 Start the meeting this is the monthly meeting of the Board of Commissioners of the Board of Elections Commissioners in Burlington. We hold this meeting the second Wednesday of the month at 530 here at 585 Pine Street. As always, Burlington residents, ratepayers are welcome to come down and join us, join the conversation. We welcome your comments, questions and concerns. So let's start us off here. The first item on the agenda tonight is the agenda. Are there any changes, revisions or anything? I don't need to add to it. Okay, I'm going to move on to number two. Minutes of the January 11th, 22 meeting, 2023, either. Are there any substitutes, changes to the minutes that you brought up on the board? And if it's just a clerical thing, we can do that, just between you and the clerk. Anything of substance? Nothing, I'll entertain a motion. Make a motion to approve the minutes for January, 2023. Second. Motion is second. Discussion on the motion. Hearing none. That's where we're going to move on to the next item. Oh, yeah, I'll hear, yeah, I'll take a vote. No, I'll take a vote. Seconded. Yeah, that's it. Passes. All in favor. Say hi. Yes, all in favor. Aye. All right. Item number three is public forum. Are there any members of the public? I see no one in the audience. Are there any members of the public online? No, it's not seeing none. Already, I'll reiterate that we're here the second Wednesday of the month, 5-5-5. As always, it's an open meeting. You're welcome to come down. Any questions, concerns to the department or the board? We invite you and welcome you all here. All right, on to item number four, commissioners' corner. Do the commissioners have anything that they would like to discuss that's come up in the next month, last month or so? No, most not. Well, I will ask about the lighting. Hopefully we'll have something for us on that. And is that it? Anything? All right, on to the GM update for yours. Thank you very much. With regards to lighting, I believe when you're working to schedule a meeting, but that there has not yet been a meeting scheduled. So that's all the update I have for that item. The top item in the update is relates to this statement that we put out along with IPEW last week related to a proposal in Montpelier to change Vermont's renewable energy standard in a way that would eliminate eligibility for McNeill to count towards Vermont's renewable energy targets. And overall would do something that I think is relatively unprecedented anywhere in the country, which is to say to a utility like BED or washing electric co-op or swatting, we're all 100% renewable already, that you now have to change the way you're 100% renewable and drive up costs for customers, for us, perhaps tens of millions of dollars of additional power supply costs when at the end of the day, you're still gonna be 100% renewable, just in a different way. So to me, that's a fairly concerning policy proposal. We had a fairly strong statement with a lot of good information and data in it on McNeill, sustainability, air emissions controls, jobs and economic impact, and carbon profile. So we're engaging heavily in that discussion in Montpelier. There's also the city council has a transportation energy utilities committee that is planning in April to have some sort of meeting focusing on McNeill and looking at it, I think with the lens of whether district energy is a good thing to have happened or not, whether the plan should continue or not. We've submitted a list of folks who we think would be good to participate in that meeting. The irony of all this is we've submitted now the Act 250 documents for district energy through Burlington District Energy, our non-profit partner run by Evergreen. So at this moment where we have this long held community goal of trying to make district energy happen, feels like there's a particular amount of discussion around McNeill's operations in general. I would say that this proposal by Renewable Energy Vermont hopefully won't pass as written, but there seems to be some interest particularly in the house this year in doing something on renewable energy and we're gonna be engaged. This is a rare instance where I would encourage the commission to be engaged as well if you see fit. Legislators are gonna be interested in this. Our local city councilors are gonna be interested in this. So I think hearing not only from us and not only from the IVW but hearing from the commission about the importance of McNeill and the importance of giving early adopters like the credit for the work that we've done and not forcing us to abandon existing cost-effective resources for more costly new resources will be an important message to share and I'd be glad to work with the commission or individual commissioners on avenues for sharing that message. So there's gonna be a lot more to come on all of that but I didn't wanna leave with that item. I can pause there if there are any questions. I think at the very least we should craft some sort of a statement. That'd be great for starters. That would be great. Very much appreciated. Yeah. Just at the top of my head, I'm sure we could take that a little further. No, that's just for starters. We'd welcome that. I saw the links to the news coverage is there a deeper dive that talks, I mean, I'm sure we can find it in the, is there a easy link to understand the deeper dive of like, though, is it directly related? Is it a collateral to damage of the greater policy change? Like can we understand a little bit deeper? What were the, how did it manifest of meaning this be the dramatic shift? Yeah, there's not a media piece yet that really goes into that level of detail and the proposal that they made that they announced at their press conference, the bill has not yet come out. And we're continuing to actively engage to advocate for some of the things we just talked about. There will be a bill that will come out. But really, if I could summarize it, the proposal that they have would say that all utilities by 2035 can have 40% of their resources from what we consider existing renewables, which means for us, and it's 2023, that in the next 12 years, we have to get 60% of our energy from quote, new renewable resources. And they would, this is to me a little bit of gimmickry, but they would propose to change the date of what counts as new renewables in Vermont law from 2015 back to 2010, which may advantage some utilities over others, depending on what investments you made between 2010 and 2015, doesn't help us with resources that McNeil or Waduski won that are older existing renewables. And then either way, because we currently are able to participate in the New England markets with a number of resources, it would change not only potentially our generation mix, but also our rec mix, what we're able to keep, what we sell. It would phase out eligibility for McNeil relative to Vermont, which may be a market that we wanna use for McNeil recs in the future. We've talked about that with the commission. Then really, if you think about the tens of millions dollars in costs, it's gonna be tied to that change of saying right now, under Vermont law, we have to be 100% renewable generation and recs. And then we're able to be exempt from certain pieces because we maintain that level. And of course, BD is actually more than 100%. But under this, we'd be looking at adding new recs to the mix, potentially new