Transportation Board - Regular Meeting

Good evening. I call to order this June 17th, 2026 regular meeting of the Board of Public Utilities. Thanks everyone for participating this evening. We will start as usual with opening the floor to public comment on matters not otherwise on our agenda this evening. Do we have any public comment? I see one. Sure. Please state your name for the record and Limit your comments to three minutes, if you would, please.

Okay. My name is Ray Sartor. I'm a resident of White Rock. And what I wanted to address is this residential demand that's being proposed. In principle, I oppose it because we're paying for the electricity twice. You're going to have an additional fee for our peak demand hour. And we're already paying the rate for whatever that hour is, given our forthcoming two-tier system. Given that in reality it won't be eliminated, I also oppose how it's being proposed, that the proposal is our peak demand over any 24 hours of the month, whereas the purpose of the two-tier pricing system is to get us to shift out of the peak demand for the system. And that's what this, if we're going to have this residential demand, it should have that same purpose also. My wife often gets up early 5 a.m. and she likes to turn on what she calls her servants. So the dishwasher will come on, the laundry, the dryer, the washing machine. She'll put a roast in the oven and all that's going on. And you're not going to tell me that her causing our personal peak to be at 5 a.m. or 6 a.m. is going to put a burden on our electrical system. If we're going to have the residential demand, there's much better ways to do it. You've already identified six hours of the day where you want people not to shift out of. So put the residential demand for the peak of that six hours is one way. Another way is, what's the peak for the whole system of the month? What's that hour? Then identify the customers that drive that peak. And a third possible way is set a goal. Say you know what the system capacity is. And I understand we don't want to have to grow the system. We want to keep the system as it is or grow it as least as possible. Set a goal like 95% of our capacity. And every time there's an hour that exceeds, that 95 capacity, then you identify who's the customers that are driving that high demand. And that way we will achieve this goal of shifting us away from our peak demand driving the system to be ever larger. And that's my comments for today. Thank you.

Thank you. Is there any other public comment in chambers? Is there any online?

Thank you, Chair Gibson. For members of the public who are joining us tonight on Zoom, when Chair Gibson calls for public comment, please use the raise hand function. If you are participating by phone, press star nine to raise your hand. If you wish to make a public comment at this time, please raise your hand on Zoom. Chair Gibson, there are no hands raised.

Thank you. That takes us to approval of the agenda. I would like to pull item 6 excuse me item 7 a off of the agenda for tonight It's listed as a rate comparisons with national data, and there was apparently a failure of communication I'll own that I guess Because what we were really looking for was cost comparison not rate comparisons, so we'll bring that issue that matter back to some future points so 7a off the agenda otherwise i'd like approval of the agenda with that change i move we approve the agenda with that change jennifer are you with us yes i'll second thank you okay moved and seconded i actually did that more as a test to make sure you were really there And awake. That may be the critical part.

Well, here, awake is another story.

Okay. Moved and seconded. We approve the agenda. All in favor? Let's see. We've got two here. Jennifer?

Yes.

Okay. You're in favor of approving the agenda as amended?

Yes. Correct. Yes.

Okay. Okay. That motion passes 3 to 0. It takes us to a statement regarding the closed session on June the 3rd. And Matt, would you be willing to read that one? Make sure I'm on the right page.

Yes. I move that the Board of Public Utilities approve the following statement for inclusion in the minutes. The matters discussed in the closed session on June 3rd, 2026 were limited only to those topics specified in the notice of the closed session, and no action was taken on any matter during the closed session.

Okay. For simplicity, I'll second that. Any discussion? Okay. Again, this is procedural, so we've got two votes here. And Jennifer? Yes.

Yes.

OK, motion passes 3 to 0. That takes us to the consent agenda. There's one change internal to the consent agenda, and that is that both of the minutes for both of the May meetings have been amended. And those amendments have been handed out. They're on the DS tonight. I think they were sent earlier too, I believe. So we should be able to pass the consent agenda as amended. with that understanding.

Perfect. I move that the Board of Public Utilities approve the items on the consent agenda as amended and that the motions and the staff reports be included in the minutes for the record.

I second.

Okay.

Any discussion? All right. It's been moved and seconded. This will take a roll call vote on. Kathy?

Member Hollingsworth?

Yes.

Member Hefner?

Yes.

And Member Gibson?

Yes.

And Member Stromberg is trying to log on.

Okay. You said Member Stromberg was trying. Is that going to the minutes he's trying? That's not quite what I meant, but anyway. Okay, motion passed 3-0. That takes us to Item 7B. Discussion and possible action on one-year rate increase for gas services. It's page 79 of our agenda doc. And we will...

Chair Gibson, we have other items for B, C, and D. Pardon? For B, C, and D are still on the agenda. Or on consent. I'm sorry about that.

Well, that's fine. Thanks for... Trying to keep us honest. Okay, Joanne.

Good evening, Chair and members of our board. On the June 9th council meeting, they had asked us, they did not pass our ordinance 02379 and asked us to come back with a one-year ordinance for gas. And sorry, my presentation has the wrong one. We had to change the ordinance number. So it's actually 02385. So this new one-year ordinance has a new ordinance number. So on the next slide. So on this slide, we're kind of showing a few different things here. The green line is our net income or loss. And this is going, it starts when we, July 1st, or how we ended June 30th of 25. At that time, our net loss was $489,267. And then you can see how it kind of trends along through the rest of the year. And right now, we were able to get actual numbers through the end of May. We don't have our June totals, obviously. We haven't finished the month. So those are estimated. And so it's looking with those numbers through May and ending June, right now it's looking like our net loss will be about $760,000 to end the gas fund this year. So this next slide, I just kind of wanted to show where all of our expenditures land. Obviously, our cost of gas is a high amount of the expenditures, but the cost of gas is a pass-through rate. And then our next one is inter-fund charges. Those are the costs that we pay the general county for services like HR and finance and procurement and those kind of items. And then our next one is salaries for our GWS staff. And then we go to our professional and contractual services. and then we have our benefits, and then we have a small portion of it goes to capital outlays. We don't have a lot of capital. This last year in gas, we did have Elk Ridge, which is coming in at about $200,000. I think our budget had $400,000, but it's coming in closer to about $200,000. Our next slide is... showing our 27, we've got 25, 26 with our 27 projections. And those are, again, based on our five-year average of 6.8 million therms sold. So you'll see the revenues, the blue operating expenses, orange, greens, cost of gas, capital is the blue, and revenue is the purple or pinkish color. And the green line that's down below is showing our net income or loss. And you'll notice in 25 and 26, again, we're at a loss of our net income. You'll see that it's trending up in 27 with these proposed rates and that again is at if we do sell 6.8 million therms of gas As you know this year was a little Warmer so we did not sell as much We're gonna come in at about five point six million therms potentially by the end of this month And then this next slide So this one I showed, I believe it was in the last two presentations for gas. But we did add the New Mexico price of natural gas delivered. But this is for fiscal year, I mean, I'm sorry, calendar year 25. So this was the cost of gas across New Mexico for January through December of 2025. And... So you'll notice that with the 50 therms and how it goes up through 150 therms, the line, and based on the calculation, they have it at decatherm. It was broken down per therm. At 70 therms, the average cost was $80.47. which is about our average of therms sold to our residential customers. And if they use 100 therms, the cost is averaging about $172.43 on their bill. So we just added that to kind of show the gas rates across New Mexico. So right now with our proposal of ordinance 02385, it has just the first year on the ordinance. And it took out everything for the second year that we had proposed initially. That was really the only change we made from the two ordinances was removing fiscal year 28. charges or rates, I'm sorry. So I'm open to any questions the board has.

Thank you. Questions?

Matt? Thank you, Chair. I had two quick questions. One maybe on the slide before on slide four. I just wanted to make sure I understood that the revenue is the only positive number on these bar charts. Is that true? And I guess my real question is, is the revenue transfer in or out of the gas fund?

I can't remember. The revenue transfer? Yeah. We do pay out of the gas fund. So that's paying out.

Okay. Yeah. So everything else, the operating expenses, the cost, the capital expenditures, those are all negative. So ideally, the blue bar matches all the other bars.

Right.

Okay. Yes. Perfect.

Thank you.

And then my other question was more of a meta question, which is how did we get here? So I don't know if you want to take that or read or file up. But I just wanted to make sure I understood. We had some public questions about the gas rate increase was voted down. Why is the board coming back with another one immediately? And I think the answer is because the council asked us to. I think I heard you say that. But can you give a little bit more details of why we're back here doing this?

Chair, Member Huebner, through the council discussion of the proposed rate increase, there was the chair suggested that we come back with a one-year increase, not two, and see where we stand a year from now. Okay. I mentioned, too, in the staff report, the same night council had been considering some charter amendments, and those may have an impact on how we project and set rates going forward for both electric and gas. But we won't know the outcome until November's election. But that would give us time during our budget process in January through March to make some proposals then. Okay, perfect. Thanks, Phil.

Thank you. Thank you. That's everything I've got. Okay.

Jen, did you have any questions?

Yeah, actually, on this chart, I had a question. I'm sorry if I'm missing something. So these are always based on a certain number of therms sold, as indicated at the bottom here. And we are actually selling recently less than that. If you actually take into account a different projection based on closer to what we're actually selling at this moment, how does that impact these charts? THINGS GET WORSE.

CHAIR, COUNSELOR HEAVENER, I'M SORRY, HOLLINSWORTH. SO I DID, IT'S NOT IN HERE, BUT I DID SOME, LIKE, PROJECTIONS, AND I I based some of my projections based on the actual sales that we're projecting for this year to kind of see if we only get to this year. Because the 6.8 million, of course, is how we did our budget back in January, February, and March and got it approved by council. So I'm kind of sticking with that in some of the charts just so that it is consistent. But looking...

I'm sorry. Well, I'm partly asking, you know, because... We need to answer the question of why are we coming back right away with a potential request for an increase in gas rates for one year. And beyond whether the council is asking us to do that or not, I would assume you might want to make the case for financially – for financial responsibility for the DPU, whether that's required, right? And so if the actual therm sold has a big impact on our solvency here, just, yeah, that's kind of why I'm asking. That might make the case for why one would need to pursue a rate increase, I guess is my question.

You're right. Yes, that is the reason. And if we do not sell as many therms of gas next year, yeah, I mean, we'd remain in probably a deficit depending on how much we sell. Because, I mean, our costs... There isn't a lot of changes in our costs. We did just pass the CBA, the agreement for gas, water, and sewers. So those new salaries are now included as well. Moving forward, we didn't have those salaries back in January when we were creating the budget. So some of those expenses will go up a little bit. But yeah, so yeah, you're right. We do need to explain that, but everything's kind of based on the 6.8 million therms that we're projecting for 27.

Okay. Yeah. And I mean, just because there's quite a bit of interest, right, in the communities, we do want to make sure that we're being as clear as possible as to what is going into these numbers. And on the next slide, we're comparing to other New Mexico communities. Again, we should, I guess, make it clear, right, that we don't know what the other communities are planning to do with their rates, right? So... Our trajectory here in purple, let's see, and I mean in the blue and red is including increases in cost or in the rate, right? But we don't know what New Mexico Gas Company is going to do or Zia, right?

Correct. We don't.

Okay.

And again, it would be nice to try to reach out to those folks and maybe get a more realistic basis for the numbers we show for other New Mexico communities. Because again, I think that is something that our customers might be looking at is how we compare. And if we're showing flat rates for them, you know, yeah, that could be a challenge to these numbers as well.

Okay. Thank you.

Did you have any more questions or comments, Jen?

I'm good at this time. Thank you.

Okay. Did Eric get online?

