Good evening. Welcome to Burlington Electric Commission's monthly November 9th, 2022 meeting. The start of the meeting is review and any modifications to the agenda. Does anyone have any edits or changes? I didn't see anything via email. No? Okay. And Commissioner Whitaker will be coming in about 15, 20 minutes or so. So next up is the minutes of the October 26, 2022 meeting. I wonder, you know, folks have had a chance to skim that. And if there are any content or substantive related issues or modifications that should be made, now is a great time to raise them so that they're on the record. Otherwise, if it's just technical edits, those are items that you can let the clerk know via email or at the end of the meeting. Is there anything that a new one found that needs to be addressed? Nope. Move to accept as presented. Second. All in favor? Aye. Excellent. Third up is the public forum and we do have someone here from the public. For folks watching at home, you're always welcome to come. We meet on the second Wednesday of the month. And if you can't come in person, you're also always welcome to call and speak with our customer service team by Mike Kannerick or reach out to any of the commissioners. But thank you. Thanks for joining Alan and thank you for the write up for folks watching. Alan joined us two months ago. And Alan, feel free to introduce yourself. Thank you very much. My name is Alan Birke. I'm a resident of Burlington and a relatively small provider of apartments. And I had addressed a couple months ago this issue of there being initial service fee charged to landlords when the power was put into a landlord's name very temporarily in order to clean and paint and do things in between tenants. And I asked you to take a look at it and I provided you some information about your authority to take a look into it. I know that it's not going to change right away. But I didn't want it to go unnoticed for too long of a period of time. So I thought from time to time I would come visit with you and perhaps add some more information. And so tonight I have a little bit more information. Since the last time that we spoke, I did do a survey of the other electric utilities in Vermont, telephone survey mostly, a couple by email, as well as Vermont Gas and the Burlington Water Department. And what we discovered is that many do, most utilities do allow for what's called a standing order in order for the, if a tenant moves out or the power turns off for any reason, it automatically goes into the name of the property owner. And when they do that, very few of them, three or four, will actually charge the property owner something to put the account into the property owner's name. Three of them, Green Mountain Power, Burlington Electric, and the Washington Electric Co-op, do have the ability to have a standing order where you don't, nobody has to contact them. It automatically goes into the property owner's name. The Vermont Electric Co-op doesn't have that ability to do it, but their fee to initiate account is only $19. And so what you have before you was a survey that shows that Burlington charges more than anybody else, 50% more than the next closest fee to execute pursuit and twist standing order. And most don't charge any fee at all to put it into the landlord's account. So I don't want to spend a lot of time on this, but I did want to make sure that you know that we're still interested. It's not showing up at one hearing saying something and forgetting about it. I'll come visit with you from time to time, perhaps provide something interesting to think about it, and perhaps one day hear that something's happening on it. But I do know that a tariff change is difficult and expensive and not something that happens overnight. So with that, unless anybody has any questions. I just have a couple of comments. First of all, thank you. This is compelling. Second, I want to give you an A plus for just doing research the right way, even including the names of the people you talked with. I can't get anybody else to do that. So you're ready for at least a master's degree at the Gund Institute. So I can start another career at age 61. Excellent work. Thank you. Thank you for coming in. Thank you very much. I do want to just note. Let's just be clear where we landed two months ago on this. I do believe the team here was going to look at it in the nearer term, but because we had just refiled a rape case in August to or June to take effect in August, that to your point, you know, we don't typically go to the public police every month. But we did say that we were going to look at it and assess in particular how much time and effort it did take. And so therefore, whether or not that $30 seemed appropriate. And I'm not sure if we put a timeline on that. Mr. Springer said FY 24. Well, we did look at it since you visited. And Andy Higbee did a write up for me on some different scenarios relative to new customers, standing orders, returning customers, how many minutes a rep would spend doing the different processes. It's not a complete analysis because in addition to whatever you might want to consider in terms of their time and the overhead related to that, there's some pieces around costs for credit checks in some cases. And, you know, there's more scenarios than just the one that you had raised. So I'm not in a position to say whether our fee is justified or not, which is different from saying it's higher or lower than the utilities. But I think the timeline you laid out, Chair Stevens, is exactly right. I think this is, we wouldn't look at this fee in isolation. We'd look at all of our fees. So we've begun the research. Andy did good work kind of writing up the initial piece of it. I think he's in touch with James. You're copied on the email. I'll take your word for it. Okay. Not with a request, but we'll need to have some coordination between James's group and Andy's group at the appropriate time to kind of figure out if it's justified or not. And in terms of taking the fees, there's been a longstanding desire to update the fees, but it's a big undertaking and would likely be coincident with a future rate case. So that's correct. I don't see us having the staff capacity to put it together absent, something like that. Actually, that's an important point for you to know in terms of staff capacity. Like everywhere, folks are, I think we're down like three engineers. I don't know how many engineers are... I don't know how many openings we have. How many openings do we have right now? We last, I checked, had 13 openings, 10 to 13 openings out of about 118 FTs, which is pretty significant for us. So my point is not that we're not going to get to this, but just it's great to have you come back. And to the extent that you bring more research and homework, that's great, because it'll just probably make the filing for when we do go before the rate case, more information can be added to that. But I just want to caveat that with that level of vacancies, it's a little bit slower to look at all of the fees. I completely understand. And just so you folks know, I'm an attorney. I spent a couple terms in the House on the Commerce Committee, was on a special committee that looked at retail wheeling and whether or not to do it in Vermont, and our group saved consumers from doing that to us. It's had disastrous consequences for California and Texas. So I know a little something about this, and I know it is not a small undertaking to do all the financial analysis necessary for a case like this. That being said, I thought I would just visit and remind you that it would be helpful to keep it on somewhere in your mind. And perhaps next time I'll come visit with something interesting and get to hear more about this survey that you've completed to date. Thank you very much. Enjoy your meeting. Thank you for coming in, Ellen. Just curious, any sense of when the broader research will be done? I think James probably needs to be looped in with Andy, and we would need to do analysis, but again, it's not something that we can necessarily prioritize in isolation. I think we would have to make a concerted effort to go into the next rate case with a fee update as part of that. And so we would probably start putting that together in March of next year. Spring. Yes, springtime. I mean, I'm doing a presentation tonight on the power markets for this winter, and I think you guys all need to be aware of what we're looking down the barrel of and where our focus is right now for this winter. So when you... Sorry. Spring-ish. Thank you, Ellen. Wouldn't we, for earlier discussions about changing how we do things, wouldn't we be having an annual rate case? We're tending that one or two percent. Yeah. Couldn't this theoretically come into 23? This would be... We are working towards having annual rate case, certainly. We've already filed the FY23 rate case, so that's underway and under review. And this is really different. This is our fees, our operating guidelines, which has a number of different pieces to it, several of which we've been interested to look at and update, some of which could go up, some might go down. We'd want to do financial analysis on what that would do to our revenues overall. So it's really important in my view to do it as part of a rate case and plan for it as part of a budget. And that's why I would... I'd be remiss if I said, okay, we can just look at this one and not really look at the whole package together. Right. I would say they're not directly linked, but if you change your revenues from any source, you need to reflect that in your revenue requirement. So, and they also share the same staff, the same people who are doing both rate cases and this kind of work too. So, for example, revenue from services is a line item that offsets the revenue you need from retail rates for electric service. So if you're going to change that, it changes your revenue requirement. I imagine all our fees sum up to a sizeable amount, but how much is actually involved in this fee, roughly? In terms of total revenue? Yeah. I don't know. We could look at it and get back to you. It doesn't... We don't typically show in the financials as a line item for each source of outside. It's essentially other electric revenues. Yeah. We could dig into it as a discrete item, but we don't have that readily available. Okay. Well, I'm just asking to see if it's very small. Okay. Thank you. Any other members from the public on TV? I don't see anybody. Okay. Again, feel free to call, reach out, email or show up on the second Wednesday if you have any interest to do so. Next up on the agenda is the commissioner's corner. Anything that anyone wants to mention or raise? Now is a good time. Well, a couple of points from last time or from the activities list. Have we wrapped up our arrangement with packetized energy because it was something about removing the technology and removing the hardware? Yeah. Packetized no longer exists as a standalone entity. They were acquired by a company called Energy Hub. So we've been working concertedly to remove the devices from the water heaters that was part of their Mellow device that was on the water heaters because we're not able to continue with that program. Their EV chargers are still installed. We have a number of EV chargers that were packetized equips that are still installed and James and his team have done good work making sure that those can continue to be compatible with our EV rates. So those continue, but the Mellow is no longer. We have an RFP. We put out an RFP to remove them and we have a respondent who seems to be a viable candidate. So we are working actually working on the RFP right now with Jeff Turner. Not the RFP. I'm sorry. The purchase order to get those removed. Okay. A question based on something you said during the last time in the minutes. The idea that if people had chargers and heat pumps and so on and so on, 100 amp service might not be enough. They'd have to go to 200 or something like that. And just as I was reading through that, I thought, yikes, we're back to the question maybe of time of day rates. So I wonder that's a potential solution rather than more technology. Just not to be answered instantaneously. And then I do have a question about the meeting regarding lighting on the 8th of December.  