resources. And I might be conservative with the tens of millions, I think it could be significant. So we're also gonna seek some analysis on this piece in as short an order as we possibly can to try to inform the discussion as well. And we'll share that with the commission, of course. Again, that's been in the shed. Is the general view about carbon or is it about something else? I would submit that this bill proposal, which is being submitted by Renewable Energy Vermont is about solar. Solar developers want more opportunities to build solar in the state of Vermont. And they feel that the existing markets are not giving them as much runway as they would like. Because according to all the data I'm familiar with from the state and the energy action network, the electric sector now constitutes between one and 2% of carbon emissions in the state, transportation and thermal are 75% roughly. So it's hard for me to understand if it's really about carbon. I think it's really about solar development, which has its own benefits, but needs to be done in a cost effective way, in a way that drives up rates significantly and adds to costs in our view. Yeah, that answers my question. I was gonna ask if it's a stake in the ground where they're asking for innovation or if it is like built on understanding maps market transformation, like maps known technologies, but mobile item works. Yeah, just rough numbers. The existing renewable energy standard drives roughly 40 megawatts a year of distributed generation solar development through a variety of programs, net metering, power purchase agreements, the standard offer program, 40 megawatts. We had roughly 20 megawatts of solar in the entire state around 2012. We have about over 400 today, and it's a thousand megawatt system roughly. So you could have potentially on a day where solar was performing at its peak and could provide a significant portion of the energy. But of course, solar has a unique profile. It's gonna produce more in the summer than the winter. It's gonna produce obviously during the day and not in the evening. And it doesn't necessarily align perfectly with where the region's cost drivers are, which tend to be in the winter and in the kind of evening hours now. So solar has a great role to play. We're a huge fan of solar. We will support solar anywhere in the city that we can add it to our mix. And we've been the top city per capita in the Northeast for a number of years now relative to solar according to Environment America. But what I've heard from the developers is that the PUC is telling them in some cases with projects that they may not be necessary because Vermont's driving 40 megawatts a year of solar and that's consistent with our current policy. And so they wanna change the policy to say, no, we need to have, I don't know, 120 megawatts a year of solar, which is a different discussion. And if we see load growth and other things, that might be interesting, but currently this utility, even though we're trying to drive load growth through EVs and heat pumps, we're not seeing it materially yet in our sales to customers. I don't think other utilities have seen it quite yet either. So it's really like, how are we pacing the development of new resources, the grid and the cost to customers that I think should be the key driver of the conversation? Thanks. We'll be glad to follow up on that. It's not all bad news in the legislative context. There's some good things happening as well. And I was down in Montpelier yesterday, we testified in favor of the Affordable Heating Act, which is a potential kind of complement to the RES on the heating side. It includes currently eligibility for renewable district energy as a credit. So our district energy system would be potentially included in this. It includes a variety of other measures that are fairly consistent with what I think we're growing and is doing. And the main focus of the utility testimony, not just us, but others, is trying to make sure it aligns well with our existing incentives and how the process will play out at the PUC for determining that. But we have confidence that that will work well. So we're hopeful to see that move. And I think the committee has a markup scheduled for later this week. And then after that happens, I believe we'll be working with Efficiency Vermont on the Act 151 extension to let us continue to use our efficiency monies for innovative programs, which we've talked about as well. So on to other news, Emily will probably touch on this more in the financials, but I did want to signal the commission that we are having a warmer than expected winter. As you may recall, when we did our budget, it was really based on the idea that energy prices were going to be fairly high during the winter period. That's not materialized in December or January. It materialized momentarily over the weekend when we had the cold snap. But we're back to a period now where prices are frankly at levels that we don't always even see in the shoulder season. And this is during the winter. Temperatures in Boston are consistently exceeding 50 degrees. So for the region as a whole, that might be a good thing to have lower prices. But for us in our budget having planned for the higher prices, it's not a positive and it's challenging us relative to certain metrics and is informing our determinations on the FY24 budget that we're working on now. So I wanted to flag that. Obviously we're doing what we can. We're gonna be running McNeil some of the time at 40 megawatts instead of 50 to conserve wood supply for days where there is higher price or perhaps for the shoulder season when there might be the opportunity to have more production that wasn't budgeted. So we're gonna do what we can in deploying McNeil to mitigate. But I think this budget has been more determined based on those energy prices than any budget. I've been part of it, BPD. And to date it has not been in our favor. So you'll see some of the impacts of that unfortunately in the financials. The strategy mentioned the Act 250 document is in. So what that is is a jurisdictional opinion. It is from Jeff Hand who's a lawyer at Firm here that's well known for their work on renewable energy at the PUC. Or essentially asserting that it is a municipal project. It wouldn't be subject to full Act 250 permit but would it amend existing permits at UVM, UVM medical and at city properties. That may or may not be accepted by the district. If it's not accepted, we would have a full Act 250 process. If it is accepted, we'll have a process focused on amendments. But either way there will be process with Act 250. It's a momentous step. We've never gone here before with district energy. We've never been designed far enough along for this to happen. We have some other kind of activities going on. We're working closely with the state on options for financing that would be at maybe a lower rate than what we're seeing in the markets right now because that's a potential cost driver for the project, these high interest rates that we're seeing. We are working with the federal government to try to bring in the leaky funding, still waiting on the deepest determination there. And then the DPW in the city has been working with the Evergreen team to try to make sure that we're aligned well on the impacts that there might be from the project and how we work with the water department with DPW on streets