 Good evening and welcome to the January 2024, a new year meeting with the Burlington Electric Commission. We meet every second Wednesday of the month at 530 here at 585 Pine Street. And always the public and great pairs are welcome to come down, share your thoughts, your concerns and join us in the conversation. The first item on the agenda is the agenda. Are there any changes or additions to the agenda this evening? Bethany? Okay, hearing none. We'll move on to item number two, the minutes of the December 13th meeting. And if there are any typos or small errors like that, I would direct it to the clerk. But are there any significant changes to the minutes that we could deal with here? Here's none. Hearing none, I'll entertain a motion. We have a motion to accept the minutes. Bethany's about the second. I wasn't hearing that. Bethany, you seconded? Yep. We have a motion and a second. Discussion of the motion. Hearing none. All those in favor of accepting the minutes for December 13th, signify by saying aye. Aye. Aye. All those opposed, do we have to do roll call? Lori, because she's a remote. Oh yes, good one, yes, you do. I'm sorry about that, Beth. So. Commissioner Modi? Aye. Commissioner Whitaker? Aye. Commissioner Anderson? Commissioner Shagnan? Oh, it was absent by that meeting. Abstain. Abstain, thank you. Motion passes. All right, well we've got three ayes and one abstention and are the commissioners not here? Commissioner Bohn, so the motion passes. We'll move on to public forum. This is the time, again, hi guys, when it's time for the public to have a say and join the discussion here. Is there anybody here and we don't see anybody here at the thing, there's nobody online. All right, well, that's too bad. But again, I'll repeat that we're here every second Wednesday of the month, 535-30 at 585-5, come on down and join the conversation. Let's move on to item number four, the commissioners corner. Do commissioners have anything that they would have, we'd like to bring up this evening? No, also. Okay, Commissioner Whitaker? Also, yes, please. Okay, well, all right, we're moving right along here. Item number five, general manager update, and with that we get general manager Springer, you have the floor. Great, thank you. Good to see everybody, happy new year. We've got a busy year so far, even though it's relatively early. Couple things pending. The one I want to jump to first is we had unanimous approval at the city council board of finance for putting our credit line increase on the town meeting date ballot, which you all approved already. This will be a couple public hearings happening and then if it goes on the town meeting date ballot, has to be approved as a charter change, has to go to legislature. Could happen this year, expedited basis maybe. If not, it would happen next year. Our goal would be if it is relatively non-controversial, be lovely to be able to move it forward and have the benefit of that as we head into fiscal year 25, but we'll be working on it one step at a time. Public hearings the next item on the process. We also have a lot going on in the legislature and starting tomorrow, the House Energy Environment Committee is gonna take testimony, they don't have a bill yet. They're gonna take testimony on framework for updating the renewable energy standard in the state. We were part of a working group and we, along with a number of other utilities and environmental groups and renewable energy Vermont, agreed on a framework that's hopefully gonna be the basis for legislation. And I expect we'll be talking more about it tomorrow. The basics for us that are important within the framework, and this was published in December, so this is a public report, is the idea would be BED 100% renewable continues to be 100% renewable, but as our load grows, we do more EVs, heat pumps, different things, we're having more electric demand, we're gonna meet a significant portion of that load growth with what's considered new renewable energy. So projects that are built in the region or in Vermont, 2010 and later, practical matter, we're talking largely wind and solar. Some of our existing assets would count theoretically towards this requirement. They may be assets where we sell renewable credits now because there's a higher value market for them, but we might be able to retain those renewable credits and use them towards this requirement going forward, if that's something that we decide to do. The other important pieces for us, we would retain some of our exemptions that exist in current law that save our rate payer significantly because we were an early actor and we're 100% and existing biomass plants, including McNeil and Ryegate would continue to count towards Vermont targets and if you were building a new plant, they'd be subject to some more rigid and stringent standards, but those are some of the pieces that were important to us. I expect we'll offer testimonies tomorrow. We'll probably be putting out some public materials on this and it'll be a topic conversation that'll go through the legislative session but has some significant pieces for us, cautiously optimistic that it'll end up in a place that's similar to that framework and then we'll be able to be fully supportive of it and implement it and it'll be a good thing for the state. Another thing we're working on that we're waiting on a decision is our incentives. I mentioned we're gonna hold incentives sort of steady as we come into January, typically we change them in January, but we're waiting on the PUC proposal for decision on Act 44. Among the new programs that we've proposed is one that's called the Super User Incentive that we were authorized for. So the idea here is that if you're driving more miles, we wanna help you get an EV even more. We wanna get you off of gasoline. So this is a concept that was advanced by a group called Caltura, which I think is based in California and we I believe would be the first utility in the country to offer any kind of program related to this. Our team proposed adding a $250 additional bonus incentive to our EV incentives. If you drive 17,700 miles a year, if you drive 25,300, which would be roughly three times the average of a Burlington driver, and then you would get an additional total of 500 as opposed to 250. So a two-tier level incentive bump that would go on top of our EV incentives would apply for new or pre-owned EVs, so either case and we'll learn a lot. Maybe it'll be useful to the state or other entities that are looking at this, looking in this space. I actually had a conversation with the New York Times about this program concept. They're apparently looking at doing a story on it. So this is something where we're maybe in the vanguard of actors in the country, either utilities or others who are doing this type of program. So that's just one of the incentives that's pending as part of the proposal for decision. I do hope we'll have some time in the spring, maybe April, comprehensive set of incentive announcements that we'll be able to make for our customers. Also, gonna be getting underway on the net zero 2023 data update with Synapse in the near future. So last year we weren't able to get it until June, I think. It was a little later than typical, but our goal is to have that data available in April. So around the same time, hopefully