Whoops. In person. Okay. Thank you. That was the only thing I was going to say is that we, for folks interested in the street lighting conversation, we have identified some time in December that we will be talking through how we've been approaching implementation and interpretation of the IES standards with our local Burlington Electric Energy Efficient Engineer Expert, who happens to be a rate payer, just to get an additional perspective instead of eyes on it. So that's scheduled for early December. It's like a 9am. It's like the first or second. It's going to be here. Yeah. If everyone wants to go, which is perfectly fine if everyone wants to go, but we would need to do public notice. So if right now we have two commissioners planning on attending, so... I can let you know next week. Yeah, that's great. I might be interested. I would say just by default, I would just, I would warn it. Yeah, sounds okay. Do you guys both want to let me... Are you for sure interested? Very. Okay. Are you? I know. I mean, I know you're interested. Whether or not you can skip out of work at 9am. Yeah, probably not. Okay. So we have three for sure. And you can let me know. I'll let you know Monday. Yeah. Okay. Thanks. Yeah. And thank you again, Muneer, for adding more to your plate. So next up we have the general manager's update. I'll be brief since we sat relatively recently. And I think one item James is going to cover in more detail in terms of winter pricing. So just wanted the commission to be aware that we're planning a visit to Iceland, New England in Massachusetts, which I'd been interested to do for a long time. I did previously back in 2014. And I think it'll be helpful for a number of members of our team to go down, meet with ISO, talk with them, see their facilities and maybe have some conversation around some of the winter energy issues that we're seeing. So that that's coming up on November 21st. I'll be happy to share more about that visit at the next meeting. We were talking a little just prior to the meeting about the orb, which is in place now at the airport. This was the Delta Climb Incubator project, one of the pilots that went forward. There was great news coverage. We had a really nice event with the mayor, Arc Turbines, which is the company and number of folks, the airport team, the BED team, Delta Climb Renewable Energy Vermont were all there. And you can go see it if you're interested. Hopefully it's spinning when you do. It was the day of the press event. And it's a vertical axis turbine that looks a little like a beach ball from a distance due to the Arc Turbines logo and some of the different labeling. And it spins relatively slowly and is capable of generating potentially what we think 7.8 megawatt hours per year, which for a three kilowatt device is about two and a half times as much as you would get from solar of an equivalent capacity. So we're eager to learn more, see if this can be a success, see if they can lower their price. And in a year, we have the option to purchase that unit or revisit the terms of the agreement. So we'll keep the commission updated on how we're doing relative to that. And then lastly, District Energy Project Work has been picking up pace again. We have got a number of developments. We had the Evergreen team in town in person last week. I had a chance to meet with them and with VGS in person. And we had multiple meetings with VGS. The 501C3 organization that's been formed, or it's not, I think it's under process of being certified as 501C3, but it's a non-profit currently that's been formed Burlington District Energy. We have a resolution to try to allow for the non-profit to seek financing terms for the project working with VEDA at the state level. We're also having some conversations with the state treasurer's office as to whether or not the local investment advisory committee might be an avenue to finance a portion of the project potentially. So we're pursuing financing options with the state. We'll be having some meetings over the course of the next few weeks with UVM and UVM Medical. We have an RFP for construction pricing that's out with, I believe, four bidders responding. So we'll hopefully have some more information on construction pricing, which is based on the actual designs and drawings. And this is an actual RFP. So we'll get not indicative, but actual construction pricing to go off of. And we've done a bunch of work to engage with the agency and natural resources on the permitting process. And I think it's not far off where the project will be ready to begin the permitting process, which is distinct from the financial agreements, which would still need to be finalized and be in place. But to keep on the timeframe of moving the project forward for construction 23 and 24, which is what we originally contemplated, it's possible that may be ready to go to permitting sooner rather than later. So we'll keep you updated on that as well. But that's what I've got. And by bin. I did have one question with regards to the, this is probably a question for Emily, but in terms of monitoring the receivables in response to COVID-19. So rearges greater than 60 days were just under half a million. Remind me, I feel like we're past the point of being able to get any federal support for that, right? Okay. And at this point, are we just, you know, repeatedly trying to follow up with folks for that? We hadn't gotten to the point, I don't believe of actually going to anyone's door with a disconnect notice, correct? We have started. We have started to do that? Okay. Yeah. When we were, we were talking about at the last meeting, our number, it turns out just earlier that we had visited about five homes. And what is the cutoff date for when winter kicks in? Well, we need to verbal starts in November, so we started talking to our customers about that, but all temperature, of course, what we do, what we do it, and there's special provisions as well for others. So we're kind of writing the paper. It's hard. Yeah. And of course, our goal is to try to communicate and come up with payment plans and never just off the half a million. Do you have any sense is that many, many people or like a few customers that are just way, way behind or well, we, with the ARCA funds, we're going to take care of a lot of that. And it's people just kind of falling behind again. So it's, I don't know the exact number, but it's, it's a good number of people. It seems like it's creeping out because there wasn't an average for all this somewhere around a quarter of a million or the internet. So I have one question. I know we just met a couple of weeks ago, but any updates on staffing? Because I know that was something I thought you said maybe that there was a candidate that was going to come on for, no? For which position? I thought help Emily. We are. We are. To help Emily. To help Emily. Finance. Okay. In the process of interviewing for the controller position, I think it's the one you were thinking of. Yeah. Yeah. Still underway. And then there was also one, I think with Jen Green, that was. Yes. The equity analyst position interviews underway for that. Okay. That's good then. Yeah. I think, I don't know, have we started with the engineer position in Chris Burns area? Not interviewing, but the job has been posted and resume is being collected. Yeah. So several positions there. Maneer's area, there are positions that were, but we've had, I think we've had subsequent vacancies since, probably even since that last meeting. Far too many, you know, goodbyes with pizza and cake during the day, the last few weeks. So we're hopeful to not only be able to fill positions, but obviously continue to retain folks as well. Right. Cause you also had some growth positions, right? I think there was. Yeah. Yeah. We're looking at adding several positions potentially. We haven't put a package together yet. It'll probably be at least until January before we would bring that forward to the council. But there are several areas where we're looking at adding staff. So, yeah, hopefully we'll get fully staffed and we'll be able to add some capacity. And then we'd be in a great position. But, you know, realistically, I'm, you know, aware that the labor market challenge is not unique to BED and is likely to persist for a period of time. So we'll do the best we can with managing the vacancies, posting when we can, recruiting when we can, and hopefully adding a few positions coming next year. Okay. Thank you for the update and thanks for the ongoing work. Next, we have the FY22 audited financial statements. So follow up from two weeks ago. It seems like it was two weeks ago. It does, right? I think it was. I'll give you some hints. So we're here to talk about FY22 results. The first thing I'll point out and make sure to note is that audited financial statements have not actually been issued yet. I expect them to be issued tomorrow. But what you have is marked draft because they are in fact draft. They are not officially issued. However, at this point, I do expect issuance very soon and I don't expect the numbers here to change if for whatever unforeseen reason they do, I will update you next meeting. And once the financial statements are issued, I'll have Lori send them to you and their final form. So you'll have that for your, for your records. Okay. I actually wanted to start here. Let me share my screen. So I'm going to start actually in a bit of a different place. I don't remember if we've shared this before or not, but you're accustomed to seeing budget versus actual results. So I thought it would be perhaps useful just to briefly touch on how did we land versus budget and then I'll go through the details of the financial statements themselves. So for the fiscal year ended June 30, 2022, we had a positive net income of almost $2 million, $1,937,000. That was favorable to budget by quite a bit, $1.129 million. So yeah, definitely an excellent