to make sure that's all working correctly. And I think next week, I'm gonna be presenting at UVM medical meeting with their neighbors that they meet with monthly on different projects. So that'll be a nice step as well. Financial piece is still moving. So there's still work to be done there. So it's not an end deal yet, of course, but we're continuing to make pretty steady progress on this. I'll pause. I still have a question. No question, okay. I'll continue. Just two other items for me, both of which we had press events for in January. What I understand is now gonna be ballot item two on the town meeting day ballot is the item that we've worked on with the department of permitting related to the carbon pollution impact fee for new construction and large existing buildings that don't go with renewable technology. We had a nice event at Hula, which is geothermal heated and cooled. We had some Burlington high school students from, we've been part of the city and lake program and we're seniors at DHS who spoke. We had a deeper renewable energy per month and the NRC on the environmental community side supportive of the initiative. And then we had our partners from the building electrification Institute who were joined us remotely to talk about how this work fits with other work that's going on in other communities. So big items coming up in just about a month now on the town meeting day ballot. And we're not, we don't advocate for these items as the city department. We just provide information, factual information about the items. So we'll continue to offer information where it's helpful, but it's now in the kind of the voting process. So we're not going to be really engaged on that side of things in any way. So we'll see, we'll see how that turns out. And then lastly, a little bit earlier in January we had our announcement around our incentive programs for 2023, some updates and changes in the new wrap tariff, which is now signed officially. And thanks to Emily for a lot of work on that back and forth with BHF-A as well as James, Chris and others. And so now that program is available. We are officially partners and we had referenced it earlier in January at the press conference, but now it's going to be an item that we can support customers in terms of on-bill financing for heat pumps and waterization for qualified customers. So another good tool in the toolbox. And we're working as well, as I mentioned here on a heat pump pilot for designing a potential future heat pump bill credit or rate. I am one of the customers who are going to participate in this pilot and to volunteer. So we're going to see if we can kind of look at the real-time data from the heat pumps and have the ED send signals to the heat pumps to be able to reduce energy use in certain quantities, not completely obviously, during peak periods in the winter and summertime. And then we're going to use that data to try to drive a design of a program to benefit customers in the future. And I'm a volunteer too. Yes. James's heat pumps are also signed up as well as mine. That's everything I've got. Excellent. Any questions? So in the last thing you mentioned, the wrapping. So I've been in touch with Brian in energy services and I'm going to see if everything works out that I can be one of the first people to take advantage of all of these things. Excellent. Weatherizing and pumping my house. Excellent. We'll see what happens. We're at the start of our experience. Yeah, exactly. So we're at the start of our journey with this. That's great. See what's going to go. Thank you for that. Yep. Okay. Next would be item number five. Item number six, rather, the FY23 financials for December. Emily. December FY23 financials were materially worse than budget mainly due to lower than budgeted energy prices. And I can tell you now that January is going to be materially worse. Worse than this. And yeah, so I think we talked to the commission about the unprecedented nature of the energy forwards, volatility, we knew that there was a risk of a mild winter affecting our power supply and it's been a mild winter. So here we are. So we as a management team will be taking actions, are taking actions, but we'll continue to probably spend serious time on this over the next few weeks to figure out how to respond to this and in particular preserve cash before the remainder of the fiscal year. So what I'm going to share with you isn't great, but I'm just letting you know that next month, my story will be even sadder, unfortunately. Question. Yes. In this table, it's like a big hit is from power supply expenses, considering the agreement we thought. And I heard you say was we had a problem selling the stuff. So I'm not sure if you can answer it. Yep. Let me walk you through. And then when I, if after I cover the power supply, I haven't answered your question. Let me know and we'll come back to that. So for the month, we had a net loss of $66,000 compared to a budgeted net income of $434,000 or half a million off for the month of where we wanted to be. For the year to date, we are just under a million dollars off with a net loss of $921,000 or the year to date versus a budgeted net income of $712,000. So walking through the details, sales to customers are generally speaking right on budget. They're up and down, but generally speaking, we're only $200,000 off for the year. We had a positive variance of $53,000 for December and that's generally like, that's really great, you know, as these things can go. Other revenues for December had a positive variance of $146,000. Most of that returns from the EU fund draw offset by EU expenses on the expense side. There were no rec revenues in December as was budgeted. Now moving to power supply expense, which as Commissioner Harrington noted was $913,000 worse than budget. So power supply, as many of you know, is a combination of several different elements. And so for December, wood fuel expense was over budget by $350,000 roughly. Part of that being due to the price that we're paying is higher than budget in order to ensure that we have adequate wood supply. We also ran McNeil 18% more than budget and so therefore we expense more wood fuel. That's one element of the 913. Purchase power, second element, was $580,000 worse than budget. Within purchase power, there are several subsections. One is capacity and that is where the unanticipated payments for mystic are coming in. So there was almost, most of that 150 was $147,000 capacity payment from the mystic plant. And then energy charges were also worse than budget by $242,000. Of that, 147 was related to the ISO exchange. And what we had happening there was we had a positive volume variance because we were running McNeil more than we had budgeted. So we had more energy to sell. However, the price was a lot less than we had budgeted. So the positive volume variance was more than offset by a negative price variance. And then transmission actually helped us that was slightly, slightly better than budget. So I'll just pause there and commission our hand in. Did that answer your question? Sorry about it, you still don't see it. Most of those numbers you just mentioned, I can't even find. Well, they all sum up the net to the 913. The biggest one is? Of that 913. Biggest one was purchased power. The combination of capacity and energy. But actually, I get prices are down because of the one winner. Yes. We