Yeah, I did. Thank you, Chair Gibson. I mean, I'm on the fence on this one. Okay, so whatever our increase was, I don't remember if it was 27%, whatever it was. But I mean, we're obviously not taking in as much revenue as we are expending. And so we can't keep that up. That is not sustainable. So yeah, maybe let's just say it was 27%. That's a whole lot. I think we need to come back with something like maybe 10%. I think it's a good idea possibly to check with other communities as a sanity check, but their realities, their dynamics are not the same as ours. So ultimately what they do doesn't affect our finances, but maybe it would make it more palatable for the public at large. If all around us are doing 10%, well then, you know, okay, maybe we can get by with 10%. That puts us in a little bit better position. So that's my thoughts.

Thank you. A question, Joanne, on this chart that we're looking at right now. The purple line there says NM price of natural gas delivered, calendar year 25. What is that? I mean, is that for all of New Mexico? Is that some particular company? What is that particular line from?

It is from, let me pull that up.

It's all of New Mexico. So every natural gas supplier averaged out is what the cost is. Okay, that's helpful. And I got that from American Public Gas Association. It's an index cost price. They do it for every state, but they don't do a national average. Okay. Okay. So basically the purple line shows we're pretty close in alignment with statewide. Or even underneath it. Average, yes.

Because this was a calendar year 25, and we're looking here at our FY26 and FY27. So if that purple line were FY26 or FY27, it'd be higher than where it is. Presumably, yes. Presumably. Suggesting we're actually underneath the statewide average. I would like to comment on something that Eric just said because I think it's our fault for putting out something that is easy to misinterpret. and that is that very high number for a percentage rate increase, 27 or whatever it is. But that's only the revenue to the county from the service charge and the fixed costs. That does not take into account, that's not what the customer sees, because the customer also sees the cost of gas, which is passed through. So if you take that out and look at what the customer sees, it's a good deal less lower percentage than that. But because it's there, it was there when this was first presented in February. It was pointed out at that point that that was something that could be misleading, and I think a lot of people have continued to be misled by that. It's not that large an increase. It's still a substantial increase, but it's not as large an increase as that 27 or whatever percent number that we have. So that's, I think, our fault for presenting it that way originally and not really correcting it. Question, a little bit of how we got here. If I remember correctly, I think it was last year or maybe the year before, we had to add, I think it was three employees for compliance purposes in gas. Is that correct?

I'll let Clay answer that. I'm not sure about his staffing.

So we didn't add any more to the overall gas water sewer. Well, we added a supervisor. We added a supervisor, right. So that did, yes, so we did add, so a supervisor had to come in, take over management of the gas system. And that did open up one spot that we needed to fill. So we did add one person. So it was one. Okay. Yeah. But what it did do was, it's kind of a long story. So in the past, the gas system's in good shape. There are some challenges with it because it's a regulated utility. There are some things that we have to keep doing now that we Probably didn't do to the level that it was required before so we've had to dedicate a solid crew of our senior pipe fitters to do these procedures because that's required and And what we would do is we'd have a water line break or a sewer backup or something We'd call those guys off the gas system because there was never an emergency on the gas system But we no longer can do that. They have to stay on it. No matter what so If you were to look at the time allocation for those senior pipe fitters, you would see them being spread amongst the other utilities. But now it's just dedicated to gas.

Which means that they're not working for the other utilities. That's correct. So in effect, we've had an increase in the number on gas and to look at it, maybe a

EASIER WAY THAN HOURS CHARGED TO GAS. THAT'S CORRECT. THE SALARIES THAT'S BEING PULLED BY THE GAS SYSTEM HAS INCREASED QUITE A BIT BECAUSE WE KEPT GETTING THESE FINDINGS AND NEAR VIOLATIONS FROM THE PRC. AND SO BASICALLY WE WERE PUT ON NOTICE THAT NO LONGER CAN WE SKIP CERTAIN OQ PROCEDURES DURING THE YEAR. WE HAVE TO DO THESE THINGS NO MATTER WHAT. So one of the issues is we bought the gas system from P&M in White Rock, and it's steel. And so there's a lot of O&M on that steel because it does not have a rectifier that induces a current in it. So we have to do all of this electrochemical cathodic protection work, and it's just never-ending. We're constantly having to check the potential between the soil and the pipe and fix these cathodic protection problems. And so it's just a lot of work and maintenance. We don't really have a lot of capital projects that we need to do anymore. We've done all of those in the past. Now it's going to be little pockets of things that we need to do. But the O&M on it is going to be this way for the duration that we own and maintain it.

Okay. How many... do you have in gas? I mean, I know it's easy to look up GWS in total, but how many of those are gas?

Yeah, that's a good question. So we will always have at least two crews, if not three, doing certain things to it. So each crew is two. It's a primary and a secondary. So we have between four and six people working on it. And like I said, all of them have to have their equipment Each two-person crew has to have one of the senior pipe fitters that has the gas fitter license. And that's one of the issues. So it takes up one of our senior pipe fitters for each one of those crews. Pipe fitter or senior pipe fitter.

Okay. Thank you. Okay.

Can I just do a quick follow up? Sure. Yeah, I just timeline. I'm just Clay. Approximately what year did we have to, you know, to promise the dedicated senior pipe fitters for gas? And approximately when did the White Rock issue with lots of the enhanced O&M work kind of come into play? I'm just curious.

So those are good questions, Member Hollingsworth. So we've always had this issue with the cathodic protection in White Rock. But what happened is, you know, the regulations, I keep going back to the analogy that it's like owning a nuclear facility. You know, it's overseen by the pipeline hazardous. I mean, the regulations come from the DOT. The division is the pipeline and hazardous material safety administration. There's a whole bunch of codified rules that have to be enforced by our local enforcement agency, which is the Public Regulation Commission. So they have a special pipeline safety bureau. And so they come in and they review everything that you do, all of your records, everything. So what they saw, since we have all of these other blended utilities in this department, was that we kept pulling people off. So it's not like we're just in the business of gas. We offer gas, water, and sewer. And so we have 22 gas, water, sewer pipe fitters, you know, the crews that run the gas, water, and sewer. Any given day, we have... to four people off and so that you start to diminish how many people you have working right so but never can we not do our gas O&Ms and so no matter what we're doing that as a primary thing because we're going to be in violation so the the issue with White Rock is is just a good example of something that we had perhaps, I don't want to say neglected, but we didn't put enough emphasis on it. And it was one of the big findings that the PRC kept hitting us with that we had low CP values, the cathodic protection values. So, no matter what, we have to start doing this work and it's time consuming and it takes these people who have the certifications to do it. Another thing is we have kind of a – it's a really interesting and robust system, but we have a 100-pound – sort of transmission system that goes through the townside area. And then we drop the pressure to a more safe 20-pound system. So it's a cool design and it's safe and everything, but it creates more work for us and more O&M because we have all of these PRV stations in town or regulation stations or of different than a PRV. But those have a lot of maintenance procedures that are required. And they go through the book. Okay, here's the date. Let's go look at these. And did you perform all of the things? If they see any rust, if they see that you didn't perform the test procedures or anything. So the guys have to do it. Yeah. So I think we really, the audit lasted for like, it was over a year between 20 and 21. And so it took a year for this big report to come out. And then by FY23, I think is when I came to BPU to explain the situation. And we had to bring in a dedicated supervisor. and completely overhaul our O&M plan for the gas system. And so I think it's been since FY23 that we've been doing this. And we've stayed in good stead with the PRC. They're happy with us now, but it was touch and go for about a year there. We were trying to stay out of violation, and they kind of put us on notice.

Interesting. Now, that helps. Thank you. Thanks, Clay.

You bet.

Any other questions from the board? I guess I'll go ahead and make a motion that's similar to the proposed or the recommended action, just phrased a little differently. I move that the Board of Public Utilities direct the utility manager to present a one-year gas services rate increase, LAC Code Ordinance 02-385, to the Board on July 22, 2026. Can we discuss the motion before we second? Or do we second then discuss? Okay, I'll second it. Okay, moved and seconded. Now discussion is open. Why? Actually, I ought to ask for public comment, so let's do that first. Is there any public comment in chambers? Okay, I don't see any. Is there any online?

Any members of the public watching on Zoom, please raise your hand now if you'd like to make public comment. Chair Gibson, there is one.

Okay, let's hear that one.

I do apologize. Linnell Brody, you may now unmute yourself to speak. You have three minutes. Please state your name for the record.

My name is Linnell Brody. I'm a resident in the western area. So we get this one-year tax rate increase. What is the purpose of just doing a one-year increase? And what would be the intent of that increase at the end of the year?

So we're listening to comment right now, not opening a discussion during public comments. And we do have your email or your community feedback form, by the way. I was going to bring that up if you didn't comment.

Great. Thank you.

So go ahead and continue with your comment.

Yeah, so... Without discussion, I do have some concerns with our citizens being able to afford yet another utility increase at this stage, considering the electric increase that's happening in July. And we'll be seeing... everybody will be seeing a rate increase, a utility bill increase. So has the board considered the financial impacts to our residents to be able to handle or absorb two rate increases in short order?

Again, you're asking questions. Sorry. We just need comment at this point.

Yeah, right.

Yep.

Yep. I guess my comment would be that I'm concerned about the community's ability to handle multiple rate increases to their utility bills this year and that the board consider spacing those rate increases out a bit further to allow citizens to adjust their finances accordingly.

Okay. Is that the extent of your comment? Yes. Okay, thank you. And like I said, we do have your comment in written form also. Is there any other public comment?

Anyone else wishing to make public comment? No, Chair Gibson.

Thank you. Okay, now it's open for board discussion.

Matt. Perfect. I guess my main question was just... The purpose of the motion is to bring the full ordinance back to us. I just wanted to make sure I understood that. Thanks. That'll be the formal public hearing.

Is there any other questions or comment here for board discussion?

Mr. Chair, just for clarification, because the current language of the proposed ordinance is not a one-year increase. It's an increase to take effect on August 31st of 2026 that would, as it reads, be a long-term permanent increase until the ordinance is amended again. So are you requesting that it be redrafted and brought back as a one-year?

No, not at all. That it be, because as was explained earlier, what was originally proposed is a two-step increase, and this would make it a one-step, just the first step of that. So it's, yeah, one increase. So you're suggesting, and I see how you've got a problem with the motion. Let's see here. How can we change that? Good point. Thank you. Because I think Ms. Brody in her written comments asked, if approved, how would the board guarantee to residents that the rate increase will end after one year? and it was not and is not intended to end after one year. It's a step increase that would then go on permanently. Well, since we've got the ordinance drafted here, I think we could just say present... LAC gas ordinance 82-385 on blah, blah, blah date. That I think gets rid of it. So I will, with the board's permission, do a friendly amendment to my own motion. Perfect. And move that the Board of Public Utilities direct the county manager TO PRESENT LAC CODE ORDINANCE 02-385 TO THE BOARD ON JULY 22, 2026. YOU SAID COUNCIL OR COUNTY MANAGER.

YOU MEAN UTILITY MANAGER? I'M SORRY. I APOLOGIZE. WE'LL TRY ONE MORE TIME. ANOTHER FRIENDLIER AMENDMENT.

I DON'T LET YOU GUYS MAKE THE MOTIONS. I CAN'T DO THIS STRAIGHT. YOU AREN'T GOING TO OBJECT. OKAY. We'll try again. I move that the Board of Public Utilities direct the Utility Manager to present LAC Code Ordinance 02-385 to the Board on July 22, 2026. I'll second that. Okay, thank you. Thanks for straightening me out here. Is there any other Board discussion?

Chair Gibson?

Sure. Go ahead.

I don't have that ordinance in front of me. Can you give me the gist of what it says?

