Jul 08, 2019 Public Utilities Board on 2019-07-08 9:00 AM

Okay, it's nine o'clock, so it's called to order the Monday, July 8th Public Utilities Board Meeting. I'd like to suggest that since the item that's in the closed meeting is not on the agenda later that we move that to the last item and then we can just, we can adjourn into the closed meeting. So the first item is the work session, receive a report and hold a discussion and give staff direction regarding the Denton Municipal Electric budget and capital improvements. Good morning, Madam Chair, board members, city manager Terry Nolte, assistant general manager DME. We're going to go over our budget today. I'm going to skip over a lot of the bullet points on the presentation that you've got. If you have any questions, please stop me and ask me. Just going to hit some highlights here. For accomplishments, I guess the ones that we're most proud of is our, the second bullet down, the excellence and reliability award from the APPA. Only 25% of utilities, municipal utilities in the U.S. receive this honor and it's a measure of reliability, sustainability, and customer service. We did also complete another of the largest power purchase agreements as part of the renewable Denton plan, 150 megawatt PPA, a fixed price solar energy during the year. On the street light program, we've patrolled street lights on two occasions. The first time we had about 600 lights we found out and have worked towards repairing. We just completed a second one and now we're down to 200. The Denton energy center, the last unit, completed its warranty repairs in May of this year, unit five, and so now we're into a steady state post startup operation. There are still some outstanding warranty issues on the control side that we're working on but we feel like we've turned the corner on that. For the rest of the year, we are working on our hedge plan development. This is one of the recommendations from the Deloitte study. We've passed a new risk management policy and as part of that policy, we'll be developing this hedge plan which is really the next step in the maturity of the energy management office and once implemented, it will help stabilize revenues, the ECA component of the rates, and it will help us to more effectively measure and report the risk to you and to city council. The ETRM system is the energy trading risk management system. It is another one of the recommendations that Deloitte had. We are in the selection process for this system. It's an essential component of our hedging program as we move forward. The texting capabilities, we're in the final testing of texting capabilities for customers to keep them informed of outages, time to restoration, and information that they will find valuable. For the next fiscal year, our objectives are to enhance our energy programs. We're looking to add lawn equipment incentives for electric lawn equipment, lawn service equipment. We also have -- we continue to see strong interest in the solar rooftop installation. We have over two megawatts of solar installed now throughout the city in rooftops. Gibbons Creek will be a focus of our efforts in the next fiscal year as we try to get a better handle on the costs and risks associated with the shutdown of the Gibbons Creek facility. There are a number of landfills and ash ponds that require remediation. The plant site is on the blocks to be sold. The revenues from the sale of the plant are intended to offset the decommissioning costs that we anticipate will be faced by the TMPA members. And then new LED lights will be initiating the start of our new LED street light program. Those lights will have controls that will automatically notify the control center when they're out so we can get out there and repair them very quickly. And they take about 80% less energy to fuel those. And then on the renewable energy front, we hope to ink our last deals to achieve the 100% renewable program, renewable dent program, inside of this fiscal year. So this year, the new management has taken a look at the process, the budgeting process, and we decided to examine the process to ensure more accurate forecasts and methodologies. A number of changes were made to ensure that the results were objective, unbiased, and the potential outcomes were properly quantified and documented for consistency in years to come. The process identified a number of gaps associated with the DME's forward forecasting approach. We've made some changes, reviewed those changes with industry experts, got a passing grade from them, and we've attached a summary of their assessment, which supports the methodology that we used. We'll continue to improve our forecasting methodology in the coming year as we look to enhance our modeling capabilities with some stochastics and neural network models that will better predict the variability of output from our renewable energy resources and the variable demand that we have. Better modeling will result in a better sensitivity analysis as we move forward. We'll talk about some of the budget impacts. So changing markets, regulations, weather, forecasts, and that's what defines the electric utility business, and each of these factors have a significant impact on the financial performance of DME. The budget that we're proposing is based upon what staff and management consider the most probable set of inputs and likely outcomes. However, many of the variables that we have to forecast to define likely revenue streams and expenses are beyond our control. This slide provides the high-level review of some of the most important ones. Each year we