bought lots more because why? We what? Why didn't we buy more? We didn't buy more. We sold at less of a profit, you could say, right? So... What did you call that an expense? Yes. It's a variance. We had budgeted for a positive expense variance, you could say. Instead, we had a real expense as opposed to a negative expense. Well, sales is an intake of money. Expenses is an outflow of money. Yes. But when I look at this table and then I listen to you, I'm hearing it doesn't work that way. Yeah, I mean, I see your point. I see your point. We budget for the excess energy that we sell through the ISO exchange as part of the power supply expense budget. Yeah, the power supply expense, it might help them lead to remind folks, is net power supply expenses. So it's power supply expenses, net of power supply revenues. Which includes both rec revenue and any excess energy sold on the ISO exchange. So a sale to customers, not a power supply revenue. Correct. Correct. So and it doesn't help you to produce less energy because, because... Well, the real question... You're selling at a lower price than you anticipated, but you're still selling it. So instead of making $1 on every unit, you're making... As long as the marginal price is above our marginal cost, right, and then you have to factor in the recs that we generate, which are then available to sell. As part of that, then yes, you're right. However, we have been watching the prices and positioning the plant to conserve wood so that we're not running full tilt. So to speak, so that in the chance that prices in March, April, May, or June are better than anticipated, we will have wood supply to run then. Which is running full tilt now, we'd expect to kind of be out of wood by the end of March. Just a quick note. That's true. Everything we said for units where we can control the output. So if it's a contracted resource like a wind resource or a hydro resource, there's either no variable cost in the case of a hydro, say, or we're not able to interrupt the output of the wind resources under contract. So, but yes, in general, we are not losing money. We are making less than we thought, materially, so. I'm embarrassed to, I guess it's clear I have never understood this after all these years. So when we take the difference between operating revenues and total expenses and come up with operating income, which checks with what I would normally think of when I said operating revenues sounded like expenses and didn't include income. So it's still confusing, but that wasn't a question. I knew you could say, okay, so you're confused. Let's move on. Well, I would offer that if it helps on, I think it's page seven every time of the packet. Let me see if I'm right, or of the financial packet. Yes, on page seven of the financials is a breakdown of net power supply, right? As James said. So that includes both the expenses of power supply and the revenues of power supply. Can you switch to the power supply detail for a second? Maybe Emily too. The purchase power detail? I'm on the page. I'm actually going to ask, unless other people are worried about this, it sounds like I have to do some homework. So I'll do it. Okay. And I'm happy to have you give me a call so we can go over in detail if you want. Yeah, yeah, I would refer you to pages kind of seven through nine where the detail is laid out and then certainly let us know the other questions. But it does seem like the worry is, so what is this mean to like the rate payers? And BED is an agency, right? Which, but I think a lot of what? We are interested is the impact to the residents and the people in Wellington. And of course it's kind of like a bad time because we just had a rate increase. We've asked for a lot of money and the communities who invested in BED and so to be have this deficit at this moment is unfortunate, yeah. Definitely, definitely. So that's what you all are going to do, say like which levers you can pull and push? I want to, yes. In certain years there are more levers you can pull and push and I think we're a little constrained at the moment both because given so much variance was on the power supply piece, there are very few pieces of budget that you can change that have an equal impact to the power supply piece. And unlike prior years, much of our capital budget is revenue bond projects. So they're going to be reimbursed but deferring and canceling them doesn't really save money in the long run. In prior years where we've had a capital budget that wasn't based on the revenue bond, deferring projects might save you on your cash and be worthwhile. So we're going to look at everything. We're going to look at even things like towards the year and making sure that revenue from expenditures that we make are able to be reimbursed in the same fiscal year so that we can bring an appropriate amount of cash on hand in the next fiscal year. So we're having monthly executive team meetings with the finance team and the policy planning teams, staff to go over opportunities to reduce expenditures or occur expenditures. But I am concerned because this is barring a change in the weather and a change in prices. Our opportunities as outlined are really limited to kind of change the power supply trajectory. And it's one thing if we don't quite hit our net income metric or our adjusted debt service coverage ratio metrics, those are unfortunate potentially and that's something that we welcome. The bigger concern is going to be cash on hand heading into next year's budget. We strive to maintain the 90 days cash on hand. That's the A rating metric for Moody's and we feel is a safe metric up for BED. And just maintaining that this year under this circumstance if it continues is going to be a challenge. And then that also puts additional pressure on the next year's rate requirement as well. So it's something to be. This is going to be a big part of the budget discussion going forward unless the dynamic fundamentally changes in the power supply piece. Yeah, so tough conundrum. Yes. So you can, and then I think also that's why the public also gets frustrated, right? Because I said, don't do the streetlight projects, right? Save that money, but you can't do that because that's a different plan. I know that may or may not be a good light example, but I know capital and operating are often really separate for publications, I guess is my point. Yeah, and the streetlighting, while there's some expense, wouldn't be at the magnitude. You're going to be deferred all of it that it would probably solve this problem. But if we had streetlighting taken away from us as a responsibility, probably being that positive from an economic standpoint, we'd welcome that if there's interest. But absent something like that, it probably wouldn't have the impact financially to make a huge difference, unfortunately. And then are there any lessons? Like, do we gamble too much on this, or? The challenge, I think, is the timing of it. Because when we're putting together the rating case, the forwards were very high. And you can't go into the public utility commission process with the forwards being that high. And if you're attempting to be more conservative, it may not play out kind of correctly in the rate process. And the one thing I would say is we don't have what some of the utilities that are under an alternative regulation plan on our investor, like Vermont Gas and GMP, have