace. And, you know, I would I would strongly recommend such an approach. And thank you just to follow up. I was trying to make precisely that point maybe sloppily. But my point being, I understand it. You know, people might be thinking that. But that really is not not an ethical option or a feasible one. So I understand. I very well understand that you go. Any other questions on kind of the operation side of things? We'll have a presentation next on the financial side of things. Some on the deck. But anything else on operations rolling outage is that kind of thing. OK, the next portion is going to be pretty involved and have a lot of information. And I imagine a robust conversation following. So we're going to take a short break about five minutes and we'll come back at one o'clock to continue the meeting. Thank you, Mayor Pro Tem. Welcome back, everyone. Good afternoon. This is a joint meeting of the Denton City Council and Public Utilities Board. We're going to hear next from Terry Nolte from DME, and he's going to cover the topics of energy management, the Dent Energy Center, mitigation measures and ERCOP market reforms. We're going to have opportunity for questions at the break. And I believe Mayor Hutzbeth will be joining us as we go through this presentation. So it will be his face you see next. And Terry, it's to you. Thank you, Mayor Pro Tem. And good afternoon, Chair Parker, members of the PUB and members of council. I'm going to ask your indulgence today as I am actually going to read through a script that I've put together for these slides, because I want to make sure that I'm covering all the information and not missing anything. So with that, I'm going to pull up the presentation. Okay. Winter Storm Uri, which was the name of the named storm that impacted ERCOT and the Texas markets several weeks ago was an unprecedented record storm that has brought to light the magnitude of the risks that all electric generation and load serving entities face. The intensity and duration of the storm coupled with market design flaws, lack of regulatory intervention, unprecedented demand for natural gas resulted in rolling outages, loss of life, billions in property damages, and as I will report here, significant unexpected power supply expenses that will ultimately have impacts to our customer owners. This presentation will briefly put Uri in perspective relative to other storm events to show you how abnormal the weather event was. I'll then provide you with the measures that DME had in place to manage the power supply price risk and provide you with our current estimate of the financial impacts. I'll then discuss the evaluations that are underway to mitigate the financial impacts of future storm events, discuss some high level ERCOT reforms that we believe are needed, and finally answer questions that you may have. While this discussion will look prospectively at ways to implement measures to prevent future economic risks, I want to be clear that despite the measures that DME will recommend today and in the future, without significant market reforms, the potential for rotating outages across all of ERCOT will remain. Initial efforts that the electric and gas industry are taking are aimed at providing earlier warning of potential events that could result in outages due to lack of electric supply and to identify where better coordination between the electric and natural gas industries have the potential to lessen the probability and duration of a recurrence. Typically, the third week in February has a temperature range of 37 to 60 degrees in Denton. The three days from February 14 to February 16 were the coldest three consecutive days in recorded history. From an electric demand perspective, the eight days from the 13th to 21st saw 42% more electric demand in Denton than average, and had the rolling outages not occurred, demand would have been 70% higher than normal. Needless to say, our forecasting tools failed to predict these high demands as the storm predictions became stronger on Friday the 12th. We took additional price protection actions on that day. For the ERCOT market, the financial impacts were nothing short of a disaster. In eight days, the cost of energy and ancillary services exceeded the prior 11 years combined. And as you have heard and will see later on, DME was significantly impacted by the sustained maximum wholesale energy price of $9,000 per megawatt hour. I think it's safe to say that no one envisioned wholesale electric market prices at the max cap for as long as it did. And these events have transformed our view as well as that of the rest of the market participants. The key conclusions I draw from what happened in the ERCOT wholesale market are that first, the ERCOT generation portfolio is fragile, with over-reliance on intermittent renewable resources that during the last two price excursions have not shown up. Secondly, the market design is fundamentally flawed without sufficient economic incentives to attract dispatchable generation and reserve capacity despite the $9,000 price cap. In fact, historical market price formation has resulted in retirements of baseload capacity that could have provided the needed reserves to have saved many lives and the economic devastation. That said, this is not a phenomena that is unique to ERCOT. Third, price volatility is likely to increase if continued development of intermittent resources with no ability for these resources to operate when they are needed most. We have all heard legislators and uninformed individuals make claims that DME was unhedged and that DME did not have the ability to participate in the futures markets. I can categorically state that those claims are untrue. As you know, DME has an energy risk management policy that is brought before the PUB and Council each year for approval. That policy provides the necessary authority for the city manager, the DME general manager, and DME staff to execute hedge transactions consistent with the policy. Further, within the policy is a hedge plan that is updated each year based upon market conditions. The objective of the hedge plan, implemented through the authority you grant us under the energy risk management policy, is to control the cost of purchase power within a range for budget and rate certainty purposes. The hedge plan is premised upon weather normalized load forecast, renewable energy outputs, and futures prices for electric and natural gas. While there is a band around the weather normalized load forecast, in no way does it permit DME to speculate on weather events that are outside a reasonable level of a probability of occurrence. URI was well outside those limits. Going into the storm, DME was in compliance with the limits of the energy risk management plan and the hedge plan. Compliance with this hedge plan is measured and reported by DME's risk management group, who act as an independent auditor of the performance of DME's energy management organization. The hedge plan is based upon monthly granularity, and inside the month, the energy management organization has the ability to optimize hedges to adjust them for real-time market and weather conditions. In the case of URI, additional financial hedges were placed on Thursday and Friday prior to the storm. The additional hedging actions performed as designed, and contributed to over $23 million in positive value. Normally, the weather or wind forecast change rapidly. Normally, when the weather or wind forecast change rapidly, the EMO has the ability to take price hedging actions during the storm. But in this particular case, on the 15th of February was a bank holiday. The natural gas and electric markets were not open, and trades on Thursday of the prior week were for four days, Saturday through Tuesday. By the time Tuesday arrived, the market was trading at the maximum cap for the rest of the week, and no additional risk management trades were available. According to the risk management plan that DME uses is the Denton Energy Center as a hedge to the intermittency of our renewables. This asset acts as a hedge against high prices by starting up in five minutes and offsetting the cost of energy purchase for load. As you will see, wind and solar resources, which are also hedges to our short load position, did not perform. Thus, as designed, we relied upon the deck to cover the shortfall of energy not generated by the renewables. As we have entered into more solar power purchase agreements, and given the high wind output that is expected at night from our wind power purchase agreements, when there is no wind at night, we count on the deck to provide the hedge. As you know, we lost natural gas pressure and consequently our deck hedge for almost two days, and thus we were buying at the maximum cap of $9,000 per megawatt hour at the same time our load was the highest at night. A quick review of the current DME power supply portfolio is presented here. The important point to understand is that our supply position is 610 megawatts, and our normal season demand position in February is 170 megawatts. While this may seem like way too much surplus, when the renewable power purchase agreements are adjusted for the weather and normalized output, the predictable capacity is significantly lower. Also on this slide is the actual demand versus the normal demand for this time of year, and as you can see, the demand was 140% of the normal levels. Now, this is a complicated chart, but it tells the story in one picture, and I'm going to walk through it with you quickly. I'm sorry, this is not the complicated one. This is actually