have our new incentives. We'll be able to provide the community update on how much fossil fuel was used, how much greenhouse gas emissions in the thermal and transportation sectors for 2023. So that'll be always useful and interesting. Couple other items. I hope you've seen on social media or maybe around town, our F-150 Lightning, which is nicely wrapped with the BED green and logo. One of three, we have one coming at McNeil two that'll have a unique McNeil based logo. And we're certainly excited to continue Electrifier Fleet and getting into the truck space as opposed to just the traditional vehicle space. It's very, very exciting. More good news. Moody's affirmed our A3 rating stable outlook back in December. Through the current actuals on the financials for this year, we're doing quite well. We still see, as we do typically around this time, some headwinds that we're gonna have to deal with in terms of other cost pressures that could affect the fiscal year. We're making some proactive efforts to improve upon what we're seeing. So obviously continuing to have those stronger metrics, having access to the increased credit line, those are all things that benefit us relative to the Moody's rating. Is A3 a continuation of our rating or is that an upgrade? Same. Same, okay. And how does that relate to the city's bond rating? I believe the city's A2, if I'm remembering correctly. Yeah, typically it'd be impossible for us to have a higher rating in the city, theoretically. But no, I believe the city's been at A2, we've been at A3, we're hoping to maintain. I think we're not necessarily looking at getting an upgrade because I think the metrics that you would need for that would require different steps. We're really looking to maintain the rating that we have. Couple other quick items, the energy assistance program which you all looked at and approved the tariff filing, the Board of Finance has done so as well unanimously and that's now going to the city council on the 16th, along with a couple of other items. So we'll have I think three items pending at the city council on the 16th, that being maybe the most prominent. And then we had here in this room last night a meeting of the TUC transportation and energy utilities committee. We have two actually items that Councillor Bergman has brought forward that relate to the carbon policy in the city. As you'll recall, we enacted at city council on November 20th, a carbon fee ordinance that took well more than a year of work that affects new construction and existing buildings 50,000 square feet or larger. That takes effect January one. So I don't know, 10 days old now. But there's an effort to already change it. And the proposal that was passed two to one here and two can all be pending at the city council which to be transparent, we've raised really significant concerns about and so have a number of stakeholders. One of them is to put on the March ballot a change to the current compliance options for the ordinance where we have aligned ourselves currently with the state clean heat standard program and said, if you're eligible under that program which is being developed at the state, you're eligible here. And we've really intended to have a broad range of renewable compliance options. Electrification is obviously the primary and that's what we're most excited about. But we know there are building types that may need a renewable fuel, whether that's renewable gas, whether it's biodiesel or wood heat, whatever it might be. Hydrogen perhaps in the future. So the current ordinance allows for that provided those fuels continue to be eligible. The ballot question would give the city of the authority to place a fee on those fuels. That has caused the University of Vermont Medical Center that in combination with the other item that I'm gonna mention to publicly state to the council that they've paused all conversations with the city and with BED on district energy because this is pending. Dr. Leffler was really clear in November at the city council that getting clarity around what this policy was gonna be was one of the key pillars for them and being able to move forward with district energy. And unfortunately they had that clarity and they no longer have it at the moment while this is pending. So we'll see this resolve one way or the other at city council sometime in January, I believe, whether or not it's gonna be placed on the ballot. The other item is different timeframe and a little bit different context but would basically say that the city council would give the TUC committee the requirement to draft ballot language for the August ballot that would expand the carbon fee to a higher number, increase the number of buildings that would be subject to it going perhaps as low as 25,000 square feet has been suggested. And then also again, potentially limit some of the compliance options. We did some analysis with the Burlington Business Association that we submitted to the TUC that looked at what buildings would be impacted if you go to 25,000 square feet. It's over 400 buildings in the city. The previous version was 80 buildings and where the previous version makes sense to me because when you're putting a carbon fee in it's a significant potential levy and we're putting it in for large sophisticated capital planning organizations like the Medical Center, UVM, Champlain, School District and city buildings are in that category. These are largely buildings that have campuses that are doing planning that can look out 10 or 15 years and say, I have a replacement and if I don't do X I'm gonna need to pay this fee. I'm gonna think about this in a particular way. When you go to the 25,000 square foot threshold we're talking about places like Crew Coffee, Little Morocco Restaurant, Burley Acts in the Old North End, Battery Street Jeans, Duncan Donuts. We're talking about not multi campus sophisticated capital planning entities but smaller businesses. Businesses in downtown and Pine Street, North Avenue, the Old North End. So my concern is I'm not even sure and we haven't done any analysis to indicate that putting a carbon fee in place for those types of buildings is even the right approach to start with much less whether increasing the fee for them and the other buildings that would be subject to it is good policy. So we've had some significant substantive and process concerns related to this. So both these items were passed two to one in the two committee last night and are pending at the city council either on the 16th or the 29th. Not sure which meeting it'll be taken up. So I just wanna make the commission aware of that. I've got it in the report here but we had some activity last night that bears on this as well. So you've got more updated version than what's in the report. And certainly we try to make every possible bit of progress we can on climate but there should be some stability in city policy if we're gonna enact a major ordinance with major stakeholder input. Having it in place unchanged for more than 10 days seems like something we would wanna do. And to be fair, critics are arguing that they think the current policy was flawed that it should be changed in this way. We disagree but that's a conversation that'll take place. So we'll see where it goes. And that's everything I've got. All righty. Questions and