It is exactly the same as the ordinance that we proposed before, except it only has one increase in it. It doesn't have the second year's increase in it at all.

You mentioned something... Which I think is very important, and that is the fact that the 27% was only one of the components of the gas increase. So I guess I was kind of expecting that. the motion would be for the staff to come back with an actual percentage based on typical usage. Is that something that can be done?

I would hope that that's in the presentation. It actually has been in the presentations all along, what the effect on a given household is, and you can work percentages from that. Um, so that's nothing new, but, uh, presumably that will be, I hope highlighted when we, when it comes back the next time to help it be more easily understood by everyone.

Okay. Cause as a part of the discussion, if it is clear that that is in the ordinance, then I will vote yes. But if it's, that's not in the ordinance, then I'll vote no.

Um, Well, the ordinance does not give a percentage increase. It gives amounts, amount for service charge, amount for what we call fixed charger. Gas consumption charge. Consumption charge, thank you. It does not give a percentage increase as such. And then, of course, the percentage increase that a given customer sees is will depend on the cost of gas, which is a pass-through that's not in the ordinance, not affected by the ordinance.

Yes, of course. But the, okay, so when they present that, if we vote yes on this and they present that to us, then we can have those discussions at that point, I'm supposing.

You sure can.

Okay. Thank you very much.

Thank you. Any other board discussion? Okay, seeing none, Kathy, would you please call the roll?

Member Hollingsworth? Yes. Member Stromberg?

Yes.

Member Hefner?

Yes.

And Member Gibson?

Yes.

Thank you.

Motion passes four to zero. Okay, that takes us to... A DISCUSSION ITEM, ELECTRIC DISTRIBUTION UNDERGROUNDING. DENNIS?

IT'S MUCH BETTER TO BE HERE PRESENTING THIS THAN THE SADIE FIGURES.

YOU'LL HAVE YOUR CHANCE ON THAT LATER.

I THOUGHT I MIGHT. THIS IS A HIGH LEVEL OVERVIEW OF WHAT IT WOULD TAKE IN COST AND SOME OF THE HURDLES to bury all of our overhead power line in Los Alamos County. Didn't look at individual properties and say, well, we've got to cut a driveway here. We've got to tear down a shed in the backyard to get under there. None of that was done. This is just using averages based on the bid that we got to do the Piedra Loop project in White Rock. And then what would it probably cost to do something internally as an add-on because I thought it was extremely expensive to do any undergrounding in this county after seeing the last two bids. So we'll move on to the next slide. And in the electrification study, I didn't want you to forget that we've already got a lot of really old stuff out there that we would like to continue replacing, and this still probably needs to continue moving forward, even if we underground the existing overhead power lines. So, yeah, let's go to the next slide. But let's look at some of the benefits of having the underground power lines. It just looks nicer. The neighborhood I live in, it's underground. It looks very nice. And underground cables don't get hit by lightning so easily. And we don't have pole fires if there's no pole, which we've had two of in the last couple of months. So you're less likely to have a tree get into your underground cabling. We don't have to trim trees. Some of those tree trimming contracts can be $25,000 to $100,000 a year. Hopefully, it'll go down when we bury the line up Camp May Road to the ski hill. We don't have to do a pole inspection. That is a savings. Last time I did it, it was $25 per pole, and we do a pole inspection about every 10 years on a complete cycle. And that includes treatment of the pole to prevent it from rotting any further. And some of the disadvantages. It costs a lot more to bury the cable because the cable itself is much more expensive. It's got to have insulation on it that we use polymer or porcelain insulators on the pole top. When there is a failure, it can be a bit more difficult to locate. I was out on the locate of the problem on May 8th, and it was a lot of trial and error because we thought, Certainly there's a broken cross arm or a tree on the line. So we patrolled all the overhead line in the area. Didn't find it. And so they opened up a switch, closed in, and it held. Then we went and started working our way down and eventually isolated what section of cable it was. But it takes a while. On overhead, it's very visible usually and easier to locate. It does help if we have fault indicators on our switches and transformers to say, I saw a significant increase in current instantaneously, and it'll have a light that glows and says, it's down line of this point. We have some equipment like that out there, and we can add that, and that would help isolate where the faults are, at least give us an idea of where to go looking. And we're probably going to have to do that as we add more and more underground and upgrade our system. But then you either have to pull it out of conduit to repair it or replace it or dig it up. And hopefully we have a loop and we can isolate it and go back and dig it up the next day. And we definitely have a lot of loops. They've done very well on the design. And we make that a requirement. had a developer say this is how we would like to have our housing development built and we looked at it and everything was radial and we went back and said no we recommend that this layout be considered because we do want a loop and last thing we wanted was 70 or 80 homes sitting there looking at our guys out there digging up their front yard trying to repair an underground fault one day. When we can say, we can loop it back to here and open it up and do it the next day. So, and then excavation for installation and repair, it can upset some people when they have a very small front yard and we tear it all to pieces digging in conduit. But that's one of the disadvantages of having it. And if you want to make a modification, it's a little more difficult to accomplish if it's buried. But in White Rock, the computer model that we have told me we have 25.5 miles of overhead power line, with 8.8 miles being single phase, 16.7 miles being And it identified 325 overhead secondary services. So this is a pretty close approximation. It may not be exactly accurate, but this is what we show in our analysis model. So it's close enough for this purpose. And then here in Los Alamos town site, Almost 45 miles of overhead power line, 17.1 single phase, 27.7 multi-phase, and quite a few overhead services, about 1647 is what we show in the model. So Bixby Electric was the low bid on the Piedra Loop project that's about to kick off. In their bed, they want to charge us $98,100 just to mobilize to start work. Their trenching is $21 a foot if they do not hit rock. It's additional if they hit rock. They're charging us $13.80 a foot for a four-inch conduit. It's single-phase, so we're using four instead of six-inch. If they hit rock, It's $56.60 additional cost per foot. We did do 10 soil tests along the line, and we have very small chance of hitting rock on this project, which made me feel very comfortable until I saw this bid come in, and it's like, wow. But I was under the impression that If you dig in white rock, you're going to hit white rock. And this is probably the best place to have to bury cable in white rock. But this is only installation of conduit. It does not include the conductor or the installation of the conductor or the changing out of leaky transformers. Our crews internally will be doing that after Bixby lays the conduit for us. So if we took that cost and assumed no rock, it would be $617,760 per mile to install conduit. An additional almost $300,000 if they hit rock. And Bixby says, yeah, they can continue working at that rate. The conductor is about $21,000. a mile to install it, or no, to just purchase it on the reel. The transformers, $3,230 I think is the cost per transformer, and that was verified again today, so that's a realistic number of about $75,000 to replace the overhead transformers if we added $23 per mile. The labor to install the conductor, would cost about $20,000 per mile with our crew. The labor to install 23 transformers, they weigh about 1,500 pounds apiece, about $50,000. And then the labor to retire the overhead line, I guesstimated about $15,000 to go pull down the conductor off the pole and pull the pole out. That's assuming we could get cable and telephone off of it. Otherwise, just cut it off above the communications and leave it for them. But this does not include cutting people's concrete driveways to put in conduit in their front yard or sidewalk repair as we work along the edge of the roadways. This is strictly assuming piedra loop where You have gravel driveways and you just move along and go back and patch it with base course. So in town site, I figure if they can work in White Rock at that rate, they can probably work in Los Alamos at that rate. So approximately the same cost per mile, about the same number of transformers per mile. And once again, does not include driveway or sidewalk repair. So secondary, that is the thing that bothers me the most. We have quite a few, almost 2,000 secondary overhead service drops to homes. And in the electrification study, they specifically spell out in one of the presentations to county council, $3,000 to $20,000 or more is the cost. But when we talked with them, I got the $6,000 to $10,000 cost. But I couldn't find it documented in the presentation. So I used $8,000 for my calculations. But when we talked with Burns and McDonald, they said probably $6,000 to $10,000 would be the average cost. Some would require more. if you're having to go from the front yard to the backyard and have a really old service with number two and it needs to be four odd, all kinds of stuff. But in some cases, a total electrical upgrade would be necessary. And from what I've seen around Los Alamos and White Rock, there's quite a few of those that would definitely need a major upgrade. But the question is, who will pay? And that comes down to a legal determination probably as much as anything because of anti-donation. So here's a couple of examples of overhead and underground secondary that I picked up. And the one on the left is a very typical 200 amp meter base and breaker panel underneath it, probably something that would be considered perfectly acceptable, except it goes out through the top of the roof and overhead to a pole. So there are some special cases like this one where you know it's going to require a lot of upgrades There's no breaker panel with a main disconnect. There's no main disconnect switch. This is probably something originally done when you had one light bulb in the middle of the room and this big round black switch on the wall like my grandmother's house had. And they probably only have two conductors and two. prongs on the receptacles around the house I'm just guessing based on I grew up in homes more like this and so yeah, they probably would have quite a cost and so right now If you ask them, they're probably saying I have no problem with my electric service but That would probably require a major upgrade just to make the changes to meet code nowadays. I So if we take these costs and say white rock would cost almost $1.1 million if we didn't hit rock, which we know we will, to bury the conduit and the conductor, $2.6 million possibly at $8,000 each average for the secondary runs, $798,000 $170 per mile for town site. Forgot what I had on White Rock that was more than town site. And then $13 million roughly for the secondaries in town site because there's so many more. So you take that cost per mile, multiply it by 25.5 on White Rock. and the $325 times $8,000 on the secondary, and then town site coming in at just under $36 million total and $13 million for the secondary. It's going to be probably close to about $80 million plus any rock adder that we hit if we hired somebody like Bixby, and they said, yeah, we can do it for that rate. So there was question of, well, how much are the transformers for the pole top, which we're going to be replacing a bunch of as we do some maintenance because we have a lot of really, really old delta two bushing transformers with two fuses and some secondary loops that to me are quite dangerous. because you have multiple transformers serving the secondary run. It runs a whole block. And the fault current on the secondary can be extremely high when you have that kind of bus. So we're going to be making them all radial off of a single transformer. But pole top transformers are a little cheaper. I actually thought they were about half this price, but no, this is a price I got today. And it's like, oh, yeah, that's cheaper than it was three years ago, but I thought it was a lot cheaper now. But, no, they like to disappoint me. And another thing to consider. Say they really manicured their backyard and the service wire is from the backyard and there's poles back there. Maybe it's on the other side of the fence where the yard isn't quite as manicured. But if we were to underground it, do we go on the street side and avoid backyards that might look like this? Because I've sold some pretty nice ones in the last year and a half. And if we go street side, well, most of the service entrances, if it's currently in the backyard, are in the back of the house. So now you've got to run down the side and around the back to get to their meter. So that would add a little more cost and hassle, but it can be done. But if we bury along the easement, do we trench or bore in backyards with fences, gardens, and sheds as obstacles? I remember at my first distribution system, a guy wanted us to put everything in the backyard along an easement. And I said, fine, but I want an alleyway, no fences. And he said, we'll make them put removable sections. I said, they'll never agree to that. And they're still going to put stuff back there on top of our facilities if we don't have a dedicated wide open accessible easement. And we fought. He lost. But it can happen that way. And we currently don't have any type of alleyways that I've seen in a lot of the community here. And just makes it difficult to do. We do have a backyard unit, which I didn't have at that system, but still getting it through some fences is difficult, especially if they don't have a gate and they say, you've got to walk through my house to go read the meter in the backyard. Had that happened too. But it just adds more difficulty if we go into backyards. Then another concern I have, is getting cooperation out of Comcast or any telephone utility. They love to ignore us. And then could we get them to bury their service wires since landline telephone is losing customers to mobile phones? And then Comcast, would they agree to bury their service wires when so much video is shifting to streaming video? And right now, I stream video. from Verizon Wireless, myself. And then Los Alamos County with Atomic Fiber is going to be doing fiber to the premise. I can imagine both Lumen and Comcast are going to be losing some of their rate base and customers to Los Alamos County, meaning why would they want to do a whole lot of capital investment when they're likely to see less of a return on that investment. So that's a consideration that I think would make it difficult for them to want to work with us. And then the next slide, I believe, demonstrates what happened after a fire. What is it, roughly 20 years ago? Twenty-six now. Twenty-six now. Wow, 2000. You had a fire. The electric facilities were buried, as you can see, the pad-mount transformers, but the poles are still there for the communications companies that did not. And Stephen Morris said, we offered to give them the conduit if they would bury, and they didn't. So are they more likely to do that now? That's something to consider, but I wanted to point out that they didn't do it back then, and I don't see a lot of expectation on return on investment if they did it now. So that's what I have on undergrounding as a cost, but I did some evaluation and consideration, and I could be wrong on some of these assumptions, but the one on the right, that's the kind of rock saw that we used in Illinois to go through granite in the Galena territory to bury underground cable. that we inherited from the investor-owned utility that was kind of like what we're facing around here. It was 40, 50 years old, failing, and not in conduit. We got to do something. So we hired a contractor with one of those things to dig down four feet in granite to lay new conductor. On the left is something that appears to be more common now and more common because I couldn't find one of those on the right to purchase new. But yeah, there's some very expensive used ones out there. But on the left, it's more common nowadays, and it goes on the end of an excavator. So suppose you wanted your own trenching crew. The excavator is about $200,000 to get one that can produce 28 gallons per minute at 300 PSI, which is what that rockhead requires. The rockhead that I showed you is about $35,000. The crew's going to need a vehicle to get around town. Figured 120,000 to equip it with all the bins. And a foreman, equipment operator, and two groundman crew members is what I estimated probably it would take. And with benefits, a four-person crew would cost us about $1,800 a day. So I thought, well, okay, you got sick leave, holidays, training, vacation. So I added all that up and I came up with, yeah, about nine weeks of nonproductive days per year total. A lot more than I gut said should be realistic, but that's what people cost us. And if we assume that we can lay 200 feet of conduit per day, which means trenching it, laying it, and back covering it. Single-phase cable, about 500 feet of cable per day in the conduit. Bixby, we are estimating at this rate of production, 37 working days to do the job. Bixby bid $984,115. That was low bid. High bid was $3.5 million. And we thought $500,000 roughly was going to come in. And so I was quite disappointed even with low bid and glad to get it compared to the other three bids we got. So I thought, well, let's just play this out. How much is the material costing us? How much is the trenching costing us? How much would it cost us if we use those assumptions I just had on the previous slide? But I looked at material cost and thought, well, I could go with our warehouse, but if it's been in there for a long time, it's going to come in really cheap and that's not fair. So most of this stuff's available at Home Depot on the website. And I thought, that's current today prices, and we can get it a little cheaper, or we need to stop buying it from where we're getting it. But this would give us a little higher extended cost internally. The 3-inch PVC is $0.47 a foot. Well, we're paying $10.90 a foot on this contract. The 3-inch elbows, $688.00. and eighty cents those are steel 38.85 is what I found I mean I thought wow these guys are making a lot of money and that's on top of trenching which is more than double what I think we could trench it for if we had our own equipment so this is just a comparison of us possibly doing it internally versus hiring Bixby to continue doing this type of work or another contractor at about the same rates. But I'm open to go back on any of these pages and give you my explanation if it wasn't clear enough. I admit I'm a nerd. I sometimes I think everybody should understand it like I do. Not everybody does. My wife is pretty good about telling me that. But I have a son who understands everything I do because he does the same thing. And I just get spoiled. But I'm open to further comments, questions.