present a five-year forecast with the next fiscal year having the highest confidence level. The budget you'll see identifies the need for additional revenues. It has a high reliance on the use of reserve funds in this fiscal year and next fiscal year, and with the exception of weather, the factors on this list really have a potential impact on our budgets in years two through five. So as we go through those, just to touch on a few of them, the decommissioning costs of TNPA, we have currently $22 million budgeted. We think that could come in less than or could come in higher than $22 million. The status of that is that the engineers have looked at the cost of decommissioning. Those plans have not been forwarded to the environmental people in TCEQ in Austin. Until they approve the plans, we won't know the final number. Positive cash flows from the TNPA site, to the extent we sell the site and can offset some of that $22 million, it will impact our budget. We currently have only expenses budgeted, no revenues for the sale of property. Our T cost recovery we anticipate will go down over time. Currently we're earning about 28% return on our investment. We expect that to move down to around 13% in the next three years. If that rate stays higher, for a longer period of time, it's worth about $2 million per year for each percent. Of course, summer temperatures, lower than normal summer temperatures as we've been experiencing, results in lower revenues for the deck. It also results in lower expenses on the purchase side for load. Because of our hedging program, we'd like to see higher temperatures and higher prices so that we can generate more revenues from the deck. We'll talk a little bit more about the deck forecast as we move forward. The last one on the positive is increased power price volatility and capacity. As you all have been informed, the reserve margins in the ERCOT market are very thin. To the extent that we have any major outages of generating units, we could see volatility increase. Volatility increases are good for the deck revenues as long as the units are available, which we anticipate they would be, and that would generate a lot more revenue and impact our budget positively. On the negative side, we could see higher forced outage rates. They are mechanical pieces of equipment. They are subject to breakdown, and although they're relatively new, there are unfreeze seen things that could crop up. The objectives of this presentation, I think you're going to take this one or are we going to the next one? Okay. With that, I'm going to turn it over to David. Good morning, board. My name is David Gaines. I'm the director of finance. I'm going to take over a few of these slides as we move forward talking through the financials, but definitely we have Terry and other DME staff here to answer specific questions. To start with, outline the pieces we want to hit on in this financial presentation. Talk through our assumptions. We really want to hit on a couple pieces concerning our debt service, purchase power, and how that affects our ECA rate, which really are some of the pivotal points in the budget for the next year. Then talk through the rate options, CIP, and touch on the TCOS that Terry mentioned previously. Just a step back as far as the process of how we got here, you know, obviously the budget has been delayed a couple months from what we've previously done into the other utilities that have already come to the board, and I think you saw a lot of the reasons in what Terry just presented, a lot of the variables that have been changing, and I think you'll see those in the slides to come, but it's definitely been a moving target, and it's taken a lot of work to get to this point, and I think you'll see that there's some significant decisions that we can have in the DME budget, which really are impacted by all of these. So here are the assumptions that we've included in our forecast for all of our scenarios, and what we really expect for next year in the budget, which 3% increase in projected demand, just strictly demand for next year, have a 3% increase. We are projected to continue the suspension of TCRF. We are currently planning to debt fund our entire CIP next year. This year we did have some revenue-funded CIP on the CIP side, looking to debt fund all of our CIP next year and in the out years of our forecast. We have no supplemental requests for new asks in the budget for next year, and we do have these two new solar resources with Laundry and Blue Belt II. The options for consideration, which you'll see on the slides to come, are rate stabilization. We are anticipating, if we kept everything stable, a significant rate increase on the ECA side. So we want to bring to you options on how can we keep that ECA rate stable, and then the second piece is that second bullet there, and really that comes down to how do we want to use our reserves, whether it's this year or in future years, to keep our rates stable and to plan for the future. So those are the pieces that we'll hit on in the coming slides. Here's some of those major budget variables, and I think Terry hit on a lot of these. We budget our debt revenues conservatively in the out years. We haven't got a full year of seeing how the debt runs yet, so we're still trying to understand how the debt corresponds to the market, but definitely in our future years, when you see our debt pro forma, have really stuck to conservative projections on what those revenues could be. We have a major variable as we talk through purchase powers, our renewable energy resource, the wind resources, and the faster