Transcript - Day 6

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Eric Blank: Good afternoon. I'm Eric Blank. This is the Public Service Company JTS 24A-442E. We're back on the record. Before we jump into it, I guess I'm a little concerned that we're not going to get this hearing in the days we have it, and I think the Commissioner calendar is so jammed we're not going to be able to add days. So I guess I'm wondering if we can potentially stay late tonight, or start early, or stay late next Monday or Tuesday. Commissioner Gilman, that work for you? Mr. Larson, do you have anything to add?

Matt Larson: No, I appreciate you raising this. We could work with either one. I will tell you we're actively looking at streamlining our cross-examination. I don't know that we'll be able to waive any witnesses entirely necessarily, but we may only have like one or two questions. So we're actively taking steps over here to try to streamline as much as possible on the back end here.

Eric Blank: I appreciate it, and I'm going to enforce the limitations on cross a little more tightly, and work to streamline my questions. Commissioner, I think Commissioner Gilman you said you were good. Monday, Tuesday and tonight?

Megan Gilman: Monday, Tuesday, tonight. I'll probably have to go on mobile by like 5:50, but that's okay. I'll just move you to my phone.

Eric Blank: Okay. And Commissioner Plant, how much flexibility do you have?

Tom Plant: Yeah, any of those works fine.

Eric Blank: All right. I should sound more busy, shouldn't I? Let me check my calendar right now. Right now, I'm just appreciative because I don't want to get into scheduling more dates because I think we're all, our calendars are a mess. So, Miss Nelson, did you have something?

Miss Nelson: Yes, Mr. Chairman. I've got two preliminary matters. The first is we can cut right now 30 minutes of our cross-examination of Mr. Martz, which was scheduled for 60 minutes.

Eric Blank: Okay, that's greatly appreciated.

Miss Nelson: And as part of that, I circulated a couple of exhibits that are in UCA's box, numbers 314 and 315. The parties have stipulated to the admission of these exhibits. Their discovery responses from Mr. Martz, so that helps. So I'd like to, if it's okay with you, I'd like to move for admission of UCA exhibits 314 and 315.

Eric Blank: Any objections? No. So moved.

Miss Nelson: And then the second preliminary matter is scheduling some of UCA witnesses. Now that we know we're going into next week, I do have a couple of restrictions on when Anna Summer and when, excuse me, Chelsea Hotelling can be put on the stand. Anna can be on anytime on the 23rd, but only until 1:00 PM on the 24th. Let me know when you're ready for Chelsea. Neither of those witnesses have cross time, do they?

Eric Blank: I'm sorry, I think we excused Miss Hotelling. I did have some questions for Miss Summer.

Miss Nelson: Oh, okay. I thought you had said that you had questions for Miss Hotelling as well. But if you don't have any questions, then yeah, that's great. I'll ask all my questions to Miss Summer.

Eric Blank: Okay, sounds good. Thank you, Mr. Baraso.

Mr. Baraso: Yes, thank you. Good afternoon. Two preliminary items from Deborah Suite, pretty similar to UCA's. Number one, we'll be waiving our cross-examination of Mr. Martz.

Eric Blank: Okay, thank you.

Mr. Baraso: And then item two, WA Sweet witness Mr. Iden is unavailable on the 24th. Not sure if he would be going then or the 23rd based on the current schedule, but I believe there is some cross-examination reserved for him. So if we could have him called up on the 23rd, even if that's out of order, that would be appreciated.

Eric Blank: Okay, got that. Great, thank you. We'll definitely accommodate that. Mr. Bonus.

Mr. Bonus: Good afternoon, Chair. I've got some good news, which is that CEO is going to waive its cross of Ken Wilson. I know it's only 10 minutes, but every little bit helps. The less good news is, we're trying to find out Mr. Haye's availability after hours right now. I know he had built some time into his life to be available extra days, but I don't think he had built time into his life to be available after hours, so we're trying to figure that out.

Eric Blank: All right. We'll accommodate that. We'll just take him during normal hours if that's a problem for him.

Mr. Bonus: Appreciate it. Thank you.

Eric Blank: We'll juggle around the extra hours and I'm hoping it won't be necessary. To me, it looks like we're maybe two or three hours long, and given that we don't have any additional days, I'm hoping we won't need to. So, Mr. Larson, yeah?

Matt Larson: Mr. Chair, just in terms of bringing back Mr. Martz, we were planning to do that at the conclusion of the company's case. I just want to confirm that that was the appropriate order. So once Mr. Martz comes off, we would bring him back for commission questions on select topics and then presumably have a brief redirect examination. Then, the company's case would conclude at that time. Is that consistent with how you wanted to handle it?

Eric Blank: That'd be great. We'll hopefully be able to do that Friday, but it may slip till Monday.

Matt Larson: Okay. And maybe that's a good place to start first thing Monday. So we'll say, or last thing Friday.

Eric Blank: Okay, because Friday we conclude at 1:00 PM. Is that correct?

Matt Larson: Oh, I think right now isn't it noon?

Eric Blank: Maybe noon. Yeah, okay.

Matt Larson: And then there was a discussion with Commissioner Gilman and one of our witnesses about moving the current versions of the ESA model versions of the ESA and interconnection agreement into the record. We do have, we produced those in discovery on March 17, 2025. We have those in our box marked as Hearing Exhibits 137, 138. We can move those now if that works for you. Any objections?

Eric Blank: That'd be great. And can you tell me the exhibit numbers again?

Matt Larson: Yeah, it's 137 and 138 in the PSGO box. That's the ESA and the energization interconnect agreement, interconnection agreement.

Eric Blank: Yep. Thank you. Mr. Bunker.

Mr. Bunker: Thank you, Mr. Chairman. Just a point of clarification. What time are you expecting that we would go to or finish tonight, Monday and Tuesday? Just so we have a little more information on that.

Eric Blank: Why don't we plan on going till 5:30 tonight? And then we'll, if we're way behind, we can go to 7:00 and start at 7:30. But I'm hoping it won't come to that. So if we could just play it by ear, that'd be great.

Mr. Bunker: Okay, thank you. Along that line, part of the reason I ask is trying to get an understanding of the highly confidential session with Mr. Bailey. What were your thoughts towards the end of, probably the end of the afternoon, with regard to that?

Eric Blank: Yeah, so we'll see how we go, but maybe we'll try and do it at the end of today or first thing Friday.

Mr. Bunker: Okay, thank you for that.

Eric Blank: So maybe we'll just see. It'd be nice if we could get Mr. Hungus in today, but we'll have to play it by ear. We may have to juggle a little. No problem. Thank you for that. I appreciate it. Mr. Larson, anything else?

Matt Larson: That's all, thank you.

Eric Blank: Thank you. Miss Whitman, you're muted.

Miss Whitman: Sorry, thank you, Commissioner. I wanted to let you know that OJT will waive its cross-examination of Mr. Congus, and that hopefully will help you out. It's only 20 minutes, so it's not going to save the day, but every little bit counts.

Eric Blank: Everybody, yes, thank you.

Miss Whitman: You're welcome.

Eric Blank: Mr. Dipman.

Mr. Dipman: Thank you, Commissioner Blank. So we will waive cross on Mr. Haye, which will also help out a little bit.

Eric Blank: Okay. Mr. Haye, how much did you have?

Mr. Dipman: I want to say 15 minutes. I have to pull it up though.

Eric Blank: That's all right. I got it. Yeah, thank you. Thanks. All right, Mr. Goodnoff, do you understand that you're still under oath?

Mr. Goodnoff: Yes, I do.

Eric Blank: Commissioner Gilman, fire away.

Megan Gilman: I've tried to streamline, but I'm very curious.

Eric Blank: Sorry if I might, if I might, one quick item Commissioner Gilman before you get started. It may be helpful. We've created a, there's been some confusion with the large loads as to what is in the updated base forecast versus not. We've created a demonstrative that's here in Exhibit 140HC. It's in our box. We've circulated it to the parties. It's basically a cut-down version of TLB2 that just retains the rows with the customers that are in the updated base forecast. So I've just circulated that. So we're not moving it now, but wanted to let you know that's available either for high confidential session, or just to talk about at a high level with Mr. Goodnoff or Mr. Bailey, to the extent it'd be helpful. And perhaps clarify what portions of that table from Mr. Bailey are in the updated base forecast. So it's Hearing 140. It should be in the box and hopefully that can be available to you and we can move it into evidence at appropriate time. So just wanted to flag that as a document that's available to the Commission and has been circulated to the parties as well for their use. And can you, is that highly confidential?

Matt Larson: Yeah, it's highly confidential. So I think our witnesses can speak about.

Matt Larson: This many customers are in this category versus now. We've also added a column to that, I should add, saying which those customers are data centers versus the strategic economic development customers. So I think we can let you know if we need to go into HC session, but if you want to have it in front of you while you're asking questions in a public session, that it just may be helpful.

Megan Gilman: Yeah, can you, Commission Counsel, I don't know if it's Miss Rosati or Miss McLaughlin, can you get that document and distribute it to the Commissioners? I think that would help me prepare for Mr. Bailey. No, I think that would be helpful. Perhaps I'll ask some general questions about the idea of it, but I haven't seen it yet, so I'll probably only be able to ask questions really of Mr. Bailey with regard to it. But I appreciate that. All right, Mr. Goodnoff, good afternoon.

Mr. Goodnoff: Good afternoon, Commissioner Gilman.

Megan Gilman: Couple just pretty broad questions with regard to load growth. In the technical appendix related to this proceeding, the company projected 2024 retail energy growth of 1.4%. Are you familiar with that?

Mr. Goodnoff: That sounds accurate. Yes. Okay.

Megan Gilman: So I took a look at the company's Q4 2024 earnings presentation, and it showed that the weather and leap year adjusted electric sales growth was actually negative 0.7%. Are you familiar with that at all?

Mr. Goodnoff: Yes. Okay.

Megan Gilman: So I'm trying to kind of understand what leads to like a 2% swing, especially considering some of these JTS forecasts could have been developed as late as mid-2024, so halfway through the year that we're forecasting for. It seems like a rather large swing and just wanted to kind of understand from your perspective why such a lower actual growth than the company had forecasted.

Mr. Goodnoff: Yeah, there really were a couple drivers in 2024. The first was frankly some weakness in commercial sales that we had not expected when we developed the JTS forecast, I believe it was around this time in 2024, maybe a little bit earlier in the year. So we saw weakness in commercial sales kind of through the back half of the year. And then we had also projected the beginning of oil and gas electrification to in 2024 that did not materialize in 2024. So those are kind of the main drivers of the weakness to forecast for that year.

Megan Gilman: Okay. Have you been able to kind of track down, I guess, with regard to both kind of the weakness in commercial sales to try to understand, is that some sort of systemic issue that could translate to also changes that would be in later years of the forecast?

Mr. Goodnoff: It's hard to say. Typically when we update a forecast, if you've got lower actuals, it that just naturally will bring your forecast down a little bit that are feeding the models. What it looks to us to be is, especially because it's mostly in the small commercial class where we're seeing that weakness, is probably a little bit of the economic uncertainty affecting business operations. You know, really that weakness started in the back half of last year when things became a lot more uncertain, I would say. So our anticipation would be if it is kind of related to short-term uncertainty, that it might be temporary. That we might actually kind of get a rebound to the economic activity we had been expecting if the uncertainty does not persist. At some point it becomes certainty if uncertainty persists long enough, right? But yes, so we do think it's a customer reaction to the uncertainty that hopefully kind of alleviates over time. Another driver of that, as I mentioned, is the oil and gas. You know, that didn't, that didn't start in 2024 to the extent we expected it to. The company is in contact with our large oil and gas customers and still believes that they do intend to electrify to the levels that are in our forecast. So that's probably just a little bit of a delay in the connection of those customers. And then I guess the one, the one that I didn't mention, just because as I'm thinking it through a bit more, is the, we had a fair amount of electrification in our residential sales forecast in 2024 as well, and that hasn't quite materialized to the extent we expected either.

Megan Gilman: Okay, okay, thank you. A couple questions about EVs. So it's my understanding at the end of 2024 we had roughly 140,000 EVs in use. Is that your understanding?

Mr. Goodnoff: Yeah, that's correct.

Megan Gilman: Does that number include plug-in hybrid as well as full battery EVs?

Mr. Goodnoff: It does.

Megan Gilman: Do you understand to what percentage it breaks down with each of those?

Mr. Goodnoff: I don't know off the top of my head. We do have that number available. So maybe a little context on how we get that EV registration, or the EV number that we that we attribute to our territory. It is through EV registration data from the state, and it's typically by zip code, and that will have kind of make and model on it. So we could ease out how much of those are plug-in versus full electric.

Megan Gilman: Is that an analysis you've done already and just have somewhere, or you would have to manipulate the data to get that?

Mr. Goodnoff: It wouldn't be much manipulation, but it might. I don't think I have it sitting in a spreadsheet currently, but we could get to it pretty quickly.

Megan Gilman: Okay. And when you forecast EV adoption, do you distinguish between plug-in hybrid and full battery EVs?

Mr. Goodnoff: Not in the forecast that we've presented thus far in this case. I will note that just as a natural progression of, you know, improving forecast assumptions, that is something that we're exploring now as we have that information on, you know, the split and then also the different usage characteristics between battery electric and plug-in hybrid. That's something that we look to incorporate in future forecasts.

Megan Gilman: Yeah, I mean, I think you would agree with me that a vehicle that can go 30 miles on a charge and a vehicle that can go 300 miles on a charge would probably have some dramatically different charging characteristics.

Mr. Goodnoff: I suspect we will see significant differences when we pull that data. Yes. Okay.

Megan Gilman: And not to mention difference in flexibility options for those drivers if they say don't want to charge because it's a little more expensive.

Mr. Goodnoff: Sure.

Megan Gilman: Okay. And then just to be clear, your base forecast for the JTS includes the high EV scenario from the T. Is that right?

Mr. Goodnoff: Not specifically from the TE. I don't believe our, it's my understanding there aren't specific EV number adoption forecasts in the TE, but it is the high case that is developed by our risk team, just as kind of the an annual update that they do. They give us three scenarios, and we have the high case in the base forecast.

Megan Gilman: Okay. And does that high case kind of proportionally hit like the governor's EV goals or does it go beyond that or how does that vary?

Mr. Goodnoff: I think it's pretty close. It's, I believe 830,000 vehicles by 2031 in our service territory specifically. So I think it's on par with the governor goals. I'm not sure if it exactly ties out or not.

Megan Gilman: Okay. And how do you understand the current adoption rates and curve up till this point to compare to the trajectory to get to that high scenario?

Mr. Goodnoff: It'll be an acceleration of EV adoption. So we're moving up the S-curve of adoption.

Megan Gilman: Okay, so proportionally we would be behind and your assumption is that adoption increases?

Mr. Goodnoff: Yes, the pace of adoption increases. That's correct.

Megan Gilman: To what degree?

Mr. Goodnoff: I mean, we're at roughly, we're at about 148,000 or so vehicles now. So we're adding 700,000 over the next six years as opposed to 140,000 over the last decade or so. So there's a pretty significant increase in the adoption of EVs.

Megan Gilman: And I presume that, but I want to confirm, you haven't kind of adjusted that forecast based on a decrease in federal support for such?

Mr. Goodnoff: No, not in the base case and not in the rebuttal forecast that we filed. It will be our intent. By the time we're developing the Phase 2 forecast, I suspect we'll know if that has been signed into law at that point, it'll be later this year. To the extent it is, we intend to build that into our Phase 2 forecast if there is a change in the tax policy that we think would impact EV adoption.

Megan Gilman: Okay. And you have like a concept how proportionally that would work or you're going to have to figure it out?

Mr. Goodnoff: It'll run through our models, the specifically the risk team's models. They account for incentives in their modeling and you know, we'd pull that out, run the models and see what it did.

Megan Gilman: Okay, got it. And then another assumption embedded in there is the mileage per year on the vehicles, which I believe the modeling uses 12,000 miles a year per vehicle.

Mr. Goodnoff: That sounds correct.

Megan Gilman: Is that a value that's based on any specific data related to EV drivers?

Mr. Goodnoff: Yeah, I believe it's based on, well I don't know about specifically EV drivers, but I think it's based on US level kind of Department of Transportation estimates for just miles driven per vehicle.

Megan Gilman: Okay. And I know you plan to do, I think, some forecast adjustments before Phase 2 as well as before the supplemental RFP, right?

Mr. Goodnoff: That's correct.

Megan Gilman: If the commission were to require the company to alter certain adoption rates, or charging patterns, or dynamic charging assumptions, is that something that could be implemented and integrated into your revamp of your forecast before Phase 2?

Mr. Goodnoff: Yes, we could certainly incorporate any order of what assumptions to make in that forecast. Just stepping back as a forecaster, I'd be concerned about putting assumptions of any of those, really, adoption or charging patterns, in that, you know, there's not really a mechanism to get to right now. So that would just be a concern. Like I'd want to understand how those assumptions were developed and make sure it was something that we think we're able to do. But as getting assumptions into the forecast, we could do.

Megan Gilman: Okay, okay, great. I wanted to look really briefly. I'm going to try and avoid bringing up exhibits so I can move along. But I just wanted to bring up a slide deck you showed at the technical conference with regard to EV load shapes. Miss Kungl, I think you have that, hopefully. And just take a look at those load shapes. So you had showed, first I want to understand, is the slide deck that you all showed at that technical conference in the record?

Mr. Goodnoff: I will look to my attorneys to confirm that. I'm not sure.

Megan Gilman: Don't need an answer right now, Mr. Eisenberg, but maybe if you can clear up for us by redirect if this is something that's already in the files. I mean, I know it was presented, I'm just not clear if it got filed in and of itself. So on slide seven of the slide deck there were these figures that showed the managed and unmanaged charging profiles for the vehicles. And it was kind of notable that the managed charging profile was actually far peakier if you look at like the magnitude of that blue line versus the unmanaged. And is this because customers are responding to the time of use price signal or what causes the managed charging to have a more dramatic peak than unmanaged?

Mr. Goodnoff: Great question. And it's the nature of the program. So it's not specifically our, you know, broad time-of-use rates, but this is the charging perks program. So this is the kind of the behavior that that program is looking to incent with the more charging overnight. You do, you see that big spike kind of when the window starts for the charging and then that works its way down over the evening. The one thing I'll note on here is that that is the only shape on this graph that is actually based on actual data, because it is the customers that are enrolled in our charging perks program.

Megan Gilman: Okay, I appreciate that. Tell me just briefly, how does the management in the charging perks program work?

Mr. Goodnoff: I'm afraid I can't answer that question. I'm not an expert on how the programs actually move the charging.

Megan Gilman: Okay. To my understanding, and maybe some combination of customer preference and time of use rates, and not like any sort of actual dynamic signals from the company to modify charging to be kind of better, is that your rougher understanding or have I gotten you too far?

Mr. Goodnoff: Probably beyond the scope of my knowledge, but you're probably correct also. Okay.

Megan Gilman: And then the company's base assumption was 5% of EV customers in managed charging in the initial years and then that ramps up to I think 70% later on. Does that sound accurate?

Mr. Goodnoff: Yes, that is correct.

Megan Gilman: And is the assumption that the managed charging always looks like this, which doesn't to me look like the company is really trying to optimize around peaks?

Mr. Goodnoff: No, actually. So one of the things that we discovered as we were pulling together this forecast is that if we did just leave the managed charging with this shape, you quickly get to a point where EVs are setting the peak. And it's when, you know, the maximum EV charging is the system peak. So we did work to mitigate that in our forecast. It's what we call trunching. So we recognize that over time as that situation starts to present itself where EVs are setting the peak, you know, we'll need to move the EV charging to a different time. The way we did that, it was pretty simple in this case. We didn't really try to necessarily predict exactly what future rate design would look like. We just knew that we needed to move that load around. And so we took this shape and then we shifted it, you know, earlier in the day or later in the day, to kind of mimic a managed program, but just assuming that we're incenting charging at different hours.

Megan Gilman: Okay. And I know we kind of originally had the 5% in managed charging number in the technical conference. Someone mentioned 10%, and then I think the company walked that back. Can you confirm for me what's the right number that we currently have in managed charging?

Mr. Goodnoff: It is about 10% now today.

Megan Gilman: Okay. And by what ratio is that in Optimize Your Charge versus Charging Perk?