Okay. Thank you. I know this was a fair amount of work to put together, but we had to start someplace.

Yes.

Thanks for doing that. Comments, questions?

Matt, we'll start with you. Sure, thanks, Chair. Thank you very much. It's a lot to think about, so thanks for pulling it all together. You made a strong case to me that nothing should be undergrounded and we should buy you a trenching crew. I think that's a little extreme.

I think that crew needs to report to Clay because they do more digging than we do. But we can work that out. Maybe he'll take them six months a year and I'll take them the other six. I don't know.

I had a couple of questions to sort of probe my extreme takeaways. For comparison, you told us in White Rock there's 25 miles of overhead and in Townsite there's 45 miles. How much is undergrounded? Is it 50-50 underground and above ground?

I think we're about 60% underground and 40% overhead, but I didn't get that information yet. I was just curious for the context.

Yeah, that would be helpful just because my takeaway is nothing should be underground.

Yeah, it may be.

Almost half is.

It may be in the electrification study. Okay. But I don't recall specifically. I think it is, but I can't guarantee it.

Okay. And then, oh. Because I used to have to do this.

So it's not really apples to apples because some of the long runs to get like out to the mesas and stuff, those are overhead. And so you get this disproportionate amount of, you know, long run to get there. And then the smaller neighborhood areas, they undergrounded like back in the 80s and stuff. But, yeah, there's this long run overhead just to get there. The long runs aren't undergrounded.

Okay, but even with the long runs, it's 40, 60. I mean, it's about half and half. It's not 10%.

No, it's actually still more overhead. Okay. Yeah, it's way more overhead because you have a lot of these long secondary runs to get to the homes and stuff, and they – The way it looks is just different when you have it overhead. You pretty much find the short path when it's underground. Like overhead, you'll have a lot of, yeah, daisy chaining and stuff like that. So it becomes more efficient when it's underground, but it's not 50-50. Yeah. Okay. I mean, think about just like the EA4 line. I mean, that's miles of line that's overhead. And so you just don't have that with the underground line. Yeah.

Okay. Well, thanks. My next question was, you presented a total estimate cost if we wanted to underground everything of about $75 million. I think that was kind of the takeaway. But I'm wondering, is there any way you can estimate what the long-term savings or benefits would be? Is it 100 years to make it worthwhile or 50? And there's some intangibles like aesthetics that you said were benefits. But you just gave us the cost case for it's really expensive. But what's the benefit of doing it or

I can't tell you how many hundreds of years it might cost or take to see the savings on maintenance. Besides this almost 80 million, that's assuming no rock adder. And the rock adder is going to come in real quick. That could easily double, I think, just based on rock from what I have heard people complain about the cost of working in rock. And then when we did those polls for the tie line with LANL in White Rock at South Monterey, I could see why Brad Parker had to go to the dentist while he was working on it because he was sitting on that machine, that backhoe pounding on that rock. And I would hate to try to guess how much that would add because I really, I don't have a good feel for where the neighborhoods have shallow rock, deep rock. I was anticipating it being three or four foot deep in the White Rock substation. It's 30 feet. And now we're having to pay a fortune to put piers down to get to it, or at least down to clay. So. I'm tired of trying to make assumptions in my own head, much less make assumptions and lie to you.

Right. I appreciate that. But I think that's one aspect we want to consider. We've got the cost.

What is the benefit?

Yeah. So then my third question is how much of the new development that's going on in the county is undergrounding? All of it. All of it. That's what I thought. So you've convinced me that it's not worth undergrounding anything. Is it just not worth retrofitting or –

Help me understand. We make the developer bury the conduit for us.

Right.

And that's where you aren't seeing it as rate payers. The developer has to do it as part of their development project. And they're already doing it for James with water and sewer anyway. And so now they're saying, let's joint trench it, which we don't have that benefit of spreading the cost among gas, water, sewer, and electric if we do this.

Okay. Thanks. That's all the questions I have right now. Thanks again for putting this all together. It's a lot to think about.

You're welcome.

Thank you. Eric, you had questions?

Yeah, thanks, man. Dennis, I tell you what, that's an awesome amount of work and I appreciate it. So I noticed that you're mentioning galvanized 90s. I recommend very, very highly that you do a look at RTRC. AKA fiberglass, but we can't say fiberglass because that's a trade name of the Corning company. So we have to say RTRC. There are lots of benefits, at least five that I can enumerate, but they would probably bore the rest of these people to tears. So let's not talk about it. We can talk about it offline, but RTRC, I think you ought to look at very closely. Um, you know, uh, Matt talked about, you know, what is the cost benefit? Personal opinion here, I don't think that there is any cost benefit whatsoever. We would do it just because we want to do it. The Sadie, you might as well quit tracking it because I think it would go through the roof. Repairs would go through the roof, which I think the cost, which I think would swamp the tree trimming. I don't think that with the current environment of everyone asking about rate increases, why we would why we would incur another however many million dollars cost. This would be with probably zero benefit. I don't think this is the right time, but I really want to thank you for your work and ask you to consider RTRC. Thanks.

I do like the fiberglass. I brought that up internally in our group, and it wasn't very well received with the rest of the team. But I'm working on them.

Appreciate it. I'll talk to you. I'm out of town. When I get back in town, I've got five benefits of RTRC that swamp any of the cost considerations. So I'll talk to you when I get back.

Okay.

Okay. Jen, do you have any input here?

I guess just a quick follow-up to one of Eric's comments there. So I'm talking about Sadie's and repairs going through the roof if we were to do this. I mean, it's not like we don't have any undergrounded systems in our county, right? So we should have a pretty good sense of whether or not there would be, because that suggests there's massive additional costs beyond this upfront cost if you were to do this. Dennis, do you think that's true? I mean, I thought most folks were doing this to have some benefits with respect to reliability and against environmental factors and other issues. Can you clarify the operational costs and the risks associated with undergrounding?

The reliability of underground cable nowadays compared to the cable that we're trying to replace is greatly improved. I was told early in my career, which has been a little bit extensive, somebody and I were discussing how long we've been in this world doing this work today, and getting that conductor right in the middle of the insulation back in the 70s was not so easy. So while you might have half an inch of insulation planned all the way through it, you might have three quarters of an inch on one side and a quarter inch on the other somewhere down that cable and that's where your first failure is likely to come because the Insulation level between the 75, 7600 volt wire and the ground is not that thick. And as the age gets on there, the insulation value starts to go down. And that's where the short circuits happen, like we had on the eighth day of May. But it just went to all three of them in that case. But the cables improved. I can't deny that. And how long will it last? I don't know. But if you have overhead anywhere, you have to have good lightning arrestors where the underground cable takes off. Because in the 80s, I learned most of the underground cable failure on distribution line was due to lightning storms hitting the overhead line and it traveled through to the underground cable. and took it out. Now, if it were all underground, all of our lightning problems would come from LANL because we would have everything underground except EA4 because, golly, gee, that's just bad enough overhead. Try to do that one underground. Right. But, and Guahe Canyon. So, we would definitely separate them. I don't know that we would have a lot of failures anything other than maybe tree roots growing into and damaging the underground cable in the conduit or the conduit getting full of water and helping deteriorate the cable. So I think we'd be in good shape for a while but we still got all of the existing old underground cable that we still need to focus on replacing anyway. Yeah. And so we would still have those failures.

Okay. Yeah, I'm just curious about the developers doing new construction. They're eating the cost effectively, and they can do this more easily because they can joint trench for water, sewer, and gas, right? Correct. Okay. But even so, based on these estimates, it would seem that these would be viewed as rather significant burdens for the developer. Are they complaining at all about, I mean, are they getting similar quotes and bids? Or are they doing, can they do things themselves?

I think they're doing it internally with their own construction crew. That's just a speculation. However, I can't guarantee that. But no, they're not complaining because everything in Los Alamos is has what we've been calling internally the Los Alamos adder anyway. And when I look at what they say they want to rent their properties for or sell them for, they're passing it on to the consumers.