renewable buildup, which you'll see as we get to the purchase powers slides. And then as Terry also mentioned, the decommissioning, the TNPA decommissioning, we have that. The cost associated from TNPA in our budget right now for what decommissioning would be over the next five years, they've given us dollar amounts that we've included in our budget to contribute to that decommissioning. That's definitely, as Terry mentioned, a variable that's out there that could change the budget in the out years if they sell, if they do get proceeds from a sale, it would negate some of those costs, but those costs would also fluctuate in the out years on what the actual decommissioning will be. So we want to touch first on our debt service for DME. We had a change to this '18-'19 budget for our debt service. What we anticipate to spend this year in debt service is going to be about $9 to $10 million higher than we budgeted, and that's driven entirely by our first principal debt service payment. And we've made interest payments up to this point on the deck. We have our first principal payment in December of this year, December of 2019. As with our other recent bond issuances, we had planned on making that payment in December and having that realized in the '19-'20 budget, that entire amount, which you can see there about the entire principal amount of the $6 million plus the larger interest amount. The bond language for this revenue bond is written differently than our other recent issuances, where instead of just making the payment in December in our bond confidence, it's required that we make a monthly transfer to our debt service fund in anticipation of the December payment. So what that does from a budget perspective is we get hit in '18-'19 for expenses we anticipated in '19-'20. So up until October 1st, up until September, we're now making that transfer, and the net impact of that is our '18-'19 budget is $9.8 million more in expenses transferred over to the debt service fund this fiscal year. It doesn't change, you know, when you take a big-picture view of our debt, of our debt service, what we're going to pay on the debt revenue bond, does not change our total amount that we're going to pay, but it does have an impact on this this year, and even as you look at a five-year window, it has that impact because you don't really realize that savings until the very end of the debt payoff. So that is a reality that we have to deal with this fiscal year, and I think as we talk to the ECA, that's where we have-- it really impacts the ECA rate. As far as budget appropriations, we're still within our debt-- for DME, our total debt service appropriations because we had originally-- our debt appropriations, we had originally planned to pay off the $28.6 million remaining on our TMPA scrubber debt. A few months ago, we stepped back when we were gearing up to make that the payoff of that debt, and decided to hold off on it, knowing that we had so many variables, and to take that large of a drawdown from our fund balance didn't seem appropriate, knowing that there are so many different piece-- moving targets, I think we're happy with that decision now that we've decided to hold off on that because it gives us these options that we'll talk about in the coming slides on what we can do with our reserves. We've also used this opportunity in the next couple months. We're going to be issuing debt citywide, and with interest rates being so significantly lower now than they've been in recent years, we have an opportunity to refinance that debt. So ultimately, we're going to, with the refinancing, save about $2 million on the remaining debt service for that TMPA scrubber debt as well. So that's given us that opportunity in the future to have a better impact on our forecast. The other large variable that impacts our ECA rate is purchase power. We are anticipating, in this fiscal year, in '18-'19, a $6.4 million increase in our estimated purchase power expenses. $4.2 million of that is incremental power supply costs from not operating Givens Creek in the summer of 2019. The budget, when it was developed last year, a lot of the assumptions within the budget still had that piece operating. So by not operating that, that's the increase associated that we're going to experience this summer now. And then also, we have $2.2 million in other incremental cost increase from market movement. I think this goes back to what Terry mentioned of really taking a different approach to how we budget purchase power and how we anticipate it, which we think is a better, more thorough way to look at our purchase power and meet our expectations. It has an impact on the out years as you see in '19-'20 with an increase, but it also impacts what we think we'll spend this year in '18-'19. So this $6.4 combined with that debt service increase is what you're going to see is that impact on what we have to have for an ECA rate this year and next year. In '19-'20, we again anticipate an additional $2.2 million increase in our purchase power based on our contracts, our market, and the demand associated with those. But then starting in '21-'24 of our forecast, we do see those, that purchase power amount start to decrease in the future years. So I mentioned ECA rate, the energy cost adjustment rate a lot, and I just wanted to just use this opportunity to step back and talk about what those are as we consider the alternatives moving forward. The ECA rate is really meant to, high level is meant to fluctuate with what are the actual costs to provide the energy. That number is going to fluctuate obviously year to