commissioners. Everybody's good. I have one. Yeah. Is this sort of a second chance for some of the advocates to get at district energy? Or this was going on even before that, right? Yeah. It's unclear to me how this would impact district energy. They put a line in the whereas clause that says it's not intended to affect district energy and Jean Bergman who is the city councilor who's sponsoring it said it wasn't his intent. The language itself doesn't say that. Jean did suggest that they could amend that but we only saw the language 24 hours prior to the TOOP meeting that was gonna be acted on at the TOOP meeting. So we really hadn't had a chance to analyze how it would impact district energy but it is a bigger issue to be fair. There are critics who feel that any renewable fuel can be district energy, wood heat, renewable gas, biodiesel, because they emit carbon at some point in their life cycle should not be a compliance option or should be limited in terms of its compliance. At the state level, they're doing life cycle emissions analysis on all of these fuels. And what we've said is if they reduce greenhouse gas emissions, we want them to count in Burlington. The state with a much more sophisticated infrastructure behind this with many, many more staff are potentially gonna implement for the clean heat standard some sort of a sliding scale approach where different fuels may be worth different values of credits. For the limited city team that'll be administering this ordinance that's probably overly complex to ask of the Department of Permanent and Inspections to implement something that's on a sliding scale per ton per credit. We really wanna try to make this administratively as simple as possible. So the idea is a fuel is either in or it's not in and that'll create more certainty for the regulated community as well. So this will impact much more than district energy. Whether or not it actually impacts district energy isn't clear at the moment just cause we haven't had the ability to understand the implications for it yet. It's having an impact unfortunately on the conversation around district energy cause the medical center made clear that they were concerned about this potential change being announced so quickly after they thought that the current policy was implemented and therefore have paused for the time being discussions on how to advance district energy. Okay, thanks. That helps, that helps. Yeah, it's a little bit frustrating maybe but well intended. Other questions from commissioners? All right, thank you. Thank you. We'll move on to item number six in our agenda tonight. It would be the November FY24 of financials with Emily. So November, FY24 of financials. Our net income in November was $388,000. That was compared to budgeted net income of $595,000. So $207,000 worse than budget. Starting with revenues, sales to customers were better than budget very modest 25 to $76,000. Other revenues primarily to the EU were less than, no, sorry, better than budget by $77,000. And one of the major factors contributing to the worst than budget results was rec revenues. Those were less than budget by $300,000. And as you've heard me say, in several prior commission names, lower McNeil production, lower wind production, whenever we have generation resources that are producing less than budget, sometimes that saves us on power supply costs for the period of question. But it means that we have fewer recs to sell six months from that period, which can have revenue budget implications. Moving to expense, net power supply was $140,000 worse than budget. As you know, net power supply has several major components, the first being fuel. That was favorable to budget, $983,000, mostly driven by McNeil production, which was 40% less than budget. We did not run McNeil as much as budget for kind of two primary reasons. One, unfavorable economics under new prices have been low and would supply is continuing to be tough given the muddy conditions in the woods. So we wanted to conserve woods for hopefully higher energy priced periods. The next major component of net power supply, transmission expense, that was unfavorable by $113,000, October peak load was over budget. And then finally purchase power, that was worse than budget as well by $210,000. Puts and takes within there. We had lower wind production from a couple resources. The mystic capacity payment was less than we budgeted, so we saved a little bit there. On the flip side, we had higher production than budget from Great River Hydro. And since we also had less McNeil and lower wind production, that means that we paid more through the ISO exchange, which means we brought in $371,000 less revenue from the sale of excess energy and energy prices again, as I mentioned, were under budget. O&M continues to track very closely to budget. This month, there was only a $54,000 delta to budget. So year to date, we have a net income of $2.6 million, compared to a budgeted net income of $478,000, which is 2.1 million dollars better than budget. So at this point, I will, before I move to capital, kind of give you a preview of where we think the fiscal year is going. Results to date are positive and favorable to budget. However, we discussed just this week on the leadership call, two major risks to the budget at this point, even with the favorable results, year to date. One is that rec revenue, again, with the lower production, where just under $400,000 below budget for the year to date, but we're projecting an additional $1.4 million negative variance to budget between now and June. So that's going to erode some of that, $2.1 million, better than budget net income. And then secondly, as we all know, the winter has remained mild overall. And therefore, energy prices have been lower than the forwards were when we did the budget. And based on the most recent forwards, we're projecting an order of $2 million in additional net power supply expense, AKA less revenue from selling excess energy between now and June. So with those combined effects of the lower rec revenue and the increased net power supply, right now we're looking at potentially a net loss as much as $1.5 million. Obviously that would result in Moody's metrics that are not acceptable and not in our target range and the leadership team, the management team, are actively working on ways to mitigate that and affect that result between now and June while we still have some time. Questions on this before I move to capital and cash? Oh, I was just curious, Emily, sorry, and then I'm going to hop off in a minute, but is this the same problem that we had last year where we over budgeted? It's about, it's a budgeting rather than like a fiscal, like we budgeted for a more optimistic scenario than transpired and not really that cost or outpacing. Judgment, exactly, if you know what I'm saying, like the basis for the energy prices had a basis in the market forwards that existed at the time as we've gotten, so looking in May at what you think January prices are going to be, right? And then now we're in, you know, or February prices, now we're in January and looking at what you think February prices are going to be is different. So, but yes, it's not a problem of spending more than we budgeted. It's a problem of energy prices not coming in the range of the forwards. James, do