Mr. Goodnoff: That I'm not sure. I think I believe the majority, so more than half are in Optimize Your Charge, but I'm not 100% sure on.

Megan Gilman: Okay. And do you have any kind of conception on what are the limiting factors in terms of like uptake of those programs among customers?

Mr. Goodnoff: I don't, unfortunately. Okay.

Megan Gilman: Let me look. I have some more questions about those programs, but I have a feeling you're not the guy. So essentially, in your assumptions going to the 70% level, what I heard you say, and I think what I've seen in the graphs, is you take the charging perks shape and then just trunch it out. You don't assume some more sophisticated, more dynamic actual managed charging program.

Mr. Goodnoff: Correct. That is the approach we took. Okay.

Megan Gilman: And according to the technical appendix, my understanding is those trunches don't start until 2028. Is that correct?

Mr. Goodnoff: I would have said 2027 if you asked me. Maybe that was the last year without the tranches, but late this decade is when we start doing trunching.

Megan Gilman: And why is that?

Mr. Goodnoff: That's where we start to see that initial shape impact the peak.

Megan Gilman: Okay, got it. And it also, also under the radar with that peakiness until then. Yeah.

Mr. Goodnoff: And the other thing I'll note is it also kind of gives the time, it gives the company the time to go through another TE and perhaps incent something different as well. We wouldn't want to assume we can do that kind of starting tomorrow necessarily.

Megan Gilman: Okay, okay. Couple questions about oil and gas electrification. So I believe for oil and gas electrification within the RAP, you've projected around 364 megawatts of new load. Does that sound right?

Mr. Goodnoff: That's right. Yeah, that's right.

Megan Gilman: Can you help give me a concept of how large each load is and how many separate entities you're talking about serving by 2031 under that?

Mr. Goodnoff: Sure, at a very high level, I can answer that. This is a forecast that is developed by our key accounts team, who are working directly with those customers. And they tend to send us kind of aggregates, excuse me, of requests as opposed to like individual sites or something, right? But we're, it's the large customers, maybe 10 or so large oil and gas customers that are in Colorado. And it's through discussions with our key account reps, understanding the requirements to reduce their emissions. Electrification is one approach. What they think the level of electrification might be to help them meet those goals.

Megan Gilman: And what might be an average for a site, just to get a concept?

Mr. Goodnoff: I would not want to speculate on that. I've seen some as low as three megawatts. And then I'm sure there are some that are quite large.

Megan Gilman: So megawatts, megawatts, yes, in the megawatt range. Yes, okay. And then, are any oil and gas loads considered economic or strategic economic development load?

Mr. Goodnoff: No, they are not. Not included in strategic economic development. Okay, got it.

Megan Gilman: And so how do you understand kind of the probability of these gas, like do they have some probability rating, or it's just in if they're in discussions with you, you think they intend to and they're in the forecast?

Mr. Goodnoff: I would say that we've done an assessment of whether the load is likely. We're not following like a similar specific probability rating like we are for the other new loads. But you know, with sort of the mandate to reduce emissions, we believe that electrification, and our understanding is that electrification is a big part of the solution. So the loads feel very, very likely.

Megan Gilman: And do you envision any of the oil and gas electrification would be served by economic development rates or other special rates?

Mr. Goodnoff: I do not believe that's the case.

Megan Gilman: Okay, let's see. So in UCA, Dr. Milligan's testimony, Dr. Milligan contends that the company's forecasting only includes deterministic scenarios and doesn't account for how demand and supply could correlate to weather both. Do you have any response to that on how those could move together, which is not necessarily analyzed?

Mr. Goodnoff: I have not reviewed that testimony, so I'm going to think on the spot here. So we do, we do account for weather in our forecasting, and I think the assessment is correct that we're, you know, we're assuming normal weather, so it's kind of a point estimate of future weather. I think any of that stochastic modeling would be handled particularly on the weather side, would be handled through the RA study, where you're modeling potential extremes and figuring out what the reserve margin would need to be.

Megan Gilman: Okay, is that anything that specifically factors into your forecast or that you account for?

Mr. Goodnoff: No, it's not. Okay.

Megan Gilman: And then, with regard to solar adoption, it's my understanding you've forecasted around like the customer programs and what the customer programs will cause in terms of behavior and adoption.

Mr. Goodnoff: That's true in the short term, and then there's also a long-term model that's more of like a technology adoption model kind of beyond the near-term visibility we have into the specific customer programs.

Megan Gilman: Okay, so is any of that intended to capture kind of the more organic and potentially not like program induced adoption, say with a higher percentage of new homes getting solar than previously?

Mr. Goodnoff: Yeah, I think that would be picked up in the kind of the longer term modeling, that trend. Okay, okay.

Megan Gilman: And is it accurate that all of the distributed solar that's induced by PSCO programs is considered kind of a resource and subject to the ELCC evaluation or are you not aware?

Mr. Goodnoff: It is. So the forecast that I that I give to Mr. Landrum to run his modeling is it's a native load forecast. So it has the impacts of solar added back to both peak demand and energy. And then he's taking that and modeling it as a resource to meet kind of that native demand.

Megan Gilman: Okay, got it. Couple questions on, be more like building building base. Has your forecast, I think your forecast assumes essentially that the Clean Heat Plan is executed as designed or as planned in terms of you hit the goals each year. Is that fair?

Mr. Goodnoff: That's right.

Megan Gilman: And do you factor in at all actual adoption rates and kind of the pace you're seeing in the field in juxtaposition to kind of what the plan was?

Mr. Goodnoff: We haven't for this forecast update. We're so early in the implementation of these programs and, you know, the goals that have been set are ordered. So for this forecast, we are assuming that we that we hit those goals.

Megan Gilman: Okay. And am I right in what I've seen that in the JTS, and for the electric system you assume that we hit all of the Clean Heat Plan goals in your base forecast? In the company's recently submitted gas infrastructure plan, the company assumes in the base forecast that there is no Clean Heat Plan impact at all on the gas system. So to clarify, in the actual base forecast, it was prior to the Clean Heat Plan, or so we had.

Mr. Goodnoff: I think it was the company's position at the time, which was Clean Heat Plus in the base forecast. In the rebuttal forecast that we recently filed, we have updated that to be the actual Clean Heat Plan order. So maybe just a clarification there. But you're right about the dynamic between the base and the, you know, the base forecast between the two filings, and that we're assuming Clean Heat Plan levels of electrification in now this updated base and the JTS, and that I think informs the low case in the GI.

Megan Gilman: Right, but the base case in each would, the base case in the electric system we're planning to for forecasting, and the base case in the gas system we're planning to, are different futures. They have different levels of electrification, yes. Okay. So with regard to all electric, if you see an all-electric heat pump installation, am I right that the company's assumption there is it would be paired with supplemental electric resistance at like 10 kilowatts or so per home? Does that sound right?

Mr. Goodnoff: It's a bit in the weeds of the modeling that's produced by another team. That number sounds roughly accurate though.

Megan Gilman: Okay. And in order to develop that, does the company look into any actual usage patterns of all electric customers with heat pumps and electric resistance or kind of factor in any data on newly installed systems with regard to the proportion that are designed in that way?

Mr. Goodnoff: Yeah, unfortunately I'm not sure I know the answer to that question. I believe there's a fair bit of modeling what kind of the optimal performance would be. They may have started looking at some actual kind of field equipment for this forecast. I'm not sure if they did or not, but that is certainly something the company's tracking and could certainly be helpful in informing future forecasts of electrification if we see kind of actual behavior deviating from the assumptions that are currently in the model.

Megan Gilman: Okay. And I don't know if you're familiar with Mr. Iden's testimony referring to Elephant Energy heat pump implementation. Are you familiar with that?

Mr. Goodnoff: I read his testimony.

Megan Gilman: And within that testimony, they're claiming that a full two-thirds of their Front Range installations have no backup resistance at all. And that they have performed through cold snaps. Do you have any reason to kind of dispute the information they're providing there?

Mr. Goodnoff: No reason to dispute the information. Okay.

Megan Gilman: And then a Sweet witness in the Clean Heat Plan proceeding testified that air source heat pump systems only require 3 to 8 kilowatts of supplemental electric heat, which we did, we didn't really confirm if 10 kilowatts was what's in here, but there's a potential that it's off by a few magnitudes in terms of what the company is forecasting here.

Mr. Goodnoff: You know, I believe Mr. Iden cited that testimony in the Clean Heat testimony and his testimony in this case. To my knowledge or based on my understanding of those calculations, I think they were just internal questions about whether those calculations necessarily applicable to the to the customers in Colorado specifically.

Megan Gilman: Okay. Just a couple questions now about revamp of the forecast and I'll be done. So I wanted to understand what factors you're anticipating including in the forecast revamp before Phase 2.

Mr. Goodnoff: Sure, the intent is for that to be a full forecast update. So that will include updated history obviously. We'll bring in, you know, the last year or so of history and updated economic outlook, which will include, you know, to the extent we're either in a recession or the odds of a recession have gone up, that will be factored into the forecast. I already mentioned the tax policy, you know, if there's certainty around that tax policy that would be brought into the forecast as well. And then, you know, based on our proposal in rebuttal, a fresh look at the new large loads as well. If there are new customers that have hit the 80 or 90% threshold to be included in the forecast, then those would be included in the forecast.

Megan Gilman: Okay, got it. Is there any, and then kind of as I understand it, and so last time I think you all just take that forecast and move it into Phase 2. Is there any way where the commission or different stakeholders see that renewed forecast before it's utilized?

Mr. Goodnoff: Yeah, I think the challenge is timing. There are, we want to, we'll want to have the latest, greatest information that we can flow into the forecast. And, you know, that process of review could potentially make some of the assumptions stale. So I think that's really where we see the challenge in providing like a, kind of a, a long kind of feedback period on what's been included in the updated forecast.

Megan Gilman: Yeah, I'm trying to figure out with large loads being such a new and such a major issue in this proceeding, I think it's fair to say. And we already saw, you know, an adjustment of half of those loads just between direct and rebuttal. I'm trying to figure out how we could understand what is actually going into the Phase 2 modeling if there's some sort of major adjustment to the large loads that seems pertinent to share, and trying to figure out how that could occur.

Mr. Goodnoff: Understood. I might defer you to Mr. [unidentified speaker] when he comes back up about the mechanisms to provide assumptions. I'm just not sure what the answer to that is.

Megan Gilman: Okay. And then kind of same exact question on the supplemental RFP, which is in a few years, and honestly, who has any idea what's going to happen in a few years? But I presume like the first time that's a full revamp with all new projections, economic outlook, all the rest.

Mr. Goodnoff: That's correct.

Megan Gilman: Okay. And then, probably I'll have the same question on that, especially because that's much further away from when we're making all these decisions. How and in what way would there be kind of any transparency or potentially even evaluation of what forecast will be used?

Mr. Goodnoff: Yeah, I did hear some of your questioning with Mr. [unidentified speaker] along the lines of incorporating outcomes of specific cases into that supplemental RFP. I bring that up as a way to say I think the timing will be a challenge there as well, just being able to process the orders and then kind of translate that into a load forecast. Again, as far as sharing specific assumptions though, I would refer you to Mr. Iden to answer that.

Megan Gilman: Okay, thanks. Mr. Goodnoff, those are my only questions. Thank you.

Eric Blank: Thank you, Commissioner Gilman. Commissioner Plant?

Tom Plant: Thank you. Good, I guess it's afternoon. Good afternoon, Mr. Goodnoff.

Mr. Goodnoff: Afternoon, Commissioner.

Tom Plant: So, to follow up on a couple of the questions that Commissioner Gilman asked about, one of the things that she mentioned was that there was a projected growth in 2024 of 1.5% and that it ended up being, you know, negative at that time. And I think you pointed to a couple of things that didn't happen that you had expected to happen within the oil and gas sector. And that the forecast didn't show up quite at the level you had expected. But in looking back over the decade preceding that, I think the cumulative growth over 10 years was about 1.6%. So I'm wondering, I mean, to have that kind of a shift, to have 10 years basically of growth projected in one year seems like a fairly significant change. And yet, you know, what you ended up having was a negative growth. Was there any re-evaluation in terms of that projection of whether or not some of the expectations that you had as you're as you're looking at that forecast were accurate or if you were missing something, if there was higher level of, I don't know if efficiency than you would expected or something that's like making these forecasts so grossly different from what you had expected?

Mr. Goodnoff: Yeah, I think it's a good question and I think ultimately it ended up being a matter of timing. I mean, what was driving the growth in 2024 and also what's driving a lot of the growth going forward, it's really a fundamental change in how we are expecting customers to use electricity, right? So you point to the historical growth of 1.6% over 10 years, you've got just normal economic growth, customer growth, population growth, being offset essentially by DG and energy efficiency. That's kind of what's causing that flatish growth and there was a COVID impact in there as well but saw a lot of that come back. We still have those dynamics, but now we are taking a lot of, formerly a lot of end uses that were formerly not being driven by electricity and electrifying. So you've got significant growth in oil and gas electrification, beneficial electrification as I mentioned with Commissioner Gilman, a significant uptick in the EV adoption. And our assessment of 2024 was not that those things are not going to happen, but they just didn't quite start when we expected them to. So we're confident in the long-term projection of the growth due to those items. Didn't quite see what we expected in 2024. Could be for a number of reasons. I do think a big part of that is a lot of the economic uncertainty that I mentioned, just maybe things were a little bit slower to develop than what we had forecasted.

Tom Plant: On the managed charging, when you talk about managed charging and when you model it within your model, is that, are you referring to active managed charging on behalf of the company, you know, through your program, or are you talking about, you know, more generally a shift in usage?

Mr. Goodnoff: It's the former. And as I mentioned with Commissioner Gilman, the shape is based on company program managed charging.

Tom Plant: Okay. And is it possible that a part of this, you know, lower growth than you're expecting, is because people are just inherently charging at different times than the expectation, or do you have any insight into that?

Mr. Goodnoff: Well, the numbers we were citing were sales numbers. So, you know, time of charging wouldn't impact sales as much as perhaps demand at the time of the peak.

Tom Plant: Yeah, that's what I'm kind of wondering about in terms of how it's impacting the peak. I think your assumed managed charging level as you said was 10% and then increasing 2.5% per year. And I'm just wondering if that peak time is that being, is it tracking with those assumptions in terms of what you're seeing in the actual system?

Mr. Goodnoff: It's a challenge to know the actual EV load at the time of the peak. I mean, a lot of that's going to be based on assumptions. Just we don't have all of our EV charging metered, metered separately in particular. I'm not sure I could speculate on that at this point.

Tom Plant: As we're looking at managed charging going forward, do you know, is there any, I mean, I'm looking at Mr. Goen's direct testimony in the TEP and on page 20 of that direct testimony, the forecast was 22% participation in managed charging in 2024, 38% in 2025, and 50% by 2026. Obviously, if we're at 5 or 10%, we're nowhere near that projection. Is there any evaluation in the company of why we're not getting to those projected, I think that was a Guidehouse study for the TEP, why we're not getting to those projected levels of managed charging and if there's any changes that need to be made in the program in order to help us get there?

Mr. Goodnoff: I mean, sure. Within the company, yes, we have an EV team that was an active participant in the TEP, obviously, that was looking at exactly those things. I'm not sure what the answer to that question is though.

Tom Plant: Is there any evaluation of the economic impact in terms of, you know, I mean, for our benefit, if we're able to instead of growing by 2.5% per year, if we're able to grow that managed charging at 5% or 10% per year because of, you know, significant changes for the program, what that would lead to within this ERP in terms of savings so that we can determine, you know, what would be a cost-effective level of investment?

Mr. Goodnoff: Not to my knowledge. It wouldn't surprise me if that work was being, or similar work was being done, but I'm not aware of it.

Tom Plant: Did you do any sort of modeling where you sort of, you know, looked at different levels of changes in the assumption of managed charging and how that impacted the level of peak and what the ultimate impacts of those changes would be?

Mr. Goodnoff: Sort of is the answer. So we did do an analysis of what the peak demand would be if we were to not make assumptions about an increase in managed charging, and very specifically the trunching that I discussed earlier this afternoon. So leaving the managed charging on kind of that existing managed charging shape, the result of that was a more than 2-gigawatt increase in the peak by 2030 or by 2050, entirely driven by EV charging. So that analysis is what led us to start trunching the EVs and recognizing that there would need to be a change in the way that EVs were charged over time just to mitigate that peak impact. But as far as how we did that, we didn't do like a specific in-depth economic analysis as to, you know, the best times of day to move the EV charging. We took a pretty simplistic approach of just shifting the shape throughout the day, kind of with the expectation that those issues are more suited for the TE than the case that we're in now.

Tom Plant: Yeah, I guess what I'm trying to get at is, and it doesn't, you know, the time of day, I know it's important in the whole, you know, the overall analysis of the resource plan and what resources are providing that power at what time. But I'm kind of interested in what reduction in peak could be achieved by accomplishing a 10% increase in managed charging annually or a 5% instead of a 2.5%, since we're so far behind. And I'm wondering if, you know, if we were able to get to a 10% change, I mean, that would put us significantly ahead of the ball once we got to the end of this RAP, and I got to think it would save significant resources that are needed to meet those peaks.

Mr. Goodnoff: Yeah, understood. I don't know the answer to that now. But if the question is, you know, not necessarily around how to get different behavior, but just what the impact of different behavior would be, that is something that, you know, would be pretty straightforward to model.

Tom Plant: If it would be possible to get some sort of a model looking at that, or your SOP, I think that would be helpful, as well as what Commissioner Gilman was asking about, the split between the PHEVs and the EVs in the vehicle count. I think that would be helpful for us as we're trying to analyze our options here on the managed demand. You know, there's obviously been some testimony to use that as a load reduction number in this proceeding. I think what the company is doing is really applying, is it correct that you're applying an ELCC that's basically a proxy for our energy storage that you apply to that managed demand?

Mr. Goodnoff: Yeah, that's beyond the scope of my knowledge. I think you're speaking specifically about demand response, which is treated as a resource. So Mr. Landrum would have been the better person to answer that question.

Tom Plant: I read something about, you know, using the renewable battery, or the battery connect, I'm sorry, I can't remember the name of the program, but the one with the batteries, and you know, that had a certain assumption to it. I don't know if the BPP managed demand is a part of that evaluation as well, but I mean, I can also ask Mr. Pollock about that to get into that any deeper.

Mr. Goodnoff: Yeah, so helpful, helpful flag for me that you were referring to VPP issues. And I think you beat me to the punch of referring you to Mr. Pollock for that.

Tom Plant: Okay. All right. And on, you were talking about with Commissioner Gilman, I was wondering, do you know at what temperature your model assumes a shift to resistance with the heat pumps?

Mr. Goodnoff: I don't know that specifically. Okay.

Tom Plant: All right, thanks. I don't have any further questions. Thanks.

Eric Blank: Thank you. Thank you, Commissioner Plant. I just wanted to follow up on both Commissioner Plant and Commissioner Gilman's discussion with you on plug-in hybrid versus regular EVs. Do you have year-by-year data, adoption level data, between the two of those? And if so, could you put it into this record somehow?

Mr. Goodnoff: I have to see how far back we could go with year-by-year data, but we could certainly give a snapshot currently and probably some history as well.

Eric Blank: I'm talking about the forecast. Okay.

Mr. Goodnoff: So right now in the forecast, we're not making a distinction between the two. So it's just an EV count forecast.

Eric Blank: Isn't that a big deal though, to distinguish between the two? Because I would think the plug-ins would have a very different charging pattern.

Mr. Goodnoff: Yeah, as I mentioned with Commissioner Gilman, that is a forecast assumption that we are evaluating and intend to incorporate in future forecasts, almost certainly in the Phase 2. We don't have that developed yet. I'm not sure if we'll have it in time to file like in the SOP, I think you requested, but something we can share at some point. We will be accounting for that split going forward.

Eric Blank: Do you think you could supply it prior to the Phase 2 going out?

Mr. Goodnoff: I suspect we could. I probably confirm with Mr. [unidentified speaker] the timing of that.

Eric Blank: Can we turn to page 16 of your rebuttal testimony, Hearing Exhibit 122? And just so I'm clear, it looks like, yeah, if you scroll down so we can see the whole table, it looks like between 2025 and 2028, you're losing over 550 megawatts of wholesale peak demand. Is that right? I don't think I fully appreciated how far and extensively this wholesale demand was getting reduced.