year based on market and other contracts and different variables as we've seen. And so we look at that ECA rate as one that is meant to fluctuate with the market, whereas base rates are intended to be more stable and they have a lot of those fixed costs from personnel to O&M and all of these other costs that we've shown here that are included in the budget, whereas ECA includes purchase power. Our policy and our ECA policy, we have planned to pay for our deck operating costs, our debt service with the ECA, so those three pieces right there obviously have increased this fiscal year and are going to increase next fiscal year. So that's why we're seeing a higher ECA rate based strictly on what the costs are this year and next fiscal year. So here's our current rate recovery at a high level. We've highlighted the -- Sorry. Back up to the last slide. Yep. The ECA rate, I know what it is, it's very cost effective. Right. Why do we continue to include the debt service in the ECA? You know that's a -- Could you get closer to the microphone, Billy? Oh, sorry. Why do we continue to include the debt service in our ECA rate? You know, that's a great question and it was part of the policy that was enacted in advance of the deck was to say we want all debt costs to be part of the ECA and the theory behind that is the deck is providing energy, so any cost that we drive toward the deck would be an energy cost and also the cost that we have for the deck should lower what we have to pay on the energy side through purchase power. So it's definitely a policy discussion that we can have. If we want to, you know, we can kind of alter the way that we calculate the ECA if we want to have that discussion of taking debt service out in the future, but this is the way that we calculate it right now. Okay. Yeah. I think in the past, and it's been a few years, I was on this board a long time ago, but we didn't put those -- of course we didn't have the deck either, but it was about energy cost. Right. Debt service, I mean, is that energy cost? I think it's just how we define it because obviously the debt service is a fixed cost where it's not going to fluctuate with the energy, so that would be the argument to take it out where the argument to keep it in would be it's a cost that you have to provide the energy and I think -- I assume that was a rationale for including it in the first place. I don't know. I always thought of it as -- it was -- the ECA was the adjustment that it was predicted on the cost of energy that natural gas, fuel, whatever we were -- coal at the time. Right. You know? So okay. I think it's a good conversation to have. We don't have to have it today. Yeah. Well, I just say we've had this debate internally as well, and I think the issue is the deck is an -- it is a purchased power hedge. You wouldn't have a debt without the deck, and you can break it up. It's not going to move the needle. You're still going to end up with a rate at the end of the day on the base adjustment in the ECA. It's all going to come out through the wash the same, but you just don't have that debt service without the deck and that hedging without the debt service, so you can't untangle them. Theoretically, though, we sell the energy into the grid and not necessarily to ourselves, although we do own the deck. Don't get me wrong. The way we've been asked to present the budget with pro forma on the deck itself, I think what our concern is that everything be consistent, that it not look like we're trying to move certain costs into the base rate while cherry picking what goes in the ECA, and it's just -- again, it's going to end up at the end of the day in one rate. It may change the base versus the ECA, but the rate's going to be what the rate needs to be. I hear you. I just always thought the ECA was the over and above, and the debt that the city owes is the debt that the city owes. Granted, I'm saying now that it fluctuates, apparently, because it depends on the bond and what's going on. Okay. I'd like not to drop this -- I'll drop it today, but just continue that conversation. That's fine. Okay. So I wanted to paint a picture of what we look at, what we're looking at for this estimate and for our proposed budget in the future years. This is not our proposed budget. This is what over and under recovery would have. We kept our current rates out into the future, our current ECA rate shown there and our current base rate out into the future years. I think what you can see is, obviously, on the ECA side, we continue to under recover in the out years, and then overall, together with some over recovery to some extent, on the base rate side, you can see our total under recovery for the estimate, for our proposed 2020 in the out years, if we kept rates stable for the entirety of this forecast. Really, this is just meant to paint that picture of here's what would happen if we kept rates stable, and then we'll start talking through what are our options to avoid scenarios like this. So if we just kept our status quo, these are the options that we have moving forward. The first one really isn't an option, more just to paint the picture again of where we sit and what choices we have in front of us. If we kept everything stable when we said, oh, the base rates are going to stay where they are, the ECA rates are going to fluctuate as needed to cover this, the '18-'19 increase and the '19-'20 increase, we would see a 25% increase to the total residential rate. Obviously, as we talk through, we have significant reserves right now. We don't see this as a viable option. This is more just to say here's a