Okay. All right. And last but not least, I seem to recall when I first joined the board, we had a discussion with utility folks from Taos. And if I remember correctly, I believe they were talking about undergrounding a lot of their capability. Do you know how other communities, I mean, we're not the only northern New Mexico community with lots of tough and other rock to deal with. Are other communities looking into doing this kind of work and are they facing similar high bids and so forth?

I was at Jemez Mountains for approximately three years, and we did not have significant rock issues anywhere in the service area. And unfortunately, I know Jemez Mountains did not want to incur any capital cost. They had not for years. We did a lot of capital improvement while I was there, but undergrounding was not a topic of interest for us, even in town. In fact, they had cable failures when I got there, and they had backfed around them, and 10 years later, they still hadn't repaired the cable. I actually had a contractor come in and replace some failed cable that had been going for up to 10 years dead. They had no interest in undergrounding or any maintenance, really. And Kit Carson in Taos. I don't know how much rock they have, but I know between Espanola or between Velarde and Taos, there's quite a bit of rock through the canyons there. But I don't know what it's like once you get up closer to Taos. I think it's mostly dirt like we had in Espanola. But you guys probably know better than I do.

Not necessarily. Okay. All right. Thank you.

Thank you, Jen. Fundamentally, it seems to me that the issue here is primarily aesthetics versus cost. And one would assume it's going to cost something more initially to replace overhead lines and put them underground. The question is kind of how much. you seem to have given us kind of the cost to do underground lines, but that's not compared to overhead lines. We're going to be renewing a lot of overhead circuitry also, which means new poles, some new poles anyway. New conductors, which admittedly cost less for overhead cable than underground. Transformers look like they're very similar in cost. So really the question is how do they compare not just the absolute cost of undergrounding, but how does it compare to the renewal work that we're going to be doing anyway over the next 20 or 30 years? This isn't something we would do immediately. And the reason the question comes up right now is we're looking at a long-term renewal. So if we ever are going to underground any part of the community, this would be the time to think about it and start planning it as part of the renewal that's going to be taking place anyway. So I'm not sure that the cost estimates... really tell us what we need to know, how to compare one to the other. That's one concern I have. Jen brought up the question of maintenance costs, and it would seem I would agree with her. We've got a lot of experience with underground utilities, underground electric and we've got experience with overhead. We ought to be able to, based on experience, figure out roughly what the differences in maintenance costs are. And, of course, for overhead, that also really includes tree trimming and things of that variety that you wouldn't have to do if you went underground. So that, too, is part of it. I think, a fair comparison if you're going to look long term. This estimate, of course, it's a scary number, naturally, although when you look over 20, 30, 40 years, it's not quite so bad on a per year basis. But I also suspect the number is really higher than this if you did it as an absolute, not as a comparison. But because of the terrain, because of the rock, There's probably areas that are easier to do, i.e. less expensive, and others that are more difficult. So it's a good place to start, say, oh, if we were going to do the whole county, this might be what the cost would be. But I would think that there's probably some low-hanging fruit where it would be considerably less expensive or easier to do. and other areas that are probably more difficult. For instance, there's some areas where the power lines, I think, are out closer to the street instead of through the backyards. So you don't have the going through the backyards issue. And the service panels in homes are on the front or the side someplace where they can be accessed from the front rather than the problem with them being in the back, which is a a significant problem. I don't know how much of the town that has overhead lines has easements in the front and how many has easements in the back. That might be a difference in terms of what areas we might consider doing and others where it might not be practical or within reason to do, shall we say. So I'm really trying to figure out how to compare. So when we look at renewal for any given area, or maybe for a large area, say maybe it's practical to underground here, and maybe it's not practical to underground over there. This seems to be kind of a place to start, but we need to look a little further to see see what what we really could do if we really wanted to do it and I don't know if we want to do it that's why we're asking the questions here with respect to the communication services how long you may or may not know how long are those agreements the franchise agreements or whatever we have how long do those run I'm wondering if On the next renewal, we can't insist that they be put underground. I mean, I do remember what happened at Cerro Grande, where we put the electric underground and then thinking we were going to get rid of all the poles, and they insisted that we keep the poles there so they could put their lines on them, which seemed kind of dumb then and still does. And that's been more than a quarter of a century now. Is there a way to, over time, I'm not saying next year or five years from now, but over time, force those communications lines to go underground and get rid of the polls?

I think that's going to end up coming from your county and your legal counsel. I got in trouble when I was a manager in Ohio because all of us managers like to play attorney and Buckeye Powers attorney. which chastise us at every manager's meeting about doing that. So I learned my lesson.

Well, I'm throwing the question out as something to think about as we go forward. I don't necessarily, we obviously don't have all the answers tonight.

Certainly.

But this is a place to start, and we appreciate that. I think we can...

I can give you the cost of replacing a pole right now on our make ready is about $3,500.00. That includes all of the effort to do it, energized and such. So just figure $3,500 a pole is going to be a pretty good average price for a while.

So if that's $3,500 per pole, how much is that per mile?

I used to allow 20 to 22 poles per mile. So $70,000 roughly per mile to build. Just... A gut kickback there without the transformers. Those add a little cost because we're going to be replacing a bunch of 60-year-old transformers. I mean, these are before Lyndon Baines Johnson was in office because they're black instead of gray. So I know how old they are.

Okay. Well. Over a long period of time, we're going to be replacing a lot of poles.

Yes, we are.

And we're doing a lot of that now. Maybe it makes sense to replace those with underground line. That's what we're trying to figure out and get a handle on here, at least in some parts of town. Okay. That's all I have for now, I think. Thanks for... Okay. putting the numbers together and bringing up some of the other issues that we can't quantify very well yet.

You're very welcome. I enjoy being here.

Before you leave, does any of the board have any other questions or comments? Okay. Thank you. Okay. That takes us to... Review of Tenure Budget Plan and Reserve Policies. Joanne.

Good evening. We're going to go over the financial guidelines that were approved by the board back in August of 2016. To kind of put a presentation together of what we have now and kind of look at what what it looks like, because I know we had questions during budget about all of this. So on the next slide, I broke down each of the reserve that were in the guidelines. So we have like our operation reserves. That's set at 180 days of budget with a floor of 90 days. Our debt service reserves is required by our loan documents. Our retirement and reclamation reserve are per agreements, and I believe the only one we have right now is in electric production for the San Juan generating station. The capital expenditure reserves is the annual depreciation plus 2.5%. We have our rate stabilization reserve, which is a 10-year historical average cost per commodity times the 12-month average for our projected consumption. And then we have our contingency reserve, which is the single largest equipment that has a potential to fail. And that's set by our yearly DPU asset management team. So the next slide. So these are some of the loan requirements. And I spoke with Ms. Dazzy, our CFO of the county, and got some of these numbers and went through some of this with her on a high-level discussion. So the New Mexico Finance Authority requires a debt coverage ratio of at least one. The New Mexico Environment Department requires a debt coverage ratio of 1.2. And in our concurrent strategic goals, objective 2.3, we have our debt coverage ratio of 1.3 or greater. So that's what we try to meet every year when we're doing our budget. So the next two slides, I kind of went online. I did some research and I found some of these two cities in Washington. Their populations are a little bit closer to ours than other ones that I found online. So I don't really know how to say this town, Issaquah, I'm guessing. Is it okay? They have a population of 39,200. I think we're about 20,000. And so they only do water, sewer, and stormwater. So they don't do everything like we do, but they had some reserve targets listed. And so they have capital plan reserve, and they use kind of their CIP to do that on a five-year. They do a debt coverage ratio. They do 1.5 of net revenues to the total debt service. They set their operating reserves at 90 days of their operating expenses. Their debt service is the amount needed to pay their current and future debt, 125%, or as bond covenants indicate. And then they have an emergency capital repair amount required to pay for any unanticipated capital costs. The next town is Bainbridge Island. So they had all these little towns in Washington. So this one is a little bit closer to us. They have about 25,000. Again, they do water, sewer, and then these two towns do storm and surface water. I'm not sure exactly what those are, but... SO THEY'RE ALSO AN ENTERPRISE FUND LIKE WE ARE. AND SO THEY HAVE A CAPITAL CONTINGENCY RESERVE OF 1% OF THEIR UTILITY SYSTEMS CAPITAL ASSETS NETBOOK VALUE. THEY HAVE OPERATING RESERVES FOR THEIR WATER AND SEWER AND THEY DO A MINIMUM OF 60 DAYS OF ONGOING OPERATIONS EXPENSE AT YEAR END. THEY PROVIDE CASH FOR OPERATIONS IN CASE OF SEASONAL VARIATIONS IN REVENUE OR EXPENSES. And then for their storm and surface water, they do a minimum of 90 days of operating expenses. And these fees, I guess, are due twice a year. So they have this range due to the fees being due. And then they have a restricted debt reserve. And so it's amount of their debt due, similar to kind of what we do right now. So moving on, I put three charts for each of our sub-funds. So chart number one is what was presented originally in our budget. So there was no changes. I just took it out from our budget book. You might have noticed in the gas fund, it was at 90 days instead of 180 days. And that's because we took it to the budget with the 90 days. And that also was approved by our financial advisor. STATEMENT THAT'S APPROVED BY OUR CFO. SO I KEPT IT THAT WAY. SO YOU'LL SEE THAT KIND OF VARIANCE IN THE GAS FROM CHART NUMBER TWO WHERE MOST OF THEM ARE AT THE 180 DAYS BUT GAS FOR SOME REASON WE TOOK IT AT THE 90 DAYS SO I JUST LEFT IT THAT WAY. And then chart number three, oh, let me go. So chart number two has moving from 180 days to 90-day operating reserves and then setting the capital expenditure reserves to 180 days based on our 10-year average since we do a 10-year forecast. And we kind of found that during our research, and we found that's kind of what the Governance Finance Officers Association, GFOA, has as an example of setting capital expenditure reserves. So we took that. And then chart three has those two additional, those two changes, and then a revised rate stabilization reserve is set at 20%. SO IN THE CHARTS, THE PRESENTED IS SHOWN ARE HOW MUCH OF THOSE RESERVES ARE PART OF OUR ANNUAL REVENUE, JUST TO KIND OF SEE. SO THE NEXT SLIDE SHOWS OUR ELECTRIC PRODUCTION. AND SO IN CHART ONE, THE AMOUNT OF THE RESERVE is expected to be at 14.8 million. And that's looking at about 30% of revenue. And then chart two, with the different changes moving from 180 days to 90 days in operation reserves and changing our capital expenditures, it drops the amount of our revenues to the amount that we would need to put in a reserve about 25% from the 30% that we're at now. And then in chart three, AGAIN, CHANGING OPERATION RESERVES, CAPITAL EXPENDITURE RESERVES, AND THEN PUTTING IN A RATE STABILIZATION RESERVE AT 20%. AND THAT'S OUR SALES TO ELECTRIC DISTRIBUTION. THAT BRINGS US TO ABOUT 28% OF OUR REVENUE FOR THAT ONE YEAR. AND SO EACH YEAR HAS A PERCENTAGE. AND IF WE GO TO ELECTRIC DISTRIBUTION, IT'S THE SAME IDEA THAT ALL OF THEM ARE THE SAME CHANGES FROM THE ORIGINAL. And then in the gas, again, this is where in the chart one, it's at 90 days. And in chart two, it's 180 days. So it's just reversed because that's how we took it for the budget. And you'll notice in this one, The 34% is where we're sitting now, the way we have the gas, our targets. And chart two, adding some different capital in 180 days, it takes us to 38%. And chart three, adding the reserves brings us to 75% of our revenue. Okay. Water distribution, you'll notice how we have it now. It's 67% of our revenue. And then these changes kind of drop it to about 49% to 41%. In water production... Currently, the way the reserves are set up, it's about 92% of our reserves to meet that reserve target. I'm sorry, 92% of our revenues to meet that reserve target. And some of those changes kind of drop it down to 47% and then 67%. And then in wastewater, the reserve targets right now, the way they're set, it's about 90% of our yearly revenue to meet those target. Dropping from 180 to 90 days, it's taking it to 57%. And then adding, because this one did not have a rate stabilization reserve, by adding a rate stabilization reserve, it brings us up to 77%. So these were just ideas and examples to kind of show the different things that I found online with different other utilities, looking through APPA. They didn't have anything specific to how to set cash reserves. Just different, looking at different things, speaking with Ms. Dadsey, our CFO, we talked about how the county brought up their reserves, I think, from 20% to 25%. And she'd mentioned that they follow GASB 54 to set their reserve targets. I may be saying this a little incorrectly, but I believe that's what it is. And she mentioned that we don't necessarily have to follow GASB 54 because we're an enterprise fund. But that's how they set their reserve targets and stuff is through GASB. So I put questions, but I guess I'm just, I think we just wanted a discussion about this and have you guys kind of give us suggestions or I'm not really sure where to move on from this, but this is kind of my research the last couple months trying to decide, show you some different counties, different cities, what they do and what we found.