you want to add to that? Yeah, just a quick note. The forwards are the prices that energy is selling for a period in the future at a given point in time. So there was a time where energy for January of 2024 was selling for the prices we used in the budget and in fact was selling for prices above we use them, what we use in the budget. It's not now. And we were not in a position because of our resource mix to sell our excess energy at the time those prices were there. We really are sitting on enough intermittent resources and a single resource that's so important that we really can't go out and commit in advance to selling the excess energy, or we would have done so. So it isn't even really a forecast. It's actually a chance to sell energy in April was at a higher price than it is now. Yeah, I was kind of in the same band was wondering as you had mentioned it, you know, in a number of things that your prediction was off. No, and then so come to the same line of how many different things, you know, as an aggregate of predictions that were off and it was this one thing that kind of affected all of those. Was it a triple that affected or some? No, that's not the right word, but that those prices affected any number of different predictions that you had that were that went south of what? They affected at least one other. The mystic probably was affected by them, the cost of the mystic reliability contract. But again, they're not predictions. That's why I'm trying to differentiate a bit. They're what's called forward prices. They're not a forecast per se. They are what the market is trading at a moment of time and they're your best guess as to what it is. Again, we use them like a forecast, but they're actually something slightly different. I would say given all of the various items appear on our income statement, it's not a sprawling octopus of connected items. It's really ISO exchange, which is power expense and capacity and the mystic capacity charge. It's not affecting a whole domino cascade of additional expenses or revenues, that helps. But that said, that single line of purchase power, right? Is the gorilla. Is the gorilla, yeah, right. It's the big item. And one other qualifier we'll just add, this is something we have to deal with too, is that for lack of other better choices, when we do a rake case, the department also uses those forward prices to evaluate how much revenue we need for a coming period too. And that can pose other problems. So you can see, so again, if they're predicting our rate case needs, saying that energy prices are gonna be super high, and you're gonna be selling your excess at a significant profit, and set your rates that way, that's a challenge too. So again, it's for lack of anything better, it is not truly a forecast, but it's used that way by most people in the state that I know of. Are there questions on this? Onward and forward. So here's capital spending through November, 2.7 million of the $4.2 million budget, and it's about 25% of the full year. Cash position as of November 30, operating cash was at 9 million, just over 9 million dollars compared to a budget of approximately $8 million, so better than budget. We had 111 days cash on hand, the debt service coverage ratio was 4.64, and the adjusted debt service coverage ratio 1.48. Happy to take any questions. Yeah, go on once. Okay, Missionary Whittaker, she's still with us? I think she had to drop off. Okay, well, we still have a quorum, so that's cool. Right, I guess we'll move on to the item number seven, the miscellaneous fees, and it continues to be Emily on the stock peer. The slide deck, and then also I have a couple of handouts, and if there's... I'll add that. I wonder how you went down. There's two pieces of paper. Zoom in. Thank you. Okay, yep, I got this. Successful? Okay, so what we have prepared for you tonight is for discussion. We're not requesting a decision or a vote. We're just gonna present the information that we have gathered thus far, based on our analysis of what our costs are now for these miscellaneous fees. So just starting with a little background and context. We assess our miscellaneous fees under a tariff, so therefore these fees require the same approval as all of our other tariffs. City Council, PUC approval, DPS can investigate, all of that same process, that's for our retail rates. The miscellaneous fees currently in effect went into effect on July 1st, 2010. They were based on cost from fiscal year 2009. And in FY 2009, that was prior to our deployment of the advanced metering infrastructure system, as we've talked about here. Before that we had all analog meters that had to be read manually, disconnected manually, reconnected manually, meaning someone from BED had to go out to their customer location to perform those services. Okay. So what we have done over the past, not quite a year, but is we've reviewed all the business processes associated with these services because the cost basis for this is all essentially time and materials. And so you need to investigate and make sure that you have a current understanding of who in the company is doing exactly what, using what truck or car or whatever to do the service. And including now looking at the degree or nature of the AMI involvement in that business process. So we reviewed and updated all the time involved, all the personnel involved with each service. We updated the labor rates to FY 23 labor rates. We updated the labor overhead rate to FY 23. And we also updated the minimum call and overtime rates to be sure that they're consistent with the current IBEW contract terms for those provisions. I'll note that what we haven't updated is any rate associated with the use of the vehicle. This is another thing we need to do because they haven't been looked at in a while, but every one of our fleet vehicles has a certain hourly rate associated with it. Based on the insurance cost, the maintenance cost, the depreciation of that vehicle, et cetera. So the rates used here are whatever the vehicle rates are from the last time they were updated. And that's something we know that we need to look at. It would affect these fees. It would also affect any outside billing we do for what we call work order billing or third party stuff. Someone says, please do this work for us. Work on the Sheldon roundabout. Work on the Champlain Parkway. We bill DPW or V-Trans. We have vehicle time associated with that work. So those rates are probably too low and need to be looked at again. But we haven't done anything with the vehicle rates in this analysis. Okay. So now this is why I gave you a handout because this is really hard to see on the screen. And I can flip to the Excel as well. But basically this shows all of our fees. The second column is the description of what this is about. Then there's, the third column is the cost basis as of FY09. So that's kind of to the penny, what we calculated it cost us in FY09. And then the fourth column is the rate as was set July 1st, 2010, right? Which is a little bit different than the cost basis, right? The yellow column in the middle is the current calculated cost as of FY23 based on all of the labor rate updates I went over as well as the new business process, if any. And then after the yellow column you have the dollar cost change between the old cost and the current