a pretty easy one. Slide 6 here for me. Here we see the normal load profile on a February day in blue, and now we superimpose the actual load that showed up, and you can see it was significantly higher than normal, especially the first two days. That would be Saturday and Sunday. Monday is where you see the load reductions or the rolling outages took place right here. Finally, we look at the demand, what it would have been had the load shedding event not taken place. Here you see that the peak demand would have been 400 megawatts, which would have been an all-time new peak for DME. This will change our plans for our overall energy supply as we go forward. I have alluded to the lack of intermittent renewable energy generation throughout the event. This slide shows you the variability in the forecast of wind, and in the aircott market, the wind is very important, and it's a very low-cost resource. When it doesn't show up, it usually means we're going to have shortages. The chart shows the predictions of the market from Thursday the 11th to the end of the event on Friday, and I'm going to click through the on-peak and off-peak forecast. We divide the market into the on-peak, which is the daylight hours, through 11 p.m., and then the off-peak, which is 11 p.m. to 7 a.m. Here you see the low end of the off-peak output, and this blue line represents the off-peak high estimate that came in from ERCOT. It would be above 10,000 megawatts of wind that would have showed up Thursday through Monday, with Tuesday, Wednesday having lower levels. Here's where the actual wind low-level prediction was the day before each of the days during the period, so it started out with the solid blue line. What we ended up with the day of delivery or the day before delivery was this dotted blue line, very large deviation in wind output. Here we see the same thing for the on-peak period, where we had on-peak predicting to be peaking out on Sunday, but what in actuality the revised forecast as we got into the day of delivery was significantly lower, representing 7,000 to 9,000 megawatts in the marketplace of wind energy that just didn't perform. These bars show you the difference or the amount of error that we saw in the forecast. Wind forecasting is an art more than a science. I mean, it is a science, but it has a lot of art in it, and we spend a lot of time trying to predict what the wind's going to do, because that tells us how much the deck is going to run and what the costs are going to be for the day. We spend a lot of time looking at this. These are very large deviations, these orange and gold bars, very large deviations that we saw. Now we come to the complicated slide. So this slide provides the overall DME position from Friday the 12th through Friday the 19th. We start with this horizontal dotted line that represents a balanced supply with demand. Next, we push in the price during the period. The blue line is the price starting down here going up to $1,000, peaking up here quite a bit higher, and then recovering and going into Sunday and Monday, $9,000. We had some deviations. There was a market algorithm problem here that was corrected by the PUCT, and then the price rocketed up to $9,000 and stayed at $9,000 for the remainder of the duration of the storm. Now here we see DME's position. The green line represents our physical position that we had during the storm, and as you can see, the green line is above the dotted orange line for the beginning of the period, all the way until we get into these deviations here where we lost gas to the Denton Energy Center. Anytime the green line is above the dotted orange line, that means we have surplus. Anytime it's below, that means we're in a deficit. We're buying at $9,000. Now here we see the dotted line, which shows what would have happened had the deck continued to operate, and that you can see that we would have been in a long position or in a surplus position for the entire duration of the event. And now I want to superimpose when the – this is when the load shedding started at 1.20 in the morning. Here is when the gas pressure dropped for the deck. Here is when the deck tripped offline, and you can see that green – solid green line goes straight down. Here is when we got gas back to the deck, and it took us a full 24 hours before we were able to bring the deck back online at a reduced level because of the freeze of the radiators, which I'll talk about in just a moment. And the end of the load shedding event took place at 9 a.m. on Friday. Here we see the performance of each of the supply assets in our portfolio during the event. And I just want to point out that the percent of expected output demonstrates that during the event, wind energy was practically non-existent, and solar output was just over 50 percent of the expected. And recall from a prior slide, when I say 50 percent of the expected, that's 50 percent of a number that's significantly less than the installed capacity of each of these resources. So it's a weathered, normalized output where we predict a probabilistic output for each hour of each day. And these metrics are based upon, for a typical February, what the output would have been. So when you see a 3.25 percent of wind, that's 3.25 percent of a number that's significantly lower than 150 megawatts, which is what the wind resources is capable of. The revenue numbers here are provided to contrast what the expected output versus the actual output meant from a financial perspective. And as you can see, $180 million of difference. Finally, this slide shows the estimated cost of the event to Denton. These are estimates as we are still finalizing invoice, and as you know, there are two major potential adjustments that will need to be made, depending upon whether or not ERCOT resettles the last 32 hours, and depending upon the outcome of our lawsuit against ERCOT. Let's go through the numbers quickly. Over the event, DME paid ERCOT $209 million. After paying for energy to service the demand, ancillary services, and other load-related charges, ERCOT paid DME $73.6 million for the energy that we injected into the system. We started the week with a cash balance at ERCOT of $4.8 million in collateral. We paid $22.5 million for natural gas. We gained $23.2 million from hedging activities. Our fixed price payment for power purchase agreements was $783,000, and we had a one-time PPA credit of $940,000. The net cost of the week to DME was $140 million, which was sourced from our DME reserves of just above $100 million and commercial paper debt. Finance will discuss the current plan for reestablishing a reserve for DME, and we'll be providing a recommendation on rate impacts as part of the budget discussions for next fiscal year in the coming months. I've also provided two other scenarios for comparison. A normal February weather week, which would have cost DME approximately $1.2 million, and a nominal supply performance scenario to show what the potential outcome would have been had our supply resources been able to supply their forecasted output. And as you can see, that outcome would have been much better for DME. As I indicated, we'd experienced a significant level of freeze damage at the deck when the units lost natural gas supply. The plant was designed to withstand ambient temperatures down to 19 degrees without freeze-up. Temperatures on Monday and Tuesday were sub-zero, and without heat from the engines in the coolant, our radiators froze up. On the left, you see the radiator banks, which are extensive. On the right, you see the radiator coolant pipe freeze damage. We have completed temporary repairs on the radiators on Saturday the 20th, and the plant is now back to full capacity. However, we've not determined whether these repairs are sufficient to withstand high output conditions for a long period of time, and we're working on price estimates to retube the radiators or replace them. The damages have initiated a claim with our insurance carriers, and we are in discussions with their engineers about the long-term fix. With regard to business interruption insurance, I'm disappointed to inform you that the coverage will provide no benefit for the event, since the policy has a 90-day waiting period before the coverage kicks in. We are still evaluating whether future potential losses due to damage of the radiators from the storm would be eligible for the claim. A few challenges that were identified during the storm that we addressed are shown here. As we all know now, cell towers that lost electric supply resulted in diminished cell phone coverage, and landlines were impacted as well. DME is evaluating ways to avoid these potential issues in the future. The major equipment problems identified include freeze-up of the vent system in our air compressor rooms, cooling system transmitters that froze up, and the inability to drain liquid from the cooling systems rapidly, which may have avoided some of the freezing damage. Obviously, our cooling systems will need to be weatherized and hardened as we are evaluating options. It goes without saying that we must never let this happen again, and we're aggressively looking at ways to mitigate our future financial and physical performance risk. Loss of fuel is the largest financial impact, and the options under consideration include adding backup fuel, either propane or LNG. The engines would require a modification for propane, and the air permit would also likely have to be modified. Both backup fuel options will be very expensive. There is a second pipeline on the deck property, and we are investigating the costs and