status quo if we did nothing. So here's our plans and what we want to present to the board and to council for options moving forward to not have that large increase. One is what we're calling a phased approach, which would be to utilize 44.2 million of our total reserves and essentially just shift those over to help us negate the large increase in ECA in '18-'19 and '19-'20. We would ask for a proposed 1.5% increase in the ECA next fiscal year to cover some of that increase and not cover it all by moving the reserves over two years and then move forward. That's why we're calling this one the phased approach, whereas the no increase approach would say we're going to keep both our base rate and ECA rate stable next year. We have a total rate that's the same as '18-'19 and just utilize reserves over these two years entirely to keep that rate stable. But know that in 2021 we'll need a 3% rate increase, whereas in our phased approach we think we can do a 1.5% increase in '19-'20 and then a 1.5% increase in 2021. And the excess reserves coming from us not paying off that bond in part? Correct. So as we head into the '18-'19 budget, we knew that -- and you'll see our reserves are significant. We knew we had this large amount of reserves and we were trying to -- we definitely didn't want to just sit on our reserves and one of the options was we pay off the debt. By not paying off the debt, we've kept this reserve and now it gives us these options to deal with the ECA balance over '18-'19 and '19-'20. So here are the options just in numbers. You can see our projected fund balance at the end of '18-'19, $55 million. If we just kept the status quo, we would end up with about a $90 million fund balance because the ECA would cover itself and then the base rates would continue to contribute to that fund balance. So we do not want to do the status quo, want to emphasize that. So we've, you know, Xed out that status quo. That is not our recommendation moving forward, but you can see on this phased approach and the no increase approach that increase in the total rate, that 1.5% increase in the total rate between the no increase and phased approach next fiscal year and then you can see that our fund balance is utilized slightly more in the no increase approach, but we are still in both scenarios by -- despite drawing down that significant amount of reserves over to the ECA, we have a fund balance that's still, you know, well above our minimum reserve or our minimum reserve kind of fluctuates around $40 million, and these scenarios we still anticipate being around $50 million in our reserve. So it's not a situation where we're drawing our reserves down so much that we're under our minimum reserve balance. I just want to make sure I understand the no increase approach. So we wouldn't have an increase this year, but we'd have to have a much larger increase in subsequent years. So in our current forecast in 2021, we would need a 3% increase in 2021. I think our recommendation would be for the phased approach where we just do one and a half this year, one and a half the following year, and I think what that also does is as we -- there's so many variables out there from the decommissioning cost to TCOS to all the other variables we've talked through. So by doing the -- we can do the no increase approach, but it does put us behind the -- say one of those variables goes poorly and we have to make it up even more, maybe that 3% becomes higher to 5% or so. So by doing the one and a half now puts us in a better spot to deal with any variables in 2021. I always prefer smaller, little than a -- Yeah. Right. Right. One and a half percent, one time you mentioned a total rate increase or is it an ECA rate? It's an ECA -- just on the ECA rate, it just -- the impact would be, you know, on the total rate, but it would just be on the ECA specifically, no change to the base rates next year. So as we go forward, the phased approach is our recommendation, and as we show the rest of these numbers, really focused on the phased approach, but want to show you what the no increase approach would be. Here's just average monthly bill, what that would look like with that phased approach of the one and a half percent. So you can see, you know, going up slightly in '19-'20 and then again in 2021 where the no increase approach, you just get that same hit in 2021, you end up in the same place, just not phased to get there. And here you can see just the distribution on our out years of our rate between our base rate and our ECA. One thing that you'll see in 2022, we actually are projecting right now in our forecast a decrease in the base rate. As the ECA rate, you know, grows over these years, our fund balance continue and the base rates continue to over recover, we start building up that fund balance to a large number again. So for this forecast, we've said, we think in 2022, we can at least project for this forecast a base rate decline so that we're not continuing to just increase our reserves for the out years. This is a chart that we show every budget year just to say here's where we are versus other providers. So you can see here's our 2019 rate, here's what that no increase approach rate would be obviously the same and then our phased approach where we're still, you know, right in the middle or slightly to the top or the upper end of these comparison cities or entities and then if we kept that status quo, we just let the ECA rate go and we have that large increase, we would be down here at the bottom on that comparison. So a lot of numbers here, just our pro forma on that phased rate, a couple