cost, the percent cost change, some notes. And then kind of what we currently are thinking in terms of a recommendation to you about what we should do with each fee. So I can walk through it from the top. The first one is the initial service fee. That's charged whenever we put electric service into a customer's name at a service location. So this could be a customer who's completely new to Burlington. It could be a tenant moving from one apartment to another. It could be between a tenant and a landlord for a landlord who has a standing order. This used to involve going out to the meter to get a final read for the person leaving and an initial read for the person moving in. Thus, you have a $31.40% cost from 2009. Now, there's still no power shut off. There was no power shut off back in 2009, but we don't need to roll a truck anymore. We can grab that read from the AMI, okay? So that reduces the cost basis down to $5.36. And our recommendation would be to reduce that fee. Actually, I say you're decoupled from reconnection, but that is an error. We should strike that. It's the reconnection fee has the same cost basis, but they're not actually coupled as a fee. So please ignore that. Just consider reduce the fee as the recommendation. And then the second row is a variation of that same service, same situation. It's just that it happens during non-BED business hours. So someone calls on a Saturday and says, hi, you know, I'm moving in, I want services start, please can you move it to my account. The cost basis for that has moved from $195 to $71. Again, no truck roll, grabbing a read from through the AMI. Next, we come to reconnection. Reconnection is currently defined as charging to restore service to a customer who has been disconnected for non-payment of electric services. So you can see the cost basis for that is the same as the initial service fee because it generally required the same people doing the same amount of work. However, there was a decision in 2009, 2010, to instead of charge $30 for this to only charge 20. So even though the cost basis was the same, the fee charged was less. Now we show that cost basis slightly higher, $32.10. What we have done with this fee, the business process is different, we're no longer sending a metering technician or somebody out to the home or the service location. We are performing the reconnection remotely. However, to do that remote reconnection, we're using the capability of the AMI to do a reconnection remotely, which we paid extra for when we bought the AMI meters. When we purchased the AMI meters back in 2010, 11, we had a choice of buy AMI meters that do all the things AMI meters do, but do not do remote disconnections or reconnections or buy a more expensive AMI meter that has the remote switch. And we opted to buy the more expensive meter that has the remote switch. So what we've done for this reconnection fee is we've calculated sort of an AMI carrying cost to reflect the fact that there was an incremental cost to the company of this functionality that allows us to no longer need to roll a truck to perform that service. And using the incremental difference between the simpler meter and the more complicated meter, we've then applied that increment to, you know, the annual software maintenance on the AMI head-end software. The time we pay, you know, meter cash analysts and our building supervisor to maintain the help and keep the AMI running, our IT folks who maintain the servers, et cetera. So the AMI is, the meters are now fully depreciated, but there is a carrying cost to the company of kind of keeping the AMI working and in operating order, the expense associated with the metering department, for example. So that's all built in to this new AMI carrying cost, and that's included in the cost basis for the reconnection. So one, I think point of discussion is the reconnection, the cost basis is the same, no matter what the reason, you're reconnecting the customer. Right now, the description and the operating guidelines say, charge this fee to someone who's been shut off for non-payment and wants their service restored. If you were to reconnect someone who wanted to disconnect for non-payment reasons, it would be the same business process, the same things involved. So we have a recommendation here to apply the fee to all reconnections, not just for non-payment. And then charge this fee instead of the initial service fee when the reconnection is accompanied by also switching service from one customer to another. So power, a former household, house owner moves out, they want the power shut off, new person moves in. That would be initial service, but it would also be reconnect. So we just charge them the reconnect fee in that instance. Which is roughly the same as, no, it isn't, it's 30, it's a... Yeah, yeah, yeah. But someone switching service, tenant, replacing tenant with no power shut off, just the initial service fee. Yeah. Okay, okay. Those are the two, I'd say those talk to, initial service and reconnection, whether you do it during working hours or business hours. Those are the ones with the major sort of changes to the business process since AMI has come along. The rest of these, temporary service return checks, taking a meter down, temporarily reciting collections, customer assistance, like not a lot has changed in terms of who does what, how. It's those increases and changes are largely driven by changes in labor rates and labor overhead, okay. So temporary service, that's usually when someone, a building is under construction and we set up temporary single phase 240 bolt, 100 amp service. We kind of charge a flat rate for that. The prior cost basis, about $37 now, 800 and 40. So it's a really big increase. It's so big I'm wondering if it's correct if I messed up my spreadsheet. Let me just check that for a second. Oh, that's why there's, oh yeah, 537, my bad. Yeah, that's better. The A40 number isn't correct? No, the A40 number is correct. I was reading the five as a dollar sign giving my aging eyes. So yes, it's gone from $537 cost basis to $840 cost basis. So our recommendation there would to be to increase the fee to be in line with cost. Return check, that's basically a bad check fee. Currently it used to cost $9.62, we charge $10. Now our cost is around $27. Meter removal replacement for siding. So that's when someone is maybe like replacing the siding on their house and they need to have the meter kind of taken off temporarily at the siding up and then put the meter back on after whatever work on the exterior of the building is being done. We charge a flat rate for that. The old cost basis was $95.02. Now it's 135 or 40 cents. Again, our recommendation would be to increase that fee. Okay, so collections. This is an interesting one. So this one is, you can see in the description charged on the BED personnel collects funds at a customer service location. For example, if funds are collected during the course of the disconnection process, this fee will be charged versus a disconnection fee. Which I don't see anything but a disconnection fee. Correct, exactly. We don't charge a disconnection fee. Maybe we did it some point in the past and that's old language. But if we need to go out to your house to collect payment, that's a $20 charge even though the old cost basis was $35. Now if we were