result for the department. And major contributors to that were rate increase, increased sales to customers, and then power supply expense was favorable mostly due to the strong winter energy prices. So those were kind of the two big, big drivers. And we'll go through details of this on the income statement, but I wanted to give you just high level of where we landed versus budget. And then in terms of capital spending, overall spent about 65% of the capital budget. Most of the budget spent in generation and distribution, general includes not only IT forward, but also IT in general and facilities in general services where a few of those items were affected by supply chain delays in IT equipment and an electric bucket truck being a relatively big ticket item. Oh, sorry. Bucket truck was falling in this row here, general. So this percentage that we haven't done isn't necessarily a concern in terms of deferred maintenance. I would say yeah, the supply chain of vehicles has been a concern and we've been trying to mitigate that and try to plan and keep up with it, but we're certainly watching the fleet and its age and we want to electrify the fleet, right? So we're making decisions to purchase electric vehicles, but availability is challenging. I meant more writ large. Oh, I don't know. I don't think so. Yeah. And so here's where we ended. I think I've already reported cash numbers to you, but again, 8.4 million ending cash balance. That's 120 days cash on hand as of June 30. The debt service coverage ratio as of June 30, 4.61, well above the 1.25 that were required to maintain, and then the adjusted debt service coverage ratio 1.22. So I'll flip now to the draft financial statements. I also will just say that I expect no changes. I still expect an unmodified opinion. I haven't learned anything new from KPNG that differs from what they communicated with you last meeting. And I also, before I go through these, just want to let you know that the finance and accounting team has just done an amazing job this year. We went through the audit without a finance director last year, but I think this year actually was even more challenging. Last year it was only me who was new to the process, and they were all experienced and had been through it before, and I could really, you know, they pulled, they did everything, right? This year we had a number of new people on the team, a promotion, a new hire, a vacancy right around August 1st, right? So everybody pulled together and really worked as a team to get it done. So I just want to mention Cheryl Mitchell, the financial analyst who's usually not very involved in the audit, stepped in to help out Melissa Legg, the payroll administrator, Heidi Grohlander, the new AP administrator, Erin Cushing, promoted from AP to fixed asset accountant her first time dealing with fixed assets in the audit. And then new hire Amanda Hurlbut who started in mid-September very quickly came up to speed to kind of put finishing touches on things and final reconciliations. And then really the Lynch pin senior staff accountant for McNeil, Ian Liu, who just was like the backstop for any question that nobody else could answer, Ian figured it out. So I really want to just convey my appreciation and gratitude to the team and let you know that they're the ones behind the successful audit this year. So with that, stepping into the balance sheet has two pieces, two pages, assets and deferred outflows on one side, liabilities and deferred in the flows on the other side. And I'll just go through kind of some of the biggest changes here from year to year to highlight for your attention. Capital assets did not change that much, relatively minor decrease of $51,680. That's a net of additions to capital assets versus depreciation. So holding steady there. Cash increased pretty significantly, up $2.4 million, that's about 24%. Again, the two major drivers, the 2021 rate increase as well as sales of excess energy in the winter. The rest of these current assets did not change very significantly. The next one I want to call your attention to is in the non-current assets, restricted investments with bond trustees. That number did go up quite a lot because we issued the 2022A revenue bond, right? So there is where you can see the additional $20 million on the balance sheet. I'm just seeing if I can get rid of that light bulb thing. I don't think so. Okay, moving on. Next row I'll highlight is regulatory assets that has increased $218,000 from fiscal 2021 to 2022. A couple new things that we received approval to book as regulatory assets in the 2021 rate increase. One was to amortize the IBEW pension back payment over a number of years. The second was to amortize the triennial consulting engineer review that we are required by bond resolution to have performed of the electric system and the McNeill station. That's an every three-year expense. It's fairly significant. We received approval to amortize that over three years. And then also in fiscal 2022, we received approval of an additional accounting order or a modification of a previous accounting order to amortize additional noncapitalized labor that was unable to be spent on capital projects due to COVID delays. So the next item that is new on the balance sheet this year is this one, RES inventory. And you'll notice at the top of the page, apologies for not highlighting this off, we've restated 2021 results. Okay. And the restatement for the balance sheet essentially consists of this new asset inventory asset for RECs and tier three credits that are available for use for compliance with the Vermont renewable energy standard. So we modified assets and expenses for FY 21 in this presentation and then also are reporting a new inventory amount for FY 22 on the balance sheet. Can I ask a question about that? And if it's a big thing, we can talk about it another time, but is that real money or is that like a credit? They are credits that I think have real value. That's perhaps the best way to say it. Okay. Yeah. Okay. And it counts as a capital asset. I wouldn't say a capital asset, but an asset, right? So RECs, we could go trade them and sell them instead of bank them. So they have value, a market value that we could recognize in the market through a trade. The tier three credits don't have a market right now. In theory, maybe someday they could, but there's no sort of active or standard market for them. The only sort of way to use them is to file with the PUC that says, here's how many credits we generated and here's what we need to comply based on our load for the previous calendar year. So what we're doing is we are incentivizing all of the strategic electrification we can, right? And we're paying customers, we're paying out cash for those incentives. And then instead of expensing one to one every dollar for every dollar we pay out in cash, we are putting them all in an inventory bank. And then we are only expensing the amount equivalent to what we would, what we need to expense for compliance. And we're leaving the rest in the bank. So that's what the inventory represents. So that's where the value comes from? Okay. Yes. Yes. So just theoretically, like hypothetically, in a year or yeah, in a calendar year, when we underperformed, right, or had a terrible year for tier three programs, right, we could go to the bank. Yeah, right, we could use those credits in inventory to comply for a year where we didn't generate enough from activity. Yes, that's where that's how they translate into value at some point. Okay. Thank you. You can bank up to three years, right? Rex, you can bank for up to three years. Tier three has no expiration under current statute. Okay. Next line to call your attention to is another new one, other non-current assets. This is the Moran frame. It's the other side of the Moran frame liability that is the uncorrected audit difference, right? We'll be seeking approval from the public utility commission to book this as a regulatory asset. And then the changes here in deferred outflow of resources are mostly actuarially driven. Could you remind me again about the associated companies we have equity in? Yes, that represents, let me go back to that, that represents our equity interest as a partial owner of TransCo and Velco, the liabilities, current liabilities here, this $12.8 million, that's an increase of about $2.7 million from FY21. Most of that is due to an increase in accounts payable. You can see this line here is up about $1.9 million versus FY21. Most of that is due to timing of rec purchases that we made late in the fiscal year where they were still payable as of June 30. The non-current liability section, the long-term debt that's there are revenue bonds, our GEO bonds that's driven by the maturity schedules, the payment schedules of the bonds. Other non-current liabilities increased fairly significantly, up $1.2 million from FY21. That's that increase is composed of two parts. One, we took out an equipment financing note to help finance the new meter data management system, which we executed in July 2021. So it was kind of a while ago, but it was an FY22 activity. And then the other piece that's sitting there is the Moran frame liability. Net pension liability went down quite a bit this year, 5.8 million. Again, those changes are actuarially driven. And then just think the important thing here to see is that the total net position increased by $1.94 million compared to FY21. And that is really that net income, the positive net income we talked about when we talked about budget to actual sort of falling to the bottom line here. I'd like to have a question. Yes. Some of this is what I'd call a flow, which is dollars per year, but the bond is dollars, right? I'm not sure I follow, but. Debt service is measured in dollars per year. But when you list the value of debt, is that the value of the bond itself? That is the value of all the debt outstanding, not the annual payment on it. Does that answer the question? Well, now the question then is, do you ever add those together? Yes. I think would you. I'm a stock flow guy. I love it. So. I'm not. Are you looking for like the annual amount of debt service we're going to pay? I'm trying to understand the table and I'm not sure I haven't checked which numbers are added to what, but I see things listed that seem to be dimensionally incommensurate. One is debt service or something like it, which is measured in dollars per year. And the other is the value of a bond, which is matters in dollars. Okay, so the top the current liabilities at the top of the page. Where you see the 1.85 million for revenue bonds and 3.575 for geo bonds. That represents the amount of debt service that we are. Will pay in FY 23. So it's the portion of the whole debt that remains that's going to be next to be paid. And then the long term under the non current liabilities is sort of the rest of it. So the balance sheet isn't really presenting a cash flow of debt service over time. It's it's presenting a snapshot of the liability of the department. But if I wanted to tease debt service out of this page. I don't think you I don't