Mr. Goodnoff: Yeah, that's accurate. We have a large customer moving off the system by 2026, and then a couple more moving off by 2028. Okay.

Eric Blank: And looking at the top table, last column, you show total system peak demand of 7,231 in 2024. Is that right?

Mr. Goodnoff: That's right.

Eric Blank: And that increased 171 megawatts from the base case. Can you help me understand what drove this?

Mr. Goodnoff: Yeah, it is assumption-driven. I will say that's not like an actual 2024 number, it's in the modeling assumptions. And it's, you can see the breakout in the drivers there. You can see it's predominantly in the retail XEV and large loads. And the main driver of that is, in the rebuttal case we factored in the new TOU window as opposed to the one that existed when we developed the base case. And as a result, that increased the load from 4:00 to 5:00 PM and made that the peak hour as opposed to 5:00 to 6:00 PM. So it's a combination of just different assumptions around TOU and then also an hour shift as well, which is why the EVs changed a little bit because of the hour shift.

Eric Blank: Can we pull up what has been marked as Hearing Exhibit 2906, and let me represent to you that this is the Public Service Company 10K filing with the Securities Exchange Commission. And if you would, would you be willing to accept that subject to later check?

Mr. Goodnoff: Yes, that's fine.

Eric Blank: And can we turn to page six? So do you see in the middle on the left column that actual peak demand was 7,804 megawatts and that was experienced on August 1st? I do. All right. And the data you presented to us in the rebuttal testimony was 150 megawatts higher. Can you help me understand why you're presenting forecasted data when actual is available? And it seems like the direct testimony was right. And in any event, I don't think the time of use rates were in effect in either 2024 or 2025.

Mr. Goodnoff: Yeah, sure. So I, the main difference in kind of what's reported here versus what's in the table that we just reviewed in my testimony, I'm just trying to kind of skim and see what if there's any description of the demand here. I believe it's the difference between obligation and native. So the numbers that I provide will have solar added back, the impact of solar at the time of the peak added back. So that would naturally be higher. And it would be in that, you know, 150, 200 megawatt range roughly. So I think that's the key driver here.

Eric Blank: Okay, so your numbers have solar added, so it's grossed up for solar. Yes.

Mr. Goodenough: Yes. Yeah, the numbers that I present in my testimony are grossed up for solar. So native load, which is then sent to Mr. Landram, who treats that solar as a resource.

Examiner: Why would you do that? It seems really counterintuitive.

Mr. Goodenough: It's the way we do it. I don't know if I have a better answer than that. Well, it is in that it's specifically the treatment of solar as a resource as opposed to a load modifier. It sits in Mr. Landram's modeling instead of mine.

Examiner: Yeah, but it's, you'd think it would reduce load off the peak. I mean, I could see why you wouldn't want to reduce your native load, but to inflate your native load to somehow account for solar. I don't know, I'm confused.

Mr. Goodenough: Yeah. Maybe I can help, maybe not, because I'm probably going to repeat myself. We're not inflating the native load to account for solar. We're including solar to get to the native load. So the solar is a difference between the native load and the obligation, which is typically what would get reported as an actual load would be that obligation.

Examiner: All right. While we're on this document, can you go up to page four for a second? Scroll down. Can you see that revenue per retail customer per kW is 13.82 cents a kilowatt hour?

Mr. Goodenough: Where is this, sorry?

Examiner: Yes, for 2024. Yes. And can you see how total retail revenue per kilowatt hour is 11.17?

Mr. Goodenough: Yes.

Examiner: All right. Yes, we can take this down. Thanks. And if we can go back to page 16 of your rebuttal testimony, and again in 2025, you're showing 7,448, and that's 233 megawatts higher than in the base case. Is that right?

Mr. Goodenough: That's correct.

Examiner: And again, is this for time of use rates?

Mr. Goodenough: Yeah, that's the dynamic that's driving that retail large loads up is the new time of use window.

Examiner: And you understand that in 2025 the time of use rates don't go into effect till October?

Mr. Goodenough: Yeah, that's right.

Examiner: And then, just as we go down this column, why wouldn't it, once the time of use rates start as the peak shifts later into the evening, why wouldn't the time of use rates start lowering the demand by a similar amount, hundreds of megawatts, instead it just goes down by 25?

Mr. Goodenough: Yeah, great question. So this is specifically a comparison to the base case. So in the base case, we had reductions of, you know, roughly 100 megawatts. I'm just going to give round numbers here. So when we get to 2028 and the hour has shifted to later in the day to be the same as the peak hour in the base case, we're getting an additional 25 megawatts from the inclusion of the CTU rate and the SG time differentiated demand rate. So that's why you see that negative 25 megawatts. The reason you're seeing higher positive numbers in 2024 through 2026, in particular, is with that peak moving to the 4 to 5 p.m. window, which is no longer in the TOU window. You're removing the impact that we had in the base case and adding a little bit of load there as well. So it's taking out the incentive, taking out the reduction is the vast majority of that plus 156 and then a little bit of added load, throwing that out as well.

Examiner: All right. And you can see in 2031, as you talked about with others, you have 710 megawatts of EV charging load. Do you see that?

Mr. Goodenough: Yes.

Examiner: How would you, if we implemented an annual demand ratchet that required customers to pay the full cost they imposed on the system to charge during that peak, how would you model that?

Mr. Goodenough: Great question. I'm not sure how I could, not sure I can say exactly how we would model the impact right now, but I could speak to how it would be brought into the forecast. So we would do an estimated impact of, you know, higher rates during certain times, what we think the load shifting might be. And then the way that we're doing our forecasting now, we call it 8760 forecasting. So, you know, every hour of the day for 30 years, for every concept. So we have an 8760 for residential load, for non-residential load, for wholesale, for various EV charging tranches, for various types of beneficial electrification. Once we had what we thought would be the estimated impact on the EV shape itself, we would just kind of slot that in to the EV charging and then see what that did to the ultimate peak demand forecast. To the extent it didn't shift the hour of the peak, you would expect this number to go down if we implemented those demand rates. How much, I'm not sure I could say without further study.

Examiner: All right. And on the first table, the far-most right column, you see those numbers: 7448, 7235, 7295, 7403, 7847, and 8255.

Mr. Goodenough: Okay.

Examiner: Can we pull up Mr. Landram's rebuttal testimony, hearing exhibit 118, at page 82? I guess what it's going to show is that in 2026, if you can zoom in on that native load forecast line, in 2025, it's basically the same, 7,448 is what is in your forecast. And then in 2026, it's 7,235 in your forecast. And then in 2027, it's 7,5, sorry, it's 7,295. So it's basically even in 2025 and 2026. Then in 2027, it's 200 megawatts higher, and in 2028 to 2031, it's roughly 250 to 300 megawatts higher. Can you help me understand why in 2025 and 2026 there's virtually no difference, and then it expands greatly to 250 to 300 megawatts in the out years?

Mr. Goodenough: Yeah, it's a slightly different presentation of peak that's causing this. I do touch on this, just for your reference, a bit, I believe in the technical appendix about why the numbers in my forecast are slightly different from what Mr. Landram presents for future reference. The numbers in my tables are their native load, but they're at the time of the obligation peak. So if the obligation peak is at 6 p.m., hour ending 18, you know, we'll take the actual loads. We're modeling the loads with solar added back. What Mr. Landram presents is the true native load peak. So that would almost certainly be earlier in the day. Once you add the solar back, it's typically at hour ending 17. The reason you see the numbers be basically the same for the first couple years and then deviate is for the first couple years that's the same hour. The obligation peak is the same hour as the native peak. So therefore, you end up with the same native load at the time of the obligation peak. As that time shifts later in the day, that will impact my numbers. As the time of the obligation peak shifts later in the day, that will impact my numbers, but won't impact Mr. Landram's numbers.

Examiner: So it lowers your numbers?

Mr. Goodenough: It does, because load is generally declining as the day progresses. Mr. Landram, he could, or somebody can correct me if I'm wrong, I'm pretty sure this is the case though, the native peak remains at hour ending 17. The true native load peak that Mr. Landram chose remains at hour ending 17, at least through 2031. Whereas my peak, the peak reported in my testimony, will shift later in the day as more solar comes on.

Examiner: I'm sure this is going to be a Mr. Ming or Mr. Landram question, but why are we managing to the system peak when our highest loss of load probability is almost certainly going to be 8, 9, 10 o'clock? I mean, we're curtailing solar or 5. So I'm just lost why we're managing, why we're investing millions of dollars to manage to the system, to the like native peak, not the highest loss of load probability hour.

Mr. Goodenough: I understand the question. I'm not the witness to answer that.

Examiner: Yeah, fair enough.

Eric Blank (Chair): All right. Mr. Eisenberg, redirect.

Sam Eisenberg: Thank you, Chair. Can we pull back up Mr. Goodenough's rebuttal testimony, which is hearing exhibit 122? We're here on page 16. I just have a really small correction, I think. Mr. G, if you can help me out here. These two tables have peak demand in megawatts and then the change in megawatts. Do you see that?

Mr. Goodenough: Yes.

Sam Eisenberg: And then if we could go to the next page, we got two tables and this is the native energy in gigawatt hours. I think there's just an error that second table should also, the units should also be gigawatt hours. Is that correct?

Mr. Goodenough: Yes, that's correct.

Sam Eisenberg: Thank you. We can take this down. Chair, I don't have a complete answer to the last line of questions you asked without consulting with Mr. Landram. But I'd note that Mr. Ming's exhibit ZM1, which is hearing exhibit 109 on page 31, may be the first place to look for some discussion of how the forecast that Mr. Goodenough produces is then used both in Mr. Ming's analysis and Mr. Landram's analysis. Apologies, I don't have the right witnesses to give you.

Eric Blank (Chair): No, no, no, that's not your fault, that's my fault. What's the hearing exhibit?

Sam Eisenberg: Yeah, it's 109 ZM1. So it's the resource adequacy study. Thanks.

Eric Blank (Chair): No, it's my fault, not yours. No problem.

Sam Eisenberg: Mr. Goodenough, are you familiar with how the company makes a filing with its inputs and assumptions prior to the RFP issuance?

Mr. Goodenough: The only format that I'm familiar with is kind of this Phase 1 format. I think Mr. Bailey would be better to ask any subsequent assumptions by that's works.

Sam Eisenberg: Going, just going back to questions you had yesterday from staff regarding large loads. Could you just clarify at a high level what is in the updated base forecast in the rebuttal testimony in terms of the large loads? This is the, folks can follow along on that hearing exhibit 140, which is of course confidential. But if you could just give a public summary of that.

Mr. Goodenough: Yeah, there were really three buckets of loads that we included in the updated base forecast. It's roughly a third, a third, a third, not precise, but that's the way I think about it. The first is in the data center category. There are data centers that we have connected. And the load that's included for those connected data centers is a ramp that we've largely agreed to with that customer. The second category is, I guess, what I would consider new data centers. So they haven't connected to the system yet. We haven't started getting sales from them yet, but that's a highly likely customer. To my understanding, they've signed an IIA at this point. So that's the first two-thirds of the updated base forecast. And then the last bucket is the strategic economic development customers, so not data centers, customers that have a strong tie to Colorado, have a reason to locate here, aren't necessarily shopping around. And some of those customers are, I mean, they're pretty publicly known as well. So, you know, we do feel very certain, or we're as certain as we can be, that they will request the loads that they've asked for, or that they'll use the loads that they've asked for.

Sam Eisenberg: And then could you also just, just to clean this up, clarify the difference between, for large, just limited to large loads, what's in the updated base forecast versus what is in the, what would be in the low forecast if you were to do the refresh as of today, pretending we were going into the RFP?

Mr. Goodenough: Yeah. If we used the same principles that we used to develop the low forecast, which utilized information of about a year ago, the updated forecast would be higher. It would include all of the data center loads, so the 602 megawatts of data center loads, given the probabilities that we now have assigned to those customers. It would not include any of the strategic economic development customers, just based purely on their probability. But for the reasons I mentioned a moment ago, the reason that we included those in the updated base forecast is because of the kind of known and strong desire of those customers to connect to our system and the fact that they are largely based in Colorado.

Sam Eisenberg: Nothing further. Thank you very much, Mr. Goodenough.

Eric Blank (Chair): Thank you, Chair. Thank you, Mr. Goodenough. You may be excused. Thank you. Let's see. We got Mr. Bailey. Good afternoon.

Mr. Bailey: Good afternoon. Mr. Chairman, and to confirm, can you hear me all right?

Eric Blank (Chair): We can.

Mr. Bailey: Wonderful.

Eric Blank (Chair): Is Mr. Bailey out there?

Miss Shields: Yes. If you can give us a moment. I know that he has set up.

Eric Blank (Chair): Mr. Bailey, can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Mr. Bailey: I do.

Eric Blank (Chair): You can put down your hand. Is anybody with you or communicating with you in any way?

Mr. Bailey: No.

Eric Blank (Chair): If that changes, will you let us know?

Mr. Bailey: Yes.

Miss Shields: Back to you, Miss Shields. Great. And one preliminary matter before I put him on the stand is we had indicated earlier, we understand that Mr. Bailey, that there is a highly confidential session that will be anticipated for him. We are happy to accommodate that at the Commissioners' convenience. But wanted to explore if that's something you'd like to logistically sort out now or wait until we get to the end of the day.

Eric Blank (Chair): Yeah. I think, let's see where we're at at the end of the day. I have over three hours of cross for Mr. Bailey. So, we're happy to accommodate that. It's at the Commissioners' convenience. But wanted to explore if that's something you'd like to logistically sort out now, or I'm hearing, I'm hearing a recording. Can you guys shut that off somehow?

Miss Shields: Yes, I believe that was coming from Mr. Bailey's device. Chairman, when we sort that out, could I just ask Mr. Eisenberg a quick question? I had presumed maybe on redirect you would get to the question about if those slides from the technical conference are in the record or not. Can you just confirm for me or are you still looking into that?

Sam Eisenberg: Yes, I think he was just helping Mr. Bailey with his technical issues. If we might be able to revisit that, I assure you we can put that on our list of to-dos. Great, just don't want it to get dropped. Thanks.

Eric Blank (Chair): Yeah, if you guys could get that in the record, that'd be great. I'm getting feedback, I don't know if anybody else is. I think it's coming from you. When you muted, it went away. Why don't we take a five minute break until? Oh, you think we're good? All right, Miss Shields, back to you.

Miss Shields: All right. Mr. Bailey, if you could please state your name and title for the record.

Mr. Bailey: Yes. Thomas L. Bailey. I am the Area Vice President for Commercial Industrial Solutions.

Miss Shields: Thank you. And are you the same Mr. Thomas Bailey who submitted hearing exhibit 107 direct testimony and hearing exhibit 123, highly confidential, your rebuttal testimony along with all attachments?

Mr. Bailey: Yes.

Miss Shields: And if I were to ask you those same questions today, would your answers be the same?

Mr. Bailey: Yes.

Miss Shields: All right. With that, we'd like to make the witness available for cross-examination. Miss Chong, I got five minutes.

Ailen Chong: Thank you, Mr. Chair. Good afternoon, Mr. Bailey. For the record, my name is Ailen Chong, and I'm an Assistant Attorney General representing trial staff in this proceeding. It's nice to meet you.

Mr. Bailey: It's good to meet you, Miss Chong. Thank you.

Ailen Chong: Thanks. Mr. Bailey, are you familiar with what we've been referring to as a triparty framework?

Mr. Bailey: I am.

Ailen Chong: Specifically, in that agreement, the company agrees to use the large load principles that are listed in your rebuttal testimony. Is that correct?

Mr. Bailey: Yes. TLBR1, I believe. I believe it's TLBR2, the large load commercial principles. Yes, TLBR2, yeah.

Ailen Chong: Were you listening to my brief discussion with Mr. Goodenough regarding the updates to the large load base forecast yesterday?

Mr. Bailey: Yes.

Ailen Chong: Okay. He indicated that he had consulted with you in making the updates to the large load base forecast. Is that correct?

Mr. Bailey: Yes, that is accurate.

Ailen Chong: So I'll pose my question to you. Were the large load principles used to make the updates to the large load base forecast?

Mr. Bailey: Yes, but with one clarity, I just want to make sure we're discussing the probabilities on page 30 of my testimony versus the principles, which is the commercial principles recommended for an ESA.

Ailen Chong: I'm actually speaking about the large load commercial principles.

Mr. Bailey: Okay, yes.

Ailen Chong: And your answer is yes?

Mr. Bailey: Yes. Okay, great.

Ailen Chong: And does the company intend to modify those large load commercial principles based on its discussions with the large load clients?

Mr. Bailey: We will utilize those commercial principles as listed, and obviously, as discussed in my testimony, work through the opportunities to negotiate those principles in an ESA.

Ailen Chong: Okay. And if any modifications are made to those large load commercial principles, how does the company intend to inform the commission of those changes?

Mr. Bailey: Well, as at this time, and directed in my rebuttal testimony, I talk about maintaining commercial flexibility. Again, we've listed the commercial principles. We are verbally discussing them with customers now. Our intent in this interim period that I've discussed in my testimony is to implement those. And then obviously, we've agreed to the large load tariff filing in January of 2026.

Ailen Chong: So it's your testimony today that those large load principles will not have any modifications made to them?

Mr. Bailey: Could you restate that question? I just want to make sure I'm answering it clearly.

Ailen Chong: Yeah. So in your discussions with large load clients, is it the company's intent to make any modifications to those principles?

Mr. Bailey: We will utilize, and we are utilizing, the principles that I outlined in my testimony. Again, we're asking for the flexibility in this interim term to negotiate those principles with customers to ensure that they can get online in a timely manner.

Ailen Chong: Okay. And as those principles are negotiated with customers, how does the company intend to inform the commission of those changes?

Mr. Bailey: Well, at this time, and per my testimony, we're not asking for approval or submission of those ESAs, if and when we come to an agreement. Obviously, stipulated, we are going to file our large load tariff in January. Great.

Ailen Chong: Thank you, Mr. Bailey. Staff has no more questions.

Eric Blank (Chair): Thank you. Thank you, Miss Chong. Let's see. I have Conservation Coalition 20 minutes, and it's 2:30.

Matt Ghart: Thank you. Good afternoon, Mr. Bailey.

Mr. Bailey: Good afternoon, sir. How are you?

Matt Ghart: I'm well, thank you. And for the record, my name is Matt Ghart with the Conservation Coalition. So I want to start out asking you some questions about what I understand as the company's proposal for the base and supplemental solicitations. My understanding is for those solicitations, the company is still proposing to include new large loads in the load forecast with less than a 90% probability. Correct?

Mr. Bailey: Yeah. Just so I'm clear, my updated base forecast has the strategic economic development customers that we discussed, and Mr. Goodenough discussed as well, which are below the 80%. But as we've discussed and defined, those customers are located here in Colorado.

Matt Ghart: Yeah. Sorry. I'm not, I'm not asking about the strategic economic development customers. So apologize for interrupting you. What I'm asking is, setting aside strategic economic development customers, for the base and supplemental solicitations, you're asking approval for a framework in which new large loads could be included in the solicitation before they have signed an IIA or an ESA. Correct?

Mr. Bailey: Are you, just so I'm clear, you're representing the triparty framework?

Matt Ghart: I'm asking about whatever the company's current position is, whether that's the triparty framework or whatever it happens to be as we sit here today.

Mr. Bailey: Sure. No, thank you. That's helpful. In the triparty framework, we've obviously outlined a framework of customers less than 100 megawatts at the 80% level, which we are negotiating, the ESA and the IIA would be included. And then obviously anything greater than 100 megawatts would require the 90%, which is signed IIA or ESA.

Matt Ghart: Okay. So below 100 megawatts still need to have signed an IIA or ESA prior to inclusion in the base or supplemental solicitations? For the incremental need pool, it's the negotiations of the ESA or IIA. Okay. And for the commercial principles that you were just discussing with staff, so aside from the increase in the interconnection deposit, would you agree that most of those principles are terms that would be implemented in a contract such as an IIA or an ESA?

Mr. Bailey: Related to the commercial principles, and I think as I discussed in my rebuttal, these are what we're verbally discussing and in negotiations and implementing and plan to implement with new customers greater than 100 megawatts as we move forward in signing an ESA. And those will be, you know, as we construct that ESA, our intent is to adhere to those principles.