benefits associated with a second pipe connection. Our current gas supply contract is a non-firm contract. Firming of gas supplies involves the purchase of firm gas transport and storage of natural gas. This option would increase the annual fixed costs of the deck in a significant manner. Not on the list is the potential to put a booster compressor on the existing pipeline, as the supplier believes there is adequate gas supply, just that high demand did not enable them to meet the inlet pressure requirements of the deck. As you saw in the prior slide, the best performing asset was our whitetail contract. It's a structured transaction that provides a guaranteed hourly volume of energy at a fixed price from a renewable asset. The energy management organization will begin analysis and seek proposals to swap some or all of our intermittent renewable positions for financially settled fixed shapes at fixed prices. Obviously, this will increase our PPA costs, as we will need to pay to have another party take on these risks. We currently purchase outage insurance for the deck in the summer months to provide a level of financial protection. We will evaluate adding winter coverage to that policy for next year. As we discussed, our current hedge plan dictates the hedging actions we must take. In consultation with the risk management committee, the EMO will evaluate and provide recommendations on changes to the hedge targets for the winter season. Intermittency of our renewable resources is something that can't be avoided. During the last two $9,000 per megawatt-hour periods, our wind PPAs have delivered no energy. We will evaluate ways to back up these resources with spending reserves from available market resources and will adjust our renewable portfolio accordingly to achieve the 100% renewable energy mandate under the Denton renewable resource plan. There's a lot of discussion in Austin about winterizing gas and power assets. We have already provided a discussion about these efforts at the deck, but we'll explore options with Santa Rita, our wind resource, and Whitetail. As part of our hedge plan revisions, we will evaluate how to diversify our risk away from the deck. This could involve swapping capacity with other gas-fired resources or putting in place financial transactions that are independent of actual deck performance. One inexpensive option we are considering is adding additional weather forecasting capabilities to the EMO. While we subscribe to services, it may be prudent to add a meteorologist to staff to develop longer-range outlooks and to run Denton-specific variations so that the EMO can take additional hedging positions prior to weather events to provide needed financial protections. All of these options will cost money, and we'll be back in front of both the PUB and the council to discuss and seek guidance and approval. Early in this presentation, I mentioned that the ERCOT market reforms are needed. Clearly, this is not a well-functioning market. When prices inside of 24 hours have ranged from $9,000 to negative $7 per megawatt, and major market participants are going bankrupt, the key items that I believe need to be addressed are, first, the market must recognize and account for large numbers of intermittent resources that are now counted on to meet peak demands. Out of a peak demand of 74 gigawatts, over 48 percent of the energy could come from renewables in ERCOT. While this certainly is meeting environmental policy objectives for Texas and has delivered low-cost energy, these resources are not dependable at peak demand times. Secondly, the uplift of defaulting parties' financial obligations to the remaining market participants is not sustainable and leverages the strong credit ratings and balance sheets of MOUs and co-ops to the benefit of the unregulated market participants. As we have claimed, this also violates the state constitution. The third item is runaway prices for protracted periods of time must be stopped, and the imposition of some type of circuit breaker into the market to protect ratepayers and market participants is needed. Fourth, because Texas relies almost exclusively on natural gas to back up the intermittency of renewables and to provide spinning reserves, better coordination between the electric and gas industries is needed to avoid a loss of life and property damages in the event of additional load shed events. Before we get to questions, I wanted to briefly discuss what we expect from the legislature and ERCOT and the PCT. ERCOT has issued an order to resettle certain ancillary costs during the EAA event, during the load shed event. This is a generating unit by generating unit exercise that will take some time. I expect this to result in a reduction to one of the components that cost us so much money, and that's a $49 million cost for ancillary services that we incurred during the period. But I can't provide any estimates at this time. Senate Bill 2142 requires the resettlement of the last 32 hours of the load shed period. The bill was passed by the Senate, is supported by the Lieutenant Governor, and has been referred to committee in the House. While it may seem just from a layman's perspective, it is extremely complicated to think about resettling this period. International markets have already settled trades based upon the cleared prices. For DME, the resettlement could cost us up to an additional $17 million, on top of the cost I've already reported. We have filed comments with the Public Utility Commission of Texas indicating that we are opposed to such a resettlement. Council has heard from legal counsel on the merits of our case against ERCOT. At this point, it is impossible to predict the magnitude of the uplift because market participants' short pays and defaults are still occurring without remedy. Two large cooperatives that have declared bankruptcy need to be settled before a reasonable estimate can be established. A number of bills have been introduced and scheduled for hearing this week that are aimed at requiring integration of the natural gas and electric regulatory bodies. It's likely that something makes it out of the legislature, and we will continue to monitor these develops and keep both of these bodies informed. And with that, Mayor Pro Tem, or Mayor, if you're here, and Chair Parker, I'm going to stop sharing and answer questions. Okay. Thank you, Terry. And thank you, Mayor Pro Tem. Appreciate your assistance with that. So we'll take questions. Let's go Commissioner Bill Cheek, and then Council Member Meltzer, and who else did I see? We'll go Commissioner Susan Parker, and then we'll get Armature, Council Member Armature. Okay. Mr. Cheek. Thank you, Mayor. Question for Terry. I wanted to ask you to expand a little bit more on the natural gas, or lack thereof. Question of why exactly was gas cut off to the plant, and what were we paying over the normal, timely prices at peak time for natural gas once it turned back on? Yes. So the Denton Energy Center tripped on a low pressure from the gas pipeline. I don't remember the specific time, but it was Tuesday morning. In discussions with the pipeline provider, or the gas provider, they are still at a loss as to why pressure was low. It's a new section of pipe that's been built, and they believe that the pressure should have been sufficient. However, we do have the data needed to support that the units could not be started back up because of low pressure. During that time, we were paying just absolutely outrageous prices. Normally gas this time of year would be trading prior to the event was trading right around $3 a million BTU. We paid as high as $700 a million BTU during the event. Is there any chance that we had curtailment from the gas company, and that's the reason for the low pressure? We have not been able to verify that we were curtailed in our discussions with the gas pipeline company. They have claimed that there was no curtailment. They believe that it was just the demand on the gas system from all the home heating and other electrical demand that the system just couldn't keep up with the demand, and that's why the pressure dropped. And I should also point out that obviously with the rolling outages, this phenomenon was experienced by dozens of plants around the Aricot market. We have Councilmember Meltzer, Commissioner Parker, Armature, and then, Mr. Rybak, I see you there after Councilmember Armature. Thank you. I would just like to unpack the dynamics of what happened a little further. Our contracted resources weren't performing, and the deck had that interruption, so we had to go to the market without a hedge, and the prices were super high. Now, the prices were super high. Why? Was it because the other power providers in the grid were paying super high prices for natural gas? Yeah, so the price is actually derived from an equation that is run by Aricot every five minutes based on the relationship of supply and demand. And when there's not enough supply to meet demand, certain scarcity price adders are added to the equation. But it's the essence of the equation that a greater incentive would be needed to get providers to produce, and does the price need to be higher because they were facing high natural gas prices? You follow me? Why do they need it? I do, yes. And so in the summer, for example, in the summer of 2019 where we saw $9,000 prices, gas prices were at normal levels, yet we saw $9,000 prices because supply did not meet the demand. And any time that supply is less than demand or is close to a level that could cause these types of rolling outages, the Aricot