needing to send someone to the home, that would be $58.60. Wanted to note here that we have submitted requests to the PUC to suspend the rules for remote disconnections to allow us to call or notify the customer a certain number of times. So then after we've done that, send them a letter, do whatever, but not actually have to go to the house and be able to do remote disconnection. And then there's another docket kind of statewide with the PUC looking at this to allow remote disconnections for nonpayment. So depending on the outcome of that, this whole idea of going to someone's house to collect funds might become moot. So our recommendation would be to eliminate that fee and only charge reconnect fee to restore power after someone's paid up. Again, all things for discussion. And then finally we come to customer assistance. The first one's working hours, the second one's after working hours. This is a fee if someone calls and reports some sort of unknown trouble with the power, you know, flickering lights powers off or something's not right. We will kind of walk, you know, did you check your breaker? Did you, you know, do this and that? And if they're like, yep, I did all that, there's something wrong, please come out. We send someone out and then it's determined that yes, after all, it is something on their equipment but not on the utilities equipment. We charge them a flat. A flat rate of currently $28 for that. If it turns out to be something on our fault, on our side or our equipment, then there's no charge at all. It's really, we go out and it's nothing to do with us. That's when we charge that. So the basis for that now is $46.97. After hours, it's now $461.95. So that's kind of the analysis of all the fees. And then the only other slide I have is your second piece of paper, which is a little bit on how our current fees and then the new cost basis for fees compares to GMP, Vermont Electric Co-op, Washington Electric Co-op. Oh, sorry, actually, I lied. One more slide before that, which was what would be the revenue impact if, and understanding as an if, because no decision has been made, but if you simply took the yellow column of FY23 costs and you said, okay, that's what we're charging for all of these services, it would decrease our revenue from the initial service fee by about $154,000 based on the volume of those that we do. That would be partially offset by the increases in the other fees. However, the initial service fee is the one we do the most volume on. So the increases in the other fees would have to go a long way to make up for that. So the net decrease I'm estimating in the range of 125 to $135,000 reduction in revenues. As we've discussed with the commission, we are trying to as concurrently as we can. We've reviewed our conduit rental rate. That also hasn't been updated in about 10 years, I believe. It's going to increase. I can't say right now by how much. I will expect it to maybe not completely, but go a good way towards offsetting that net decrease. So we're trying to make this a revenue neutral change between the conduit rental and these miscellaneous fees. And then here's the final slide, which is kind of how our costs and current fees compare to a few other utilities in the state. So GMP charges $20 for initial service fee. Their operating guidelines do specify they charge that for a standing order as well as kind of a reconnect situation. So they charge you even when there's no service turn on, turn off, turn on, turn off, turn on. VAC has I believe some AMI customers but also some customers without AMI. So their fees range quite widely depending on whether it's something they can do remotely with AMI or whether it's a situation where they have to send someone to the location. So you can see VAC kind of has three levels of fees depending on the situation from $11 to 75. They don't seem to differentiate after hours that could tell. Interestingly, everyone, well, today everyone. GMP, VAC, and VAC charge for disconnection as well as reconnection. We don't charge for disconnection. GMP charges $35 for all disconnects no matter the reason, could be non-payment, it could be someone just requests it, doesn't matter. And then VAC charges between $24 and $256 depending again on whether they can do it remotely, that's 24 or up to the 256 if someone, if a line crew personnel has to make a site visit. So if I'm just a renter in GMP's service area and I disconnect because I'm moving out and I'm done with my, I'm done, I'm moving outside of the state. There's a fee that's associated with me leaving that apartment and shutting and killing that power. So does that, as well as I pay a fee just to connect when I started, right? There's a fee on both ends of the game with GMP. Is that, am I reading that right? Again, this is interpretation because I'm not, I'm only basing this on their operating guidelines and I haven't spoken to anyone about their practice, but I would say that's a reasonable, 20 on the front end, 35 on the back end, wow. And then you can see, but GMP doesn't charge for reconnect. So they do the disconnect, but not the reconnect. We do the opposite and VAC again charges kind of that similar range from 24 to 256 depending on the situation. I'm sorry, I've been skipping over Washington Electric inadvertently, they charge either 20 or 100 if a line crew person has to do it, both for disconnect and reconnect. So interestingly, VAC and WAC, you see charge for both. We charge for one and GMP charges for the other, VAC and WAC charge for both. For both, wow. And then after hours is more expensive, not surprisingly, and interestingly, the other utilities, they have a return check fee that varies from, sorry, $10 at WAC to 41 at VAC. GMPs is 13 and they have a collections fee, GMP 35, VAC 75 or 208, WAC 20, same as ours, but then nobody has temporary service or meter removal for siding or customer assistance. I don't know why, but those seem to be new to us. So that's what I have in terms of information. Happy to take questions or feedback or anything you'd like to discuss. The only question I have is the opt-out. I know we have a small percentage of opt-outs, where would that fall in if we have to go out and do it out manually? For PUC border or PUC rule, we're not allowed to charge anything different for opt-out customers than we are for AMI customers. Okay. So you're correct that reconnection for one, the cost basis is different for AMI versus opt-out, but we're not allowed to differentiate in terms of fees. Okay. James, did you wanna say something? Yeah, the statute says, it's interesting, I haven't seen the VEC charges till now. The statute says, choose not to have a wireless smart meter installed at no additional monthly or other charge. So it's interesting when you see something like charging 24 from AMI disconnect and 75 for a site visit disconnect, whether that does or does not constitute an opt-out customer paying more for the same service. So that's an interesting question. Right. It could be perhaps related to VECs deployment of AMI, potentially, perhaps not. Yeah, their AMI is AMR. It's power line carrier, I believe. Yeah, it is. But it's not really the same as ours anyway, so I don't know. But it is an interesting question about that particular thing. Okay, good. So, well, I mean, so this is just sort of the first