Matt Ghart: Okay. What I'm trying to get at is, would you agree that before a customer signs an IIA or an ESA that contains the commercial principles, the commercial principles by themselves don't really do much to protect customers against any risks associated with procuring resources for a particular new large load?

Mr. Bailey: I don't agree with that. Considering, you know, customers, as we move forward, and we've talked about in the triparty agreement and matching in the layout of this, the Phase 1 and Phase 2, matching those customers that we sign ESAs with over 100 megawatts with the appropriate generation requirements. And those are very important and we've talked about that. I know several witnesses have, and certainly our expectations and intent on how we negotiate ESAs moving forward.

Matt Ghart: Okay. I'll try to come at it a different way. So one of the commercial principles is an exit fee, right?

Mr. Bailey: Yes.

Matt Ghart: Okay. So if you have a customer who hasn't yet signed a contract with that exit fee, the company goes out and procures resources for that customer and the customer withdraws, how does the existence of the exit fee and the commercial principles protect customers in that instance?

Mr. Bailey: And just so I'm clear, you're, in that example, you're making the assumption that the customer has not signed an ESA?

Matt Ghart: Yes. And so that, you know, at that time, they've signed an IIA in that regard because they're at their 90% level of over 100 megawatts. In that example, as we move forward, again, I just want to restate that our intent and our work, and as quickly as we're working, the customers expecting that ESA very soon after the IIA in that regard of the ESA. We have a long list in our pipeline. We have customers that we are negotiating with prior to the 80% and the 80% moving to the 90%. So, Mr. Ghart, I understand your question on risk. I can't guarantee that there's, and remove all risk. But I think what we've shown in our project pipeline is that we have customers who are prepared to move into the state of Colorado with the certainty of generation and the plan accordance in what we've laid out in our Phase 1 and Phase 2 approach. So, have you heard, well, I'll phrase it this way. My understanding is that the company has stated that it believes that if it were to go out and procure resources for a customer before it has signed an IIA or ESA, and then that customer withdraws, the company is confident that another load would materialize to utilize those resources. Is that a fair representation?

Mr. Bailey: Could you, you know, could you give me maybe an example, Mr. Ghart, of that, and thinking about kind of a real world or a note to a previous witness response?

Matt Ghart: Sure. So I heard Mr. Goodenough say something to the effect of, the company believes that there is not that much risk of procuring resources for a customer before it has signed an IIA or ESA because the company believes that if that customer withdraws, new load will replace it and utilize any resources procured for that customer. Do you recall Mr. Goodenough saying something to that effect, or is it your understanding that that's the company's position?

Mr. Bailey: Yeah, thank you. And I do recall, I appreciate that. I am in agreement with that. And I would, you know, I'll just note a couple of items. Obviously, within this hearing proceeding, we've got significant requests on other growth outside of large load or strategic economic development customers or data centers. So I am in agreement with that. We are also currently, and I think this has been represented, we're behind the ball. We're behind in our ability to meet new load growth and customer demand. I would say from my experience, Mr. Ghart, and what I, how I've worked in other jurisdictions, if we get to your example and we have some length for a short period of time, I welcome that length because it allows us to plan accordingly. It allows us to create economic development opportunities for current customers in Colorado and for customers who want to locate here in the future.

Matt Ghart: Thanks. My questions around this are really around the issue of allocation of financial risk if the company's prediction turns out not to be true. So my question is, has the company proposed any mechanism by which if the company were wrong and it procures resources before a customer signed an IIA or an ESA, and then new load doesn't materialize, would any of that financial risk from stranded assets fall on the company under the company's proposals?

Mr. Bailey: I am not aware of any proposal related to your example.

Matt Ghart: Okay. And if the company is so confident that new load would materialize, would the company agree to share in some of that financial risk associated with the risk of stranded assets?

Mr. Bailey: I'm not willing to agree with that at this time.

Matt Ghart: Okay. So I have just two more topics for you, Mr. Bailey. My understanding, as we just talked about, is that for customers 100 megawatts or more in the incremental need pool, the company's position now is that it would only activate the need pool for those customers once they're at the 90% probability, so they've signed an IIA or an ESA. Is that correct?

Mr. Bailey: Related to the incremental need pool, the trigger as is explained in the triparty framework.

Matt Ghart: Okay. So the company believes that at least for that subset of customers, waiting until an IIA or an ESA has been signed is workable for both the company and those customers, right?

Mr. Bailey: And make sure I'm clear, representing the trigger of the incremental need pool. Yes, yes, we do. And we also believe it's prudent based upon our approach to my updated base load forecast and the customers we have in the pipeline and represented in our probability analysis.

Matt Ghart: Okay. And I recognize this is not the company's preferred approach, but wouldn't it also be workable to use that same 90% threshold for all new large loads?

Mr. Bailey: Are you representing those large loads over 100 megawatts?

Matt Ghart: Over or under. I don't believe so. And again, I know you weren't representing the strategic economic development customers, but those are a great example of customers who are on our system and may not hit those probabilities currently, but are required in our plan. To serve them is paramount on having generation and for them to meet their expansion plans. And so, as an example, you may have a customer that is under current contract and is in that expansion phase. And so it's very important to meet those needs specific to those customers under 100 megawatts. So the 80% we feel is also a prudent approach, as we've laid out in the triparty framework.

Matt Ghart: Let me try to separate that out. So let's deal first with new large loads other than strategic economic development customers. So for anyone who's not classified as a strategic economic development customer, why wouldn't it be workable to apply the 90% threshold to all new large loads?

Mr. Bailey: Well, I mean, the hypothetical, I'd have to really think about. But, you know, I wouldn't agree with that because it's such a broad base of new customers coming onto our system, to your example, below 100 megawatts, that I think there's nuances there that we would just have to consider. So I can't agree with that 90%. It's an interesting question, but certainly not laid out in our agreement.

Matt Ghart: Okay. And then just last set of questions. So returning to the strategic economic development customers, you could procure resources for those customers through the incremental need pool, correct?

Mr. Bailey: The current customers today that I outlined in my testimony. I'll rephrase it. Is there any technical reason that there couldn't be a rule that says a strategic economic development customer can have resources procured for it after it signed an IIA or an ESA, including through the incremental need pool?

Matt Ghart: Well, I, you know, I go back to how we define those customers in my testimony. I think for the future, as we, as several witnesses have discussed, if we have a customer come to us in the future, let's say, after, you know, after the Phase 2 RFP, and they hit an 80% or a 90%, again, per the triparty framework, that would trigger the incremental need pool at that time.

Matt Ghart: Sure. What I'm trying to get at is, if you have a customer that's already located in Colorado and the company is claiming that applying the strategic economic development customer criteria, it believes that customer is likely to take service, why couldn't you wait until they have signed an IIA or an ESA? And then if time is of the essence, procure resources for them through the incremental need pool?

Mr. Bailey: Well, in that example, you're likely, and actually not likely, you're delaying their needs of their expansions today. And so those, in your example, those strategic economic development customers have meters set in the state of Colorado and are preparing or have announced expansion and have received either potential state incentives or governance support. So we need to prioritize, as I discussed, in the Phase 1 request.

Matt Ghart: Okay. Just to clarify, are you saying that to qualify as a strategic economic development customer, you have to have already received some kind of state incentive to expand the business? Is that a criterion?

Mr. Bailey: No, not at all. I'm just stating that they may have received or they may have gone through a process of a state agency or Governor's office for support.

Matt Ghart: Okay. Thank you for your time, Mr. Bailey. I appreciate it. I have no further questions, Mr. Chair.

Eric Blank (Chair): Why don't we take a 10-minute break to 2:55, and I show you with 40 minutes, Miss Vitali. So let's take a 10-minute break and come back at 2:55.

Cynthia Vitali: All right, Miss Vitali, it's 2:55 and I have 40 minutes for you. You're up. Thank you. Good afternoon, Mr. Bailey. How are you?

Mr. Bailey: I'm good, Miss Vitali. How are you? Good to see you.

Cynthia Vitali: I'm doing well, thanks. For the record, my name is Cynthia Vitali, representing the Colorado Energy Office, and I have two sets of questions for you today, which hopefully should take much less than 40 minutes. First, I'd like to talk to you about the large load probabilities table in your testimony. Could we pull up Mr. Bailey's rebuttal, hearing exhibit 123, and go to page 30? Great, thank you. My co-counsel, Mr. Banis, asked Mr. Goodenough a couple questions about this table last week, and he referred some of those questions to you. So I'm hoping you can help us just get a better understanding of this table and what it really means. So to start, this table describes the probabilities in terms of percentage of a large load coming online in relation to each of the 10 steps identified. Is that correct?

Mr. Bailey: Yes, that's accurate. And as my team and teams inside Public Service work through and prioritize projects.

Cynthia Vitali: Thank you. And could we scroll to page 23 of this same hearing exhibit, line 16? Thank you. And here, starting on line 16, it says, quote, "As set forth in table TLBR1 below, this 80% probability for large load customers means, among other things, that the counterparty has site control, both the system impact study and facility study have been completed, and the company is actively negotiating its IIA and ESA with the customer or has entered into an IIA ESA with the customer." Did I get that right?

Mr. Bailey: Yes, that is accurate from line 16 to 22. Great. So I want to ask you about the use of the words "among other things" in that quote. So when you say that, does that mean or are you referring to the other kind of criteria already listed in that table, or are you referring to other things that are not listed in the table at all?

Cynthia Vitali: Thank you. Yeah, I think it's important, you know, I did hear the questions that were given to Mr. Goodenough, so I appreciate allowing to clarify. So the first thing I would say is the site control is important, but I'd also point to, site control could be they own the land. That's very important. I think as we look at the percent at 50, and then moving on from the facility studies and the system impact study, other things, in my expert opinion, and what I've seen out in the markets, there could be an area where they have completed contract work for fiber upgrades, for black fiber, for fiber requirements at the site. It could be the fact that they've secured a water agreement. Again, those are areas that we watch, maybe on an ancillary side, but it's equally important. And we certainly want to make sure that we're working the customer. But that's how, as I, as I work through this and my team works through it, we consider in totality these 10 steps. We really prioritize is how we get that customer through the process and taking service from us.

Mr. Bailey: Okay, thanks. That's really helpful. And perhaps could we scroll back to page 30 again to the chart? Thank you. So I just heard you reference some things that I don't see on the chart in terms of water rights and fiber. So is it a fair characterization to say there are other criteria here that are not explicitly listed in this chart?

Cynthia Vitali: There's certainly other criteria that an end-use customer may be working through. And I use the data center example, but there may be other requirements for non-data center customers that we may not be tracking but certainly would be important to that site.

Mr. Bailey: Okay. Is there anywhere in your testimony or perhaps somewhere else in the record that lays out all of those other factors like fiber or water rights or anything else just so we can see and kind of get a sense of everything that the company might be looking at?

Cynthia Vitali: No, I don't believe there are.

Mr. Bailey: Okay, that's helpful. Thank you. And then sticking with this chart here, so is this meant to be additive? And what I mean by that? So if we take row 50, "land purchased," does that imply that everything in rows 10 through 40 has also been accomplished before you get to line 50?

Cynthia Vitali: Thank you for the question. It's a great question. And I would say, Miss Vitali, as we step through these processes, if a project, I'd like to, I'm kind of adding to, utilizing the synonym linear to additive as you go through this. I think it's important to denote that our expectation, how we manage projects, it would go in a linear basis. I'll give you an example where it hasn't, but it doesn't mean that it impedes the process. We had a customer come to us and said, "Hey, I've purchased the land. I own this 300-acre swath of land." And we're like, "That's great. We need to now do an interconnection submission. That's required. We need to, you know, execute the system impact study, and if amenable, we'll sign the NDA." So again, I think if you think about it in a linear process, in a perfect world, it would work that way. But I would just denote that once you get past 50 in the percent column, those other steps are critical as we work through this process, getting up to the 80, 90, and 100% threshold.

Mr. Bailey: Okay. So, and thanks for the correction of thinking about it in terms of being linear rather than additive. So are you saying that steps 10 through 50 are generally linear? Like, you know, if you to get to 20, you must have done 10 and so on through 50. Is that right?

Cynthia Vitali: I would say the linear would be step by step of getting to, like, the SIS completion, really 50 to 100 in my example, would be kind of the linear approach.

Mr. Bailey: Okay, got it. So it, so you're saying that perhaps steps 10 through 50 are not necessarily linear, but 50 through 100 are linear?

Cynthia Vitali: Yes. In my example, like the customer came in, they purchased the land, we would sit there and say, "Okay, in that definition, and it, and it compartmentalized, it would be at 50%. But we'd have to take a step back and submit the interconnect, execute the SIS, and if needed, an NDA."

Mr. Bailey: Okay, thank you. This is helpful. And I appreciate your patience walking me through this, just to make sure I'm super clear and we have it clear in the record. So, are you saying that after step 50, all the following ones, 60 through 100, those would have to happen in a linear fashion?

Cynthia Vitali: That is accurate.

Mr. Bailey: Okay, thank you. I appreciate that. And then, you know, maybe getting a little more into statistics here. So the table shows there are 10 steps a potential load would need before coming online. Is that right?

Cynthia Vitali: Yes, as depicted here.

Mr. Bailey: Okay. And then each step makes it 10% more likely that the project would actually come online?

Cynthia Vitali: Yes, as we defined.

Mr. Bailey: Okay. And Mr. Banis asked Mr. Goodenough this question. Has the company conducted a statistical analysis to reach the conclusion that each step makes it exactly 10% more likely that the project will be successful in coming online? So I'm now asking you that question. Has the company conducted such a statistical analysis?

Cynthia Vitali: Thank you. We have not completed a statistical analysis. And what I'd really dive into here, and I appreciate the question, excellent question, when we created this step process, we were internally really trying to dive into key project and stagegate management. And so prioritizing the top projects, as we've discussed, and then also making sure we weren't pushing projects ahead of a schedule that wasn't going to meet the needs of the utility and certainly the customer. And so, this is, I admittedly state, this is very granular. This is part of my experience over my 25 years, but also my team's experience and how we communicate across a matrix organization between our engineering team, our planning team, account management, finance, load forecasting. So we like where we are today, and certainly we work through this process accordingly to make sure projects get to the right percent to trigger the needs.

Mr. Bailey: Okay. Could we bring up hearing exhibit 408? And we're still sticking with the topic of the chart. Don't worry. Thank you. And could we just scroll down so we could see the sponsors? And thank you, that's perfect. Mr. Bailey, you're listed as one of the sponsors on this discovery response. Is that correct?

Cynthia Vitali: Yes, that is accurate.

Mr. Bailey: Okay. And so, I'll read the first sentence in the response in subpart B where it says, quote, "The assigned percentages are better interpreted as categories rather than specific probabilities." End quote. Did I get that right?

Cynthia Vitali: Yes.

Mr. Bailey: Okay. So is that, so based on what you just answered to the previous question about the lack of a statistical analysis, and then this response, is this a better way for us to be thinking about this chart, is that each, each row is kind of a category rather than necessarily a specific exact 10% denotation in that, in that question?

Cynthia Vitali: If that's helpful, I think if it's helpful to the parties to consider categories. What I don't want to lose is the importance of how we track these projects in the percent column. I mean, that is what's getting us to that 80 and 90 and 100% threshold. It's very important that we, that we follow it, as we describe and laid it up in a step-by-step basis.

Mr. Bailey: Okay, that's helpful. Thank you. And then kind of focusing on the 80 and 90% that you just brought up. So, again, this is a question that Mr. Banis asked of Mr. Goodenough last week. So now I'll ask you whether the company would be open to replacing the percentages with instead explicitly defined steps.

Cynthia Vitali: Can you be more specific in what you mean by specifically defined steps?

Mr. Bailey: Sure. And could we one more time bring back Mr. Bailey's rebuttal, just so we have the chart in front of us. Page, oh, perfect, there it is. Thank you. So instead of using percent, for example, 80% as the trigger, it would be that negotiations on an ESA or IIA are underway and that that would just be the trigger that everyone understands, instead of using 80%.

Cynthia Vitali: Thank you. I don't think I, and I, I won't think we can agree to that. I'd like, and we like how the 80 and 90 and 100% in this example are defined in the step process. As I mentioned earlier, I think it's really important to retain to this. Now, the title of the column, to your point, if it's, if it helps with clarity, may change. But we really want to stick to the importance of what we are doing and how we're executing these steps appropriately.

Mr. Bailey: Okay. And I think kind of calling back to our earlier discussion about the quote where you referenced other things, and then we talked about how there, you know, there are some things that your team would look at that are not listed in this chart. Would it be possible to revise the chart so that, especially for the 80, 90% triggers, which I, you know, I think are probably the most important ones in a lot of ways. It's, it's really clear what the whole universe of things would be that would constitute that 80 or 90% trigger?

Cynthia Vitali: Yeah, thank you. I don't agree with that premise, really based upon those examples I gave previously, maybe secondary or tertiary items that are required from other resources or other companies that Public Service, nor my team or other teams have control over. What I really, as we've laid out here, there are areas that we can really control and move forward with the process. And that's what we want to measure and that's what we want to make sure is placed into the requirements for the customers meeting each step.

Mr. Bailey: Okay. I think I think I got that one. Kind of follow up. So are you saying especially for the 80, 90, 100% that there, there wouldn't really be anything outside of what's already defined in this chart that would, that would be part of those triggers?

Cynthia Vitali: Yes, as my previous statement, I think these are the right steps that we are taking to ensure that customers are coming online appropriately as laid out here.

Mr. Bailey: Okay. Thank you. I really appreciate you walking me through that and answering a lot of questions on it.

Cynthia Vitali: You're very welcome. I think we are ready to move on to my next topic, which is interconnection agreements. And I know the company just introduced hearing exhibit 138, the interconnection agreement template earlier this afternoon. We haven't had a time to do, had the time to do a, you know, real full review of it. So I'm going to try and ask you a couple clarifying questions right now. And I don't think we need to bring it up, but I might ask for it at some point. So would all large loads that connect at the transmission level require an interconnection agreement?

Mr. Bailey: Thank you. And I'll work to answer your questions to the best of my ability. I know Mr. Martz also oversees the signatures of the interconnection agreement, so I may kick to him. But for a large load customer and the customers that we have on the system and then we're working through in our, the large loads over 100 megawatts, yes, they would have an interconnect agreement signed at the transmission level.

Cynthia Vitali: Okay. And just to be super clear, so that it would just be loads over 100 megawatts that are connecting at the transmission level, those would all require an interconnection agreement.

Mr. Bailey: They would. I don't want to, I took your question as, I'm sorry, the large loads over 100 megawatts. You could have a customer who's at the transmission level below 100 megawatts, who would have a transmission interconnect agreement.

Cynthia Vitali: Okay. Yes, I think you interpreted that question correctly. That's what I was trying to ask. And then would all large loads that connect at the distribution level require an interconnection agreement?

Mr. Bailey: My understanding, and Mr. Martz may, you know, I would ask you to ask him this question. I think there's an agreement at a distribution level that is different than a transmission defined interconnection agreement.

Cynthia Vitali: Okay. So, so you're saying they would sign a different agreement than what? If it's, if it's applicable to the, to the distribution level and the requirement to come online, I'm just not as familiar at the distribution level if that's handled in a tariff with, with just a tariff document that's already filed. It's just not, it not in my core, core area. I apologize.

Mr. Bailey: No, no problem at all.

Cynthia Vitali: So it sounds like we should ask Mr. Martz about this question, and he might be able to help us.

Mr. Bailey: Yes, on that differentiation, that'd be great.

Cynthia Vitali: Okay, got it. Well, we do have time with him. So that is great. And let me just take a quick look. That's all I have for you today, Mr. Bailey. Thank you very much.

Mr. Bailey: Thank you. Good to see you.

Cynthia Vitali: Thank you, Miss Vitali.

Eric Blank (Chair): Mr. Barroso, I have 30 minutes, of which I think some of that is confidential session.

Parks Barroso: Yes, thank you. That is correct, Chair. Good afternoon, Mr. Bailey.

Mr. Bailey: Good afternoon, sir. How are you?