think you could do that because they all have different, you know, coupon amounts and different interest rates, right? Different maturity schedules, different premiums, right? And so, you know, the revenue bond line represents the 2014 A and B, the 2017 A and B, right? The 22 a and the geo bond amount represents, you know, 10, I don't know, multiple geo bonds, right, that we're still paying off some dating back several years. There is a detailed footnote schedule that shows the annual amount paid, you know, the amount of principal and interest paid in FY 22. Well, let me just that's of interest. Halfway down is a number, 113 million. That's the sum of the 12, 8 and 100. What is that measured in? Dollars. For fiscal year? For fiscal year 22. Okay. So all of these are monies that we would be paying out during that year? No, no. That is the total liability of the department that is money we owe at some point in time. A snapshot of what we owe on June 30. We do have a debt service schedule that that really looks at each year's proposed kind of payment that fits or what you were thinking about. Well, I think it's again, I better defer the conversation sometime later. But it's sort of an apples and oranges picture that I'm drawing here. It's accusing me. The 12, 8 is the 12, 8 where it says total current liabilities. That's what we would have to pay in FY 2023. But then this also shows everything else we're going to have to pay into the past FY 2020. And that's the next category, non-current. You're right. It's apples to oranges. I mean, it's not saying we owe all of that right now. Okay. Thank you. Does that help? Yeah. Okay. It helps me understand what it says. I'll chat with you later about what I think. What it means? Yeah. What it means, it doesn't mean. Okay. Are there other questions or are you going? Okay. The income statement. So revenues at the top is usual. Sales to a little black box. Is that possible? It was a white box. Was it bother you? No, no. Well, I'd be nice if it's gone, but I thought when she looked at it and it turned white, it was still black and dark. It's not on my screen as black. Okay. All right. You can keep going. We don't have to. Sales to customers increased by 3.7 million in 22 as opposed to 21. Maybe I'll move it down out of the way. There we go. Most of that due to the 2021 rate increase. Okay. Other revenues decreased modestly at $173,000. Most of that, well, some of that anyway, declining rec revenue due to lower wind production and a lower price for McNeil recs offset by a higher volume of McNeil recs sold. The provision for uncollectible accounts. We discussed this last year. We had made a change in our methodology for estimating that during the pandemic because we knew we had access to federal grant monies potentially to help with that. As commissioner Whitaker observed or asked earlier, we no longer have access to those monies or none that we know of currently. So we've reverted to our previous standard methodology for estimating that amount. Come to operating expenses. So reduction, which is increased just under half a million dollars. Flex operating and maintenance expenses that make me go on the gas turbine. Purchase power, very little change. Really holding steady from 2021. A mix of pluses and minuses, netting to almost zero change, increased rec purchases, increased price for and volume for Vermont wind and Hydro Quebec that was offset, however, by decreasing capacity prices and sales of excess energy this winter. Transmission expense increased almost $900,000, $869,000. Most of that driven by higher ISO New England transmission rates. Distribution expense of 3.352 million. All quite in line with FY21 customer accounting, service and sales. This increased by 590,000 from FY21. This was driven by some increased software expenses, but it was offset by the accounting change we made for tier three credits. Administrative and general expenses were down significantly, actually 1.159 million. Most of that pension and benefits costs. So I know you've discussed the pension expense that we have to take. We've budgeted for that. It actually was less than what we budgeted this year, which was a pleasant surprise. Depreciation and amortization increased by 719,000. Most of that additional depreciation on the distribution plant. And so here we have just to look at our operating income, positive operating income of 1.9 million. And then we also restated expenses for FY21. So we had, I want to say, forget what our net loss was in FY21. I think it was a net operating loss of like 100,000 or something. And now it's 20, it's a positive income, positive operating income of about 30,000. Velco dividends were pretty much in line from 22 to 21. Interest income, very little change. Grant income was down significantly. However, FY21 was kind of an unusually high grant income year. Yeah, yeah. And then unrealized loss on investment. This used to be rolled up in other income and not on its own line. We changed the presentation this year because it's a bit more of a significant number. The reason it's more significant is that we have more funds invested right now because of the revenue bond. And so this is the sort of how up or down we are compared to our initial account value and the construction fund. So it's unrealized in that, if we were to sell all the Treasury bills today on June 30 would have had this much loss. But the next day, we might have had an unrealized gain. So we've pulled that out in terms of presentation this year. So taxes, capital asset, the usual things that we've been talking about. So here's again, the 1.938 increase in net position or net income, same thing. And then the total net position, which ties to the balance sheet. Any questions on that before I go to the cash flow? Okay. Cash flow is busy. So I won't take you through every line of this. But the big categories here, I think, are fairly intuitive. So net cash from operating activities, that was up by 2.9 million from 21 to 22, makes sense given the improved operating results that we saw. Cash flows from capital and related financing increased by 19 million. That's because we issued the bond. So we had the 20 million flowing in there. And then similarly, cash flows from investing. You can see purchase of investments also changed by 20 million. That's because we invested the money that we got from the bond to keep it working for us on the side as we draw it down. So total increase in cash from 21 to 22, you can see that change here from 9.8 million to 12.2 million. That's a 2.4 million dollar increase. And then the bottom of this sheet, the reconciliation, is just another way of showing how you get the difference in the operating cash at the top. I'm sorry. I didn't mean to scroll all over the place. Okay. And then finally, I'll just review quickly. Again, this is a reminder, a presentation change we made last year. We present the Energy Efficiency Utility Fund as a separate fiduciary fund. So it's not co-mingled with BEDs, assets and liabilities. Not significant changes in this fund from 22 to 21. Cash increased by about $500,000. Accounts receivable and payable changes are general, basically speak, are essentially timing differences. So slight increase in net position for the EU fund of around $300,000 or $400,000. And then there's a sort of income statement showing additions to the fund, collections from customers, from the EEC charge on bills, forward capacity and Reggie revenues. And then the payments we made for programs, again, not a lot of change from FY21. So that's what I was going to cover for the 22 results. Any questions? Apparently no. Thank you. And thank you to your team. When you do get the final documents tomorrow, what is the process then for MUMMY? So when the financial statements are issued tomorrow, we will send them to a few people. I'll share them with the city's auditors. I will share them with our bond trustee and probably with ISO New England as well, just as part of regular reporting we need to do. But there's a, the statements are issued, and then we coordinate kind of a management representation letter that we provide to the auditors as part of the issuance process.  That's about it. Also roll into the next year's budget, right? When's that season? So yeah, the budget building will start around January. Yep. Thank you. So that was just a discussion. Next we have, well I feel like you kind of skimmed over these a little bit, but, or no, that was from last time. Financials, FY23, September. So you don't get to go away yet. Apologies that these weren't in your packet. Finance team is just about caught up, but I anticipate that for December meeting, October results will be in your packet, and we'll be, we'll be back on schedule for monthly closing. I just got these today myself, so make this so you can see them. Not quite that big. Okay. So for September we reported a net loss of about a million dollars compared to a budgeted net loss of 817,000. So we were 223,000 worse than budget. Of year to date, we have a net income as of September 30 of $195,000. That's $700,000 worse than budget. Moving through kind of the details, sales to customers relatively on budget, both residential and commercial were up modestly. Miscellaneous electric revenues were up. Most of this is EEU as there was no power supply, not a rec delivery month in September. Power supply overall was 60, about $60,000 better than budget. Fuel was favorable as McNeill was offline, so therefore production was far less than budgeted. Capacity was favorable by 13,000. Purchase power was unfavorable. So we have a number of offsetting variations from budget because wind and McNeill production were under budget. Therefore, the ISO exchange expense was higher than budget. We're also with a gas turbine service. We are under budget in terms of for reserve revenues at the moment. O&M was unfavorable. Most of this is due to timing. Other income and deductions unfavorable by 224,000. Part of that, customer contributions for construction, the timing of those, and then the other one, that unrealized loss or gain on investments that we talked about. So in sum, the difference is made up in part due to timing, but then the other major chunk is due to McNeill, Georgia, not necessarily having the opportunity and the gas turbine not being able to sell into the market, essentially. And we're assuming, or rather that's when we'll be talking and hearing from James. Okay, you know where I was going with that. Okay, we're assuming that that'll improve or change, or yeah, okay. So capital spending about $2 million so far versus a budget so far this year of 3.3 million at this point in the fiscal year. That's 23% of the total fiscal year budget. The usual timing differences happening here to affect that. Cash we were, as of September 30th, $6.6 million available. That's 106 days cash on hand. Debt service coverage ratio 3.56 and the adjusted coverage ratio 1.01. Questions on this? Okay, thank you. Next we have Paul Alexander with the 2022 property and BNM renewal discussion vote. Thank you, Emily. Okay, I can't believe that worked. Good evening. Paul Alexander here for the annual property boiling machinery, insurance renewal. I think all of you have sat through this before, so exciting stuff. Okay, let's move this out of the way. Okay, not that you're last in line, so it's always a timing thing. Quote, Jim. I presented this last Tuesday night to the Board of Finance, so it was passed there and then went on consent agenda this past Monday of this week. So this line renews on the 20th this month. So your vote is still important. Okay, so this is property boiling machinery. This is by far our biggest line of insurance.  