algorithm produces a price that's $9,000 or a high price. It could be less than $9,000, maybe $1,000. And it's a function of that relationship between the supply and the demand and how much reserve capacity remains online for that five-minute period. So it's staying high for an extended period of time. And the algorithm is saying, well, two things. Demand is still high, and supply is not coming on. Is that more or less what you mean? And why wasn't supply coming on? Supply was not coming on because it wasn't physically capable of producing. Either it had no fuel or it had no wind or there was no sun, and therefore it couldn't keep up with an all-time record peak demand. And I want to quickly point out, it wasn't just renewable resources that were down. It was everything, correct. Who benefited from the price being that high for that long? Who backed up the Brinks truck to City Hall? I wish I knew the answer to that question. I don't know the answer to that question. I think that will be something that the PUCT, the legislature, and even FERC, once the investigations are over, will know the answer to that question. And we do know that some speculators made big money. And that would be speculation by trading companies, by hedge funds that are in the business of taking on risk for profit. And through the financial markets, they made bets that prices would be high. They didn't know they were going to be this high for as long as they were, but they made bets that prices would be high and it paid off for them. This is all taking place during a declared disaster. So I imagine that's the foundation for a price gouging investigation, where you can't charge $100 a gallon for gas when people are fleeing a tornado or something like that. As far as the legislative environment, is there any appetite at all? We don't know where the windfall profits went, but given that it was during a declared disaster, not just in the last 32 hours, it was declared on the 12th and renewed on the 15th or 17th, is there any appetite at all for any kind of a clawback of windfall profits wherever they fell? My understanding, Council Member Meltzer, is that if there were going to be an investigation on price gouging, that would have to be initiated by the attorney general's office. And I'm not aware that that investigation has begun. I know there are requests for information that have come from the attorney general to various market participants. I'll pause. All right. And then Commissioner Parker. I've been getting several questions, because everybody knows I moved here from the frozen tundra of Minnesota, that the wind, was it a lack of wind, or was it that the turbines weren't working? And what can we do to ensure that winterization is better? Another question I have is our deck, the utility I came from, has the exact same engines. And it gets cold in Minnesota, and they don't fail. So can you explain what the differences are? I believe it's that we design them differently. You design for heat here, redesign for cold there. And then, I think you already covered it, but if you could talk about it one more time, is how much did we lose because the gas wasn't, gas pressure wasn't there and we tripped off, how much money did we not get to sell into the market that could have maybe made this as less devastating as it is? Was that way too many all at once? No, I think I got them. Hopefully I can, so the answer to your question on wind is a combination of both. As we went into the, on Thursday and Friday, we were predicting low wind output for the weekend, and even into into Monday, relative to what normal wind levels would have been. So nine, 10,000 megawatts of wind relative to what we would normally see, which would be significantly double that, triple that number. What happened was as the precipitation came in, and much like when you get on a plane in a snowstorm or before you pull away from the gate, shortly after you pull it, you know, they de-ice the wings on the plane to keep them from freezing up. Same phenomena here. Ice got on the blades and the blades were then no longer safe to operate. And so that's what happened in the case of Santa Rita. They physically could not operate because there was frozen ice on the blades. So that was a phenomenon that was seen across the marketplace. We are looking at what is done in the northern climes where we see that. My understanding though is that in Minnesota, Iowa, those places, that type of precipitation is not common. And so normally it would be snow, which doesn't freeze on the blade, whereas freezing rain would, and that's what we had. And so they, the cost to install heaters, for example, on those blades is prohibitive and is not normally done. For the deck, you are correct. We designed the deck, as I mentioned, for a 19 degree minimum temperature. That's the, that's a decision that was made back during the design phase for the deck. It could have been designed to go down to zero or sub zero. The output would be adversely affected because as you add more glycol to the coolant systems, you get less heat transfer and that would reduce the output. What was a 225 megawatt output would probably drop down below 200 if we had glycol concentrations that were sufficient to keep us below zero. As far as the amount of money that the deck, the deck not being able to run, it's a significant number. I can get back to you with a specific number. I think of it in terms of gross margin. The amount of money would have made above operating costs because we were paying very high costs for gas at that time. And that number was probably north of $50 million. Thank you. Okay. Thank you. And Council Member Armature. Yes. So I have two questions. I'll ask the bigger one first. Given the high and variable price of gas and are limited, in fact, the non-existence of any kind of control that we have over the price of gas together with the cost of the maintenance and operation of the Denton Energy Center in relation to its revenue leading up to and of course including the recent Snowpocalypse, Snowvid event. And also, you know, given our limited ability, in fact, in capacity to regulate weatherization of renewable resources for those entities that we contract with, right? We can't tell them, you know, now you have to go winterize your wind generation facilities if they're not our facilities. So given all of those factors that I know, you know, you're so well aware of, you know, why are we not consider or I should say, are we considering investing in renewable, in weatherized renewable generation sources as well as battery storage, but especially the weatherized renewable generation sources which are not dependent on fossil fuel to run and would presumably, you know, would satisfy that, you know, at the proper scale, that generation work requirement of ERCOT to be hooked up to the grid. Just wondering if you could speak to that, why we're not looking there. Sure. That's a good question and I think the answer is pretty simple. We have looked at other sources of renewable energy in different regions of Texas in order to get some regional diversity. The wind farms in South Texas and along the coast did fairly well during this episode. As you may be, as you may remember, Councilmember Armenter, we had evaluated coastal wind last year and we found that it did not compete well from a financial perspective with other sources of renewable energy that we were evaluating pursuant to an RFP. We may now have to go back and relook at the way we evaluate those bids to see if perhaps there is an allowance for the fact that these performed well, but I will tell you that the sellers, the owners of those will also re-evaluate the value that they bring to the market and so their offer prices are probably going to be significantly higher. But I think the one point that everyone needs to keep in mind is that regardless of the renewable resource that we contract with, what history has shown us in the last two years is that at times of critical need, they don't show up because they are by nature intermittent and they can only produce during times when the wind is blowing and the sun is shining. And no matter what we do, we have to have a provision to back up that intermittency, and that's what the DEC is intended to do. So I would like to just respond to that and then ask my second question. Of course, I understand that renewable energy is intermittent, but it's also my understanding that when the city invested in enterprise consulting to help balance our renewable portfolio, they explained how a balanced renewable portfolio that includes coastal wind, and that was the key for coastal wind for them, it costs a little bit more. And I see what you're saying. It makes sense that the price would go up now that people are seeing or understanding more of the value of coastal wind and there will probably be more of a demand for it. But coastal wind as part of a balanced portfolio, together with the backup that a grid is at least supposed to provide, covers that limitation of the intermittent nature of those renewable resources. Gas, as we found out, is also intermittent, dependent on pricing and availability, also being a finite limited resource. So that's just kind of my two cents on the matter, but I'm glad that we will be going back and re-looking at how we evaluate the fiscal responsibility of investing in coastal wind, because I continue to believe that even though it costs more, it is a good investment for part of our backup plan. So my next question, which is a simpler one, or at least a smaller one, is related to Commissioner