Parks Barroso: I'm well, thank you. And for the record, my name is Parks Barroso, and I'm representing Deborah and Sweep. Mr. Bailey, I'd like to start by talking with you about the company's large load strategy. And you've already discussed the large load principles with counsel for several parties, but let's still go there. So in rebuttal, you stated that the intent of those principles is to ensure that new large load customers have, quote, "skin in the game" to avoid the risk of procuring generation for speculative new load or procuring load for customers that may move projects to different jurisdictions or disappear altogether. Do you recall that?

Mr. Bailey: I do. Yes, thank you.

Parks Barroso: And based on those statements, you agree then that there is a risk in a situation where the company procures generation for a customer who then moves their project to a different jurisdiction?

Mr. Bailey: In your example, have they, has that customer signed an ESA under these commercial principles I laid out?

Parks Barroso: My example wasn't being that specific. I was just referring to the words from your testimony. Generally speaking, is there a risk if generation is procured for a customer who then moves their project to a different jurisdiction?

Mr. Bailey: Thank you. I'll point to my testimony under the commercial principles. Obviously, we've laid out significant, enumerated principles here. We're working with customers now, and I think in your example, I would draw myself to exit fee provisions that we're discussing. Mitigating risk and how we are incorporating not only the exit fees but the contract minimums, the contract term are going to be very important. As I stated earlier, I can't guarantee or mitigate all risk, but what we are doing here, not only incorporating the commercial principles but matching the customers to the ESA requirements in this interim period, is going to be very important to answer your question to mitigating that risk.

Parks Barroso: I appreciate that, Mr. Bailey. I think what I'm asking then is, the principles are a way to mitigate that risk, and that risk, one of those risks is, for example, procuring generation for a customer that then withdraws or moves to a different jurisdiction?

Mr. Bailey: Well, not only these customers, but, you know, utilities deal with that risk of customers leaving the rate base each year. I would point back to a previous statement I made about the question about having generation on the system. We have significant growth opportunities in Public Service. I don't really, I've got limited time, so I'm going to move on.

Parks Barroso: I believe you've stated this in prior discussion with counsel, but those large load commercial principles are not binding, correct?

Mr. Bailey: They are not currently in a form ESA.

Parks Barroso: We are working in this interim period to negotiate these principles, retain our commercial flexibility in the interim period, and obviously we've agreed to the large load tariff filing in January of 2026. Yes, thank you. And between now and the tariff filing in 2026, would the company be providing the commission or parties with copies of ESAs or IIAs once they've been executed with a particular customer?

Mr. Bailey: We have not made that commitment. And so we've just talked through the fact that the principles are not binding, at least for the interim period until 2026. And the company's not made the commitment to provide those executed contracts. I guess my question is, how will the commission or parties know the extent to which any of those principles are actually reflected in a contractual agreement with any given customer?

Parks Barroso: Yeah, thank you for the question. Let me, let me take a step back. And I think it's really important, you know, as we've denoted in the updated base forecast, we've got nine important customers that we've, we've asked for approval in the Phase 1 approach. All of those customers except one, we have an ESA with. So as we're incorporating these commercial principles, I can tell you that we are having those discussions verbally and placing in those commercial principles. And so we are doing that diligently because one, the customer wants to sign an agreement, but two, in signing that agreement, they need the certainty of the generation plan and what we've laid out in the Phase 1 and the Phase 2 approach.

Parks Barroso: Thank you, Mr. Bailey. I don't think that answers the question I asked, which is, to what extent or how will the commission know how many of those commercial principles are actually being reflected in those contracts? I think my understanding is that because those principles are currently negotiable, it could be one, it could be all, it could be some that actually make it into the contract.

Mr. Bailey: Well, again, I go back, we're maintaining the flexibility. I think it's important to denote those customers over 100 megawatts, our intent and our purpose is to implement these commercial principles. That is where we are today, and I can tell you we are doing that right now.

Parks Barroso: Okay. And I apologize for asking the same question, but there's no way that the commission will know the extent to which those principles will be in the contracts under the company's proposal, is that correct?

Mr. Bailey: I believe as I previously stated, we are not asking for submission or approval of those contracts.

Mr. Barasa: And to clear something up because I wasn't clear on this, Mr. Bailey, to the extent that those principles are in the contract, would that be in the ESA or would that be in the IIA?

Mr. Bailey: Those would be in the ESA. In the ESA.

Mr. Barasa: Thank you. And so I think you discussed this previously with counsel, but in the probability framework, a customer is considered 90% probability if they've signed either an ESA or an IIA. Is that correct?

Mr. Bailey: Yes, that is accurate.

Mr. Barasa: And so isn't it then possible that a customer could have signed an IIA, be assigned a 90% probability, but then because they have not signed an ESA, they have not committed to any of the large load principles at that point in time?

Mr. Bailey: I don't agree with that, and I will give you maybe a couple of examples. One, customers who have signed an IIA, and we actually have a customer today who has signed an IIA, who's contributed a significant amount of dollars that are at risk, and they're at risk. So that is one of the areas where you would assign kind of the securitization of the commercial principles in your example. The second area is, as they move to the ESA, the incorporated principles, as we've negotiated, they have openly and want to sign that ESA. So I'm not going to agree that they haven't incorporated any of them, but they understand that they have at-risk dollars for upgraded transmission line, substation equipment, switching station, etcetera, or have provided securitization, which is one of the requirements in the commercial principles that I outlined.

Mr. Barasa: Thank you. So to clarify then, there are some commercial principles that can be effectuated through signing an IIA. Is that what you're saying now?

Mr. Bailey: Well, what I'm saying, I don't want to conflate the two because they're still going to have to sign an ESA that will outline it. But some of the requirements of signing an IIA is a stage-gate approach where they're providing upfront dollars for us to procure equipment. And that again, that stage-gate approach may have securitization, may have letters of credit or cash requirements upfront. I'm just denoting that that is a core principle that we're utilizing today, but also needs to be updated in the ESAs as we move forward, and we're committed to do that.

Mr. Barasa: Okay, thank you for that. Let's switch gears now to talk about the load forecast. In your public rebuttal testimony, you discussed Customer B, which was a large load customer with over 90% probability, who withdrew their interconnection requests after the company had filed its direct case. Do you remember that?

Mr. Bailey: Yes, I do.

Mr. Barasa: And I'm paraphrasing here, and we can pull up your testimony if it's helpful, but you discuss how interveners point to this as an example of large loads being speculative or uncertain. But your argument, or the company's argument, is that the entire reason the customer withdrew was due to a lack of certainty. Does that sound right?

Mr. Bailey: Yes, that is accurate.

Mr. Barasa: And, great. Thank you. When the company began discussions with that Customer B, did you inform that customer of the existing Colorado resource planning process and what to expect in terms of timing for interconnection?

Mr. Bailey: They were well aware of the process for the interconnection agreement, also the ESA agreement. I will be very clear, I don't consider some of the feedback as speculative because they would infer conjecture as we're working through. And as we've outlined these customers, I've met with this customer, I've met with them several times. Their concern, as we have dictated in some of our problem statements, is if you can get us to X amount of megawatts in 2027 and 2028 of generation, we will sign that ESA. Where we, what we couldn't guarantee that and we couldn't show a process forward as we've discussed in the Phase One and Phase Two approach, they couldn't then make a decision because they had land control. They had the SIS complete. We were moving quickly, and so that was the reason, and the core message they gave me was all about the generation plan and the timing of that certainty.

Mr. Barasa: Okay, Mr. Bailey, has anything changed with Colorado's resource planning process from the time that you'd begun discussions with that Customer B and that customer withdrawing their interconnection request?

Mr. Bailey: Could you clarify? I didn't quite understand the question.

Mr. Barasa: Sure. So you mentioned earlier in your answer that the customer was well aware of the process when you began discussions with them. Has anything changed with Colorado's resource planning process since the time that you initiated discussions?

Miss Shields: Objection. It calls for a legal conclusion and speculation. Mr. Bailey is not an attorney, nor is he a resource planning expert. Overall, keep going, Mr. Barasa. Mr. Bailey.

Formatted Transcript (Part 2 of 5)

Mr. Bailey: Yes, that'd be great. Could you please repeat the question?

Mr. Barasa: Sure. So in your response earlier, you mentioned that the customer was well aware of the process when you began discussions with them. And my question to you was, has anything changed with Colorado's resource planning process since those discussions began?

Mr. Bailey: Again, I'm not a resource planner, but I would just denote the tri-party agreement and what we're agreeing to within this process to get new resources online, to get certainty, have an incremental need pool, and an opportunity for supplemental RFP was all very important at that time.

Mr. Barasa: Okay. I guess what I'm getting at here is, is it correct that this Customer B, they got to 90% probability, meaning they signed either an IIA or an ESA, with full knowledge of how Colorado's process works related to when generation can and will come online? Correct?

Mr. Bailey: They're certainly aware of the timing. They're also very aware that utilities and parties were working together and trying to work together to expedite that process. But again, if I can't give certainty and provide certainty because it hasn't been approved, I'm not going to enter into an ESA with a customer with a lack of generation in the timeframe they need.

Mr. Barasa: And when you were communicating the process with this customer or with other customers, were you also indicating the company's current capacity position? In other words, the fact that the company is not currently capacity long?

Mr. Bailey: They were certainly aware of the dynamics of that, and I would also denote that the customer has the option to come back into our project pipeline, and they may one day. We continue those discussions. They're a key partner and a key customer in other locations.

Mr. Barasa: Thank you. And a clarifying question here because I'm not sure the answer. In terms of negotiations with prospective customers, at what point in time do they receive the total estimated cost for receiving and initiating service? Is that once you're in negotiations over an ESA and IIA? Is it at some point sooner in the process?

Mr. Bailey: Thank you. Just to clarify, are you, I just want to make sure we're discussing the interconnection of like a transmission and a substation? Is that your question?

Mr. Barasa: Correct.

Mr. Bailey: So they will receive those preliminary numbers as you go into the facility study, and then they are outlined in the interconnect agreement, and then there's a, there's obviously a true-up mechanism.

Mr. Barasa: Great, thank you. That is very helpful. Changing topics here a little bit, Mr. Bailey, in your rebuttal testimony, you'd included a question and answer on trends in other jurisdictions with respect to commercial provisions that utilities are implementing to promote certainty. Do you remember that?

Mr. Bailey: I do.

Mr. Barasa: And we can pull up your testimony if it's helpful. Who was at page 45? But is it fair to say that you keep up to date with trends across the country in terms of other utilities that are seeking to serve demand from new large customers?

Mr. Bailey: We do, and I have counterparts in other utilities where we discuss those opportunities. And it could be a topic at EEI or NEOUK as an example. I will denote that there are obviously nuances based upon the jurisdiction, and the utility, and the position of generation or transmission. And so there's not a one-size-fits-all in that accord. So I think we take information and we absorb that, educate ourselves, and then utilize where appropriate, but also I think really dictating the importance of how we're bringing new customers on the system is how we are working through that process.

Mr. Barasa: Okay. Are you aware that some utilities across the country, in response to data center interconnection requests, have sought to modify their transmission and distribution line extension tariffs?

Mr. Bailey: I am not familiar with that at that detail.

Mr. Barasa: Okay. Would it surprise you if I represented that other utilities that are modifying or have sought to modify their extension policies have done so out of a recognition that line extension costs were being passed through to all ratepayers in order to connect large customers like data centers?

Mr. Bailey: Subject to check. I won't disagree with that.

Mr. Barasa: And in the company's 2026 tariff filing that we discussed previously, do you anticipate that changing the company's line extension tariffs or policies would be part of that filing?

Mr. Bailey: I'm not aware of that filing, and I would just denote that in our current interconnect agreement for transmission customers, we denote the requirement for those dedicated assets to be paid upfront by those transmission customers.

Mr. Barasa: Last line of questions for you here, Mr. Bailey. I'd like to discuss that category of large load customers that we're now referring to as strategic economic development customers.

Mr. Bailey: Thank you.

Mr. Barasa: Sure. I couldn't find a definition in the company's testimony. Do you have a definition for us of what should be considered a strategic economic development customer?

Mr. Bailey: Yes, thank you. As I point out in my testimony, and as denoted in the schedule, those five customers are current customers. They employ or will employ thousands of employees, contribute to the tax base. They are creating products that everyone on this call is aware of. They are very important to the local economy and are taking service from public service now.

Mr. Barasa: So just picking up on the first part of that, does that mean a customer must be a current customer in order to be a strategic economic development customer?

Mr. Bailey: No, I wouldn't define it that way.

Mr. Barasa: Has the company developed any metrics or parameters to define or classify a new large customer as a strategic economic development customer?

Mr. Bailey: We don't have specific definitions. I would just point to the fact that these are very important customers to the Colorado economy who have significant local, regional, and state support. And so we take that very seriously. We have a duty and obligation to serve them, and that's our expectation as we move forward in this request.

Mr. Barasa: And I guess you might disagree with this, but is one way to define this customer group without metrics or parameters as any large load customer that is not a data center but that the company deems important to the Colorado economy?

Mr. Bailey: I don't, I won't agree to that because I think it puts it into a box for future restrictions. Again, I think as we've denoted in my testimony and in my response, I just think they're very important, and we have an obligation to serve as they requested our service.

Mr. Barasa: Okay. So maybe not putting it in a box then, it's possible that any new large customer who is not a data center could be considered a strategic economic development customer. Is that a fair characterization?

Formatted Transcript (Part 3 of 5)

Mr. Bailey: That is possible.

Mr. Barasa: Okay. And regarding the Phase 2 framework or the tri-party framework, and specifically the incremental need pool, could the company activate that incremental need pool for strategic economic development customers again in the future if they hit the 80% or the 90% requirements as it's defined?

Mr. Bailey: Okay. Thank you. That was my clarifying question. Is in that process, the 80% or 90% does apply to strategic economic development customers in the future? Yes, as we've discussed previously, and in the future meaning in the incremental need pool. Correct, as defined in the tri-party agreement.

Mr. Barasa: Thank you, Mr. Bailey. Those are all of the public questions I have for you. Thank you for your time.

Mr. Bailey: Thank you, appreciate your time.

Chairman Eric Blank: I got you like six or eight minutes left for confidential, Mr. Barasa. Let's see, I got UCA 60 minutes not including some confidential time. Mr. Bunker, it's 3:36. Yes, thank you.

Mr. Bunker: Thank you, Mr. Chairman. And yes, just to clarify, a couple of the witnesses that we waived cross on, I moved that time over for the highly confidential time. So thank you for that lenience. I appreciate it.

Chairman Eric Blank: All right. Mr. Bailey, good afternoon, good to see you again.

Mr. Bailey: Mr. Bunker, great to see you again. How are you?

Mr. Bunker: I am well, thank you. Hope you are also well.

Mr. Bailey: I am. I appreciate it. Good. Let's start with a little background here if we could. Your Hearing Exhibit 107 is your direct testimony. And on page five, you indicate, and I'll wait until it's pulled up. Thank you. On page five, at lines four through six here, you indicate your testimony supports the company's JTS base case planning forecast for Public Service Company's large customer load forecast. Is that correct?

Mr. Bailey: Yes, lines 4 through 6, which you quoted.

Mr. Bunker: Right. And on lines 10 through 11 on that page here, you indicate your direct testimony explains how the company developed that new customer load growth forecast. Is that right?

Mr. Bailey: Yes, that's accurate.

Mr. Bunker: Yeah. Then on lines 11 through 14, you state your team is responsible for attracting and working with prospective large load customers. So is it correct to interpret that as your group not only tries to attract these kinds of customers, but you negotiate the contracts with them? Would that be accurate?

Mr. Bailey: That is accurate. I would just offer some addition. My team is not the only one at that table negotiating. We have a matrix organization where we have support internally to ensure we have proper negotiation standards and governance.

Mr. Bunker: Sure. Thank you for that clarification. I think the point I was getting at is you're pretty familiar with the contracting function with regard to these new customers, right?

Mr. Bailey: Yes, I am.

Mr. Bunker: Okay. And as you'll recall from your 2023 Economic Development Rate or EDR case in 23A 03303E, you were the company's lead witness in that EDR case, right?

Mr. Bailey: Yes, that is accurate.

Mr. Bunker: And in your public rebuttal testimony, on page 52, this is Hearing Exhibit 123, your rebuttal testimony, there at the bottom of page 52, on lines 15 through 19 here, you discussed that 2023 EDR case, and that was an application case involving a non-standard EDR agreement for a company called QTS, and that involved a large data center campus in Aurora, Colorado. Right?

Mr. Bailey: Yes, that is accurate.

Mr. Bunker: And can you confirm one of the differences between a standard EDR agreement and the non-standard EDR agreement is that a standard EDR agreement is for a new load of between 3 and 20 megawatts, and a non-standard EDR agreement is required for a new load of 20 megawatts or more? Is that correct?

Mr. Bailey: Correct. That's one of the provisions in the statute that's required.

Mr. Bunker: Okay. Thank you for that. And if you'll think back to the Public Service Company QTS EDR case in 2023, that case involved two separate agreements: an EDR Electric Service Agreement, or an ESA, and a Transmission Facilities Construction Service Agreement, a TSA. Is that right?

Mr. Bailey: Yes, I believe that's accurate.

Mr. Bunker: Okay. And a non-standard EDR contract was required for QTS because the load was expected to reach an average estimated total load of approximately 160 megawatts at full capacity. Right?

Mr. Bailey: Subject to check, I believe that's accurate.

Mr. Bunker: Okay. And the Transmission Facilities Construction Service Agreement, the second agreement we're talking about, under that agreement QTS would pay the company to construct and operate approximately 1.4 miles of dedicated double circuit 230 kilovolt transmission line and associated transmission facilities. Correct?

Mr. Bailey: Yes, they were required to pay that as I previously discussed in a stage-gate process that was outlined.

Formatted Transcript (Part 4 of 5)

Mr. Bunker: Okay, so given that Public Service does not currently have an approved large load tariff, is it correct then that the contractual relationship between Public Service Company and a new large load customer currently would be one of two sets of contracts? And that is a combination of an EDR agreement and a transmission facilities construction agreement, such as was the case with QTS, or the second option would be the Electric Service Agreement, the ESA, and the interconnection agreement, which you just spoke with some of my co-counsel or fellow counsel about. Is that right?

Mr. Bailey: Yes, with, I just want to be very clear, the relationship with the end-use customer will be with both the IIA and the ESA. IIA stipulating the infrastructure agreement, the ESA stipulating the electric or energy service agreement.

Mr. Bunker: Right. So I know my question was a little long, but it would either be the EDR situation like QTS has, or it would be the Electric Service Agreement and Interconnection Agreement, which you were just cross-examined about by the last couple of counsel. Is that right?

Mr. Bailey: With the challenge, and I'd point to my rebuttal testimony, and we've been very clear about not utilizing and not extending the EDR as we've done previously with QTS. So I would only stipulate to the fact that they would have an ESA and an interconnect agreement at full tariff rates.

Mr. Bunker: Okay. So that actually gets to my next question, and that is, I take it you were listening to Mr. Ihle's testimony last week, and he indicated that with regard to large load demands, the company intends to stop offering new discounted or economic development rates. Is that right?

Mr. Bailey: Yes, I believe that's a paraphrase of his expectation and certainly mine in my testimony.

Mr. Bunker: Okay. So is it correct that Public Service currently has a total of two EDR customers, and that is Pepsi under a standard EDR agreement and QTS under a non-standard EDR agreement?

Miss Shields: Excuse me, I'd like to just voice an objection that I'm concerned that we may have been starting to disclose some highly confidential information related to some of these customers. The company is open to going back and reviewing the record to confirm that, in which case we may seek to strike from the record or at least mark as highly confidential some from the record. That would include individual customer loads, as well as certain customer names. The company again, like I said, we're willing to go back and confirm whether or not some of that information is highly confidential, but I do just want to voice a preliminary objection that we have some concerns.

Chairman Eric Blank: Mr. Bunker, can you confirm that your questions aren't highly confidential or even confidential?

Mr. Bunker: I don't think they are. I know the QTS stuff wasn't. No, it isn't. And if you look at the application of the QTS application on pages 2 and 5, you'll see some of the information I just asked about in the application in that case in 2023. Pepsi is, as far as I know, a standard EDR agreement customer under the Commission approved tariff. If that sounds right to me, Miss Shields, I'm very familiar with the QTS record, and that is public. So, keep an eye out, but keep going, Mr. Bunker.