It's the only one over 100,000. So for multiple reasons, the magnitude of the line itself and because it crosses over a couple policy years, city attorneys encourage us to go through this process. So again, repeat for most of you, not all of you, what's covered commercial property boiling machinery. So that's really everything that's tangible. Put your hands on from the desk in this building to the McNeill station, buildings, furniture, computers, et cetera. Current status and it has been for the last several years, the magnitude of this of writing our property boiling machinery, particularly because of McNeill station. We have four different carriers. So all the other lines are one carrier, one line of business. These are four that team together. AIG, StarTech, Zurich and Aegis, each get a piece of the pie, if you will, and share in those premiums. And then the losses, if we had any, knock on wood, we haven't. We've got a really good history down there. So again, this line expires on November 20th. We pay currently right now an annual premium of $663,508.14. As you might recall, three or four years ago, a significant jump. We were in the mid-200s. So what's in your handouts? The standard four pieces are Hickok and Bourbons, our insurance agent. So they had a cover letter walking through some of the pluses and minuses of where we're here and what's going on. A cover letter from myself, a two-tab, very brief. It's all that shows a history from 1994. It's a bar chart and stuff. I'm going to cover those now if you want to. And a really handy, if you haven't spent any time, Hickok and Bourbons has what they call a quota share program. It's really just a bar chart, but it's really a one snapshot. It shows all four carriers, how much that they cover, and their premiums that go along with that. And more importantly, how well percentage they're covering from two columns, one with McNeil assets and one with a non-McNeil. And again, McNeil is a focus and what makes it most difficult to write this line of business. What's new this year or what points Hickok and Bourbons want me to point out? As always, Hickok and Bourbons works, they start in this around May. So it's quite a process to get this, and we're still not done. That's why I'm going to ask you to vote for a not to exceed amount because they negotiate literally right up to the last day, which is November 20th. We will not go beyond the 20th. Yes. You're mentioning a handout. I'm not seeing it. The package that would have came from Laurie, the backup information. You can get any of that? No. Okay. Well, good news. It's attached to this slide. So you're in for it. I've got the time and we're in the right place.  I've been scrolling up and down. I saw Bob looking at his package. He's still looking. Well, at the end of this next slide, I'm going to walk you right through. I do have them attached to this presentation. So make seed my 10 minutes. Okay. Apologize for that. Capacity is nothing more than what the insurance companies are willing to write what they can write. So it takes the four of them together to write this line of business. The good news is the renewal premium is going to, is anticipated to increase last year's amount of 663.508 with a not to exceed 683.413. That's nothing more than 3% of what we are currently paying and what we budgeted through Hickok Abortment. So that is actually good news compared to some of the increases. That's yeah.  It's an insurance term. It just means everything you're covering. What's the total book of business that you are writing covering again from the computers to the laptops to the McNeil station? So if you recall, there's a cap. So we have our total book of business.  Okay. And it has been a cap for several years now at $175 million. No concerns for a couple of reasons. One, the McNeil station is almost at that limit, $190 million. And this plan, obviously our headquarters, the less than three miles away McNeil, it would take a huge event to take both those buildings out of commission at the same time. So highly unlikely obviously for many reasons, fire explosion and so on. So we're basically covered in whole, but that's we are cap. So if both those plans burn to the ground, we'd be coming up short, but that's not going to happen. And I guess it is also good news in the cover letter that you did not get. They list a lower premium. So again, we're not to exceed the $683 million. They, as of a week ago, anticipate and still negotiations anticipate will come in actually a little bit less than that about $672,000, but about a little less than $12,000 less, which is great. That would be like a 1.35% increase. So which is good given that line. So a couple of really good things going on. Some considerations every year we talk about not just ways to reduce this line, but there's other things we can do with or without the city. Hickok and Borman is the same insurance agent for BED as well as the city. So one of the things they looked into was combining on a cyber liability policy with the city. But through Paul Plunkett said, at least now for aligning the terms, conditions and pricing did not benefit either party meaning BED or the city. So we'll keep looking at that, but we're not going to do that certainly this year. Joint Captive, as you know, Vermont, we're third in the world for Captives. Cayman Islands, Bermuda, Vermont, again, talked to FM Global and Energy Insurance Mutual. They have what's called a minimum premium, no matter what, they won't write that below $750,000. So that's that price along with some of the long-term risks to BED, again, right now we're not going to pursue that. And really the biggest benefit is, again, AIG is one of the four carriers, but they're not shared equally. Their rate that they charge us per $100 of coverage is like two and a half times less than some of the other carriers. So the more they write, the more money we save, and the more percentage we'll take away. And I'm going to show you that chart in a second here. So they came to us and wanted to write more than the 25% they have. And we were one time a month ago looking at 50%. And that would have been significant savings for us. Didn't share all those details with Darren, but it's really good news because they want more of the book. So at the last minute, though, the politics that may be, they end up writing only 35%. But there's 10% more. But again, that's why we're at a savings of about $13,000. Next year, we're hoping to write about 50% of McNeil and non-McNeil. I'm going to show that to you in a slide in a second. And their interest is they're looking at what the actual risk is and saying there isn't really that much risk. It's been good for so many decades. And therefore, we think it's a worthwhile... Great question. So from my notes, why is AIG so interesting? Here we go. No losses. We've had a loss free for them. They've been with us forever for over 20 plus years. McNeil recommendations. We've done a lot of things, really kudos to Darren and Maneer and the staff down at McNeil of getting all these engineering recommendations done. And that really makes us look a lot better on their books, much lower risk. And we're showing that we're committed to being a long-term partner. No speeding tickets. Pardon? No speeding tickets. Right. No speeding tickets. And we've been really flexible with them. We're changing our levels of coverage, raising our deductibles and that stuff. So just a real good partnership between us and Hickok and Borman and them. So they're one of those four carers. But the more they want to write, it's much really good news for us. So fingers crossed for next year. Good question. Okay. So before I get to my slides, the impact on budget, as I mentioned already, this line again renews November 20th. As you know, we're on a fiscal year of policy. So we basically have five months from July through November at the current premium rate and then seven months at whatever the new rate is going to be. So the budget is a combination of those two numbers. This amount not to exceed what obviously would be a zero percent change in our budget. And again, reiterating that Hickok and Borman thinks we'll come in a little bit less. We'll know that in the next week or two. But no matter what, we can't let the policy lapse. We will bind at the knot to exceed if not something better. Okay. Skipping over the motion for a second now. I'm going to skip here are all the handouts. I'll make sure you get. There is my cover letter. Okay. And with everything I've just covered. So there's no need. Here's Hickok and Borman's cover letter from Paul Plunkett. Okay. Here is that slide that I mentioned, which is really fantastic. Property quota share program structure. But you can see here, if you follow my cursor here, two columns. This is the assets other than McNeil. So that's Pine Street, gas turbine, when you see wind hydro, it's all lumped them to this column and then the McNeil. And these are the four carriers, Aegis, Zerk, StarTech. And down here, the most critical bucket, AIG. And you can see here that they're writing 35%. This was 25% last year, 35%. Fingers crossed, that'll be even higher next year. So the more they take of this pie, the less it goes around to these other carriers. This is a critical number right here, 0.17. That's 17 cents per $100 of coverage, if you will. And look at the rate of Zerk, 38.1. There's your 2.2 times, if you will. So the more AIG writes, and the less these other companies, nothing against it. They're good partners, but until they can meet that rate, we'll ask AIG to keep writing more and more as their capacity can handle. That's the slide that is critical. And again, here's the infamous chart. You can see what happened not that long ago. We were running along about 2.0 and bang. That's when we had an exponential increase in our premium. Here we are starting to flatten off, which is great. And those are the slides you did not see. Okay, questions? If not... I'm glad it wasn't that type of jump from, you know, five years ago. Yeah. Kudos to Paul for his hard work. I mean, he's got... It's all behind the scenes, and it's a lot of negotiation back and forth. No, he seems to have her back, so... Yeah. It's a good job for us and the city. And not to assume you're going to pass it, but for the city attorney, this... Would this happen before she wrote back to me? You can stop at the city attorney's office because we already have approval from Board of Finance and City Council. So if someone's going to read that, you can pause right