Parker's question about winterization of wind. I'm not going to repeat her question because you answered it, but I'm wondering if you could speak about what you mentioned about the consideration of possibly hiring an in-house meteorologist to consider weather issues and to what extent we know the weatherization of those wind contracts that we contract with. In other words, I would imagine that a meteorologist would think, okay, because of the weather and because we have these contracts with these wind generation facilities that are not properly weatherized, it's going to affect us in this that way. Are those contractors transparent with, maybe not with the public, but at least with the cities they contract with, about their weatherization? And to what extent would a meteorologist be able to help us better prepare for that? The concept of bringing a meteorologist on board to help us to better predict weather is really focused on taking real-time actions to hedge price risk based upon those weather forecasts. And I would not tie it to the physical assets themselves, the renewable assets. Under our power purchase agreements, our suppliers are not obligated to provide us a quantity of energy over any particular period of time. It's a take and pay contract, so we pay for the energy as it's delivered. And so if we were to insert contract provisions that said you must be able to perform at this level during these periods of time, that would change the economics and the risk profile for that particular generator. And we would have to renegotiate those contracts almost entirely. So while I understand what you're saying, I just want to make sure you're clear, I'm clear, that the concept of bringing somebody on board as a meteorologist would be more to increase what we were able to do, which was to put hedges in place that achieved $23 million of value. We would do more of that proactive hedging in real time in order to recognize the risks that we face with the intermittency of our renewables. And as you point out, the potential for a gas interruption. Thank you for that. That makes me think of a third question. I know Mayor Pro Tem mentioned in the previous segment, we could each ask three questions. I don't know if I can ask that now. Mayor Hudspeth, or should I wait until -- Yes, go right ahead. Okay. Thank you. This is when you were talking about contracts, it made me think, and please let me know if this would be a better question for a later segment of the presentation, but it seems apt to me right now. Has his staff investigated our contracts with Wartsilla, the gas plant manufacturer, and also Burns McDonald, the contractor who helped set it up? I know this was before you got here, that those contracts were established, but to see if there's anything in those contracts that could have possibly misrepresented, you know, the preparedness of the DEC, you know, for such an event. I'm not saying there is. I'm just curious. I thought now might be a good time to ask. We've accepted the facility, and the warranty periods are over for the DEC and for the equipment there. So I would not suggest that there be an opportunity to do what you're suggesting. Okay. And so that takes us to -- and, Lee, help me enunciate your last name right. You are correct, Ryback. Okay. Thank you, sir. No, thank you. I appreciate it. Terry, I've got a real nerdy engineering question for you. When you were talking about the problems with the DEC, the one thing that caught my attention was a cooling system transmitter scaling. So I'm curious if you could clarify that. And secondarily, you talked about some heat exchanger mitigation to overcome the very cold temperatures and the -- obviously, the heat exchanger is full of water. So what are those strategies, and could you just expound on that a little bit? Sure. The transmitter scaling issue was really freezing up of the transmitters and the ice that was forming inside of the transmitters themselves or the sensors, the sensing probes for temperature. We couldn't get an accurate temperature reading on the liquid that was in the radiator systems. The mitigation, as we think about the long-term fix for the damage that was caused, there are two options, really. One is to replace the end tubes. So these are cooling systems where there's a manifold where the heated fluid comes in, passes all the way through the heat exchanger and comes back. And at each end, there's a tube, you know, a 90-degree, 180-degree tube that bends around to return the liquid. That's where we saw the bulk of the damage. And so the mitigation might be to be able to go in and just replace those end tubes rather than the radiators themselves. We do not believe that there's damage to the long runs that run through the radiator fins themselves. Right, through the coil tubes themselves. Yep. Okay. Has any thought been given to providing some kind of heat source at the base of the heat exchanger in an emergency event like this, of course? Yes, sir. That's what we're considering is we'll be doing an analysis, engineering analysis of whether adding heat or adding additional glycol concentrations or having the ability to evacuate that liquid very quickly in the event that it drops below design temperatures. And we'll do a net present value analysis to bring it back to you and give you our recommendation on the path to proceed. Oh, thank you very much. I appreciate it. Mr. Mayor and Madam Chairman, I'm going to have to step away for a few minutes. I beg your indulgence, but I shall return. Thank you. Mayor Pro Tem Davis, then Commissioner Solve, and then Ben, did I see your hand? Okay. Yeah. And then Ben, thank you. Thank you, Mayor. Terry, my first questions are about the legislature. First, on the resettlement bill, we know that the Senate passed their bill that's now over to the House to do. The House is going to kind of take a longer look at it, I think, than the Senate probably did. And you already said that it's hard to say exactly how people are going to benefit or exactly what Denton's going to have to give up if we resettle those 32 hours. But can you can you break down for us why those 32 hours are the time period that's being looked at for resettlement? And in a general sense, who would benefit? We know the municipal operators like Denton stand to lose in a resettlement. Who stands to benefit in a general sense if that market is resettled? That's a great question. So the bill has been referred to state affairs, we understand that state affairs will take their time to gather additional information before they hear the bill and before they take a vote on it. So the reason why the 32 hours is under consideration is that beginning at our at that 32nd hour before the end of the event, there was adequate reserve capacity in the market, where ERCOT could have started to bring load back on. ERCOT chose at that point to keep the prices at $9,000 to send a signal to the marketplace for load not to come back into the market. So if you think about a large industrial customer that say has three, 400 megawatts of load in a single location, were they to come back on all of a sudden and absorb whatever that reserve capacity was in the market, and then another generating unit would have tripped off, they would have been back into rolling outages again. And so ERCOT decided that they would not release the $9,000 until such time as they had adequate reserve capacity online to assure that when those when that load came back on, there would be sufficient resources with adequate reserves to meet the demand. And that's been referred to by the lieutenant governor as a mistake. You know, it's been been referred to by ERCOT as the way the market works. And so there's a big debate about whether that should happen or not. I hope that answers your question. The winners and losers, I'm sorry. So so the winners on that would be the folks that were buying energy from the market at $9,000, they would their bill would be lowered. In our case, we were, we had brought the deck back online, we were running at minimums, because all the energy that we could produce was not needed, there wasn't sufficient demand in the marketplace for us to run them up to full output. And so we were being paid a standby charge or a reserve charge for the difference between the level that we were putting out and the maximum that they could achieve at that time. And it's that difference where we were being paid $9,000 for energy that we actually were not generating, we're sitting there as a reserve unit, as were other units in the market. That's those are the people that would be the losers. Okay, and I guess can you, is it possible to break that down further from we know, the folks who are buying power off the market? Did that does that mean? Are those mostly municipal operators? Are they? Are they mostly privately held companies? Or is it just everybody at that time? Yeah, so I should clarify that, just to be clear, everybody buys from the market. So everybody's buying the $9,000 price at the time. The question is, what are you injecting to offset that $9,000 price that you're you're paying? So if you had no generation, you weren't inputting anything into the market to offset that expense, you would be a winner in a resettlement. If you had generation that you were injecting back into the market, you would be a loser in that resettlement. Okay. And we kind of talked briefly about ERCOT reforms that are in the legislature. And the speaker proposed a package of bills that kind of address things generally. He's got one proposal that includes changing the governance