Thank you, Joanne.

You're welcome.

Questions, comments?

Go ahead, Matt. Sure. I'm happy to start us off. First, Joanne, thanks a lot. This is a lot to put together, and I think I follow it, but I'm not sure I understand it or know what to do with it. Yeah. And so I think there's a lot of knobs to tweak, and you've shown us three different cases.

Right.

And so I want to digest it and think through it some more, but you've thought through it a lot more. I mean, what's your conclusion? I wanted a conclusion slide. Yeah.

Well, okay, so this was set back in 2016, right? And I'm not sure. I wasn't in a position to know what our cash was back then, and I don't know if it was assumed it was in a better position than some of our funds are now. I don't know that for a fact. But what I was noticing in speaking with Ms. Dadsey, some of these percentages that, you know, based on how our financial guidelines are structured, reserves right now, it's really high. It's kind of hard to meet. So I was trying to find a way that maybe we could work at meeting those reserves. I mean, it's hard to put 90% of your revenues into a reserve account, and probably why we haven't funded those in the last 10 years. That's my guess. I don't know. I've only been doing this for one year, but looking at it, I mean... you would think by now we would have and I don't know and I know that you have to fund each of the reserves like you have to fund operation reserves before you move on to the next one because that's how it's described in the reserves and I also think there's a muni code about it or I don't know there's something in there that also so yeah I think some of them are just a little high which is you know so I was trying to find a way to meet that reserve that we could have the money and be able to put money aside and hopefully in 10 years get there. And so that's kind of what I saw.

That's helpful because I had to say reserves are important. I understand that. They cascade like you talked about. We have to fill some with more priority. But yeah, when I see 90% of revenues going to reserves, that Seems crazy.

Right. That's kind of where I'm like, I don't know how to meet that and meet all those different reserves. We need all of them for various different reasons and all the funds, you know, we have things that break and we don't have it in, you know, capital projects. So we need to find that money somewhere and get a pipe fixed or, you know, whatever it is out in the field. So.

Yeah. And I guess one thing that I, had trouble thinking through was each of, each of the utilities are so separate and some, you know, one knob tweak or what, you know, one of the different charts was great. And the other one, it totally threw that utility out of whack. I don't know that we can split up how we manage reserves for each utility fund. I don't think we could do that. I guess we could do whatever we want, but it looks like, It's complicated because you can't have a single knob fix all the reserves and everything.

Yeah, it almost feels that way, too. Yeah, like it's not a one kind of fits all kind of thing, but that's how it's set right now. So, yeah.

Okay. Thank you very much. You're welcome. That's a lot to look at. You're welcome. A lot of work to put together, so thank you. That's everything I have.

Thank you. Jen, do you have any questions?

Yeah, sorry, I had to find the unmute. Just a minor question. So the operation reserve for gas was, I guess, currently set at 90, but everything else is set at 180. Sorry, I missed why gas is the one that was different.

I'll be honest, I don't remember if we did that on purpose because the gas fund was so at a negative or if it was just an error when we created the schedule of funds. It's been so long and we've looked at so many numbers, but that's what was presented for the budget and also the schedule of funds that was approved and signed by Mrs. Dadsky. So I left it that way, but I'm not sure why we did that. I'll be honest.

Okay. Yeah. I mean, because if in chart two, you're reversing, you're, dropping the number to 90 for everything. I mean, it might be worth just keeping in this case it at 90, right. Just to be consistent. So then everything for chart two is in 90, but anyway.

Right. I just put the 180. So you guys could see the difference between the two. Yeah. Yeah. Sorry.

No, that's okay. And, I mean, it seems like an sort of important one. You mentioned that that has to kind of get done first, but compared to the two examples that you found, The 180 that we typically use seems rather excessive. Is that, do you think, generally the case?

Well, through, like, when I was looking at all different types of utility companies, a lot of them were set at about 90 days. But there was a plethora of different ways that different companies do that. So, yeah. Okay.

interesting but it's good to know there's some flexibility right and that we probably should be revisiting these numbers so because as you said we're hitting we're we're giving ourselves targets that might be near impossible to reach and cause us to to take actions that are may not be necessary could be problematic so okay right all right thank you very much for doing this you're welcome thank you jen eric do you have anything

Hello, Eric.

He is there, Chair, but he's not unmuting himself.

Okay. Well, if you have anything to say, unmute and come back. We'll give you another chance here. The basic question here is what's adequate for reserves? Right. You know, I mean, we try to use objective measures like numbers of days or percentages of something, but the question is, is that adequate or not? It would seem to me that we have 10 years of experience with these policies, and we certainly should have records that shouldn't be too hard to access going back that far, where we ought to be able to see what our experience has been. Could even run test cases against our experience and say, well, suppose that our reserve was 90 days for something instead of 180 days. Would that have ever gotten us into trouble? Would that have ever been inadequate for a given purpose? I mean, you know, we know... What kinds of things have happened and maybe a ballpark at least of what they've cost us, whether it's a particular component failure or an unexpected expense that comes up or just we didn't use as much gas this winter as we were expecting to. And we didn't have the reserves to cover it very well. Didn't have the reserves to cover it at all, which got us deeper into a hole. But it would be useful, I think, to take a look at that last decade of history and see what we could learn from that. And yes, it's... It's interesting to look at other places and what they do and how they do things or what the industry is, what's common in the industry. That's useful also. But what happens here is important also. And we've got that information.

Right. Yeah, because kind of going back to... is that, you know, like the one size doesn't fit all, like gas. We have six months or five months where we, you know, the winter months where we have a lot of sales and then it slows down. And in fall, like exactly like water, we have kind of a six month period where people water and then in the winter it slows down. And then, like, electric, it's probably pretty consistent through the year. You might have a couple months right at the beginning, end of spring, summer, and fall where it might dip a little bit until, like, heating or cooling kind of kicks in. So, yeah, we do need to look a little bit more at our 10-year kind of history.

I think that would be useful. I do have a shorter-term question. Sure. You show... rate stabilization reserves in chart three for electric production, gas, water production, and wastewater. But we don't have rate stabilization reserves in chart one or two for those. We don't have apparently not thought we needed a rate stabilization reserve. So why do we add those in chart three? Is it just to make it consistent all the way across the board for all utilities? Even though, as we've just discussed, that's probably not necessary.

I think we kind of just put that in there because any one of these, like I said, like gas, we have the six months, or water, we have about six months of high usage. Just to have something so that our rates, if we need to, not do larger rate increases if things kind of drop. So we did put them in all the funds. Probably when we created the budget, they should have been in every single one of the funds because the way the financial guidelines says that it needs to be in there unless there is a pass-through rate. And the only one we have a pass-through rate right now is gas. So...

So if that's the case, if you're suggesting that we consider putting a rate stabilization reserve in all of the funds, except for gas perhaps, that actually increases the reserve requirement.

It does, yes.

Because they're not there now.

Right.

It seems... difficult to imagine why we might need a rate stabilization reserve in those utilities where we control the whole process, like water and wastewater. So I'm not sure why we would need to do that for those. You do have one in... Electric distribution, but not in electric production. Well, that puts it in the electric fund anyway. My question, whether it should be in production or distribution, I'm not sure we would need it in both because they kind of go in series with each other. So I'm not sure it would be needed in electric production. So I think we can fine-tune a little bit more looking at the need in each fund. I mean, it's nice and it's easy when you say, we're going to use the same requirements for each fund, but that may not be what we need in each fund.

Exactly. I agree. I just kind of brought in just a starting point for us. It's...

No. This is a starting point discussion. Exactly.

So, yes, you're right.

That's fine. Let's see. I had one other one, and, of course, now I've forgotten what it is. We'll see if Eric has come back online and has any questions. And apparently not.

No, no, I'm online. I don't have any questions. I'm just listening.

Okay, all right. So it's back to me to try to remember what my other question was.

All right. If we can go to the gas one, I just wanted to offer an observation. This past year, we had the unseasonably warm winter. We sold 20% less gas. That's why we're short, and that's roughly the $750,000. And if you look at your operation reserve for 90 days, that's $919,000. That's 25%. So the numbers, I guess I would never go below 90 days because we've already experienced a 20% fluctuation in our operations. So I just wanted to point like a real case of when you need that reserve in place. So I'm just pointing that out in light of we've been considering the gas rates and fees and charges, etc.

Well, that's part of why I would like to look at the history and see things like that. Where have we wished we had or where have we had and used reserves for various things.

I'd say a majority probably was capital budget revisions to build a project. We pass a lot of budget revisions every year. It'll take quite a bit of time for us to sift through those to get them tabulated, but pretty frequently we dipped in the reserves to build a capital improvement project.

which may tell us we need to somehow do a better job of budgeting for capital projects based on more realistic estimates in this environment, unfortunately.

Which changes every time there's a war. To be honest, we've had two since I've been in seven years here. Okay.

Let's see here.

Well, I guess you're off the hook on my, because I can't remember my last question.

Until you're done, then of course I will remember it.

But anyway, does anyone else have any further questions or comments? Okay. Thank you very much, Joanne. Good place to start. Thank you. This is a big item in our budget, so it is worth it. At least critically reviewing, if not refining, to better match our needs.

Thank you. Work on it.

Thank you. Okay. That brings us to 7.30. Do we want to take a break here or keep going? What's the preference? Keep going. Keep going. Anybody particularly want a break here? I'm not seeing a cry for it, so we'll keep going. Okay. Chair's report. The first one is simple. Matt and I have swapped farmers' markets dates. He's going to do the 25th of June. I'm going to do the 24th of September. Second one is not simple at all. DOE is now telling us that maybe we'll see a draft DCA from them. Sometime in the next couple weeks or so. If so, remember our current extension only goes to the end of July. Can we consider it, and we meaning the county, the board, council, community, et cetera, in a month? If we're going to do that, we're going to need to look at this rather long, complex, cumbersome document that as soon as we reasonably can. Philo has polled board members and found out it looks like maybe, if we have anything from DOE in a timely manner, that we could meet on the afternoon of the 8th of July at about 3 o'clock. Does that sound like something that at least hopefully, that we can meet. Can you meet then, Jennifer?

Yes. Yeah, I've already spoken with Philo about that. Okay. My only ask was that if it's possible to go earlier than 3 p.m., that would be great. But I understand that might not be possible.

Well, we'll do the best we can. Let's see. You're going to be gone. I'm sharing time zones with Jen, so I second her opinion. Okay. Charlie's not here. He's probably the one who wants to have it later. And Eric, what's your preference there if we can, to the extent that we can accommodate it? Eric?