there. Is there a motion to... Or rather, is there any discussion or concerns or questions that folks want to raise? Okay, is there a motion to approve? I'll make a motion to authorize the general manager of the Brownton Electric Department to execute the property and boiler and machinery insurance coverage renewal contract with the AIG Zurich StarTech Agents for the policy period 11-2022 through 11-2023, whether or not to exceed premium of $683,413 as outlined in this memo. Second? Second. All in favor? Aye. Aye. Thank you, Paul. Good job, Paul. I have a defense. Are you going to... Paul just wanted to surprise us with all the good news. That's the way... Well, he sent it to me to put it all together because he was going to the city council with Board of Finance, so I sent it to him. He never occurred to me to keep one. So I... I think I have a little plan to mice in there. Oh! So last on the agenda, thanks again, Paul, is a winter 2022-2023 update discussion and James, thanks for coming on up. So my PowerPoint does not have any attachments and they have not been provided. So I think we're... Start with the basics. Just go right to the beginning. We all thought it was probably a good idea to talk to you guys about winter 2022-2023. You're going to hear the term unprecedented. It is unprecedented what we've been seeing in the wholesale markets. We're far from the only people that have been sort of stunned by the wholesale markets, but we are not as impacted by the wholesale markets as many people. And the way we're impacted is interesting, and that's why we thought it would be reasonable to sort of call your attention to this. Something should make this... There we go. So I'm just going to remind you quickly that there is a very, very strong relationship between natural gas prices and electric prices, and New England has spoken about that before. That has not changed. So whenever you heard anything in the news story recently about natural gas, that's hitting this market, the electric market. Okay, here we go. And again, we're not heavily impacted by it directly at our fundamental level because we have a renewable resource mix. The only two of our resources that really have any component about the wholesale markets and natural gas is Hydro-Quebec has a partial index to it, and that was part of the 2012 deal before any of this ever happened, and McNeil indirectly because of transportation costs of wood, but not a very big direct impact from fossil fuel changes there either. This is not a problem for us because the cost of our resources is going up. It's a different issue for us, if you will. So I'll remind you that this is the sort of the setup is that we have access resources, and we have access resources from renewable resources for the next several years. So we're coming into this market with resources, net resources to sell, as long as our resources produce as expected. Okay, that's a proviso, and it's an important one, but if they produce as expected, we are a net seller of energy, and we are actually more of a net seller of energy in the winter, which of course is again, I'm going to show you what that means, but it means a lot of money at this point, but a lot of volatility. James, though, there was a little BED recently issued an RFP to consider local in-state and regional renewable energy for procurement. Is that like asking folks who own plants, do they want to sell power to us? That's essentially a start to look at replacing inspiring things in that 2025-2026 window. We're sort of looking ahead, and I'll mention that at the end. I can't talk about what the results are so far, but we did issue a broad RFP communicated to everyone we could think of from renewable energy, Vermont, to people who own, to HydroCorpac, I mean really the entire spectrum from local in-state, solar to large national corporations. This is what's been happening to the prices. If you look on the far right side, we're showing essentially the projected prices. They're forward prices. They're what people are selling power for for the winter months, and we are seeing January power in excess of $250 a megawatt hour. Highest historical price in January was just shy of, which was just a little bit over $150, said another way that's 25 cents a kilowatt hour for electric energy at wholesale without transmission, without capacity, without delivery, and without renewability. That is pure wholesale brown market power. At over 25 cents a kilowatt hour. Can you just say what it has been like recently? I mean, I know, but just for anyone watching at home. Well, if I again, three and five. Well, you can see it right here actually is January has never been probably, well, January has been down around the four level. If you look back to 2016 and 2017 and 2020, but 2020 was a COVID year. So the fact that it was trading around four cents was a little off, but four is a possible number. And on the other end, 150 is the worst we've ever seen. Okay. And we're over 250. So not only has it moved up a long way. In the last 18 months, it's moved from about six and a half cents to about 25 cents. So in the last 18 months, it's quadrupled. So again, when people talk about the prices being unprecedented, they're unprecedented. And it is a lot of uncertainty about the availability of natural gas and the frequency and duration of cold snaps. The longer the cold snaps go on, the more the natural gas pulls gets pulled away from the generating sector to the heating sector. The generating sector does not have firm commitments for natural gas for energy production. The heating sector has first drawn it. So the longer that cold snap goes on and the more heating load accumulates, the less and less gas is available for the generating plants. Now they can try to bring liquid natural gas into the Everett port in Boston to help with that. But the situation in Europe is throwing a lot of question on where the natural gas would go. And one of the biggest New England companies has asked for a federal waiver of the rules that normally govern what types of ships can dock at Everett. So again, this is not a small problem. Nor do I see this problem going away next year or the year after that. It would take a gas transmission pipeline or something like that to solve it. So for a while, we're looking at very high winter prices, I suspect. This is just taking the previous date and turning into a one value for the entire winter period. And there you see even stronger. You know, when you when you when you average across December, January, February, you can even see a stronger effect. So highest there has been maybe 130 and we're still over 200 on average for that period. So that's turned into rate cases around New England. Obviously it has not turned into rate cases in Burlington Electric, but it has turned into very large rate cases in the areas that deregulated the electric industry. So these are some cited numbers from news stories. You know, these people are looking at rate increases of 30%, 40%, 50%, 60% in a single year. That's because they're served at the competitive market. They don't they don't have a utility who is holding a portfolio of long term resources to average out those effects. So again, you know, Vermont right now is looking very good in terms of this. I mean, we will see, I suspect some Vermont increases and that'll be people who are short, who who are not sufficiently covered in energy and we're planning on buying some on the spot market and are now exposed to those spot market prices. They will probably have to come in for a rate case. And I would not advise to see that coming in next month or two. This though is an it was what I really want to talk to you about. The data line is when we filed the rate case and what those winter prices were. Okay. And the line after the dotted line is what's happened to it since then. And what that represents is the price that's applied to our excess energy. Essentially, that's how much we stood to make from selling that excess energy. So it increased significantly after the rate filing. It is now decreased to where it is below the rate filing. And to put that in context between June 16th when we filed and today, our total net cost of power has fluctuated by $4 million from $500,000 worse than when we filed to $3.2 million better than when we filed. And that is the monetizing of just that excess position. If you weren't hedged, if you were sitting on the whole, you know, resource portfolio, you'd be looking at the 60%, 70% type of rate increases. We're actually right now exposed to low market prices. So if we have a mild winter and these prices don't come in at these levels, then actually what will happen is we won't realize our budget. Not because we're paying more, it's because we're selling our excess for less than we thought. And again, you know, to see movement of $4 million in four months, you know, in your net power supply cost due to the monetizing of a 15% excess position is a lot of movement. So, you know, we need to be aware that we are certainly watching this. We're monitoring it very closely. We are looking for ways to lay off some of that risk of the prices not coming in, but it is very difficult to do so. Transacting at prices this high is not easy for anybody because people become exposed to collateral calls, things like that. It's just, you know, it gets to be very hard to transact. So we are looking at one potential transaction that might help lay off some of this risk at known prices, and then we wouldn't be exposed to the prices being low. On the other hand, to be fair, they could come in higher than this. You know, that is possible too. A colder than normal winter would drive prices up in general. So that's really the message we wanted to tell you is that we're looking down the barrel even with fully hedged and excess power of volatility. It's just a different kind of volatility. It's volatility of loss of potential revenues, not of increased costs. So are you also split, like, are we working at, like, there's this financial piece, right? But the other thing is we're trying to be more energy efficient, trying to electrify as much as possible. So are those forces large enough to exacerbate this? No. It doesn't make, it won't make, because we're just talking about like heat pumps and whatever. Not yet. I mean, you know, those are anticipated to grow or load materially, but not in the context of buy this winter. We're not seeing so many heat pumps that we're seeing a loss of winter sales. But at some point right now, if the market were 25 cents, it's actually more economical or more lucrative to sell it to the wholesale market than to a customer at 16. I mean, so there are economic impacts of converting 25 cent wholesale sales to 16 cent resale sales, but I'm not seeing a problem for that in the next winter or two. But could I just add something briefly on that point? It's more of a legislative policy issue that I think we're going to see is a lot of the conversation is around the renewable energy standard is that the utilities are going to see all this new load from heat pumps and EVs. We're going