a fuel adjustment clause. So if you're a Vermont Gas customer, you'll see that the commodity price changed and the gas rate changed earlier this year, or I should say later last year, when there was upward pressure. And I think on a recent bill, I saw that the commodity price changed and the gas price is going to decrease. And all of that happens relatively automatically at the public utility commission. We don't have any of that. So we are under a traditional rate making process where each year you go in with the numbers that you have. And they may change. And there's no real mechanism to adjust the rate need or have any sort of supplementary charge for a period of time to adjust for fuel costs. Or they also have storm adjusters in some cases as well. So that would be a nice tool in the toolbox. You might be able to, if you were looking at something like this, you might have been like, OK, we're going to have a temporary surcharge during this period to cover the cost, the differential. But then it's not going to necessarily affect our cash and rate needs for next year. And unfortunately, that's not the way it works for us. So it will affect those things. And that's something that not only we looked at, it would require legislative change, but a charter change and a vote. And it's a lengthy process. So not something that would be an easy tool to access for us, unfortunately. But it would help resolve this issue a little bit. We're going to do everything we can. We will have a rate requirement for next year. There will be a rate change for next year. We'll do everything we can to keep it as reasonable as possible, given the various dynamics on the power supply side. And I think if we see forwards for next year that looked like the forwards this year, we would probably advocate for being more conservative with them in the process. Whether that gets upheld in a rate making process is to be determined. It's still complicated, right? We're paying extra to have additional fuel supply on hand. But then prices are really, it's hard for me to keep it all straight, but. Again, keep in mind, we're not operating at a loss. We're just not operating at the desired profit. Yeah, it's a frustrating dynamic. And all things equal, if the prices had been higher this winter, we'd be going into the next fiscal year with a larger cash reserve. Our rate need would be lower. It would be beneficial for our customers. We're not in that place at the moment. Inflation is still fairly high, still impacting supply chain. We do have labor cost increases and other things that would drive a rate need regardless. So the question is, how much can we mitigate the impact of these changes, both in this fiscal year and in the next fiscal year? I mean, the numbers that were included in our rate case for the value of selling this excess power for January and February are roughly four times what it's actually been coming in at. So again, it's coming in at above variable cost, but it's coming in at a quarter of what was expected. So that's how big a change this is. The rest of the numbers here pale by comparison. But I'll continue to walk you through them a little less. Other operating expense other than power supply had a relatively small variance of $136,000 over budget, largely due to timing. Moving down out of the operating piece into other income and deductions, we had a positive variance there for the month of $346,000. That's a combination of things. Interest rates have gone up, so interest income is higher. Gains on investments were higher than budgeted. And our miscellaneous non-operating income is also higher, driven by customer contributions to capital projects. So as I said at the top, in sum, we had a net loss for the month of $209,000 and a net loss for the year of $921,000. Moving to capital spending for December was $4.2 million to date compared to the budget for the year to date of $5.6 million. As Dara mentioned, we're continuing to see supply chain delays of getting materials. But we are keeping projects moving, ordering well in advance and being creative with our planning and procurement strategies as well as we can be. The cash position for the department as of the end of December was $4.7 million. That is well below the budget target we had for December of 8.9. That is the impact mostly of the lower energy prices. I can tell you that cash improved for January a little bit by about a million dollars. Still well below where we'd budgeted it to be, and it's well below where we need to end the year to have 90 days. So we'll be taking steps in the next month or so to preserve cash. That is my report unless there are a few other questions. I've never seen that before. So just another healthy four or five more million in there. I've seen it as high as 12, so it's a bit scary. So that's my last year, I think. Yeah, 10 to 12. 10 to 12 in the US. Any questions for Emily? Thank you. Yes. Next thing would be the IRP forecast update. And this is James. Can I hear you, sir? Still can. There we go. No, definitely. That was joking. Sorry I'm not there in person. Normally I would prefer to present in person, but I'm sick and you definitely do not want to get whatever I've got. We wanted to come in and give a brief after the last commission meeting where there were some questions about the IRP. We wanted to show some information on where things stand. In particular today, we're going to talk a bit about the forecast and some of the key driving variables and where our forecast cases are landing on those variables. Because we have a couple of new commissioners. Emily, next slide, please. I'm going to remind folks what is an IRP. That is a triennial utility obligation created by 30 Vermont statutes annotated to 18C. I had to look up triennial to make sure I got that right, but it is triennial, not triennial. And you can read that at your leisure. We'll be sharing the PowerPoint after the meeting. We'll share it with Lori and she can circulate it. But it's really just a plan for meeting the public's needs at the lowest possible lifecycle cost, but including environmental and economic costs. And really, you have to consider all types of investments. So energy supply, transmission, distribution, transmission, efficiency, and then consider those economic costs in relation to those four criteria. It's, next slide, please. It is perhaps as interesting to talk about what is an IRP not. And an IRP is not an actual approval to undertake any of the actions that the IRP or the plan concluded were appropriate. So when your IRP is approved, if in your IRP you said, you're gonna pursue a new wind generating station, that doesn't get approved. That's not what is being approved when the IRP is approved. It's not a determination of prudency with regard to any action with respect to rate recovery either. So you can have actions in the IRP that is approved, that is an approved IRP that you then may have to seek permitting approval for. You could be chastised in a rate case for it being an improved decision. An IRP is not protection against any of those things. And so, if something requires PUC approval, like building a generating plant, it will still require the same PUC approval, even if it was included in an IRP as an action step. It does have the advantage under, whoops, I'm sorry, I wasn't able to go back for a sec. 30VSA 248 does have a little context that says, with respect