He confirmed three with me.

Okay. Yeah. Well, first we have to get something from DOE for it to... be anything we can do anything with. But anyway, I want people aware of that possibly coming down the pipeline. Item three, Nick Nelson has offered to give any of us who wish or arrange for any of us who wish a tour of the lab's combustion turbine. And so I'd like to find out who from the board would be interested in that besides me.

It's an interesting tour. I've already done it. So I leave my spot for somebody else, but I recommend it. It's a good tour.

Eric, have you already seen that thing?

You know, if I can, you know, keep me apprised of when that is happening, because I would certainly be interested. I just don't know if I'll be available.

Well, we'll try to do it when you can be available.

Yeah, that'd be great. I'd appreciate it.

Okay. And Charlie, we don't know. Okay, so that's, let's see. Jan, you're not going to be here for the next considerable while, are you? Okay, maybe that's next year for you. Okay, and last item on my report is that a week ago, I flew over the Foxtail Flat site. last Wednesday morning, a little before 8 o'clock in the morning. There's a lot of trucks. There's a lot of equipment down there. What was moving at that time, anyway, was earth movers. There was a lot of dirt being hauled. It kind of looked like they were leveling out different areas, presumably to put solar panels on a level platform. That's kind of what it looked like. Of course, I couldn't tell for sure what they were doing, but they were moving a lot of dirt. It certainly didn't look like any real construction yet, certainly not solar panels and things like that. Those would be at the last, I think. Anyhow, I thought it was interesting. There was quite a bit of activity there. And that's all I have under my report. Do any other board members have anything?

Mr. Gibson, I would really be, oh gosh, appreciative if the Foxtail Flat solar website would be updated. I mean, I keep harping on this, but the last update was December of 2024.

Well, something for our staff to talk with Desiree about.

yeah chair and we are updating our website the county's web page on the project because we just got all the press release and photos so that's in process and we also have a presentation next week with the council on the project but Desiree getting their website we will request again and Every other week, Eric, just so you know, whenever we meet with them.

You know, I appreciate that. I just don't get a warm fuzzy when Foxtail Flats has no updates, Desiree has no updates. I'm kind of wondering what's going on here. So I appreciate your bird-dogging them.

Okay. Thanks for the reminder again, Eric. At least we know something really is happening physically now.

Well, I don't know that because I don't see it on the website. I'm not flying overhead, but I appreciate your visual confirmation.

Well, I didn't make that one up. And it was only me flying, so I couldn't take pictures while I was flying at the same time. Anyhow, moving on, utility manager's report.

Yes, chair and members of the board. So New Mexico's under a red flag warning, and it's been hot and dry and windy. So PNM has disabled their automatic reclosers on both their transmission lines feeding our area. And that's just part of the wildfire risk mitigation measures. And, you know, at this point, YOU KNOW, THE WEATHER'S THERE. IT'S ALL THROUGHOUT THEIR SERVICE AREA. SO WHILE THERE'S NO PUBLIC SAFETY POWER SHUTOFFS CURRENTLY ANTICIPATED, BUT WHEN YOU DISABLE THOSE RECLOSERS, IT JUST INCREASES THE LIKELIHOOD OF AN UNPLANNED OUTAGE SHOULD ONE OF THEM BE TRIPPED. SO JUST WANTED TO BRING THAT TO THE BOARD'S ATTENTION. And, you know, we continue to monitor that. And if there is an unplanned outage, we'll obviously be letting everyone know. But we have two feeds. But should there be an outage due to wind or whatever, fire, you know, those are things we're going to have to bear in mind as we're at risk. And then for the White Rock substation, I had the pre-construction meeting today to drill and construct the caisson for the foundation of the transformer, and that's going to be ongoing for the next couple of weeks. The tie line recloser control's been programmed and ready to go online should there be a need. And then for Elkridge, there is one home yet to be turned over. They did... don't have any gas service, but I don't think they're using any gas right now and haven't made a priority to switch over because the weather's probably nice enough for them. And then on New Mexico gas, they have mobilized to begin the hydro testing of the seven to eight miles of high pressure gas line from Santa Fe to Los Alamos. And they're setting up the virtual pipeline and they'll be in operation from now until mid-August. And recruitment status, we have quite a few rounds of interviews over the next week, the end of this week and next week, for the GWS superintendent, the energy and water conservation coordinator, and the senior engineer. Then the other vacancies are electric distribution engineer manager, associate engineer that specializes more in electric, management analyst, water operator, two power system operators, and engineering aid for utility locates. The Plumbers and Pipefitters Union contract renewal was approved for five years, and that will run through June 30 of 2031. The ECA, that was mentioned already by Chair, so we're And it's in their hands for review. And in talking to the Albuquerque office, their goal is to turn it over by the end of the month. So that's June 30, July 1, I hope, no later, so that we could try to hold that special meeting on the 8th of July. And then the subgrant agreement was approved last week by council for the Jemez Mountain Fire Protection Project. And it's out for signatures with FEMA. Once I get that back, then that's our green light to get going on procurement and construction bids. And that's just to cover the electrical undergrounding and removal of the overhead line. Then we talked about Foxtail Flats. It's under construction. We have a meeting next week to meet with their best contractor, And that's battery energy storage system. And they want to understand a little better how we want to operate and discharge the battery as they set up their programming and SCADA systems for that. And for the chromium plume, I work with Council Chair Reidy on a list of questions. He's next week going to be at the Energy Community Alliance meeting and going to meet with Deputy Secretary Walsh. So he's got a list. I think we had five questions for him. Then the New Mexico Environment Department Sanitary Survey items. We got all of that completed short of this one housekeeping curb at Sycamore Tank. This tank was turned over to the county by the laboratory with no as-built drawings and there's no foundation under this lab, and we're trying to work through NMED on what the best path forward is. They want to assure proper drainage around the tank, but standard means and methods are a little unique in this case. So we're still requesting an on-site inspection to help determine the best path forward, and they're backlog wrapping up their fiscal year. They're not able to get out quite yet. And then PFAS, our class action suit, we provide some reformatted data to match their needs for, you know, they have thousands of communities that have to pull together data. And they asked for two more samples. I think we got one today, and we'll hopefully get one in the next week or two on the other well. And meeting with... NNSA DOE staff, in review of the SWISe water needs, we had an initial meeting and showed that they exceeded their water, their annual water rights allotment. And based on that, they moved up their reclaimed water facility improvements so that they could stay under that annual water rights allotment. That removed one argument for expansion of water production for a new well. But we still have our argument that we lost PM3. It was offline because of chromium plume. We still have resiliency and redundancy needs that need to be replaced. We'll continue to pursue the different angles on that and We're finalizing the contract for the 40-year water plan, so hopefully have that at the regular July meeting to BPU, and we're continuing to work on some federal funding to investigate the new well at Overlook Park that could use San Juan Chama water. And then we talked a little tonight about the extended electrical outage on May 8th and 9th, and the With our engineer, we determined there was some programming on the relays that were missing, and so staff's working on the task order with our on-call engineer, TND, to get some updated programming to add to the relays, and it'll be a great safety improvement when we get that completed. And then we applied for a federal grant for $275,000 to... the natural gas distribution infrastructure safety and modernization Grant program it's a federal program and it's for Central Avenue from 9th down to the Trinity roundabout and We do have Development plans in place to you know do a mixed-use development at the Old Smith site and So this will help increase the capacity of the pipeline as well as replace an aged line that's over 50 years old. And then UAMPS, the CFPP is still alive, so I still had chair duties today at the board meeting. And we did have a resolution to move. We still have a balance of funds in Bank of America over to Wells Fargo. through a line of credit, once DOE reimburses UAMPS or the CFPP, then those balances go away. And then the other thing that was interesting about today's meeting was, and we'll have Mason Baker come in September, that a lot of the projects they're pursuing right now, and this is a big shift in the last couple months, they're looking at improving their capacity needs through EDAM, and adding BESS is the quickest way to meet capacity needs, so they're looking at several projects right now. So we'll hear more about that, something that will feed into our Foxtail Flats business plan for sure. And then PNM, this is kind of good news, and it's like an old project that's still alive, everyone. It's our San Juan Chattering Station has been fully demolished and decommissioned. It's to the ground. We had the final report submitted to San Juan County to comply with their ordinance, which required everything to be removed down to the ground. And... So it was carried out per that plan. Um, and most, you know, a lot of material was recycled. I mentioned that over probably over the last year and, uh, things have been disposed of and recycled. So the, uh, process was a three-year process to bring that plant down. So, uh, mine reclamation work is more extensive because there's a lot of, um, regrading. and reseeding that will run through 2030. So we still have another four years of work there. With that, I'd stand for any questions.

Okay, let's see. Eric, you've got your hand up.

Yeah, I appreciate that. Okay, so I'm interested because you're talking about battery energy storage systems. Foxtail Flats has told us that they can utilize the 320 megawatt hours daily, but in order to do that with the charge and discharge rates, they need 533 megawatt hours of batteries. So because they can't go 100 to zero, they really need to go 80% charge to 20% charge. So I would really enjoy hearing what they have to say about these numbers. And if you want to get me involved, I'll be glad to get involved.

Those are great questions. I hope to learn more next week.

Well, I look forward to what you learn because the numbers that they're telling us just absolutely don't add up.

Thank you.

Any more, Eric?

No, that's good for me.

Okay. I don't see Jennifer's hand up, so...

Matt? Great. Thank you, Chair. Thanks, Philo. Lots going on, as always. The one that caught my eye was the natural gas federal grant application, and I was curious, is there match required with that, or is it all federal funding?

What we put in the application was in our CIP program for 2028. The road will be rebuilt in The type of match that we offered was like our traffic control and the general conditions when we coordinate with public works. That would be our cost share. But there wasn't a match requirement for the pipe component, which is the 275.

Okay. And I'm interested in thinking about, with the county goals on reducing the use of natural gas, if the county should be funding the upgrades, especially if it's to motivate new development. We talked earlier about putting – make the new developers pay and potentially, you know, incentivizing gas-free on new developments. And so I'd just be curious if you're keeping that in the back of your mind as you pursue – I mean, I think it's good – we have to maintain and replace things. I understand that. And federal funding is great for that. But if we want to pursue our long-term goals of getting off natural gas – there's push the cost to somebody else.

So there's quite a bit, uh, you know, this, this project I think is going from Trinity to central through their site. And then we have kind of our central Avenue that serves all the apartments down here and, and below that are outside of the project limits. So, uh,

When the road gets done, we need to... That's the time to do it, yeah.

And that's why we applied for funding. Because it's in our budget, we'll hopefully avoid some costs down there. Okay, thanks. That's everything for me. Okay.

A couple of questions. First, the outage from May 8th. You said that some of the programming was missing. Do we know how that happened or how it was not caught or what are the lessons learned from that?

Well, I'll ask Dennis because he did the research, but I'll ask him to go up and explain in more detail.