that we want to point out, you can see our fund balance in the ending next year at $50 million and then starting to go up over the next couple of years, 54, around $54 million and then after we have that base rate decline, it drops but it also drops because as we'll talk about later on our T cost and as Terry mentioned earlier, right now we're getting a large return on all of our T cost out of transmission assets whereas we are anticipating at some point over the next couple of years that will be reevaluated and that, you know, 28% will come down to-- right now for this model, we have in those out years, it dropping to 13% just as kind of a guess of where it might end up but that does have an impact on these out years in the model of that less revenue. You can also see the revenue funded capital where we're not-- we had, you know, focused on some revenue funded capital CIP projects this fiscal year, our plan in the future years is to debt fund those capital projects. So here's-- I wanna put this in here as just a breakdown of our total purchase power and this is before that debt revenue that we get to-- that offsets our purchase power just what that total purchase power looks like and I wanna point out, you can see here our TMPA amount that's included in purchase power, the $4.3 million, $2.8 million of that is for decommissioning cost, that's again part of that-- the schedule that TMPA has given us of 20, $22 million over the next five years that we'll be paying toward decommissioning cost. That number is gonna-- it varies through the year so it fluctuates from 2 million and then in a year or two, it's 8 million so it just kind of-- it goes up and down with the years, those are shown in our forecast but the first cost that we'll have next fiscal year is at $2.8 million and here's again on those ECA expenses as we talk through, here's our energy cost that are in the ECA that have always been the ECA that 44.96 and then you can see those deck expenses and the deck fuel that makes up the rest of our ECA that we have to recover with that rate. Just some dollars ago in this-- obviously I'll tidy the budget book that was presented to the board where you can see the base rates continuing to increase until we have that rate reduction with demand and then our ECA rates following accordingly to the plan that we laid out and we have a deck forecast later but you can see that we really have budget conservatively on the usage of the deck, that is definitely one that will continue to change in the next couple of years as we get more information on the deck but we want to stay as conservative as possible with those estimates. You can also see if you see that dip in the other revenue from 52 million to 34 million that has a few different impacts but obviously a large one is that TCOS, that TCOS piece. On the expense side, you know, everything is essentially in line on the admin and the power supply side and then the energy center will show later in a different breakout but you can see those expenses in the out years as well. So here's a breakdown at a high level of RCIP and definitely if you have any questions on anything in specific, we can get into those. We've just shown this at a high level here. We have all of the details as well if you have any questions. You can see we have increased the RCIP for distribution next year. This was another piece of that step, trying to take a step back and look at why we budgeted, what we budgeted last year, what was the methodology and a piece that came from that was that we really needed more dollars in RCIP devoted to distribution and so you can see that reflected here and in the out years and then on transmission as well obviously these assets in these next year and the following year are going to have that high rate of return with the transmission on the TCOS and in the out years it will be a little bit different. There's a lot to this slide. I think the easiest way to look at it is just what-- with each of-- on this-- when we look at our CIP for transmission, what essentially is our return on investment for what we paid towards transmission, all the debt cost that goes with those-- with that transmission. So over the life of each asset that we buy, what is our total expense over 30 years and then what is our total revenue as you can see in 2019, total expense on this 7.5 million in transmission CIP is 12.76 but because of our large rate of return right now, we anticipate to get 19.16 in TCOS revenue. So over 30 years with that rate of return, we end up in the positive of 6.39. That continues obviously throughout the-- throughout the forecast, we are getting a return on all of those transmission asset investments but it does change in the out years with a different rate of return used. For the position summary, we're not-- not anticipating too much new in the DME budget from a position perspective. We are increasing the proposed budget by two FTEs and these are really two plan operators that will work out at the deck. The deck, if you look at this current budget, we are having significant amount of overtime just to meet all of the hours that need-- that are needed for the deck to operate. So these two FTEs really make a lot of sense to bring in to help offset that overtime and operate the deck effectively and we're also transferring a position from our email group over to the deck for engineering needs associated with the deck. Here's our deck pro forma and I'll just touch on this high level and then I'll hand back over to Terry to talk through the deck and any more specifics but you can see as we're estimating this