to, and 30VSA 248 is the Certificate of Public Good statute criteria and statute criteria number six, which is one of the things you have to satisfy, says that with respect to purchase investments or constructions by a company is consistent with the principles or resource selection expressed in the company's approved IRP. So really, approval equates to approval of the decision-making process described in that IRP, not any of the results. And honestly, if you had concluded something, but an assumption needed to be updated before you made a decision, and you didn't do it, that would be imprudent. So an IRP is a snapshot in a moment of time of how you make decisions about resources and how you balance them against each other. Next slide, please. So for the major statutory components of an IRP, and these are pieces we'll be bringing to you, the forecast is certainly the primary one, that's a primary input, and the forecast is telling you what load you're trying to serve. The forecast, in our case, is actually net of energy efficiency, effectively, because the target for energy efficiency is decided in a second process called a demand-resourcing plan. So these are two disconnected three-year processes, one of which determines the appropriate amount to spend on energy efficiency, and the other does really everything else. So we inject the amount from our most recent DRP as a reduction in load forecast under our integrated resource plan for energy efficiency. So we're not really trading that off against anything, and the target is maximum achievable potential, so you really can't change its amount all that much, even if you want to. You are doing resource evaluations, and there are trade-offs. So for example, if you could do more energy efficiency, you could consider that an alternative to buying a new resource. If you needed distribution upgrades, you could potentially consider demand response and lowering the demands that you're forecasting, a trade-off against distribution. But the distribution evaluation is a very big piece of it, and that certainly was a major focus of the last integrated resource plan, where we specifically looked at significantly increasing loads, loads increasing well in excess of anything we'd ever put in an IRP. In particular, we'd never done an IRP at Burlington Electric before the last one that considered loads in excess of 80 megawatts. The last IRP had a case at 102.8 megawatts, and that would be a case driven by significant new electrification loads. You consider the economic impact of the choices you're making, and so for example, you would be looking at an energy resource, and you would say, based on all of the assumption in the IRP, would investing in this energy resource increase or decrease the economic impacts on my customers under these various cases or various assumption sets? And you do try to develop a rate trajectory, and you're looking for something that, a sort of total plan that yields the lowest rate trajectory while accomplishing your goals. We do also look at environmental impacts, and we can look at them both from a monetary point of view, if there is a monetary market that captures that value, or we can simply look at it from a carbon dioxide emissions point of view, even if there is no market, and we could assign a value to that, but it would be a non-economic value if we did that, it wouldn't go into the rate path. So unless there's a way to monetize it from a rate path point of view, you can consider it, but it won't affect your rate path directly. It might affect your decisions. Next slide, please. The DPS issued new guidance for IRPs on December 30th, 2022. That is an update from the prior 2016 version which governed our last IRP. This is not an exhaustive list of what they've added, but it's some of the more significant ones, they've added sections on environmental justice, public participation, and technology development flow charts, and that's really, a lot of that is on the distribution side. That's not a lot of time in a three-year process for us to incorporate these suggestions by September. We will be reviewing to what extent can we accomplish a guidance, by the way, the guidance was issued in draft form on December 30th. Comments from everybody were due January 31st, and I don't think they've issued a final version yet. So at some point it becomes very difficult to incorporate new guidance in a document that's due in a certain number of months. So we will look at these. If we can incorporate them, we will do so. If not, we will let the department know essentially that they either need to extend the timeline or recognize that they will not be included in this IRP. One other thing I'll mention is that there is also an MOU that was signed as a result of the last IRP that has certain actions that we have to take, and those will have to be in this IRP. So for example, updating the McNeill Economic Analysis is wonderful. Next slide, please, Emily. From the forecast front, second. I see you. So, sorry, from the forecasting front, unlike in prior IRPs, some of the assumptions regarding the pace of electrification are really the biggest unknowns in terms of impact on the load we will be serving. In prior IRPs, 2008, 12, 16, et cetera, there was a lot of discussion about what are you gonna forecast for a change in GDP? What do you think the population in Burlington will be doing over the 20 years? Compared to the effect that those kind of variables can have on the load forecast, the assumptions about new EV deployments and about new heat pump deployments and about how much they will consume, will wildly crush the impact of those types of variables. So what will drive the cases here between the low base and high case where we try to look at multiple cases and see how robust the answers are at different levels of load? Do you get the same answer if you don't get a lot of deployment? Do you get the same answer if you get more deployment than you expected? The drivers for the number of EVs and the number of heat pumps is really going to be two of the biggest things we've got to deal with. And we've got a couple of slides where we wanna talk about those deployment rates. Pregnant pause for next slide. Thank you. Anyway, pardon me again. This is the IRP deployment EV deployment trajectories. The gray line, the blue line and the orange line are from the current IRP draft and they represent deployment rates of electric vehicles under what we are calling low base and high case. In this case, it was fairly easy to give a comparative value from the net zero roadmap and that is the green line, is the 2030 net zero roadmap deployment rate of EVs to achieve net zero in the transportation sector by 2030. And this particular graph is focusing on light duty vehicles, which is really the predominant type of vehicle that's being modeled. The right hand margin shows the approximate saturation or market share under each of the cases. The only qualifier I need to give you and the reason there's an asterisk under market share is that the denominators for these two calculations are not the same. The net zero roadmap used an increasing number of EVs over time. So it's a growing denominator and the IRP cases right now for low ratio share are calculated on a static 25,000 roughly vehicles in Burlington. If you were to change the denominator to the net zero case for the three IRP scenarios, they