blush at all this. What's the, you know, where do we go from here? Is this something that we take a look at all these over the next whatever amount of time and kind of check, you know, this one's like come to some, have a debate or discussion back and forth, first of all, what's the next process of having a discussion about these and making some decisions? And then secondly, does this, the result of that, does that go to the PEC? Yeah. That's part of rate filing or something of that nature? Sure, yeah. I mean, I would say we're willing to discuss, you know, as much or little as the commission wishes. So, it's really let us know. You know, if you wanna discuss further another meeting, if you'd like more information, what information would be helpful? Or if you feel like, yeah, bring us a proposal next meeting and we'll be prepared to act on it. It's really the commission's decision about how to proceed. But if we get to a point of decision and moving something forward, the next step would be, you know, decide what the actual new fee would be. So, if the basis is $5.36, do we charge five? Do we charge $5.50? Do we charge $6, right? So we're gonna kind of, you know, generally when we move that very precise figure to around $1, so we figure out what that should be. And then the commission would approve a slate of fees and then we would go to the city council. They would need to approve that same tariff filing. And then, yeah, we would submit it to the PUC for their approval. And then whatever, however long the process takes of the PUC would be up to the PUC. I would love some info from the rest of the commission. Anymore? Commissioner Whitaker? Oh, she's gone. Wow, such a three of us. So, wow. So clearly minus the other two, I wouldn't want to start getting into a, getting into a back and forth about this or getting too far into the weeds about this. Yeah, I think this might need to sort of move on to, on a future agenda for with a full board to really have a discussion about it. I think, yeah, that's where I get into it. I definitely want to get your input to this for sure. They come to the public forum as I figured. This is when they want to hear from you. Yes, this is when we want to hear from you. Yeah, that's my first initial thing because there's only three of us that certainly can't have a full discussion about it. At the very least. Wouldn't add it to the February agenda? Yeah, with, yeah, with sort of a casting out a thing to commissioners to really think about this and see if there are any specific ones in here that give you gas and agree for anything that might be where they have a discussion or how much can we still check that off the box and feel that it's okay. What's up for discussion? What's not? I guess would be that my first initial thought. I would ask General Manager Springer what his thoughts were about this as well. I mean, I think Emily laid everything out really well comprehensively. I think it makes sense to me that, you know, following whatever discussion we have today that bring it back to the next meeting, hopefully we'll have the full commission available. And if you'd prefer we can, you know, we can sort this a little more and make a more formal recommendation as to what we would propose relative to each of these. I mean, we've laid out some good information, but we can do that. So that assumes that this is not a recommendation but rather kind of the raw numbers. That's right. Not necessarily a. Yeah, we're not proposing action tonight. This is sort of an initial cut. You know, we may go back and learn some new things or refine it, take whatever feedback you have and refine it. And then we could come back for, you know, next meeting with something more formal and this has to go to city council. So that would be the first step would be you all making a recommendation, but it would go to the council board of finance process before it goes to PUC. So would we have to put, would we have to have a public hearing, if you will, on it? No, it wouldn't be any different than recommending a rape case, for example. I mean, every meeting you have has a public hearing component. Yeah, I mean, but you don't talk about where it's like an official discussion of it to go with all that kind of thing with public input. I mean, we could do, we have a variety of public communication methods. So, you know, if this was going to be something that would be coming to the council, something that would be going to the PUC, we could do, you know, North Avenue News column, looking at Mike, you know, put something on the important message on the bill, you know, do some things to let people know that this is proposed, put some material on the website. So, you know, those are all options. Yeah, just so that perhaps the public has a bite at the apple too, to some degree. I think just in like, in general, especially with the contractors on our temporary service rate, seeing that being that's jumping the way it is, we might want to get something out of the contractors, which, you know, customer service or service can do that. Well, so there's another option, I guess, you know, relative to all of that, which would be, we could do some communications about this in the interim, and instead of acting next month, you could put an agenda item next month. We could, you know, invite anyone who has feedback to join the commission at public forum, and then you could take action in March, if you'd like. And in that way, there's been at least some interim periods and process. Right, I mean, I don't see, you know, dealing with these, you know, fees kind of, all the time I do anyways. I don't see it being a huge issue. I just think it's a couple of big jumps on a couple of them that we might want to get some feedback if there's somebody wants to put some feedback on. Mike, do you think we could do some communications ahead of the next commission meeting to let people know some of the discussion and invite them to provide comment? Okay, great. I mean, the numbers that we have here now are these real close to where we think we want to be. So, I mean, we're not expecting to see big change till next month when we see it come down through. No, I think we've done an internal review. We've, you know, engaged distribution, engineering, customer care, you know, billing, people seem comfortable with, you know, the business process, the right people's time, you know, are listed, so, yeah. Not good, no way that I can plan on the next month's meeting where I'm going to be thought of these numbers. And then I also like Mr. Springer's idea of giving, like to your point, giving people some time to come and have a discussion with us and maybe do, maybe take action in March. March, yep. That seems reasonable. We'll plan on that and Mike can, you know, send, if we do like a column in North Avenue News or any other kind of website materials, yeah, whatever way that we can send them to you all as well. We can post on Front Ports Forum. Front Ports Forum, all of the usual suspects. Yep, we'll do our normal round of communications and let people know these are under discussion. Join the next commission meeting if they have feedback to, you know, share with the BED and the commission. That would make sense to me. Sounds good. Mr. Beerhead, love to hear from you. Come on up. Thank you. Jim, or