year, we are estimating a, you know, a net income loss essentially is one way to look at it. I think there's a lot of different caveats to look when we can talk through the deck and that Terry can touch on but as far as just what is the revenue we're estimating for the deck and what are the-- all expenses including the deck and this deck debt service is now included in the estimate anticipating a 2.4 million dollar expenditures over revenue and then each of those out years you can see with the conservative essence we have now how that-- how that comes out with that really increasing that-- that income loss increasing each year 8.9, 10.1, 12 and through the out years. I'm gonna hand it over to Terry now to talk a little bit more about the deck. Thank you, David. Okay, I mean obviously you can see here that the deck net incomes are decreasing over time. This is a reflection of the current forward curve. When we value the deck, we basically look at what the future value of energy is that can be produced from the deck during these out years and if I can just-- let's see, where are those other slides? Yeah, I need to get to the other slide. Oh, it's on the other presentation. No, this one right here. Yeah, that one right here. Yep. Thank you. So this is the forward curve and again you can see the shape of the forward curves here for power. This is the power forward curve and you can see it's decreasing over time. What we represent here is the on-peak price which is the Monday through Friday, 7 in the morning to 10 o'clock at night, 11 o'clock at night and obviously all the value is on these peaks in the summer, July and August is where all the value is. 90% of the deck revenue is achieved during July, August and September. So as these peaks go down, that represents less revenue option-- opportunity for the deck and that's why that net income number continues to look bad. The gas curve on the other hand does have a slight decrease through 2022 and then it starts to increase and this is problematic for the deck because as gas prices go up and power prices go down, we're effectively squeezing the margin, the gross margin that can be achieved by the deck. Now, the one thing that you'll hear me say, these two graphs in front of you are wrong. They are forward curves just like anybody's projection of the stock market, they're a guess. They are the best current estimate of what buyers and sellers would be willing to transact there. The other point I'll make is that since we only have, you know, very limited amount of data on operating the deck during the summers, there's significant available margins inside of the day. So each day as we offer the deck into the marketplace, it's based upon the price for the next day. Inside of the day, because market prices vary every five minutes, we could see spikes and we saw a couple this weekend, a couple $300 prices this weekend. We ran the deck yesterday most of the day because of the hot weather. That was not projected in these curves. So once we get through this summer and we see how it performs, we will hopefully be able to add some more value into our forecast for the deck. This summer may not be the best litmus test because it's been relatively mild. We've had a lot of rain, mild temperatures, healthy grid, healthy generation stack, and so we haven't seen much stress on the grid. So you know, the deck as a resource, we're going to see some low price years, low performance years, and then we're going to see some really good performing years as well. And it's there as insurance, again, to protect the load against those high prices. So I think that's the extent of our presentation. I'd be glad to answer any questions that you might have. All right. Questions? We must have done a great job. Or we're confused. We're still-- Totally confused. It's a lot to process. Yes, it is. But I do prefer that phased in. I've always preferred that. All right. Thank you. Next. Oh, you got more? Okay. I know there's a lot of information there, so we can definitely bring the presentation back at the next PEB meeting, if you'd like, just to have any additional questions. And obviously, we'll be coming back soon with rate ordinances and things like that that will be associated with the budget. So it won't be the last time that you see the budget. But if you'd like, we could just at least have it on the agenda for next time to answer any questions. I think I would like that. It's a lot to digest. Perfect. And then there was a closed session item associated with the budget presentation. That was really just in case you wanted to get into the PPA discussions as an offshoot of the presentation. But if not, then I don't think the closed session will be in this... Actually, I would like that. Okay. Great. Perfect. All right. Thank you. Thank you. All right. Consent agenda. Does any board member wish to pull an item from the consent agenda? All right. Then, do I have a motion to approve items A through G? Second. All in favor, say aye. Aye. Motion carries. Items for individual consideration. The Public Utility Board's minutes of June 24th, 2019. Were there any changes or corrections? Hearing none, they'll be approved. What's the right wording? ACM update. Good morning, board members. On the ACM update items, you have a few items in there. Quarterly financial report ending March 31. That's just more of a four-year information. If there's any information that you would like after reviewing that, we'd be more than happy to get that for you. I was looking at that same report this morning. Ethan Cox, Director of Public Works. I need to go back and