would drop relative to the 98% in the net zero roadmap. Those, that 81% market share 60 and 32, I can't read it, sorry, 53, would all drop relative to the 98, the 98 would stay the same. We are having some difficulty putting these things directly against each other and we're gonna talk about that particularly in the next slide, which is on heat pump rates. But I mean, I think what this shows is that there is a shortfall between the projected deployment rate of under the IRP scenarios. The base case would have us at 60% roughly of market share. And we knew that. We don't necessarily think that we are on trajectory to meet the 2030 net zero roadmap. So the gap above those cases doesn't surprise me that much. You can also see by the way, the blue line on the left is our historical deployment rate. And you can see that the blue line, the base case line, is really driven strongly by ITRON's forecasting off of past practice. And then we are judgmentally adjusting it upwards or downwards. I'm sorry, I just wanna ask if there were any particular questions on that slide right now. The EV one? Yes, please. I'm curious why you're cutting vehicles and not vehicle miles. We're using the deployment of vehicles and then vehicle miles is a function of creating an average use. So these vehicle deployments to become electric consumption get multiplied by an average use. The average use is affected by vehicle miles driven for Burlington customers. So these become energy sales forecasts when coupled with forecast of average use over time. And there's no nuance between like miles for an electric vehicle versus a ICD or whatever? In this particular context under the IRP, and I don't believe there is, under the net zero roadmap, there are some very complicated interplays. For example, they're projecting, increasing efficiency of vehicles over time and things like that. But by and large, this is based on an average use assumption over time. We can pull that, but I don't have it with me as a graph. I don't necessarily think it's static, by the way, either. Yeah, I was just gonna say, James, we do track our kind of BMT data in the roadmap updates using an average that's based on the two-year trailing based on the local Chittam County Regional Planning numbers and one-year trailing based on the state average. Right, and there's multiple sources of average mileage you could have what's called the tier three tag, technical advisory group assumptions about my vehicle miles. I'd have to get the actual assumption about vehicle miles because what I've actually got is consumption per vehicle per year, which then gets multiplied by deployment rate in vehicles per year. Because again, we're concerned in terms of a load forecast about electric energy at the end of the day. Any other questions on this? Sorry, just a clarifying question. You said this was the old IRP modeling though and you're gonna be updating it through your process. No, no, no, no. Oh, no, this is the current. Okay. It's current IRP modeling against the net zero roadmap in green. These are the assumptions that we're making that are two critical ones that are driving the load forecast scenarios that we will then go on to analyze in the IRP in terms of distribution impacts, economic impacts, environmental impacts and everything else. And in all of this again, remember, in three years you'll be updating the IRP. So unless you're making a 20 year decision, you're not really relying that heavily on those out years right now. Because you know that the uncertainty out there is higher than it is upfront for sure. Next slide please. So this is the potential heat pump trajectories. And I want to note right away that we have changed your comparative measure here from being the net zero roadmap to being the green mountain power base case. If the comparisons in low ratio share in the EVs are difficult, the comparisons for deployment rates of heat pump technology between the net zero roadmap and the IRP modeling is very difficult and we'll probably need synapse to calculate a few things for us before we can actually do that. Synapse is looking at whole home conversions to heat pumps over time with a changing percentage of the home load being served by the heat pump over time and with changing efficiencies in heat pumps over time. That is almost certain and it's displacing anywhere from 75 to 85% of the heating load in the house over the evaluation window in the synapse report. You know that's not a single head mini split. So all of the IRP modeling done by ITRON who's our forecasting consultant is based around heat pump counts. They have also done that work for green mountain power. So the green mountain power is a deployment of units of heat pumps as are our three graphs. We are trying to convert the net zero roadmap to being equivalent but it requires some estimates of the average number of heat pump units required to do what they modeled in their plan and their roadmap. That's proving difficult. So we've given you at least one comparison because otherwise I would just be showing you three lines that curve with no frame of reference as to what anybody else thinks might be going on. The yellow line is GMP's base case. What this data shows is that we are below GMP's base case, in our base case, the blue line and the gray line which is our low case. And only in our high deployment rate case are we exceeding GMP's base case. GMP's high case would probably be higher than our high case, virtually certain. And I guarantee you that the net zero roadmap would be higher than all of those. Okay, and as soon as we can do that math if we can do that math, we'll put that out as well. But this feels sort of intuitively correct to me in the sense that at a base case deployment rate I would expect GMP to be deploying heat pumps faster than Burlington Electric. We are looking at competing against a 95% saturation of natural gas. They have significant oil and propene that they are competing against. They do not have universality of natural gas in their customer base and the economics of deploying a heat pump against oil and propane are certainly better than deploying them against natural gas today. Now, they've gotten better. As Darren has said, we're probably a little bit above break even right now. But again, you're incurring a capital cost to more or less break even, whereas against oil and propane you're incurring a capital cost to save operating costs. Better economics. Again, we're not surprised that our heat pump deployments would not be meeting the net zero deployment rates. Again, there's no reason that they would. We don't have a program or an active dynamic or a requirement or something else that would push us to the net zero deployment rate yet. That's what we're trying to do when we're looking at the net zero roadmap is figure out how to close the gaps and move the deployment rates so the technology is up to where they need to be. Are you considering the overlay of Vermont gases, efforts in the sphere because of it not being a whole cloth replacement, but actually encouraging, at least through their pilot, the remaining heating system in place but the tea pump being an addition and therefore potentially extending that opportunity. Sure, sure. I'm just thinking of like, if you're looking at models for understanding number of your impact and your amount of impact, you have obviously another person in