James? Yeah, I was just gonna say, all of that is great to get the front end engagement. And then once we file with the PUC, there will be the whole formal process. So, you know, request for comments, probably a, these are not done very often, but there should be public hearing, all of the things that you typically associate with a contested rate case. Yeah. Okay. I don't think we need to spend a lot of time getting the information out of it, but we'll get a little bits and pieces of it. The ample time for, especially you take contractors and stuff to weigh in. Sure. Yeah, like I say, anything we can get for the official process is great. Yeah. Yeah. Thanks, James. Thanks, James. Good evening. I'm Alan Beerke, and I really have just seen this now for the first time in Chateau with Emily, briefly, earlier this week, I believe, and she wanted, or maybe last week, and she just wanted to firm up some things before I saw anything. So this is the first look that I'm getting at the same time that you are. Yeah. And what I would say is, thank you. Thank you very much for taking this issue seriously and looking at it to the board and the department. And it sort of shows what I suspected and what we, what I came here talking about with regard to the initial service fee. I would like to raise very early and very quickly that there is still a distinction that I had made between a customer that comes to you from Massachusetts and signs up for a new account and you don't have any information that their information has to be entered into a computer. I wasn't sure whether they still did security deposits. I guess they don't, so there's no evaluation for a security deposit. There is an evaluation if they've been a previous customer and didn't pay, left an unpaid bill. They have to pay that before they can have service put in their name. There are still some steps that are being required to open a new account, an initial service, that are not necessary when transferring power to an existing customer pursuing to a standing order. I suspect that they should be less. Now we're talking about $5, $6. I can live with $5, $6. But you may want to consider that there is a public benefit to electrification. Do you know that? That's part of the mission of BED in the first place. And what Emily ran through is that in the past, in the 2009, 2010, there were some policy decisions made around saying, well, the fee, the cost basis is $30, but we're only gonna charge $20 for reconnection for nonpayment or the cost basis was something larger and we made it smaller for collection at a customer's location. So it is certainly within the realm of what you've done before. And if you were to eliminate it, pursuant to any fee, pursuant to the transfer, pursuant to a standing order, you would be in company with other utilities in Vermont. So there are six utilities that charge an initial customer fee to come and turn on power. Two of the six have an initial service fee, but no fee for transferring pursuant to a standing order. You would cross the threshold of being 50% of the utilities, charge nothing pursuant to a standing order, even though they do also charge for initial service. So I don't wanna look a 83% fee decrease like a gift in the mouth. But I do think that you're setting policy for the next decades at the pace that these things get looked at. If electrification is in fact a public good and having standing orders in place is something that you want to encourage, it doesn't look like it would cost very much to do so. And with that, I'm gonna spend more time understanding this a little bit more and you'll probably see me next month. And I think this whole standing order thing is probably something that we wanna look at as well. Emily, yeah. Yeah, sure, I can just address that concern a little bit. So the $5, $5.36 cost basis that you see on the sheet for the initial service fee that is based on existing customer being the new customer, someone we already know like yourself. So if we are having the new person from out of state or someone from a different town someone who's not been a previous customer already, that would cost or that would takes about 10 additional minutes. So that would raise that $5.36 sent cost to around $14 in change. So the cost basis you're seeing is assuming the known to us already in the system customer as would be the case in a standing order. We considered the, okay, well, what if it's a new, how much more rigor moral would you have to go through to kind of collect in additional information? It is a bit more time. It'd be about $10 more worth of cost. But the recommendation or the proposal to you would likely to be keeping it in the $5 or $6 range and not assuming all situations are that. But it's something to consider. And that would be the difference about between $5 or $6 to around $14 or $15. So. Can I ask you a question? Yeah, please. You're right here. If the chair allows it. Yeah, go ahead. Yeah, absolutely, go ahead. Scott, could you find out if we know the proportion relative to the accounts that are transferred pursuant to a standing order as opposed to a brand new customer that's never, or I'm sorry, a brand new customer that's never been in the system versus a customer that's already in the system. And you may not know that information, but if you have a month to look at it, perhaps that would be something for the next meeting. Yeah, we can ask her. Is that data that we can. Our customer care team might have a ballpark. Yeah, that just might be something that you would want to know. Yeah, absolutely, I agree. Thank you. Anything more? I have nothing more unless somebody has. I just want to thank you. Clearly, this is a subject that, and a thing that has kind of slipped the cracks a little bit. And so I appreciate you coming forward, bringing this to our attention, because clearly it's brought up a lot of conversation and the need to address these issues. And I think this is absolutely a perfect example of why customer engagement with the commission and the department, and this is what works. Someone coming forward and going, hey, there's something that needs to be looked at. We're looking at it and we're gonna, obviously, affect some changes. So I appreciate you coming forward and bringing this to us, because it's clearly something we need to look at. So I appreciate you coming and bringing this to our attention. Thank you. And yeah, this is how it should work, right? I agree. Awesome, all right. So we will get more of a recommendation, I guess, from the department between now and next meeting. We'll get more information out to folks about what's going on and see if we can get some more engagement from contractors and the like, see what that looks like. And then look at, I definitely want to look at this whole standing order thing as a part of that. And then look for having some action on this in March. Does that sound reasonable? All right, thank you. All right, sounds good. On to, where am I here? Commissioner Check-In, our last subject. Do any commissioners have any final thoughts and any things that they wanna bring up here at the end? No, almost nothing. All right, I will entertain a motion to adjourn. Motion made. Do I have a second? Sure, I'll second. Made and seconded, all in favor. Aye. Aye, all right. We're adjourned, thank you for watching.