Mr. Bunker: Okay, thank you. Kind of to go full circle on, to just finish up this topic, since the EDR agreements will no longer be offered, if a large load customer approaches Public Service regarding a new large load service agreement at this time, and there's no large load tariff in place at this time, is it correct then that the combination of the Electric Service Agreement, the ESA, and an Interconnection Agreement, the IIA, are the contracts the company will use to negotiate between Public Service and a new large load customer?

Mr. Bailey: Yes, with the, with the, pointed to my rebuttal testimony on the commercial principles that I've outlined in this interim period that we're working towards. I do want to make sure that we're very clear about one item. While we are not currently, and again, to Mr. Ihle's point and to mine, extending an offer for the EDR, we're not taking that out of our tariff book as an opportunity. But again, we, as we've stated, we're governing that process. Certainly, we have a requirement that, and the Commission has a requirement for due diligence there. But I just want to be very clear about that.

Mr. Bunker: Thank you for that clarification. And I think if I understand what you've just alluded to, the EDR tariff will still be in place in the tariff book, but when it comes to large load customers between now and the time the large load tariff is approved by the Commission, Public Service would really exclusively utilize the ESA and the IIA contracts for a large load customer. Is that a fair assessment?

Mr. Bailey: Certainly, Mr. Bunker, that's our intent and that's our expectations outlined. What I don't want to do is give a perception of any type of guarantee. I've been in this business a long time, and while we may not extend based on macro requirements of an incentive in any EDR, there may be other situations where we potentially could be dictated to or a requirement at another level to engage in an EDR negotiation.

Mr. Bunker: Thank you for that. And as you maybe recall, at the beginning of today's hearing, Public Service introduced Exhibits 137 and 138 as hearing exhibits, and these are copies of what was referred to as the model ESA and IIA agreements. Did you happen to hear that?

Mr. Bailey: I did hear that submission. Thank you.

Mr. Bunker: Okay. So when, and I'll admit I have not had a chance to fully review either of these two agreements, but is it fair to say, based on your testimony, that the ESA and the IIA are, if you will, template starting points for negotiations and they may be modified? In other words, it's not a kind of a take it or leave it, sign this agreement, but rather that it could be modified. Is that accurate based on your testimony?

Mr. Bailey: Yeah, with one condition. And again, you may ask this question, Mr. Marts, on the IIA. From my background and my experience with IIAs, they're certainly more formatted to the infrastructure. And so when you talk about a negotiation, I wouldn't be as familiar with those negotiations outside of defining a stage-gate payment. On the ESA, yes, that to your point, that is the form, and again, as I discussed and testified earlier, utilizing the common principles that will be placed into that ESA as we work forward with new customers in the interim period.

Mr. Bunker: Okay. And the commercial principles that you have discussed with Mr. Barasa and I, and I believe perhaps other counsel during your cross-examination, the commercial principles, would those be things that are included already in the ESA IIA or would those be negotiated terms that are included in the final documents to be signed?

Mr. Bailey: The latter. Those are expectations, and as I've previously stated, what we are working through today and our intent is to have those commercial principles in the agreements until the large load tariff is filed.

Mr. Bunker: Okay. So in order for the Commission or the other parties in this case to know what is in the final draft of an ESA or an IIA, it would require that the Commission and the parties be able to see a copy of it, right? For them to view it?

Mr. Bailey: Yes, to see a copy. Again, I'd go back to my testimony, we're not requesting or asking for a requirement to file these for review and or approval.

Mr. Bunker: Okay, but of course, if the Commission directed you to file them, you would, right?

Mr. Bailey: Yes.

Mr. Bunker: Okay, thank you. If we could now move to Hearing Exhibit 2606, and this is Attachment SJD-9. And as this document's being pulled up, Mr. Bailey, this is the Staff Public Service CIA JTS Phase 2 Framework document. I think you indicated you're familiar with this, right?

Mr. Bailey: Yes, I am. I believe I reference it as a tri-party framework.

Mr. Bunker: Okay. And so if we could go to page four, and at the bottom of the document, it's Section 7, the large load principles and tariff filing section of this four-page document. The second sentence in Section 7 includes the following statement: "The company will make a large load tariff filing no later than January 31, 2026." Is that right?

Mr. Bailey: Yes, starting with "In addition," correct.

Mr. Bunker: And is it your understanding during Mr. Ihle's testimony last week, he confirmed Public Service Company now intends to file the large load tariff by January 31st, 2026?

Mr. Bailey: Yes, I'm aware of that.

Mr. Bunker: Okay. Focusing on the first sentence in that Section 7, and here it says, "Staff, the company, and CIA agree that the company will use the large load principles listed in Table TLB-R2 described in the rebuttal testimony of Thomas Bailey." And my question for you, sir, is, what do you interpret, interpret using the large load principles listed in your rebuttal Table B-R2, what do you, what do you interpret that to mean?

Mr. Bailey: I don't know if I agree with interpretation. I would just state that what is, what is in this framework, we will utilize the large load principles as I've listed in TLB-R2. I believe it's pretty straightforward.

Formatted Transcript (Part 5 of 5)

Mr. Bunker: Okay. Let's look for a moment, just to bring this around so that we're all on the same page here. This would be a rebuttal testimony, Exhibit 123. And I don't recall where your Table Two in your rebuttal testimony is. I know there's one on page 30, but I don't recall if that was Table One or Two.

Mr. Bailey: Page 40.

Mr. Bunker: Page 40. Thank you, sir. You know your testimony well.

Mr. Bailey: I appreciate it. Yes, sir.

Mr. Bunker: All right. Table Two, this is the summary of the large load commercial principles. Okay. So as we can see, there are a number of commercial principles and the summary, and it goes on to the top of page 41. So there's a handful of roughly 10 criteria or principles, and then a summary that in some cases is a few words, in other places it's multiple sentences. Right? So going back to what it states in Section 7 of this, what you recall, the three-party or the tri-party framework, and it says that the company will use the large load principles listed in this table, Table Two. What you're saying there is that the sum, the total, if you will, of these various principles will all be things that are intended to be covered within the tariff filing?

Mr. Bailey: Yes, I, you know, discussion with the commercial principles in the left-hand column. Obviously, the tri-party agreement doesn't stipulate the summary. There's going to be stakeholders which we've agreed to engage, and certainly interveners. So the commercial principles as laid out is the expectation in the tri-party agreement.

Mr. Bunker: Okay, thank you for that. So the large load tariff will replace using the non-standard EDR agreement of over 20 megawatts and the Transmission Facility Construction Service Agreement for a large load customer. Is that right?

Mr. Bailey: I don't believe that's accurate. As you stated on the EDR, again, I think depending on the outcome of the large load tariff, there may be iterations placed in from other contracts, but I don't know if it quote-unquote takes the place of an EDR non-standard agreement. I can't, I just don't have that knowledge right now.

Mr. Bunker: Well, let me be kind of candid here. Where I'm going with this is that after the large load tariff is approved by the Commission, the use of a non-standard EDR agreement for over 20 megawatts and the use of the Electric Service Agreement and the Interconnection Agreement that are currently being used, those would all be replaced by the tariff, the large load tariff. Would you agree with that?

Mr. Bailey: Again, not knowing how the structure of the large load tariff will be finalized, I don't know if I can agree to that. Certainly, there are expectations that the large load tariff will govern these commercial principles and certainly the expectation of customers over 100 megawatts. In your example there, you know, there's an EDR non-standard. There's a delta there between 20 and 100 megawatts, so I can't sit here today and say that is going to overtake that.

Mr. Bunker: Okay. But for a large load customer, you wouldn't be offering an EDR contract. So does the fact that it's between 20 and 100 megawatts, is that a, is that a difference when it is a large load customer?

Mr. Bailey: Yeah, I don't think I have that. We've agreed that, again, I'm not going to get into a corner saying we won't offer an EDR. I haven't stipulated that. I'm just saying that at this time, we're not extending incentive rates or EDR rates. Again, that can and could change into the future.

Mr. Bunker: Okay. At what point in time will Public Service move large load customers from their combination EDR and Transmission Facilities Construction Agreement or their combination ESA and IIA to the Commission-approved large load tariff?

Mr. Bailey: I believe our expectation is that the tariff would be for future customers taking this service as a requirement over 100 megawatts. Once that is approved, we are not asking for, requesting a grandfather of current customers over 100 megawatts.

Mr. Bunker: I'm sorry. So you are or are not asking for a grandfathering of existing contracts once the large load tariff is in place? I missed that, I'm sorry.

Mr. Bailey: We are not asking for a grandfather of customers over 100 megawatts as looking at the load and threshold applicability, be new or expanded load of 100 megawatts or more in your example of a large load tariff that is approved at say the end of 2026 or early 2027.

Mr. Bunker: Okay. We could go to your rebuttal testimony again. This is hearing Exhibit 123. And starting at the bottom of page five, and here on line eight, you talk about the three-prong strategy called the large load strategy. Is that right?

Mr. Bailey: I'm sorry, can you show, were you, did you state line eight?

Mr. Bunker: No, I said, yes, I said line eight on page five. Okay. And I'm sorry, can you restate your question there? I think it's 18.

Mr. Bailey: Ah, you are correct. Thank you, sir.

Mr. Bunker: You're very welcome. I appreciate it. So on line 18, you state support for Public Service's three-prong strategy, which you refer to as the large. Mr. Bunker, I apologize. I think you froze for a couple seconds. On line 8 on page five, or line 18, I'm sorry, you refer to a three-prong strategy, and you also talk about the large load strategy.

Mr. Bailey: I do. To your question, there was an intermittent period where you were frozen. I just want to make sure I heard the entire question. And Mr. Chairman, and Mr. Bailey, I've noticed while I'm looking at my screen, it says internet connectivity is, well, it went away, but it was shaky or something like that. So if I lose you, or I freeze, I apologize in advance.

Chairman Eric Blank: We can hear and see you clearly now, so you're good.

Mr. Bunker: Excellent. Thank you. And Mr. Bailey, on line 20 here, you talk about the first prong of this large load strategy, and it would be the two RFP process and the creation of an incremental need pool and/or a new large load tariff. Correct?

Mr. Bailey: Yes, lines 18 through 23.

Mr. Bunker: Okay. And I'd like to focus on the tariff. And if we could scoot to page 25 of this document, and at lines 20 to 22, and in your footnote 27, you indicate parties recommend a variety of additional processes, which include directing the company to file a large load and/or clean transition tariff. Right?

Mr. Bailey: Yes, lines 20, 21, and 22.

Mr. Bunker: And on page 25, footnote 27, here you referenced the answer testimony of UCA witness Dr. Scott England, and the answer testimony of Andy Eden, who I believe is a WR witness. Is that right?

Mr. Bailey: Yes.

Mr. Bunker: And do you recall Dr. England recommending the Commission should order the filing of a new large load tariff applicable to data centers and other like new customers with ratepayer safeguards to protect against cross-subsidization and potential stranded assets?

Mr. Bailey: Subject to check, I trust your overview.

Mr. Bunker: Okay. And as we discussed a few minutes ago, Public Service is committed to filing a large load tariff by January 31, 2026. And this is a change from your rebuttal testimony statements concerning a large load tariff filing by the end of 2026, or alternatively, the filing of a notice in this proceeding explaining why a new large load tariff is not appropriate. Is that right?

Mr. Bailey: Yes, that's accurate, as stipulated in the tri-party agreement.

Mr. Bunker: Okay. And if we could move to page 45 of your rebuttal testimony, and starting at line 14 and continuing on to page 47, at line five here, in this about two and a half pages of testimony, you discuss trends a company is seeing in other jurisdictions with regard to commercial provisions that utilities are implementing to promote certainty with respect to large load customers. Is that right?

Mr. Bailey: Yes, beginning on line 45, through the middle of, or through line 46, page 46. Yes, page 45, 14, on to 46. Yes.

Mr. Bunker: And, yeah, and on page 46, at lines 5 to 12, and in your footnote 40 here, you cite the Indiana Utility Regulatory Commission order that approved a large load tariff, and you provide a hyperlink to that case in footnote 40. Is that right?

Mr. Bailey: Yes, that is accurate. Thank you for scrolling.

Mr. Bunker: And are you aware UCA files surrebuttal comments in this case?

Mr. Bailey: I am.

Mr. Bunker: Okay. If we could pull up Hearing Exhibit 308. This is the exhibit that has a bunch of things titled 308. So which, what's the actual title of it? Okay, this would be Hearing Exhibit 308, UCA Surrebuttal Comments. Okay. And then there will be three documents, Attachments One, Two, and Three, and there two affidavits. I do not need any of those five documents right now, just the comments. The comments are Attachments One, Attachment Two, Attachment Three. They're all three separate. Right? I do not need that. I just need the UCA Surrebuttal Comments. Okay. It's a 15-page document if that's what you happen to be looking at.

Mr. Bailey: Yep, that is it. Thank you.

Mr. Bunker: And if we could go to page four, and here on page four, you'll see that with regard to large load tariffs, that the UCA's proposals, and you'll see this in the first two lines of that paragraph above the table, that the UCA's proposals are primarily guided by the large load tariffs approved by the Indiana and Wyoming Commissions. Is that right?

Mr. Bailey: Yes, I see that with the comment. Yep.

Mr. Bunker: And then you'll see in Footnote 12 at the bottom, we've attached for the Commission's benefit, as well as the parties, the Indiana and Wyoming tariffs are Attachments One and Two. And you'll see that in Footnote 12. And then also in Footnote 13, you'll see a copy of the Missouri tariff. And going back to the narrative just above the table, you'll see that the UCA attaches a Missouri tariff which requires Every Missouri Metro to track revenues and expenses related to large load customers to ensure that each customer is paying its fair share. It is part of the rate-setting process. Do you see that?

Mr. Bailey: I do. I have not reviewed the Missouri findings, but I take that as the report.

Mr. Bunker: Okay. And obviously, you cited the Indiana tariff, and it sounds like you're familiar with the Wyoming tariff. Is that right?

Mr. Bailey: Somewhat. I'm more familiar with the Indiana tariff based on some of my counterparties' involvement. I believe that was one of the first tariffs filed and then completed in settlement.

Mr. Bunker: Okay. And would you agree, Mr. Bailey, that the Commission-approved tariffs in Indiana, Wyoming, and Missouri are examples that would provide a good starting point with regard to a large load tariff and its terms and conditions for this Commission, the parties, and for Public Service with regard to this January 1 or January 31, 2026 filing?

Miss Shields: Objection. To the extent that Mr. Bunker is asking the witness to call for the truth of the matter asserted therein, these various documents, these various other proceedings. He's already indicated that he's not familiar intimately with each and every one of these specific tariffs. This is also similarly coming from the direct testimony of his own witness who has the ability to be put on the stand and subject to cross-examination. And I'd further object as counsel to the proposition for which Evergy Missouri Metro special high load factor market rate schedule stands for within the reference testimony. Mr. Bunker, I'm asking the witness, Mr. Chairman, whether these are three examples that might be used for the drafting of a large load tariff.

Chairman Eric Blank: Here in Colorado, are they examples that the Commission, the parties, and Public Service could rely on in terms of a starting point? I'll overrule the objection for this specific question, but I generally agree with Miss Shields that this should be left to your witness. And there's maybe not a lot more room to keep going on this exhibit. But I'll overrule the objection for now. Mr. Bailey.

Mr. Bailey: Thank you. Mr. Bunker, would you mind repeating the question? Your original question.

Mr. Bunker: Sure. I'm asking if these three tariffs are examples that provide a good starting point with regard to a large load tariff and its terms and conditions for this Commission, the parties, and for Public Service with respect to the January 31, 2026 filing.

Mr. Bailey: Thank you, Mr. Bunker. I don't agree with that assessment based on the uniqueness and the nuances that come into every jurisdiction. I've worked in both in two of these jurisdictions previously, and I can't denote or tend to understand how they are, have taken stakeholder feedback, how they've incorporated customer expectations. So I can't and won't agree to that question.

Mr. Bunker: Okay. Let's go back to your rebuttal testimony and on page six, at lines 16, or 6 through 17 here, you discuss the third prong of the three-prong strategy, and this concerns large load commercial principles and procedural recommendations. Is that right?

Mr. Bailey: Yes, lines five, six, and seven.

Mr. Bunker: Yeah. And on lines 7 through 9 there on page six, with respect to commercial principles, you state that such principles are designed to mitigate risk to existing customers and protect the company and customers against the risk of uncertain or phantom load. Is that correct?

Mr. Bailey: Yes, that is accurate.

Mr. Bunker: And if we had turned to page 39 of your rebuttal testimony, starting at line 18, and then on to the next two pages, that's page 40 and 41, where you have your table TLB-R2, your commercial principles, which we've talked a little bit about. Here, is it your understanding that these commercial principles should be included in a large load tariff to mitigate the risk for existing customers and to protect the company and customers against the risk of the uncertain or phantom loads that you were talking about on page six?

Mr. Bailey: Yes, I do. And I think we previously discussed the statement in the tri-party agreement that we reviewed a few minutes ago. Again, with the understanding that we retain the commercial opportunity for flexibility of negotiation, but the commercial principles are expected, and it's our intent to be in the large load tariff.

Mr. Bunker: Okay. So these commercial principles would be included in negotiations with large load customers prior to the large load tariff being approved. Is that right?

Mr. Bailey: Yes, as previously stated, we're utilizing those in the framework for this interim period to give some certainty to customers as they want to come online prior to the tariff.

Mr. Bunker: Okay. And if we could go back to Hearing Exhibit 308, this is UCA Surrebuttal Comments on page four. And here you'll see the table starting on the bottom of page four, and this is your table rebuttal table TLB-R2 with an added column for UCA's recommendations. Do you see that?

Miss Shields: Objection, hearsay. I mean, we're back at the same table that UCA has proposed. And at this point, I'm all I'm hearing is Mr. Bunker asking my witness to speak to the truth of the matter asserted in this document. It's not his testimony. We haven't verified that this is our table.

Chairman Eric Blank: I agree, Mr. Bunker, this is for your witness to do, not cross Mr. Bailey. And especially given the time, I think I want to sustain that objection. But if you'd like to respond.

Mr. Bunker: You know, I will, I will comment that this has been admitted at the beginning of the hearing as a hearing exhibit. That this is the witness's table, it so states in the first sentence above the table at the start of the paragraph. And that I certainly don't have to ask or take the time to ask this witness, "Do you agree with each of the following UCA recommendations as to these 10 or 12 commercial principles?" I wasn't planning on doing that either way. But the point is to be interrupted before I can even lay any foundation for asking a question. I'll just move on. Let's go back to your rebuttal testimony at page 41. Actually, pull up that document. Can I take a look at that again? So your intent is to ask this witness whether his, can you scroll down to see? So your intent is to ask him whether he agrees

Chairman Eric Blank: Or disagrees with a recitation?

Mr. Bunker: Yes. For example, let's go to the top of page three or page five, rather, where we keep hearing a reference regarding 100 megawatts or more of load. The UCA's position is 75 megawatts of load at any time. Would Public Service agree to that? It might be helpful in terms of the Commission's order and directives regarding, "We want this tariff filed, and we want these kinds of things considered." We can make the argument in our SOP. Can you scroll up to the top? Is this your surrebuttal? This is the surrebuttal. Yes.

Chairman Eric Blank: I think given how this case is postured, I think just if you can do this speedily and focus on the core ones and keep the whole thing to an hour, Mr. Bunker, I just feel like we're under a lot of pressure to get this hearing in. So, but I'll overrule the objection with those requests.

Mr. Bunker: Thank you. So, Mr. Bailey, let's move to the top of page five in this first item, the load threshold. And there's been testimony regarding 100 megawatts or more is considered a large load. And would you agree with the UCA's recommendation that a new large load should be defined as 75 megawatts at any time?

Mr. Bailey: I won't agree with that recommendation. And also, I would, again, I didn't create this table. And if it's referenced in that middle column, as I, I forget the title, I would like to, if the opportunity presents itself, check the language to ensure it's accurate for my rebuttal testimony.

Mr. Bunker: Okay. All right. I will just move on, save some time here. Let's move to page 41 of your testimony, your rebuttal testimony. On lines five through eight, you state, "These large load commercial principles ensure new large customers have sufficient skin in the game to avoid the risk of procuring generation for speculative new load, or procuring loads for customers that may move projects to different jurisdictions or disappear altogether." Correct?