of ERCOT just a little bit, you know, putting some consumer representatives on there, that kind of stuff. But is there any are there any serious efforts in Austin to restructure ERCOT, not just change the board up, but to restructure ERCOT, what it does and how it does business? You know, we, as you're probably aware, Mayor Pro Tem, we do employ a lobbyist firm to help us with our work in Austin. And I think their perspective is that because this is so complicated, and because the market is to change the market design, to the extent it probably needs to be changed, is such an undertaking, it's not likely that there's enough time in the regular session to make those kind of wholesale changes. And so what we're hearing is that they'll go through the remainder of the session in a fact gathering manner. And then could be a special session in which we'd see the kind of changes that I think you're alluding to. Okay. And last question, if I could, Mayor? Yes, sir. So I'm trying to kind of bring everything you're telling us about our financial picture, our generation picture, the wind resources that performed in a disappointing way, the situation at the deck that didn't energy center with the gas supply. And I keep going back to your graph, your slide that had the dotted line of our position or our breakeven position, and then the green line that showed our position over time. And I mean, tell me if I'm wrong here, but it looks like up until the moment that that low pressure tripped in the gas line, and we lost gas at the deck, up until that moment, we were in a very good financial position. We were in a very good generation position. We're all suffering through the rolling blackouts that are rolling outages that ERCOT was prescribing us to do. But up until that moment, the city of Denton and DME financially was doing everything exactly as we should. I think that's an accurate statement. I would point out that during those first two days, Saturday and Sunday, demands were significantly higher than what we had expected. And so we were buying energy from the market at the then spot market price wasn't 9000. But it was 1000 to 2000 $3,000 at times. So no matter what we are the way that our generation portfolio had performed, the fact was we were having to meet 40% more demand than we had planned on. And so, as I mentioned, we did take some action on Thursday and Friday and putting hedge transactions in, recognizing that the demand would be higher. And those those actions paid off. You know, we did realize gains on those transactions. So we would have been okay. I'm not saying that we would have came out, you know, making money. But we would have certainly been well within the reserves that we have set aside for these types of events. Thanks. Okay, Commissioner Soff. Yeah, Terry, thank you for your presentation. It answered most of my questions and very, very informative. My question is, is this will the vulnerabilities that have been exposed by this extreme weather be incorporated into a long range resilience strategy plan that will address the continuing impacts of climate change on our area? Well, I can speak to kind of the long range as I mentioned early in my presentation, the fact that the unabated demand would have been 400 megawatts, we will plan to meet that demand and we will set up our our supply portfolio to meet that demand. With regard to your question about climate change, I think, you know, depending on who you read and who you listen to, while this was a very cold event, many scientists have said it's a result of climate change because of the changing climate. It causes these types of volatility in weather patterns. And we don't know definitively whether that's true or not. But in any case, all we can do is prepare for that, which we believe could happen in the future. And obviously, this is a wake up call for all of us that these episodes of winter cold weather, whether they're repeatable or not, and only time will tell whether they're repeatable. We need to be prepared for them. And and we will do that. We will be prepared for them. It will be not without cost, but we will be prepared for them. Thanks. I think precaution is the best policy. And just as one quick observation, if I may, I hope that this also will jumpstart further efforts within the city for energy conservation and building codes that are more more appropriate for colder weather rather rather than just heat. So, I mean, it's a it's a huge picture. And I hope that this will initiate a lot more discussions about what the city as a whole can do to lessen the impacts of these things. Thank you. Okay. And Commissioner Jumper. Yeah. Hi. So, I was curious to get a little more information about, I guess, the practice of hedging. You know, I'm new to the board, but a couple of days just doesn't seem like a whole lot, given the things we know about Texas with drought and hurricanes and tornadoes and such. Is that a standard that what I feel like is a relatively short time? Is that a standard practice? What are what are other places doing? Are we doing better or worse? What can you answer to any of that? So what do you if I could just get one clarifying when you say a couple of days, what are you referring to? Oh, so you had mentioned you bought prepaid on Thursday or Friday through the following Tuesday for energy. So that it doesn't feel like a very long time to me. But give me a point of reference. Yeah. So the markets trade in you can buy and hedge a year at a time, a quarter at a time, a month at a time, a week at a time, a day at a time, balance of the week, all those products trade in the marketplace. And so depending on what risk you're trying to cover, you can transact on any of those temporal periods. So in our hedging plan, because we look at monthly, our monthly exposure, we generally are doing monthly transactions, some annual transactions because we do hedge out into the future, a significant amount. In this particular case, what was unique about it not only was the weather abnormal, and just, you know, an eight sigma or a black swan event from a probability perspective, the fact that it occurred over a long weekend that was a bank holiday, exacerbated our ability to actually react to the changing weather. And if you may recall, the week running up to the storm, the weather forecast kept getting colder and colder and colder. And the weather kept moving out one more day, one more day, and then it would be colder and then it'd be one more day. And so, you know, we try to be judicious, the use of our dollars that we have available to go out and do these hedges, we don't want to get too far in front of it, because if we buy at a high price, and then the weather doesn't come in, we find ourselves in a position where we have to liquidate into a much lower price market and lose money that way. And likewise, we don't want to not hedge and expose ourselves to significant financial risk. Now, if we had a crystal ball, and we knew that that gas demands would be at all time highs, and that we had the potential to lose pressure, we would have taken more aggressive actions the prior week. But there's just no way to, you know, in the trading business, you can look back, you don't want a Monday morning quarterback, but you want to look back to learn. You don't want to second guess, because you try to make the best decisions that you can given the facts that are in front of you at the time. Thank you. So kind of follow up to that, would you be able to say like, what percentage of our purchases are hedged or in real time or whatnot? What can you speak to that? Yes, I can. There, we're kind of venturing off into an area that's commercially competitive information that's protected under the under the appropriate acts or sections of the statute. But we, we, we hedge almost 100% of our expected demand and our expected generation. Okay. Thank you. Okay, no other question. Okay, anyone. So let's go Councilmember Ryan, and then we'll see if there's any other questions before we circle back. And after Councilmember Ryan, can someone orient me? So we have a three o'clock meeting that we need to start. So I need someone to kind of orient me on where we are and bring me up to speed, but Councilmember Ryan. Thank you, Mayor. Terry, you mentioned a couple of times about the possibility of resettlement of ancillary services. And we can all understand supply and demand. We can definitely debate how far that price should be able to go to. That's definitely something to talk about. But what is involved in ancillary services? And because I noticed they made a huge jump. Yeah, they did. It's a great question. It's not an easy answer. So ancillary services are the types of non-energy products that the grid needs in order to remain reliable. There are four main types. One is reg up or regulation up. One is regulation down. One is spinning reserve. And the fourth one is regulation, type of regulation. The fourth type of regulation I'm drawing a blank on right now, responsive regulation. So we think about it since we can't really store electricity in a meaningful way. Yes, there is battery technology. But by and large, supply must meet demand at every millisecond. And so as people turn on lights, turn on motors, you're increasing the demand or decreasing the demand. And the spinning generators in the grid have to be able to react to that. So ERCOT has set up these four products called ancillary services to enable them to call on reg up, reg down, spinning reserve in order to meet that variation in the demand and in the generation. So if you lose a generator