double check those tonnages to make sure we're not reporting net versus gross, and that's maybe some of the imbalance there. Typically look at those reports from our processor on a monthly basis. I did see a couple months ago that our gross tonnages were going down, but what that is is our contamination rates dropping. I need to go back and double check and make sure that we're not reporting two different data sets on that table. A drop in contamination rate is good, though. It is a very good thing. We're from 35% down to 25% the last month I checked. Let me double check on that and I'll circle back on a future ACM update with any changes. I was wondering what the source of revenue was for recycling. Is that just part of the solid waste fee? No, we actually have revenues that we get for the sale of commodities through the market, so if it's something that we sell directly through a scrap metal outfit, some of that comes directly in. The others is basically just a profit or revenue sharing through our agreement with Pratt Industries. It's also a portion of the fee, though. Really what the fee is designed to do is the collection of recyclables, so running the trucks up and down the street. There is some revenue coming in, but we don't count that as recycling revenue, per se. The recycling revenue itself comes from the commodity sales. So obviously if our recycling tonnage is down, we might want to get out some education, maybe increase that. Yeah, those percentages are a big shift, and so I need to go back and double check that and I'll bring that back to the board for you. All right, great. Thank you. I have a question. We stopped getting recyclables from other municipalities, though, right? Didn't we do that? Weren't we getting recyclables and charging a scale fee for those things? Or were those calculated? According to our recycling contract with Pratt Industries, we can accept or they can accept recyclables from other communities. We've never counted that in terms of our tonnages. However, we do get a $5 per ton fee for anything that they collect from other communities. They've scaled that back greatly. Number one, they're having a hard time moving stuff in the market, and other communities have contamination issues just like us, some much, much worse than us, and so Pratt's been very selective in who they partner with. They want to make sure they're getting clean materials and that they can move it in the market. But that wouldn't have been attributed to the decline that she's talking about. Not that I'm aware of. Like I said, I'll take a look at the data and make sure that's not the case. And if I remember, you had the question on the Valet pilot project? Me? No questions. Yes, that information has been provided to you. And if any additional questions that you might have, we'd be glad to address those. The only other two items are the future agenda items. I've got a list there for you. The report on the solid waste Valet collection was obviously provided today. The report on the DEC is actually a part of the presentation that was given today. It's a part of exhibit five for the DEC dashboard. So if you do have any questions on that, I'd be glad to get answers for you. And then we have a pending item on recycling. And we also have an item pending, item one reviewing the changing the time for the PUB meeting to 9 a.m. for both meetings instead of a 9 a.m. and a 6 p.m. So we'll work on getting that scheduled going on to the future agenda items. We did review the electric budget today. So that one's been taken care of. We've got two upcoming sessions that are going to be heavily focused on the budgets and rates. So the July 22nd, we'll be looking at the rate ordinances, which will basically be your first opportunity to see the rate schedules and kind of what those are looking like based on discussions that we've had with the budget. And then on August 12th, we will actually be, if all goes as planned, we'll be bringing forward the utility rate ordinances for water, wastewater, customer service and solid waste for a recommendation for the board. And that is all I have. Okay. Concluding items, then any board member wishes to have something brought put on the agenda in the future? I don't want to put anything on the agenda, but I just wanted to make an announcement. I've had a really good time working with all you guys, but immediately following the closed item that we're having, this will be my last meeting. But I have had a great time. It's been almost four years. Worked with some of y'all a short period of time, some of y'all longer, but got some other things that I want to experiment with and I don't feel like I'll be able to meet the attendance requirements. And so this will be my last meeting. All right. I'll miss you. So thanks a lot. Thanks y'all for working with me, teaching me all kinds of stuff about electricity. I appreciate it. You can take my share. But thank you very much. And I'm always not sure how I do this, Larry. So do we adjourn and then go into closed session? Okay. So do we have a motion to adjourn to go into- I'll make sure we adjourn one last time. All right. Do we have a second? I'll second. All in favor, aye. Aye. Now I do have to read what the closed meeting is about, correct? Okay. Deliberations regarding certain public power utilities competitive matters under Texas governmental code section 551.086 to deliberate and discuss competitive information regarding the public power operational and financial matters pertaining to the purchases and risks of wholesale energy supply and pertaining to the proposed electric budget.