Mr. Bailey: Yes, lines 5 through 8.

Mr. Bunker: Do you agree the stakeholder process to develop a large load tariff should include a process for assigning costs to large load customers and protections for other rate classes with respect to stranded asset risk and cross-subsidization?

Mr. Bailey: Mr. Bunker, I can't agree with that.

Mr. Bunker: Okay. Let's move to your rebuttal testimony on page six. And here we're talking about a little out of order, but it's your second prong of this three-prong strategy. And here you state on lines three through five that the updated large load forecast includes large load customers with 80% and above probability and 602 megawatts by 2031, and strategic economic development customers 342 megawatts by 2031. Is that right?

Mr. Bailey: Yes, as defined in my updated base forecast.

Mr. Bunker: Okay. And I think you were asked this before, and let me skip that question and move to this one instead. Is it correct that Public Service's advocacy is to not hold strategic economic development customers to the same large load probability percentage factors as it does for a data center large load customer?

Mr. Bailey: I don't agree with the term of advocacy. I think I would point to how I've testified on the requirements and our expectations of an obligation and a duty to serve those customers who requested service, who are currently customers in the state of Colorado taking service through Public Service.

Mr. Bunker: Is it your understanding based on Mr. Ihle's testimony that in order to move to a 100% probability, both the ESA and IIA must be signed?

Mr. Bailey: Can you point to his testimony so that I can review that?

Mr. Bunker: Well, it came up on cross-exam, so I don't have a copy of the hearing transcript. But I believe he said in order, and perhaps we look at your large load probability table on page 30, and as I look at 90%, the slash mark, if you will, between the IIA and ESA, Mr. Ihle suggested is an "or." However, when you look at 80% negotiations on ESA/IIA, that was considered to be an "and." I'm just clarifying with you in order to move to 100%, you've got to have both the IIA and the ESA signed.

Mr. Bailey: Yes, under your example, and as we move through this step process.

Mr. Bunker: Okay. If we could move to page 12 of your rebuttal testimony, and we're looking here at starting at line 14 through 16. You indicate the rebuttal case updated base forecast adjusts the new large load forecast downward from 1,923 megawatts by 2031 in Public Service's direct case to 929 megawatts by 2031 in your rebuttal case. So that's a reduction of slightly more than 50%. Is that right?

Mr. Bailey: Yes, and approximately one gigawatt.

Mr. Bunker: Okay. Now, if we could go to page 23 of your testimony, on lines 13 through 16 here, the numbers are slightly different. On lines 14 to 16, and here you have large load customers with 80% and above probability, 602 megawatts by 2031, and strategic economic development customers of 342 megawatts by 2031, or a total of 944 megawatts. So my question is, which of those two is correct in terms of a total, 944 megawatts or 929 megawatts by 2031?

Mr. Bailey: Yes, thank you. And it's a clarification, a nice clarification. I think it's, you know, the previous work was kind of based on a forecast and the timing, you know, of that forecast. I don't know, I'm not going to sit there and say that it's correct, but these are the numbers where you think about as we plan for the load that's required in our, that the customers have requested and required in a contract. This is the load that we would be building to.

Mr. Bunker: So my question was, which total is correct? The 929 megawatts that we see on page 12 or the 944 megawatts that we see here on page, total on page 23?

Mr. Bailey: Yes, and again, I think the correction and I think the clarity is really a timing issue related to the forecasting of the previous number. These are what we are planning to and the requests from the customer at the 944.

Mr. Bunker: I'm sorry, maybe I'm dense. I'm not quite sure I follow that. The difference between the 15 megawatts. I'm not quite in the total, I'm not quite following you, sir. I'm sorry. So you, there's a timing issue in the previous number, thinking about how we forecast and bring those numbers on. These are requested by the customers as their total load. And so building, building to this load, or the customer requests. So is the 929, is that the, is 929 megawatts on page 12, is that the number the Commission should focus on rather than what these customers might be requesting? This is more what you forecast as I understand it, is 929.

Mr. Bailey: Yeah, the numbers on this page, the 602 and 342 are the customer requests of what we will be contracting to.

Mr. Bunker: Okay. Scanning the last couple of questions here, Mr. Chairman, and I think they have either been asked and then answered through my questions or through other counsel. Give me a moment, please. Yes, I'm finished with the public session, Mr. Chairman, and Mr. Bailey. Thank you.

Chairman Eric Blank: Hey, Mr. Bunker, before you leave, just for planning purposes, do you have a sense of how much confidential cross you have for Mr. Bailey?

Mr. Bunker: I would say roughly 20 minutes.

Chairman Eric Blank: All right. Can we take down this exhibit? I'm told Commission counsel doesn't have any questions for Mr. Bailey. Commissioner Gilman, questions for Mr. Bailey? Public questions? Yes.

Commissioner Megan Gilman: I will have some confidential questions as well, but I'll go with my public questions now if that works.

Chairman Eric Blank: That'd be great.

Commissioner Megan Gilman: Okay, great. Good afternoon, Mr. Bailey.

Mr. Bailey: Good afternoon, Commissioner Gilman. Hope you're well.

Commissioner Megan Gilman: I am, thanks. So wherever possible, I'll try and generalize a few of these concepts to keep as many of these public as possible just for transparency purposes. And some of them, if we need to get more specific in confidential session, we certainly could later. So first, with regard to resource adequacy, so looking at the loads and resources information, I went over with Mr. Land, and kind of the realistic expectations and limitations on building new generation in the short term. I won't get into details about the customers, but suffice to say there are customers, largely customers that you expect to be hooking up and taking service in 2025. Yes, that is accurate. Okay. So that would mean they've signed agreements and are in construction. Yes. Okay. So with signed agreements, the company would be obligated to essentially build the infrastructure to get them served. Is that right?

Mr. Bailey: Both build or serve them from current resources.

Commissioner Megan Gilman: Okay. But you would be building the transmission infrastructure, the substations, whatever else is needed to get them served?

Mr. Bailey: The transmission either has been built or in the process.

Commissioner Megan Gilman: Okay. So I'm just kind of curious how the company's able to commit to providing service for new large loads beginning to receive service in 2025, given the lack of capacity to meet existing resource adequacy parameters for the same time frame.

Mr. Bailey: Thank you, Commissioner. Can you be maybe more specific on the numeric? I just want to make sure I know we have customers who are ramping at a lower level and certainly the expectations in the forecast and meeting those obligations. I think I understand your question, but I just want to be clear.

Commissioner Gilman: Yeah. I mean, I'm just looking at your Attachment TLB2, which we won't pull up because it's highly confidential. But that provides for capacity in 2025 for certain customers listed as 100% probability. And I was wondering how we juxtapose that with the company's current resource adequacy situation where they are considerably negative on their resource adequacy parameters for 2025.

Mr. Bailey: I see. Again, I'm not a resource adequacy planner or modeler. So I don't think I can answer that question as it's planned in the expected resources.

Commissioner Gilman: So if you're negotiating with these customers or potential customers, but aren't kind of in the resource planning or aware where the resources come to serve them, and we're not meeting our resource adequacy parameters, yet signing up new capacity to serve, who makes that determination then? And just to be clear, who makes a determination on when the customers come online in accordance with that you can agree to bring them online?

Mr. Bailey: Yeah. Well, we work together as a team and obviously modeling new customers at whatever level in the example, we'll work through that process and then have to go through the L&R table and the resources coming online and certainly the timing of those resources in non-peak periods. But it's a collective effort and then the approval process, I think goes through the resource adequacy lead in that regard to that question.

Commissioner Gilman: So who is I guess the resource adequacy lead? Like who gives you the green light that a new customer can come online given the resource adequacy situation?

Mr. Bailey: I would pitch that question to Mr. March, I believe.

Commissioner Gilman: Okay. I want to get to a couple questions on the strategic economic development customers. So that's a concept introduced in rebuttal, right?

Mr. Bailey: Yes, that's accurate.

Commissioner Gilman: Okay. Based on the name, they're both strategic and economic development related. I was wondering, is there any analysis that the company applies to determine how many jobs or how many taxes or whatever benchmark is being used to classify those as such?

Mr. Bailey: We do not have specific analysis. I would just point to kind of previous statements about our relationships with those customers. They're all managed accounts and so, you know, we're working through with those customers on their expansion plans and their expectations for how they come online.

Commissioner Gilman: Now I heard in your discussion with council, one of them was questioning you that it could be possible that these would not be existing customers.

Mr. Bailey: Yeah, yes. And for clarity, I think his question, if I recall, was for future, putting them into the incremental need pool. But the current strategic economic development customers represented in my rebuttal are current customers on our system.

Commissioner Gilman: Okay. And am I correct that the entirety of the predicted strategic economic development loads are included in the forecasts as you present them?

Mr. Bailey: Yes, referenced in the TLB, the highly confidential document.

Commissioner Gilman: Okay. And that's their inclusion is regardless of their individual probability rating?

Mr. Bailey: Yes, that's accurate.

Commissioner Gilman: Okay. Have any of those strategic economic development customers signed an energy service agreement?

Mr. Bailey: I don't know the answer to that. My expectation is because they're current customers, and managed through our OpCo and account management, they either have a current large applicable CNI tariff or contract, or are in the process of signing that. My expectation because they all have meters set that they have some form of an agreement. It may not be the ESA as we defined it here.

Commissioner Gilman: Okay. So if they're already kind of large customers and this is just increasing their load basically by a significant amount, do you expect they would sign updated ESAs?

Mr. Bailey: I don't know that, Commissioner. I don't know that process.

Commissioner Gilman: And the expectation coming out of the account management team in your negotiations with them, do you need to communicate an expectation around that?

Mr. Bailey: My expectation is those conversations are going on that they're meeting a strategic, I'm sorry, meeting a contract requirement as the tariff requires.

Commissioner Gilman: Okay. So you think there are account reps talking with them about that?

Mr. Bailey: Yes. I know they are.

Commissioner Gilman: Yes. And then would they be doing system impact studies and facility studies given that they're existing customers?

Mr. Bailey: I believe, and this is subject to check, that they are a subset or coming off the distribution system, so they would do the distribution review. I think one in the expectation as they expand going forward, may convert to a transmission service and so they would go through that SIS and facility study.

Commissioner Gilman: Okay. So if they're on the distribution, if they're connecting to the distribution system, are you aware what type of agreement they would sign or would be updated for this new load?

Mr. Bailey: I'm not as familiar on the distribution review. I think Mr. Marks can help clarify that, but I know that they would that there will be a study done to ensure that at that distribution level that they can meet the needs and the requirements to serve.

Commissioner Gilman: And do they pay for that study?

Mr. Bailey: I don't know the answer to that question.

Commissioner Gilman: Okay. Not right now, but when we're in the confidential session, I'm curious, are you able to share with the commission the names of any besides the one that you've identified confidentially? And again, this is the strategic economic development customers.

Mr. Bailey: I don't believe I'm able to do that based upon the confidentiality.

Commissioner Gilman: I'm curious what dictates the confidentiality.

Mr. Bailey: The NDAs incorporated with those customers and their expectation to expand.

Commissioner Gilman: Okay. And do those customers understand that you would need generation approved by this commission in order to serve them?

Mr. Bailey: They are familiar with the process we're going through and the request we have for new generation and the timeline laid out.

Commissioner Gilman: Okay. And despite them understanding that this commission would need to approve generation to serve them, they've intentionally made it such that you can't disclose anything about them?

Mr. Bailey: Yes, that is accurate.

Commissioner Gilman: Have any of your discussions with the strategic economic development customers involved applicability of the existing or potential economic development rates?

Mr. Bailey: No, it has not.

Commissioner Gilman: Okay. So I know the company stated you don't expect them to use the rates, but it sounds like you haven't talked to them at all about the rates. So is it possible they have an expectation you're not aware of?

Mr. Bailey: No, I don't believe they have that expectation because one, we haven't extended an offer of that incentive rate and nor do we expect to.

Commissioner Gilman: Okay. I have a couple questions about system impacts. So UCA raises concerns about potential system impacts of large loads. Are you familiar with the issues they raised?

Mr. Bailey: I believe I am, but as we go through questions, I may need a reminder.

Commissioner Gilman: Okay. So they raised concerns with respect to short-term disturbances like voltage instability as well as issues related to ramping and reserves. And I'm curious if that's something you actively discuss internally at the company with regard to potential risk around new large loads.

Mr. Bailey: I am not familiar with those discussions and not part of that modeling or engineering review. But my expectation is those are part of that process. But again, I'm not an expert and I don't design and part of the design of the system and the expectation to serve them at a distribution or transmission level.

Commissioner Gilman: Okay. If there's additional kind of costs imposed on the system due to the potential system impacts that are specific to the risks around large loads, is that something that you're communicating to the large loads they may be financially responsible for mitigation of?

Mr. Bailey: Commissioner, just so I'm clear, are you discussing the direct assigned cost of a transmission or substation work for those customers?

Commissioner Gilman: No. So if there are wider system impact mitigations that are needed in order to mitigate the specific risks that a large customer could impose, are you defining that as network upgrades or network costs?

Mr. Bailey: I'm not 100% sure what the extent would be to be honest with you, because we don't have any information from the company as to what those risks look like and what the mitigations would be, presuming there are risks and there would be mitigations.

Commissioner Gilman: I see. Yeah, yeah, I don't believe I can answer that question. I think that'd be better for Mr. Morbs. Okay. So, probably not your area either, but let me try. UCA also raised concerns about large loads that could cause specific ramping or reserve problems, and I went over some of that with Mr. Landram. Did you hear that?

Mr. Bailey: I did.

Commissioner Gilman: Okay. So, do you believe such concerns should be addressed? And if so, how would those be addressed with these large loads?

Mr. Bailey: Again, I would ask Mr. Marks that question.

Commissioner Gilman: Okay. Couple questions with regard to agreements that they're signing as well as probability and risk. So you said with Miss Vitali that depths between 50% and 100%, and now we've kind of switched to the data center who are applicable to this probability matrix, the steps between 50 and 100% are essentially linear, so every step would necessarily only occur after the step before it? Is that accurate?

Mr. Bailey: Yes, that is accurate in our discussion, and they're very obviously very important to get through that process.

Commissioner Gilman: Okay. So without identifying any load, we can follow up in the confidential session if we need. Very few customers, I've noticed, are listed at an explicit load probability level. Many of them are represented by a range, a broad range of probabilities. Why, if these steps are linear, is there not more transparency about the actual level of the process each of those loads is at?

Mr. Bailey: Yes, Commissioner, thank you. And I think you're referencing maybe an example of a 50 to a 79%.

Commissioner Gilman: Yes, as an example. I think several times. Yeah. Is that accurate, my example?

Mr. Bailey: Yeah. I think it's how we are categorizing those customers in their current time frame. I think it's just because there may be, it may be at certain steps within that 50 to 79, and so it's how we've bucketed those customers in that definition. And again, we're understanding that there's some they're in that process and we're defining it. It's just an area of focus of how we've delineated that. I think for the simplicity of the filing.

Commissioner Gilman: Okay. Would this simplicity of this filing be fairly similar if you just put an exact percentage instead of a range?

Mr. Bailey: I think we can take that into consideration for clarity.

Commissioner Gilman: With Mr. Ghart, he asked you about basically the company's stance that even if one of these large loads doesn't materialize, another load will come in behind them and essentially still use the capacity that was built to serve the original customer. Do you recall that?

Mr. Bailey: I do. And I think he was also referencing those same questions that Miss Vitali had addressed.

Commissioner Gilman: Okay. And he had asked you, I'm paraphrasing, if the company would be willing to accept that risk on the building of the new infrastructure, this concept that it will be backfilled by a new customer. And I believe you responded that the company would not, is that accurate?

Mr. Bailey: Yes, that is accurate.

Commissioner Gilman: Okay. So I get the other side of that coin is if the new load doesn't come in to backfill the procured generation need and other investments, is it then the company's position that other customers should cover the cost of that investment in the case that the load doesn't show up?

Mr. Bailey: Well, at this time, again, I think we're matching and our expectation is matching those new customers and bringing that load on at the appropriate time frame. I think also in my example, if there are areas and times where we have length in a short period of time, I think that is a good thing. We're obviously behind in bringing our generation online. So if there's an interim period or a time period, we're going to utilize that length to bring on new customers and for other customers on the system to utilize it because they will benefit. All customers will benefit from that generation on the system based on the analysis we're showing.

Commissioner Gilman: But if for whatever reason the new customers don't show up in that quantity, an economic recession or whatever happens, the inverse of the company accepting risk, if they're not willing to do so, would be that the customers take that risk, is that fair assumption?

Mr. Bailey: Those assets would be system assets, which means they're funded by other ratepayers, by all ratepayers.

Commissioner Gilman: Yes. Okay. So large loads connecting at the transmission level would need an ESA and an IIA before connecting, right?

Mr. Bailey: Yes, that's accurate.

Commissioner Gilman: Okay. And you're a little unsure at the distribution level if they would need either of those or just one of those, or do you have any understanding of that?

Mr. Bailey: Yeah, I think, you know, depending on the sequence of what they've signed, it may be either or.

Commissioner Gilman: Okay, okay. To your understanding, what financial commitments are made by new large loads in signing an ESA under the current current ESA form?

Mr. Bailey: Today, there are no financial commitments outside of what is required in the IIA for the stage gate payments and the updates to the transmission work. Now, we also have securitization requirements, so there will be upfront securitization and parental guarantees, letter of credits, and or cash, so those items are at risk.

Commissioner Gilman: Okay. And you qualified that by saying "now." Is that because the company's intention is that the commercial principles will make their way into one or both of these agreements?

Mr. Bailey: Yes, the commercial principles, as we discussed earlier, are being verbalized and utilized in this interim period and obviously what we've discussed coming into the large load tariff in January of '26.

Commissioner Gilman: Okay. And have you communicated those commercial principles to all interested large loads that you're in discussions with or that appear on your attachment?

Mr. Bailey: For those that we are engaged in communications who are moving up the chain, we've been very clear about our expectation of those principles.

Commissioner Gilman: Are there people on that list in your confidential attachment with whom you're not in communications with?

Mr. Bailey: I don't believe so, minus, I mean, obviously the strategic economic development customers. I just want to be very clear, are you thinking about those that are that are over 100 megawatts who would qualify or those that are coming onto the system that would meet those requirements? We are absolutely having those discussions with them.

Commissioner Gilman: Okay. So every data center listed on TLB2, you're having discussions about the commercial principles with?

Mr. Bailey: Yes, that is accurate.

Commissioner Gilman: Okay. Have you discussed them as requirements or suggestions?

Mr. Bailey: We've discussed them as the expectations that we're going to place in the ESA and working with those customers, again, as I've previously stated, with the commercial flexibility. But they are a part of our conversation on a weekly or daily basis as we move them along with our expectation and intent they will be in the ESA in the end period of time.

Commissioner Gilman: Okay. But given the commercial flexibility you're asking for to negotiate, it's possible you could sign an ESA that doesn't include any of the commercial principles, is that fair?

Mr. Bailey: I don't necessarily agree with that. I think, you know, on the basis where you say, is it possible? But the fact of the matter is we are moving through these projects and as our project pipeline, we have customers who are willing to sign those. They need the clarity of what we're going through in this process. But I will tell you, I have not had a customer who says, I will not sign a minimum demand or an exit fee. Many of these customers are seeing it across the US and have a comfort level or an expectation that they'll be asked to sign. So I don't consider it that we'll get to an area where we will sign an ESA without these commercial principles.

Commissioner Gilman: Do you think they'll appear in the ESA and IIA or these are only in the ESA?

Mr. Bailey: My expectation is they would be only in the ESA.

Commissioner Gilman: Okay. So since you can get to a 90% probability by only signing one or the other, I could still have large loads that have not agreed to the commercial principles that get advanced into the incremental need pool or whatever it is. How could that be remedied?

Mr. Bailey: Yes, Commissioner, related to your the either on the signed A or you see at the 90%, that is accurate. What I will tell you is pragmatic and a commercial expectation as soon as these customers sign that IIA, if it's in that sequence, they are wanting and needing service as soon as they can get it, provided we can extend the infrastructure and have the generation online. So those move very quickly together. And if a customer wants to move quickly and wants to get the speed of the market, they're going to have to sign that ESA. And so I see those two documents working in parallel very quickly. And again, the IIA, we have IIAs in place where there's several millions of dollars at risk for them if they don't sign that ESA. So there are key triggers there that I think is very important to your earlier discussion about mitigating risk and creating accountability.