in the grid, you have to bring another one up to take its place. And that's what ancillary services are. They actually clear in a competitive market. There's bids and offers, and they're cleared in the day ahead market based upon bids and offers that are in the marketplace. Typically, those would be right around the same price as energy, which would be in the $20 to $30 a megawatt hour range. But we saw prices as high as $24,000 a megawatt hour for some of these ancillary services during the storm event. Okay, so that would be like when they were paying us to be on stand for full generation, but we were only at partial. Yes. So we were responsive reserve at that point. Okay. And then my other question, when it comes to winterization, you know, we see the coolant and the oil and that the contracts come through for that. How often do we change the coolant? And is that something that potentially October, November, when we're not up, we could increase it to you know, a zero or 10 below and then water it back down, you know, come March. That's a great question. And we obviously that was one of the things that was debated when the deck was being designed. And yes, you can have a separate standalone mix of glycol and water to be able to get you to sub zero temperature. The problem is, is that once you convert to that, the residual glycol and materials that are in that mix tend to coat certain areas, and you lose capacity. So once you make that decision, you can no longer achieve that full output that 225 megawatts of output, it gets rated down to 200 or so, if we're to go to that. So you'd be you've had paid, you effectively have paid for 225. But you can only realize 200. And then lastly, I don't know if you want to make comment on this, but I was in a public meeting a couple weeks ago, and Representative Patty, who's the chair of the State Committee, State Affairs Committee was there and was talking about this and basically said it was everything from the well head to the light switch that we had problems with. And one I'd never even thought of was that the gas companies did not indicate to the electric companies what were their compressor stations were that push the gas through the pipes. And those compressors went down. And that was a reason why we did see low pressure on the gas lines. It's absolutely correct. So there were a number of electric compressors that were not considered critical load. And so when the rolling outages hit, those compressors were in those outages, and they could no longer compress the gas and push it down the pipe. There has been a very concerted effort in the last three weeks to identify all those locations and to change that classification to make them critical loads. Okay. Miss Miss City Manager, can you orient me on where we are? Or I don't know who's running the presentation that just want to get a feel for how much time so we're to almost 230 now? Yes. Yes, Mayor, we have another presentation, the water wastewater and then we have the finance portion. So I think what we'll do if you're amenable is go forward with the finance presentation, see how that works out, and then look and see if we have time for the water wastewater. Okay. Yes, we'll be glad to bring the water wastewater back at a later date if that's what's needed. Okay. So looking to my peers, your thoughts, and the board members just want to get a feel for everyone's thoughts. Mayor, I'm amenable to that here in the finance piece. And we have the backups on the water wastewater that we've read to prepare. So we have a little bit of information already and we could maybe hear them another day. Okay. All right. Any anyone any Yes, by means, Miss Parker. I agree with what Jesse said. Let's do the finance and we can circle back with wastewater and all the information we need. Got it. See Karen. Thank you. Okay. Thank you, Barbara. Okay, then. Yeah, we'll do that. We'll proceed to the financial presentation. Okay, Cassie Ogden is here to present the finance presentation. Cassie Ogden, Director of Finance. I'm here to talk about the electric fund financial update. So let me share my screen and we'll get started. So we're going to go quickly through the where the fund was pre winter storm, post winter storm, kind of the current state in our uncertainties and then next steps along with kind of a calendar for you. So going into the before the winter storm and the electric fund was in a we felt like a good place given the healthy fund balance. We were in excess of 100 million in our in our fund balance, which was well above our reserve targets of 36 to 48 million. We had we exceeded our debt coverage ratio of 1.25 target. We had an annual debt service payment of 49 and a half million. You may remember our commercial paper program was approved in January, right before the winter storm and we had not issued any commercial paper notes. And as you see on the screen, our actual purchase power expenses for previous years were between 60 to 90 million for the entire year going into the storm. So post winter storm, as you've already heard Terry talk about, we incurred 209.8 million in collateral and ancillary charges for Urquhart, which was substantially higher than what we've paid in previous years combined. We had we in order to meet our cash flow needs, we did issue a hundred million dollars of commercial paper notes, which we discussed with city council on February 19th, that Friday of the of the storm. And along with the the notes issuance S and P downgraded the utility system debt rating from a negative to a plus. They also placed 21 other entities on credit watch with a negative implication. And along with bitch place, all Texas public utilities on a negative credit watch. Before the winter storm, finance had started a fund balance policy analysis to determine the appropriate amount of cash on hand required for the electric fund. Obviously given the conditions of the winter storm, that fund balance analysis and our assumptions have changed as a result. And so now we are we're going back to the table and looking at what the correct fund balance needs to be given the winter storm and the possibilities surrounding our cash flow. And we I do want to note we did discuss with our financial advisors yesterday, the hundred million dollars of commercial or I'm sorry, a fund balance that we had going into the storm is likely going to be the minimum fund balance target going forward for the electric fund. So current state where we're at, we did issue the hundred million dollars of commercial paper notes. We will be bringing back to council and PB for consideration, refunding those with long term revenue bonds. Additionally, given the additional expenses and kind of uncertainty with the uplift and the market repricing, we may have to issue additional bonds to for 40 to 60 million for those expenses if they're incurred. And how do we pay for all of these expenses? Well, we are looking at an ECA rate adjustment based on the total debt issuance. So refunding the commercial paper notes with long term revenue bonds will allows us to spread the costs over several years instead of all in one year. So we're looking at how do we do that across multiple years instead of doing one large rate increase in a single year. But we're still working through those recommendations and we want to bring we're planning to bring something back to PB and council in April. And so next steps. Obviously, we've we've gone through the winter storm incurred expenses to date to meet our purchase power needs. We the city has the utility system was downgraded by S and P's were on the negative watch list for Fitch. We still are uncertain on the total amount that is going to be required long term. As we work through that, we're going to bring back recommendations for PB and council discussion regarding rate adjustments and fund balance analysis and our capital program. And with that, I am I'll pull it down. Okay. Thank you. Questions for staff. Okay, Councilor Meltzer. Thank you. I'm sure you know the question on everyone's mind is how much will my rates go up? I heard you clearly say we don't know yet. You must have some idea it's unlikely to be less than X. It's unlikely to be more than Y. Can you give us any kind of, you know, what's the plausible range? Sure. So we have been running all kinds of scenarios regarding what possible debt service would look like and how it would impact the fund to just give you a range $100 million of our long term debt based on our current market conditions and our bond rating would give us we're approximating about 3.5% interest on a 20 year note, which would be almost $6 million a year for the fund in debt service payments. So that would be for an average residential customer, about a 5% increase. So if we look at the 140 million worst case scenario for 20 year, it's about $8 million a year for the fund in annual debt service payment, which is about a 7% increase for average residential customer. Obviously that that changes across the different customer classes. And that's very tentative. That's just where we are right now. But we will definitely bring back recommendations. I really appreciate your kind of putting some expectation out there. Thank you. Okay. Any other questions? Mayor Pro Tem Davis. Thank you, Mayor. Just to follow on to that. I also really appreciate the range. I know that nobody's trying to hold the finance department to to that. It's all dependent on so many things right now. But as that narrows some, would it be possible to produce something for us a little table on how those percentages would