I'll simplify this as much as I can. The relays in These switchgear buildings are general electric relays, and they have group settings depending on your needs for the time down line of groups 1, 2, 3, and 4. The relays had group 1 programmed to operate properly. Groups 2, 3, and 4 had no programming at all. Then, when the crew goes to work on the line, they go to the switchgear building, go into the settings, and turn off reclosing. Because if they're working on it, and there's a short, they don't want it to open and then close right back on them again. Unfortunately, the way to select which group you use is... manipulating the same buttons as you do to turn off reclosing. And so half of them were on groups two and four, and half of them were on group one. And Stephen Mares used to go in periodically and look at the settings and correct them if they were wrong. I didn't know that. Didn't know anything about these relays, I've only worked with mechanical relays in the past and Switzer relays. So I didn't know I needed to go do this, or I would have. But that's how we had the wrong settings, specifically on the circuit that had the underground fault it should have cleared. Because that relay said, oh, there's a fault. But I don't have any instructions, so it just sat back with its feet up and let it burn right on through to the main looking back at, And that happened and both mains were in parallel at the time and both tripped, which took out all of Los Alamos town site and it took us a while to figure out what happened. Fortunately, people said a transformer blew up not too far down Trinity and we went and found the jumpers burned and they gave us an idea where to start looking. And I got here about 25 minutes after I got the phone call and Wayne had already started patrolling. I thought that a transformer blew up at the hill because that's where I'd been told a transformer blew up, was just east of the apartment buildings there and thought, well, okay, I'll go down there and see if one of those pad mounts we set last year blew up. Then I met Wayne at the town site switching station. and we rode together and started riding overhead. But the relays are going to be programmed so that groups one, two, three, and four all have the same settings. And then there's another switch on the panel called Hotline Tag that will keep the linemen from having to open the little door and start pushing buttons on the relay in the future. And it will also give them a much quicker clearing if there is a fault down line where they're working because a hotline tag uses an instantaneous curve which is extremely fast versus the delay curves that we have programmed into group one so it'll be safer and more foolproof some people like the words lineman proof but we're going to call it more foolproof and just simpler going forward And that's going to be done hopefully within the next two weeks.

And will those then be on a regular inspection cycle also like Steve used to do? We can do that still, yes.

I mean, I'm not directing it to you. I'm just asking if they will. They will, but they won't need it as much as they have in the last year and previous. Right.

Thank you. That was helpful. Second question, since the San Juan Generating Station demolition project is done, I know the mine isn't yet, but the station itself, do we get any of the decommissioning reserve released, or is that held for a while?

It's, it's actually held for a while. Um, well, one is the report, you know, the San Juan County has accepted. That's the last time we submitted. It took them a few months. Uh, and then the other piece is, um, They have performance bonds that the state holds, and they have to release those. And then those funds should free up. But it's going to take a little time. Hopefully, close to the end of the year, we'll know the status of that. Okay. Thank you.

I don't see any other queries on the report. Thank you very much, Philo. Ann's been sitting here patiently all evening just waiting for your turn on stage. Go for it.

Thank you, Chair and Board. Just a couple things I wanted to mention. Utility Manager Shelton talked about fire season with the last storm that came through in the Santa Fe Forest. There are a number of Fires burning, they're small right now, but the one that you're seeing smoke north of Los Alamos, the last report I just got just before this meeting is it's grown to 128 acres. And it's three miles northeast of Chicama Mountain. So that's what's described. So check out the – there's a website that's mentioned in the – press release that, um, that we issued earlier today, for whatever reason, the fires are not big enough to make it on insuweb where a lot of us go for fire information, but stay tuned on that. Um, I wanted to mention that our new economic development administrator, um, Max Kudiakov did start, uh, early last week. So we're very happy to have him on board. Um, And then one thing that I noticed on our new website, um, our PIO, uh, Dave Kruger has really been pushing a lot of our engagement, um, current opportunities to your Have Your Say page on the website. So if you go to the main page, you have the main icons, there's a Have Your Say icon. And if you click on that, just to give you an idea of what's active right now, um, you can take the survey on the Historic Preservation Master Plan. Fire Station 4 public art theme, and then Oshley Pond Park safety bollards and the comprehensive plan. We're receiving public comments or taking surveys on all of those initiatives right now. So I think it's a nice place to go look to see, hey, what's going on? What can I engage with? And just thought I would mention that. And then for next week, we are going to have, we're going to introduce the high level concepts of two a local economic development act or lead a participation agreements were close to being ready to take to council in the form of an ordinance, which is an introduction and public hearing. But our process has added a pre intro intro where we, um, uh, the public has not, uh, they seem to like when we sort of announced it's coming and talk a little bit about the project without the pressure of a decision. versus just kind of announcing that we're introducing an ordinance. So we're going to see two of those next week on council's agenda. So we're very excited to introduce those to the public. So with that, I'll stand for any questions.

Thank you. Are there any questions? I don't see any. Thank you very much. Thank you. We'll move down the line to our council liaison.

Thank you, Chair Gibson. We had our most recent council meeting last Tuesday the 9th of June regular session and a few things of interest on the consent agenda we passed a word of bid for the western area twin tanks tank piping upgrades phase two project to New Mexico underground utilities and Also approved, as I guess Philo mentioned, the Plumbers and Pipefitters Union Agreement and approval to execute the action and recommendation from Environmental Sustainability Board on the plastic bag ban.

David Hampton will be discussing an ordinance adding Chapter 18, Article 5, banning the distribution of single-use plastic carryout bags, and encouraging retail establishments to charge a fee for recycled content paper carryout bags. And Angelico will provide updates regarding the residential sustainability report. Other updates include electrical, vehicle charging, infrastructure, community conference program, and community events. So that's all I have. Do you have any questions?

Are there any questions from the board? I don't believe so. Thank you very much, and you did just fine on your first time at BAT.

Thank you. I appreciate it. Thanks.

Thanks for your patience waiting to give your report. No worries. Okay, that takes us to Item 8G1, Discussion Possible Support of the Council Charter Review. Philo, did you want to start that off or did you want me to?

Chair, I can start it off. Last week, the council... considered a few different items for charter amendments and the most pertinent one was related to the profit transfer removing that section that's in the Charter and then they had a lot of discussion about terms and party affiliation so attached you'll see we finally got the meeting minutes and sent that out to the board you know one's most relevant but in the motion included the board of public utilities as well I think in the makeup of the parties will remain the same but I just so there's a motion before you to support removing the profit transfer section of the charter, and then if you wanted to support any other elements of the charter review that's contained within the meeting minutes, that's at your option.

Okay, thank you. The council's charter review working group proposed several different things but and for completeness the five section 911 and section 305.3 are included here in the agenda doc but they're not germane to the utility board so there's no real reason for us to be weighing in or thinking about those as a board can certainly as individuals But the change in terms of deleting the profit transfer provision, that is very much germane and hence brought forward here to give us an opportunity, if we wish, to make a recommendation to council on that.

Chair, may I make a clarification? Sure. I'm assuming most people know, but I just feel the need to say it out loud, that changes to the charter require a vote of the people, so these ordinances are only to, and the reason it's timely is because we're kind of up a deadline to be able to publish the ordinances to be able to get them on the ballot for the November election. So these actions don't recommend changing it. They recommend putting an option to change it to the voters.

Right. Thank you for the clarification. Are there questions on the subject?

I guess I have one question just to remind myself. In past years, we've had profits from the utilities that we've sent to council and then we've been able to get those back and use them on utility. Projects that's mostly what's been happening. And if this was removed, that's what would it continue to happen? So this is kind of a formalizing what's been practiced for the last couple of years And I guess my question is just how much? Have the profits been that we've sent back to the county. So is my understanding correct and then Is my near history understanding correct and then about how much money is that?

I think it's 5% of revenues for gas and electric isn't it Joanne I

Chair and Councilor Huebner, yes, it is 5%.

And we've been doing that transfer to the general fund since the charter's been in place. This return from general fund to utilities has only been the last few years. And there are specific requirements on that. If this provision went away, we wouldn't be sending that money to the general fund, and they wouldn't be sending anything back. Life would be a little simpler. And, of course, they're not under any obligation to send it back. I mean, they've got an obligation for a few years, but that's a rolling commitment. They could say, oh, we need the money for the general fund, and this would eliminate that obligation. Risk, shall we say, to utilities?

If approved by the public. If approved, yes. Great. Okay. Thank you. Thanks for the further explanation. Okay.

Is there any public comment on this issue?

Any members of the public attending via Zoom, please raise your hand now to make a public comment. There are none, Chair Gibson.

Okay. Thank you. We do have a motion of support. Would anyone care to make that motion? Sure.

I move that the board support county council's recommendation to have the county manager draft an ordinance to formally propose the following changes to the charter. Remove paragraph, quote, six, any remaining funds shall be transferred to the county general fund in section 509 of the charter.

Second.

Okay. Let Jen show the, have Jen listed as the second for the record? Okay. Is there any further discussion from the board? Seeing none, Kathy, would you please call the roll?

Member Stromberg?

Yes.

Member Hollingsworth? Yes. Yes. Member Hefner?

Yes.

And Member Gibson?

Yes. Thank you. Motion passes four to zero. I don't know if the council really cares, but you have our recommendation to go forward with this. Okay, next item is approval of the annual presentation to council, which will take place next month on the 14th of July. This is pretty much what you have seen before. In the interests of time tonight, I'm certainly not going to go through everything. There were a few more tweaks that were done, and there'll probably still have to be a few tweaks, especially if Philo's successful at hiring a couple of people, then the number of vacancies will go down. And hopefully there'll be a little bit more to say about the ECA by then. So... but this is the best we've got for right now. So I'll ask if there's any questions, comments, further proposed changes. If not, is there a motion to approve this?

Sure. I move that the Board of Public Utilities approve the annual presentation to council and Chair Gibson's delivery of the presentation at the July 15th, 2025 council work session.

I second it.

I think it's 14th. I know it says 15th, but the meeting I think is, isn't it on the 14th? Friendly amendment for the 14th. Okay. Friendly amendment is now, let's see, Jen, let's see. You made it. Somebody's got a second. Okay. Thank you. Any discussion? Not Kathy, please call the roll.

Member Stromberg?

Yes.

Member Hollingsworth?

Yes.

Member Hefner?

Yes.

And Member Gibson?

Yes.

Thank you.

Thank you. Motion passes four to zero. That takes us on to the ever popular status reports. Why is this man smiling? Are there any questions concerning status reports? I have one. What is it? Yep. Okay. Was on the May 8th outage, different parts of the town were out for different periods of time, were they not?

Correct. And that's why The tabulated data shows multiple outages for the same day. I was trying to show it really wasn't as bad on the SADI and make it more realistic. Kathy Deanna, as one of her last great things, sent me the report from the AMI system showing, as meters came back on, what sections of town were still out. And so I was able to use that to whittle that number down to an hour and a half. Otherwise, if we'd have done it with no AMI data, it would have been guessing and probably closer to four hours or five hours at it. So that's why you see in the tabulated data multiple outages on May 8th. I was using it to whittle the numbers down to get to Sadie more realistic.

Okay, and I'm glad you did. Make it as realistic as possible. Thank you. You're welcome. I just wanted to clarify that or confirm that what I thought was happening, or at least that you intended to happen, is what did happen. Thank you. Any other questions or issues on the status reports, any of the status reports? I don't see any. That will take us on to the tickler file. Are there questions, comments, concerns on the tickler file? I think we're largely getting the parking lot.

I have a question for Eric.

You had requested this town hall on climate action plan way back when. I think you had withdrawn that request, had you not?

Yeah, pretty much.

So we can take it off the parking lot then? Sure. Okay, thank you. I thought that was the case, but I wanted to check with you before we did that.

Yeah, I appreciate that.

Okay, if there's nothing else on the tickler now... We'll still be getting together, what is it, the 26th? Update it. That's before you run off, right? And so if you've got any other suggestions, concerns, let us know. And please keep Kathy informed about your availability or non-availability, not just for the scheduled meetings, but really particularly in July. I don't any time in July because we don't know for sure when this ECA is going to hit us Okay That being the case work down to public comment again. Is there any public comment?

I Don't see any in chambers Thank You chair Gibson any remaining public online who would like to make comment now No Okay

With that, we are finished. We are adjourned. Thank you very much. And we'll take a 10-minute break.