another entity who's playing in the space. And I'm just curious about your overlay of Vermont gases activities around heat pumps and what that does if they're high on it. Unless Vermont gases activities would push us outside of the orange line, which I don't see in any case, right? We will be testing a case that's that high, right? I mean, again, we will be testing a combined high case, which would be the summation of high heat pump deployment in residential units, the high deployment of EVs and that will become a low forecast that is tested for its impact on our system and our decisions. So unless you think their actions would put us totally out of the bounds of any of these three cases, then I'm not terribly worried about that. That sounds, yeah, I would think it would just be more actually pushed the other way. It would decrease the potential run rate for how much adoption you would get. Well, it depends. Like I said, you can use those explanations to understand what might move you from the base case to the high case or the low case or what might be needed to move you there. And you can use that when you're deciding what case you put the most weight on in terms of deciding to make investments. You don't want to sit there and invest in T and D upgrades on the orange curve without some real reason to believe that you're not gonna be on the blue line. What's gonna cover the gap between 20 below zero and the heat pump? In all of these cases that would be covered by residual gas and fossil fuel use. Even that's also in the net zero roadmap. Just a question of how much of it's left. I mean, I personally have two heat pumps. I was very pleased to see that over the cold weather, they operated two rating. They are specced out for minus 14 and they produced heat, two minus 14 and then they stopped. And, but there was enough buffer in the house that my well bills have been brutally driven down by having the two heat pumps this year. It's not been that hasn't been that cold either. It's been a really good year for, you know, high efficiency, super high efficiency heat pumps. And that answers my question of your, the modeling is continuous consumption of other heating equipment. So that's the interest. Has to be. And even in like I say, even in the net zero roadmap, they do not assume a technology where heat pumps can displace 100% of fossil fuel use by 2030 or 2040. They don't have a base for heating. Back up instead of gas. I don't think they assume a change to the backup heating unit. I'd have to double check that the model's pretty deep bob as to whether they actually, I think what they're doing is they're replacing natural gas customers with heat pumps and they're in a residual natural gas load. I don't think that they're moving that residual load then over to electric, but that I would have to check. That would require a fair bit of digging into the model. And I can do it. I just don't know the answer. So what we're doing though is we're combining these cases to drive variations around a base case so that we're not sitting there 20 years ago, the IRP would have had a single forecast line and all of your planning would be meeting that forecast and you would assume the forecast was accurate. Now you're gonna be looking at, what happens, what do you need if you do hit the orange line? When do you need it? What's the most economical way to meet the orange line? That kind of thing. So IRPs in Vermont no longer are single case evaluations. Now, we can update, we will provide this PowerPoint, share it with you guys. We will continue to develop PowerPoints to explain the steps that we're taking through the IRP. We will also though share this PowerPoint with the DPS and elicit their comments because we have an obligation under our MOU to begin engaging with the DPS six months before filing which I think ends up being end of this month. So it's timed very well. We will just simply share the PowerPoint as we have always done in the past. In the past, whenever we did an IRP PowerPoint for the BEC or any of the committees, we would share it with the DPS right afterwards and seek their commentary and then let you guys know what their commentary is if it's material. And that is the end of the PowerPoint. Thank you, James. Any other questions from seeing this? Thank you very much. Stay tuned. That's due in the September, right? Okay. September, September 1st. All right. Thank you, James. We'll go on to the end of number eight, commissioner's check-in. I wanted to give commissioner Whitaker an opportunity to just do something that we talked about before you came in to just if you need a brief update. Just quickly, I saw a renewable energy standard and a wood thing. Did you guys spend a lot of time talking about that? A little bit. We did. I mentioned that, well, we shared the statement that I hope you saw an email. I was in Montpelier yesterday. We're gonna spend a lot of time advocating about that. And we welcome, and this is part of the conversation, the commission's active engagement on the issue as well. And so, Chair Boothi suggested the commission might be willing to put together some sort of statement that might be helpful for us in terms of sharing with legislators, but also sharing globally with the city council because there's gonna be a forum potentially with the Transportation and Energy Utilities Committee at the council on wood energy in paper. So we welcome the commission's engagement on all of those areas. Okay, and there's no nuance in the standard for like the scrap part, I think so. Second, if you don't stop. Well, there is currently, I mean, current law certainly allows us to count wood energy towards for much renewable targets. This proposal, as it was laid out last week, by renewable energy Vermont, and which of course is subject to change in which we hope will change. As it was drafted and announced at the press conference would simply phase out eligibility regardless of sustainable harvesting, regardless of the district energy project. And we think that's not good policy. Yeah, good. I did have a question. I should have asked James. Are you still there, James? Looks like it is. Is that neat? Yeah, he wasn't the only one who ever said it. Okay, there we are. Any other... He caught that just as he came back into the room. But then he had to find his cursor, which slowed him down for a few seconds. Well, just context, you mentioned at the beginning of your remarks that we kick up in one previous IRP 202 megawatts. What kind of upper limits are you thinking about here? Or is it premature? It's... I-tron will need to run the energy forecasts through a peak demand model. And we need to then understand... It won't be as high as the 140 megawatts because none of the I-tron cases are net zero by 2030 or 2040. But we need to make sure that we understand if we get numbers that are lower than 140, what's driving the difference? Is it an assumption about the saturation? Is it that the average use assumptions are different? That is still in process. Converting an energy forecast to a peak demand forecast is still in process. Okay. Thank you. All right, thank you, James. Any other... Anyone who says that Christians want to bring up? I'll take a motion. Make a motion to adjourn. Second. All in favor. Aye. Aye. You have to wear the sweatshirt to make a motion. Get the memo. I'll stand and adjourn. Thanks, everybody. Thank you all.