to double or triple our electric use, and therefore we need a bunch of new renewable generation and a bunch of new solar. And there's just such a disconnect for me looking at that both in the pacing, because we're not seeing as you review our sales, we're seeing nothing come out of the noise yet of seasonal variability in terms of, you know, we've incentivized well over 400 EVs and over a thousand heat pumps, but the usage is such that you haven't really seen it material impact our load yet. And we're starting to invest with the revenue bond and preparing for that. But when you look at this challenge, the prices are going to be high in the winter, maybe for the foreseeable future. Solar isn't really helping us solve this challenge. McNeil is helping us solve this challenge. And yet there's a lot of criticism in certain quarters about McNeil and about biomass and saying, we don't want that, we want solar, we want wind, and we're for solar and wind too. But it really speaks to the need to have that balanced resource because absent McNeil, we would have 20 percent plus more rate pressure than we had with the 3.95 percent, we'd have a 24 or 25 percent rate case. That's one of the reasons it's difficult for us to lay off this risk, if you will. If you look at that graph, you can see that if we lose McNeil for any length of time, we stop being long. McNeil is the bottom resource and it is enough that without McNeil, we are buying wholesale market energy. So we've positioned McNeil and the McNeil foresters have worked herculean efforts. We have the biggest woodpiles I've ever seen looming over the plant. And what we've done is we've positioned ourselves to run essentially around the clock. We're doing preventative maintenance. We're coming off of that right now to try to minimize the downtime and to maximize our excess energy position during those high price times. But correct, right.  So again, we have a very key resource sitting at the bottom of that stack that can take us from being long to short by losing the one resource. So again, it's a huge hedge. And the ability to stockpile a fuel, the problem with the natural gas company in plants is they can't stockpile fuel, right? They are going to draw the gas off the transmission line and generate power. We can stockpile four months of wood onsite. What I was talking about is like we're adding electricity as much as we can and we're being as efficient as possible with that new load. That's not yet showing up as Darin said? That isn't showing up. Most people are still had the pandemic and the shifting from commercial and residential. So there's a lot of noise. I think that's what, yeah, Darin said it well, which is we know the load is there. It has to be there. I mean, those vehicles are being charged, but we haven't seen a consistent increase in load coming out of the noise post COVID yet that causes me to change my expectation of having excess energy for this winter or even next probably. So it might affect how much we bought in a replacement contract for 2026. And is this a New England thing or is it national? This is a New England thing. New England has a super high reliance on natural gas generating without the transmission to reliably fuel it in all conditions. And we have cold winters. And we have cold winters. And there's been resistance to bringing in new transmission for hydro from Canada. Correct. Multiple proposals to do that, none of which have gotten approved. And then the only other thing that's kind of lingering out there is offshore wind at scale. But that always seems to be a few years off from kind of coming online. But hopefully that'll that could be an injection that could be helpful. But I think James said, you know, pipelines, there's not appetite for that. And we've taken coal off, right? And shut down a lot of nuclear. Yeah. So you're starting to constrain the resource mix and the solutions to add to it aren't necessarily aligned with the operational, you know, reality. And McNeil, you know, the fuelable resource that can operate base load for extended periods of time, which actually makes it very unusual. So, you know, but again, just again, it's important to keep in mind that because of McNeil, we are long. If McNeil drops offline for extended periods of time, then we're buying those prices. So again, this is a, this is a, you know, we're certainly doing everything we can to position McNeil for maximum reliability this winter. We pressured ISO very, very hard to give us the outage to get ready for it. So we didn't have to have something come up in January, you know, and so again, we're, we're well positioned, but you do have to keep it in the back of your mind. It's also interesting to me as I think for the transportation sector, the big cells been electricity so stable, right? The price of electricity has always been super stable. So electrified vehicles, you're going to have lower costs and you can count on them. But we'll see this winter. I think that's more true in Vermont than it is in other states in New England, because we're still vertically integrated. To be true nationally, it just could be like, you know, you might see seasonal difference in other states in New England where you know, double digit or triple digit rate increase because of this and that becomes more of a pain point. So just keep in mind with your, if you know, if we're coming in and telling you that the weather is very, very mild, that might have adverse implications from the power supply side in loss of sale value of the excess energy. But it's arbitrage too, because you've agreed to buy it for a dollar, you're selling it for five or something. Right, we'll still buy it for a dollar, but if we sell it for three, that's not going to help our financials from budget. Right. Okay. The last thing I just wanted to quickly mention is just if you hear about this winter reliability is becoming a bit of a concern in New England for all of the reasons that I just mentioned. It is possible, we don't expect under normal operating conditions, there'd be reliability problems, but the Pentel does exist under extreme cold weather, particularly if it's extended period of cold weather, for that disruption of the gas pipeline supply to the generating become a problem, and enough of a problem to possibly allow for rolling blackouts. Again, this is not new, there's been news stories about it, if you haven't heard them, we have had calls at Burlington Electric from customers asking about the news stories, so we thought we'd at least bring this up. Again, it's not something we expect, it's not a probable event, it's a possible event. And also because it would, I think, be triggered by an extremely, an extended cold snap, it's not going to happen without some warning. We're going to have an extended forecast of minus 20 degrees for seven days, and it's going to start to look like there might be an issue. What we're talking about happening, if that did happen, and again, not saying it will happen, would be rolling blackouts. And if you've never heard of those, they have been used for a long period of time. I remember when I was a child in the Midwest, 50 years ago, they were rolling blackouts in St. Louis on really, really hot days. It would be an outage duration of, say, two or three hours, and then your power would come back on, and the outage would roll to somebody else, to make sure that nobody was sitting on, you know, being without power for days, or even significant parts of a day. So the Vermont utilities have been meeting on this for over a year, more like a year and a half now, coordinating the plans for outage coordination, scheduling, rolling blackouts, if it were to happen. But again, that is a different animal than saying we expect it to happen. We just want to be ready if it were to happen, to make sure that nobody found them. Because if the grid collapses, like happened in Texas, then it gets worse. So this would be to maintain the reliability of a grid in an extreme situation, rather than lose the whole thing. So I recall, I forgot my answer, but this is also a regional problem, be very clear, this is not a Vermont problem. This is not something Vermont can solve, and it is going to be triggered by the whole New England region calling for rolling blackouts regionally. This would not be targeted at Vermont, it would not be targeted at Burlington, it's not a local problem. It doesn't seem like we should have to blackout. We have the... The requirements are to maintain grid reliability they can call for load reductions. Okay, that's where I was going to go. So I recall Ken Nolan testifying like that in 2005, everyone shut down except us because of McNeil. But this would be basically Iso-New England telling everybody, okay. You mean what you're describing is a theoretical islanding, where, you know, Burlington says, okay, we're pulling in our resources and the grid can figure it out. Is it a theoretical possibility? Well, the near is here, doesn't he? I mean, well, that was due to a snowstorm. I mean, that was different. That wasn't a regulatory, you must do this because you're part of the regional grid. Yep. And of course what that would be viewed as is us taking more generation off the grid than we took load off the grid, and that would be problematic. But if you could island, then you could, you would be all set. As long as everything went well and nothing went wrong, and as long as you, you know, and if the grid is there when you come to go back online and sink to it and everything, I mean, theoretically, I suppose it is possible. Yes. I'm just thinking of a transit agency that has solar and storage. That would be a microgrid. So like I say, if a area could be carved out and had sufficient and proper resources to be self-sufficient, it is theoretically possible to island. But there's all kinds of headaches with that. It's gonna be interesting to see if it happens because there are a couple of. I don't know that I would use that word. Stressful. Yeah, yeah, yeah, yeah, yeah, yeah. No, I'm just thinking like of transportation. Oh, whether, whether they really have the resiliency they think they have. Yeah, like everything should be, yeah. People will find that out. Not even we open up the switches to GMP and McNeil's online. 