impact the different rate tiers? You know, we will sometimes get things expressed in dollar amounts to the average based on the average residential bill, that kind of stuff. Something like that might be helpful just as much as we can knowing that we can't guarantee any of that. Absolutely. That's part of what we plan to bring back in April. Okay. Any other questions for staff? Seeing none. Oh, okay. Yep. Miss Commission Devaney. Devaney. Sorry, another rookie question. What's uplift? Can you explain the just explain the term? I could Google it, but I would hate to see everything that would come in. I'm going to tell Terry I would pitch him the hard questions. So I'm going to put that over the theory and let him Yes, good afternoon. Uplift is a term of art that we have kind of coined. It's in the ERCOT protocols. It represents the short payments that ERCOT does not receive from its market participants. So in this case, right now, there's $3.2 billion of nonpayment in the ERCOT market for this event. A good deal of that is associated with the two bankruptcies that I mentioned, two cooperative bankruptcies. And until those bankruptcies are settled, and we see how much they actually pay, it's not going to be zero. It'll be some number above zero. We won't know exactly how much short pay will be uplifted to the rest of the market. So it means distributed to the rest of the market. Yes, ma'am. It's allocated on a pro rata share based upon your level of market participation. Okay. And as you're probably aware, we have filed a lawsuit against ERCOT to dispute the the legality of that practice. Okay, thank you. And Terry, if if you get a call from a confused UNT reporter, I explained it as though 10 people go to eat at Outback Steakhouse and only eight of them have money. And the other, the bill for the 10 gets dispersed among the eight. Great analogy. So buyer beware. Okay, any other questions? Before I come back to you, let me see anyone else. Okay, Councilmember Meltzer. So you know, the massive part of the heist, if you will, could only be addressed, I think, through, well, either the Attorney General take action or as far as I know, the legislature taking action to say, you know, people shouldn't be backing up the Brink's truck during a declared disaster. I don't know if the legislature will have the courage to take that on. But at what point do we know if there'll be action on that front or not? At what point do we say time, you know, it's just not going to happen. And we have to figure out other ways to resolve the financial impact. So we do know the 100 million. That's, that's what we've already expensed. We do have those commercial notes outstanding. So that is the immediate need right now. The 40 to 60 million range that I gave you in the presentation. That's really what's uncertain. But let's say the, you know, not just 32 hours were unwound, but the entire period of the declared disaster, that would address the 100 million as well. I'm not saying it reverses it and now we're plus, but you know, I mean, that would be the point of addressing the full range of, you know, the event would be to restore, you know, to the injured market participants like us. So that's what I'm asking even about the 100 million. At what point do we say there's no chance that won't happen? I guess I might try to answer the question. Councilmember Meltzer, I think, you know, the reality is, is that if, if the market were, if, if somehow the market were going to be resettled to a cost based settlement, so the fact that many participants paid astronomical numbers for natural gas is going to result in very high prices for electricity that was purchased in the spot market, whether it was real time or day ahead. So, as I mentioned, we paid as high as $700. So unless the gas piece is unwound as well, which I'm saying it should be. Yeah, I just don't know. You know, natural gas is a internationally traded commodity and to, to unwind that is just, I mean, it's, I can't see how it's going to be done because that money has already been settled and it's been dispersed around the globe to try to recapture that money by, by clearing entities, by brokers, by all the people that are involved in that market is just a daunting task that I don't know that quite frankly, there'd be legal right to be able to do that or even how they would be able to do it. So while, while I think your point is a good one, that if, if it were totally unwound, I think, you know, the fact, fact is that we, we bought more energy than we sold, probably would say that our bill would be lower, but that, that's about the extent of which I can kind of speculate on, on your question. You know, my, my question was about when, when do we know there's no chance of anything happening legislatively? I would guess after the end of the session, if, if that, if that Senate bill is not passed, then I guess we would know at that point. Okay, because that could have some bearing on, you know, at what point we would want to take action that would potentially affect customers. Thank you. Okay. All right. So any other questions before we close this, this segment out, get ready for our three o'clock meeting. Okay. Well, comes from Armitage. Yeah. Could you go into just, just a little more detail with the time constraints in mind, obviously about, you know, the, the differences between paying off revenue bonds versus commercial paper. You mentioned the time. What, what other differences are there? Sure. So our commercial paper notes, they are premature after 90 days. We do have an extendable program, so we can extend them for up to 270 days. And then we could make the decision at that point to roll to another note or we could refund with revenue bonds. And per our, per the guidance in the, by the statutes, we have to, if we refund, we have to use revenue-funded bonds. And so of course, so revenue bonds obviously paid for with DM, DME revenue versus commercial paper or CO, DO bonds could be from the entire general fund. So when we talk about transferring to revenue bonds, you know, regardless of the amount and the time we're talking about rate payers, you know, being, being responsible for, for paying that off, is that fair to say? Yes, I think that's fair to say the commercial paper program that was approved that we did issue the notes through was specific to utilities. So it was contemplated or set up for electric water, wastewater, and it is paid through by rates. Okay. Can you just, can you explain exactly why, not that I'm doubting it, I just, just need to learn more, you know, why could we only refinance with revenue bonds and not, you know, some other kinds of bonds that state law, federal law. I don't know, David, if you want to take this one. It's my understanding. That's a statute requirement that because it's, it's the commercial paper program is established for our utility system. We have to, if we were to refund for, with revenue bonds, I mean, with, if we were to refund with bonds, it has to be revenue bonds because those are backed by utility rates. Sure. Now David Gaines, assistant city manager and everything Cassie said is correct. Our bond council did inquire that, raise that exact question to the attorney general to say confirmation. The attorney general's office did confirm that we would have to take revenue bonds out to pay back the commercial paper because it's utility backed commercial paper. Okay. All right. Thank you. Just to, I'll just mention, you know, I, I like a council member Meltzer. I'm sure like, you know, most people here, you know, concerned about the impact on our, on our rate payers. And I know staff is too. So we'll, we'll be watching those calculations very closely moving forward. Okay. Mayor Pro Tem. I just want to add to what David said about the statutory requirements. Not every DME rate payer is a city of debt and taxpayer and not every city of debt and taxpayer is a DME rate payer. So it would be, I think unethical for us to shift a major debt burden from rate payers over to taxpayers with general revenue bonds. So I'm, I'm, I'm glad that the statute makes us keep it siloed that way because we also have rate payers that are quite large, you know, UNT, Walmart, Target, distribution centers. That's a different base of people who are paying for that debt that we're talking about now than the folks who pay for our general revenue debt. Okay. Thank you. Assuming no other questions. Okay. Great. Thank you. Thank you, Cassie. And so Ms. City, Ms. City Manager, you'll bring back the other presentation. Is there anything else we need to take up before we adjourn for a short break before we come back at three? No, Mayor, if you're amenable to this, I think what we'd like to do is if you're on board with this is schedule another joint meeting like this so we could share it also with the Public Utilities Board at the same time. So they could hear this as well. I mean, obviously it could be shared with them at another meeting, but I do think there is value in discussion between the two, the board as well as the council. And we could find a time maybe to do the water/wastewater item together. Sure. Yeah. And there may be more known at that point as well to answer some of the legacy questions. So that'd be a good opportunity. Thank you, Mayor Pro Tem Davis, for kind of bringing us to the fore to get scheduled. And thank you for filling in. Okay. Well, with that then, yes, we'll do that. But thank everyone. Sorry for missing some of it, but did enjoy the conversation. So at I'm going to conclude this joint session on the City Council end at 2 46pm.