50 megawatts. Right, we have, we have an interesting mix of generators, but he's, you know, it's right. It's a circuit question. I don't know that. I mean, we have, we have a gas turbine. We have a black start unit. We have, you know, multiple megawatts, you know, we have low generation in excess for our load, but it may not be placed, right? That's what I'm saying. It's theoretically possible for areas to island. I don't know if we can do it. So, well, and the other pieces, you know, we are part of a regional grid. And if Burlington says, whatever, there would be repercussions. Right. So the last thing I just want to mention throughout is what is this doing to the annual price of power? It's moving it up to. So we're looking now at annual, this is annual now wholesale price of power, not winter wholesale price of power. So we could start to see impacts from these markets when we go to replace our contracts. So just again, you know, this is, this is not just a winter problem. It is, but it's mostly a winter problem. This is an annual chart. Wouldn't it just be like a straight line? So rolling 12 months. So what you're doing is you basically pick up a day, drop a day. So it's not like a year. So it's, it's 12 months ending December 31st, 2018, 12 months ending January 1st, 2018. So it's a, it's a, that way you get the constant motion, not the stepwise because it doesn't move stepwise. So, but that's what it's doing is it's showing you change over the 12 month average as it moves through time. Okay. That was it. That's all. I mean, again, like I say, we are concerned and we're watching it and we're, you know, again, we're, we're sitting on the better side of the equation, right? We have excess resources at high price times. We would like those high prices to come in. I suspect we're not the, we're not, you know, we're not the, you know, the majority of people right now who would like those prices to be high. So a couple of comments, questions. Again, hedging doesn't help. I said it's difficult to hedge. Hedging does help. If you can get the, put the right hedge in place. That doesn't mean I can find a buyer that would buy the type of hedge that would help us the most. And we have tried so far. We have not succeeded. Well, we would like, I want to be careful about putting too much market information out on, but, you know, again, you're trying to match what you sell to the risk you want to retain and the risks you don't want to retain and then find out if there's somebody out there who will take that commodity on at a price that will help you and you don't have any guarantee you'll find someone. When I think about McNeil, your first concern was we couldn't sell enough energy at a high enough price. And that's to other people besides Burlingtonians, right? The excess power is sold on the wholesale market. So we know why that's a good thing, but this is also why that's a bad thing. We're Burlington Electric, but we're actually selling electricity. And of course, we want the price to be high. If we weren't selling it, that vulnerability wouldn't be there. Yes? Well, but if we were short energy, for example, let's say we took McNeil out of our portfolio and we were therefore not selling excess energy, the last rate case would have been 20% higher in order to purchase the wholesale power we need to fill up balance of our portfolio. So that would have been worse, right? I mean, I'm saying it materially worse. We're on the better side of this equation, but the only place where there's no volatility is when your resources exactly match your load in all hours of every day, and that doesn't happen anywhere. Yeah, because I was going to say, of course, what we want to then is just have is a total 100% captive hydro situation. Where it can be dispatched to match the load in every hour, because the load, the prices change hourly, not monthly. We owned it, and we didn't sell it to anybody else. Well, anytime we just did not have adequate energy, we would have to draw on the regional grid, even if it was in an hour. So again, I can say you need a perfect match hourly to wash out all of the risk of the market, and that's almost impossible to do. Unless you just have incredible overcapacity, and then you have to pay for that. We will not lose money on selling our excess energy. The question is, will we make as much as we budgeted for? But we're not going to be losing any money on this energy. As far as islanding, I'm thinking about all that woodpile I've got, and that wood stove, although it's not electricity, and I imagine there are people after saying, my generator boy, I'm glad I bought that when they hear this. I don't want to make this sound like it's going to happen, but I don't want to say that we didn't tell anybody either, that if you hear this, this is how to interpret it. Well, and I think the important piece is energy is the pulse of our economy, and how we drive and heat and cool our homes. And frankly, if you're not preparing for the worst case scenario, then you're not doing your job. So I think it's far better to be meeting as multiple utilities and saying, okay, how would we address this? How would we deal with this? And we have a war in Ukraine. We have multiple proposals to extend Quebec power down that have not moved forward. We've had multiple proposals to extend gas pipelines up that have not moved forward. And we've had a whole lot of wind projects that have not moved forward. And so we're here we are. And the wind, yeah, so I just want to say, though, that we have been attending these meetings for the last 18 months, both engineering and policy and planning for both sort of the market side, and the reliability generation, dispatching side. You know, so again, I just want people if they hear about this to not panic, but to have the frame of reference, if you will, as to what could create this kind of problem and that we would theoretically have advanced warning, and we would be able to communicate with people if it did occur before it happened. That just seems to really be a good subplot here about the benefits of being renewable and not being tied to natural gas and having our own portfolio of energy that like we're our only risk is if we don't sell it the excess at the price that we thought. But we're still protected against the external market because of the portfolio of energy that is not making as much money as we budgeted to make. Yeah, exactly. So I think that's getting lost in this like really good story about being net zero energy and being ahead the rest of New England's trying to catch up to that. Well, that's why we had a 3.95% rate increase and not the 70% rate. Right. I mean, we still have cost pressures, but they're not fossil fuel based cost pressures. Right. And I think there's some really good story in there somewhere, but that that's yeah, and everyone's here rolling blackouts about what it's actually a good story. Could you share your presentation with us? Other questions or comments? Thank you. Yeah, now that's interesting. Thank you. Yeah. I don't know that I would use the word interest. I mean, it is interesting. I thought it was super interesting. More than that. So thanks for that. Well, there's insurance, but when rock climbers, when rock climbers. Sorry. So last on the agenda, fortunately, there is no vote on that. Last on the agenda is the commissioner's corner. Any thing that folks want to bring up? This just reminded me. You mentioned, Darren, that there was a ship that missed it full of gas. That's right. That's part of the deal. That's part of the what James just discussed, the ice in New England's winter reliability plan is in part that they are paying and charging the utilities pro rata for this liquefied gas tanker that's offshore in Massachusetts and already used fuel during the summer time at expense to us, which is when Emily shared the financials and we were off 700,000, I think roughly 150,000 of that was these charges from this particular tanker, which were unbudgeted and unknown. And those were, I think, utilized in the summer time, not because they were needed, obviously, for winter reliability, but just to enable a new tanker to come in with a full load. And so, yeah, when we think about it, that's part of our region's reliability plan. It goes back to the point of, McNeil's importance, bringing in more hydro or more wind or all of the above, really, to help reduce our reliance on this one fuel that we are completely relying on in the winter time, which is natural gas. It makes me wish we could find so many more geothermal opportunities that we could actually have a lot more storage capacity. Yeah. I mean, we're tapping geothermal for ground source heating in Burlington, but my recollection is New England is just not a great geothermal electric generating resource, unfortunately. So, yeah, when we look at our options, we're thinking hydro, wind, battery storage could play a role, obviously, and maybe not moving away from some of those generators that are low carbon now, even whether it's nuclear, biomass, preserving what we have and then trying to build more. So really, we need to think about winter time renewables, particularly in the electrification scenario where more people are using heat pumps. We may see the region become more of a winter peaking region again, and we need renewables that align operationally with that. And that goes back to the orb at the airport. That's going to produce more energy theoretically in the winter time than a solar panel might. So having that could be a nice compliment to having solar in the summer. We need a whole bunch of additional winter reliable renewables, I think, in the region. I think there are a lot of homes that people could get by in when it's hot, at least here in Vermont, but they may not be able to when it's cold. Okay. If we're done and motion to adjourn. So moved. Second. All in favor. All right. Thank you, everybody. Good night.


Our unit is conducting our annual training at Camp Ripley. We're very much like a regular unit during annual training. We start around 06, and then our training will either go 24 hours or index around midnight. We have flight operations throughout the period, depending on weather and depending on other training conditions. This is my first AT. It's sort of been hectic on me because I just got back from AIT not too long ago. So I'm trying to learn as much as I can before I go back. We have four LUH-72s that have been doing flying missions around the local area. PR lanes are an opportunity for us to conduct personnel recovery because we fly a lot and in places where there might be opposition forces, we have to be prepared to conduct ourselves on the ground if we have to land. It teaches soldiers how to survive, communicate, where to go to get help, and how to find their way out of a problem if we find ourselves in one in the future. We have just thoroughly enjoyed our time here at Camp Ripley. We were looking for a training area that would allow us some maneuver space to test our capabilities, both in the air and on the ground, and this fit everything that we had. So my job with the unit is the medical NCIC for the battalion. We do everything from real-world medical coverage to planning out training for all the medics in the battalion. So I've never seen training like this done before, and I really thought it was good because it was helping our pilots and our medics. I was actually a casualty at Mystic, so I got an IV. My job is to support the battalion. I'm learning a lot more right now because of AT, and my NCOs have been teaching me a lot. They make me want to learn and continue with my MOS and just progress and be a better 92 Yankee. I love supply. It can get hectic sometimes. You're always busy. We're the first one and the last one out. It seems like our unit comes here every few years, and every time we come it produces incredible results. I'm sure we'll be back. I am excited to get home, but I will miss AT.