Commissioner Gilman: And what's like the typical time frame between signing an IIA and an ESA?

Mr. Bailey: Yeah, great question. There are nuances there, but I think our goal as we work through this is 30, 60, 90 day period depending on where we are. I would tell you that right now, we're at a period of time that if we get clarity on the phase one approach and the three-prong approach, we are going to move very quickly on some customers that are asking for service and certainly doing that under the commercial principles that I've outlined. But think about that in a 30 or 60 day plan.

Commissioner Gilman: Okay. If the ESA and IIA, or I got the order reversed, IIA and ESA occur in such rapid succession, why then is it necessary to clarify that the 90% probability is either or? Sounds like both occur almost simultaneously and only one would contain the provisions we're talking about. Wouldn't it make more sense to make it be both if they're nearly simultaneous anyway?

Mr. Bailey: Yeah, thank you, Commissioner. I appreciate that question, but I think it's about manage the time and the time frame. And so if we get that IIA signed and we can get updated information into into the, as an example, the phase two or an incremental need pool, we don't want to delay. And so that timing, even if it's 30 days or 60 days, I consider that an efficient use of time. Those are important time parameters of getting updated information into the forecast and into, in your example, the incremental need pool.

Commissioner Gilman: Okay. Can you help me understand the nature of the way you communicate the commercial principles encouraging new large load customers to provide load flexibility? What do those discussions look like in terms of what customers appear willing or interested to do?

Mr. Bailey: Yes, thank you. And great question. We have detailed discussions and we are constantly and proactively having those discussions about DR capabilities or load flex capabilities with these customers. As I denoted, we're recommending and not requiring based on some economic factors that the feedback we're getting from data centers. They obviously have sustainability goals, they have reliability goals, and certainly five nines. The feedback that we're getting and the technology and the infrastructure that these customers are reviewing, currently there's just not an economic source for backup generation or a load flex generation that can be acceptable to them. They highly regard the uptime. As we've discussed, they're 90-plus percent load factor customer, and so that's extremely important to them on their output and their profitability. And I think they're open to opportunities, but it has to be a balance for the incentive of a load flex program as well as the ability to implement it and control it.

Commissioner Gilman: Okay. And related to that, you mentioned specifically in the commercial principles the 80 to 100 hours of interruptible load shed during the year, which I think is kind of referencing the ISOC program, unless I'm wrong. Is that kind of referencing the existing ISOC program?

Mr. Bailey: Yes, I believe so. And I think it's an important number where we, you know, a little bit of modeling of how can that help in the resource plan requirements?

Commissioner Gilman: So kind of given their need to maintain uptime, you know, in your discussions with them, do you have any sense as to if that's the most appropriate product for them or the most appropriate kind of design? Like what are their interests around what they could do from a demand flexibility standpoint? And how are you taking that internally and trying to ensure you have the right product to actually provide that?

Mr. Bailey: Yes, great question. And I don't want to kind of hone in that that's the only product we discuss. It's not. I mean, there's other products that and we're open to their creative solutions as well as our internal teams. But, you know, there are, you know, these customers right now that the five nines capability or the one for one match, you know, they're designing diesel gen sets or diesel recip engines and those units that are modular, that is the most efficient and most cost effective at this time. And so there are restrictions on how you test and run those. And so thinking about those as a DR resources is just not applicable because of the emissions and the outputs and those requirements. So, we are having those conversations in great detail. We just haven't come up with a solution that's palatable for them.

Commissioner Gilman: Okay. But you're saying most of them by standard are installing diesel gen sets for backup?

Mr. Bailey: They are. There are some examples across the US where there may be some natural gas solutions that are CTs or even some LG, but those have larger costs and obviously require pipelines and different types of permitting. So again, you're getting to an area where if it's not cost effective, they're just not going to execute on those types of services.

Commissioner Gilman: Okay. And I'm just curious if in all these discussions there's been any epiphanies on what a cost-effective and interesting solution to them might look like. Like I would presume you've got the right people in the room to figure out what offerings could work for them. So what, if any insights do we have on that from all your discussions?

Mr. Bailey: Yeah, great question. We do, we do. And I'll just, you know, straightforward, there has not been an epiphany. When we dive into the details and they look at the financial requirements of their return or their hurdle rate, there is just not a solution at this time for them.

Commissioner Gilman: Okay. Is it your understanding that new data centers would require water rights, or no? Can you be more specific in your question? I have water rights in a definition in other jurisdictions. Just do they need access to significant amounts of water to operate in certain areas and locations?

Mr. Bailey: Yes, they do need water. I think, you know, I'll stop short of saying significant. There's technologies and advancements in how they're cooling and air cooling that has increased the efficiency of water usage over the years. And quite frankly, in the last five years, I give you an example. We have some customers who who come to communities or municipalities and they talk about needing multiple million gallons a day. Those requirements, what I've seen and in other areas where customers have shared how they gain those efficiencies, they dropped some of those requirements by a third or by two-thirds. And so yes, they need they need water, but it's also dictates, you know, the time of year, the cooling mechanism, the humidity. So the amount of significant, I just stop short of, but they do need water contracts to service their facility. And again, it depends on how they're utilizing them.

Commissioner Gilman: Okay. And I mean, do you generally see that if they move from water cooled to air cooled, that they'll use less water but more electricity to cool?

Mr. Bailey: Yes, in a linear fashion, but again, it depends on the location and certainly the environment they're in.

Commissioner Gilman: Does the company track or assess the likelihood in any scenario, like by location of the project, to get the water that they require to operate?

Mr. Bailey: We don't specifically track, but as we move through the process, and I think I spoke earlier, it's one of the key requirements that these customers will have in their jurisdictions. And so as we work with them collectively with communities, we're certainly aware of their progress in the process. Again, we don't have a formal tracking process for that.

Commissioner Gilman: Okay. Last question, I think. Have you had any discussions with large load customers about the potential for them to bring their own capacity to either aid in or speed your ability to serve them, given especially a resource adequacy position in the short term?

Mr. Bailey: We have not had those detailed conversations.

Commissioner Gilman: Have you ever suggested in any sort of conversation with them? I'm sorry, it broke up just a little bit. Has it ever come up at all in a conversation?

Mr. Bailey: Not in the conversations I have had. I have certainly been privy to other utilities or requests or public requests from customers, but I haven't had those direct conversations.

Commissioner Gilman: Thanks. Let's move on. Thank you, Commissioner Gilman.

Commissioner Plant: Thank you, Commissioner Gilman and Commissioner Plant. Thank you. Going back up here, I just have a couple of quick questions, Mr. Bailey. Just to follow on your discussion with Mr. Ghart, he was pointing out that you procure resources for an 80% customer, which means that they haven't signed an IIA. Is that, would that happen? Would you be procuring resources for a customer that was at 80% and hadn't signed an IIA?

Mr. Bailey: Thank you, Commissioner Plant. Good to see you. Are you referencing the probability side of this or the tri-party framework?

Commissioner Plant: Yeah, the probability. So that, I mean, if they sign an IIA, they're 90%, right? So before that, they're in discussions, which would be 80%. And I was just, I just wanted to get clarity. Would you procure resources for a customer prior to them reaching 90%?

Mr. Bailey: And I believe as as we addressed in the tri-party framework that the less than 80% would trigger the incremental need pool in that example. So I'm sorry, less than 100 megawatts, less than 100 megawatts, 80%, right?

Commissioner Plant: So if so, you would, you would potentially procure resources for a customer prior to getting a signed IIA if they were under 100 megawatts?

Mr. Bailey: Yes, as defined in the tri-party agreement and incremental need pool in that example.

Commissioner Plant: Is there, is there any kind of, you know, batching that would basically trigger? I mean, if you've got a number of, you could have basically 200 megawatts of under 100 megawatts customers that you're procuring resources for. I'm just wondering, is there, is there a certain batch level that you're looking at? Obviously with the 100 megawatt customer, you're looking at potentially losing a very, very large demand, but you could have, you know, very close to the same thing with batches of customers.

Mr. Bailey: Yes, Commissioner Plant, it's a great question and we, we've actually, you know, we're thinking about internally and contemplating because in your example, if you had, you could have one customer who has, you know, four different expansion tranches of 30 megawatts in your example. And so we haven't considered that that batch approach, but I, I will tell you, we are sensitive to how to manage it and certainly understanding the impact of what that would, of what that would trigger an incremental need pool or a supplemental RFP. But we haven't considered the batch approach. But please know, we understand the sensitivity and the impact that it could be under the 100 megawatts, because you could have, you know, multiple customers. Also to that example, we would still go through if you had, you know, 10 customers of one megawatt, we're going to, you know, we'll deal with them in the process that I think Mr. Goodenough outlined on updating the forecast in the future and having those in the appropriate stages of a future RFP or supplemental.

Commissioner Plant: Is there a, do you feel like there's maybe an incentive there for companies to to basically break up their their requests into less than 100 megawatt tranches?

Mr. Bailey: It's a great question, Commissioner Plant. I don't think there's an incentive. And really because of the basis on these customers, as kind of looked in here, either the large load or the strategic economic development, they're wanting to move quickly, but they also are investing at many times billion dollars of capital. And so breaking up those tranches is actually counter to how they expand and how they really want to go to market quickly. Also if if they did that and broke it up, our process as we've delineated, it increases some timing, right? And potentially increases uncertainty for them. So the certainty and as we talk to them and advise them about giving us an accurate and proper load ramp, I have not witnessed any of that. And quite frankly, when customers discuss it, they're coming to us with, this is what I need. Tell, we want, we want more or tell us how much you can get to us because we want to move quickly.

Commissioner Plant: Okay. And another thing I just wanted to have a little bit of clarification on. You were asked by Miss Vitali, "Would all large loads that connect at the transmission level require an interconnection agreement?" And your response was, "Over 100 megawatts, yes." You could have a large load below 100 megawatts that would have an IIA. Can you clarify that? Do all large loads, regardless of size, have to have a signed IIA if they're connected at the transmission level? Or you said, "You could have a large load below 100 megawatts." I was just wondering, is it, you could, or you have to have an IIA at the?

Mr. Bailey: Yes, Commissioner Plant, thank you. And hopefully I can clarify. I think as I talked to Miss Vitali about that, is you could have a customer who comes in below the 100 megawatts, who says, "Hey, I'm a 50 megawatt customer in that example. I want transmission service, or we don't have distribution service, so we're requiring transmission service." They would be required through that SIS and the facility study to sign an interconnection agreement, as she at that time defined.

Commissioner Plant: Okay. So really, you would have, if you're getting connected to the transmission system, you would have to have a signed IIA regardless of size, is that correct?

Mr. Bailey: Yes, Commissioner.

Commissioner Plant: Okay, great. And I think this is my last question, kind of following on. Commissioner Gilman was asking a little bit about the rebuttal testimony list of commercial principles and are part of your discussions with the large loads. The last one is load flexibility. And I think it talks in that language about encouraging load flexibility. Have you considered a requirement to either provide load flexibility at a certain posed storage at the site that would provide that kind of flexibility to the system? Thank you.

Mr. Bailey: We haven't had those conversations of requirement. But what we have, and I would say I think I mentioned this to Commissioner Gilman, we've had customers and talked about those types of behind the meter generations and storage being one of them. What we have found and the information provided to us by the customers is right now and currently the technology is just not economically feasible for them to do. And thinking about those those new resources behind the meter is just not palatable for them. It's an idea we're pursuing and I think it's very reputable and we would love to see those types of engagements. But again, you know, it's hard to require a customer when they're bringing their financial capital to the location and then and then making those decisions on those hurdle rates or return rates.

Commissioner Plant: As you said, they're, I mean, some of these customers are making billion dollar investments in the site. So providing, you know, four-hour storage for their capacity, you think that would be outside of their economic capabilities?

Mr. Bailey: Yes, Commissioner. You know, I don't think I can state what what is in or out of their economic capabilities. They're certainly investing billions of dollars. I trust in the fact that as they speak to us and as they show us data and we have the same data, you know, we're procuring from the same resources on the expectation of those of those assets, they're not making those decisions at this time.

Commissioner Plant: Can you definitively state that? Thank you. That is all the questions I have. Mr. Chairman, thanks.

Chairman Blank: Thank you, Commissioner Plant. Hey, Mr. Bailey, how are you?

Mr. Bailey: I'm good, Chair Blank. How are you doing, sir?

Chairman Blank: Hanging in there. My understanding is that the nine large new large load customers you listed on Hearing Exhibit 140 would all sign something like the Electric Service Agreement or ESA that was providing provided as Hearing Exhibit 137. Is that more or less right?

Mr. Bailey: Yes, I think with a clarity, eight of nine, eight out of those nine customers have current agreements in place. There's one customer that I think I discussed, I know I discussed, that we're talking in great detail about the commercial principles that I outlined in my testimony.

Chairman Blank: Okay. And that sample contract has a one-year term after which either party can terminate based on 30 days notice. Is that correct?

Mr. Bailey: Yes, I believe that's accurate.

Chairman Blank: And the company committed to submit an advice letter filing modifying the current tariff for new large load customers by January 31st, 2026. I think you've already testified to that. To the extent this commission modified the current tariff as a result of that filing, advice letter filing, for those large new load customers that have already signed an ESA, they'd be still subject to any tariff change resulting from that case at least after the initial one-year term. Is that a correct understanding of the ESA and how that tariff filing would work?

Mr. Bailey: With Commissioner Blank, thank you for the question. I think with a couple of clarifications. Obviously in those those customers that have been provided in the 140, the new commercial principles as aligned in the new tariff will be for customers greater than 100 megawatts. And there's obviously a customer on that list that we defined that's already receiving service and already has a contract that is addressed currently that Mr. Bunker recognized. We are not asking for a grandfather of customers over 100 megawatts and for those under, they'd be utilized the current applicable large CNI tariff that they're taking service under now.

Chairman Blank: So put aside, I guess it's, well, put aside the one tariff that we approved where I think we locked it in for 10 years, right? Every other customer, if the tariff changed, that they would be subject to the new tariff after say the 2026 advice letter filing, is that am I understanding that right? For for new loads or expanded loads under 100 megawatts after that that tariff is approved, and for over 100 megawatts, you're not locking in today's rates for 10 years, are you?

Mr. Bailey: Just so I'm clear, if in your example, if we go out and sign an ESA under the commercial principles in this interim period, we're locking in the applicable tariff rates today and certainly would would be adjudicated in other rate proceedings.

Chairman Blank: Have you done that already? In in my example of signing an ESA with in this interim period, assume this commission finds that the current tariffs come nowhere close to covering the actual incremental costs these customers put on the system. Are you signing 10-year agreements now that take away our ability to modify the tariff to reflect those costs?

Mr. Bailey: Commissioner Blank, I'm not a pricing expert on incremental and marginal cost. What I will say is we have not signed a customer currently in the interim period in the ESA form, representing that customer we we talked about previously, that's the 10-year contract that is adjudicated and approved. Our expectation is that current customers if we signed over 100 megawatts in this in this interim period that abide by these commercial principles with our intent, they would not be grandfathered into to a new large tariff.

Chairman Blank: Now, they will be paying the, I didn't, I don't know what you mean by grandfathered in to a new large tariff. Are you, are so for over 100 megawatts, are you offering 10-year contracts at current tariff rates?

Mr. Bailey: We are not. We're in verbal negotiations in this interim period with with a customer and and a second customer of saying if implementing these commercial principles, long-term contracts, again, reference by negotiating period. But those contracts in our in our proposal and our plan, if we execute those in this interim period, they still would be have the large CNI applicable rate structure as defined in the tariff. We're not providing or expanding the EDR, but we're not asking for those customers in this interim period to be placed into the new large load tariff that we're going to file in January of '26.

Chairman Blank: And say the existing CNI tariff goes up 10% two years from now for whatever reason, will those customers in this interim period pay that 10% increase or are you guaranteeing current rates for 10 years?

Mr. Bailey: Chairman Blank, we are not guaranteeing current rates for 10 years or giving incentive. The as we discuss, the form ESA that we provided, those customers will pay the applicable rates now and in the future of rate mechanisms and tariff proceedings. What I am stating is that if we sign, if and when we sign a customer in this interim term and that and there's commercial principles that we negotiate or have flexibility on, it's those areas of focus that won't be grandfathered into the new tariff for 100 megawatts.

Chairman Blank: So there'll be two tariffs. One will be a new large load tariff that you file after January, and then second, loads over 100 megawatts could be subject, could agree to take the existing CNI tariff. But after January, whatever 2026, or whenever that gets adjudicated, gets decided, they have to go into that, that, however that case is resolved. Is that a fair understanding of what you're saying?

Mr. Bailey: That that is likely the expectation. I'll just take one caveat and maybe it's nomenclature. I wouldn't say there'd be two tariffs. I would just say that we would have an ESA that is that is negotiated with these updated commercial principles that would align with the existing applicable large CNI tariff. Once we file a new large load tariff in January and it's adjudicated throughout, then then 100 megawatt customers who take service after that tariff is is approved by this commission would adhere to that tariff.

Chairman Blank: And would you sign these contracts prior to a commission decision approving your principles?

Mr. Bailey: In the interim period, if if we can get to an agreement with an in-use customer or customers and and it meets our internal requirements, we would sign those customers prior to your example.

Chairman Blank: If there were a commission decision in this case asking you to modify those principles, then I assume you could do whatever you want maybe at your own risk before then, but then after that, you'd comply with a commission's approved principles.

Mr. Bailey: We certainly would comply with with commission directive and principles as they are assigned coming out of this hearing.

Chairman Blank: All right. I heard several public service company witnesses suggest that if one new large customer dropped out, they'd be replaced by another. But is it possible in your experience that much of the new load could lose interest at the same time because of some new technology change in training or using AI, because of improvements that greatly lower data center energy use, or because of rising interest rates or an economic downturn? It just seems like these customer decisions may be highly correlated. Just curious if you have any thoughts based on your experience.

Mr. Bailey: Yes, Chairman Blank, I appreciate the question. And I want to be careful that we don't dictate all these customers in a monolithic path. I think we've as Mr. Good stated and as I've talked about is we obviously have a data center customer, we have these strategic economic development customers. And if you look at that approximately 950 megawatts, it's a diverse set of customers. We certainly hear and have information about efficiencies in the AI and data center market. What I what I would tell you from my experience and what I've seen not only in Colorado but across the nation, we're not seeing a reduction in request in our projects and our project pipeline. And even denoted in in my rebuttal, you can see what we've added since we've changed our our load forecast from from my base and my direct. So we're conscious of it, we're certainly sensitive to it. We just have not seen any major changes or expectation from our customers. And if there are efficiency models, I think everybody gains. And so these customers can place more servers, more technology into the same space and utilize the level of megawatts that they require. So I don't believe there is a quote unquote mass exodus, but I do believe that we have the right customers coming into our service territory.

Chairman Blank: You mentioned that individual customers may have several million dollars at risk. As I understand it, in this case, you're asking us to approve really multi-billion dollar generation and transmission investments for these customers, some of which have not even put down the million dollars. But any thoughts or comment you can provide on this potential mismatch in commitment given that the regulated system is outspending these customers thousands to one?

Mr. Bailey: Yeah, thank you, Chairman Blank. Certainly respect the question, appreciate the question. I think as we have submitted in my rebuttal, the, it's a fairly conservative model for just specific to the to the large load customers and strategic economic development customers. Approximately a third of that load, 350 are customers who are here and so those customers are going to expand. They're in the markets, they're creating jobs. We have then another approximate 600 of which four have signed or three have signed contracts and one's prepared to sign. So I think the risk is minimal. I think matching the generation of approximately 950 megawatts is prudent and is certainly timely in what we've proposed. And so I understand and respect the question and understand where it's coming from. But I think we have done a very nice job of providing a forecast and a mitigation schedule that allows some comfort and the mitigation of risk.

Chairman Blank: In response to a question from Mr. Ghart, you talked about the need for certainty of generation if approved by the PUC with the second resource acquisition, the strategic resource fund, and the incremental resource need pool. Give these customers enough confidence that once they signed, the company could bring resources forward in a timely manner.

Mr. Bailey: Chairman Blank, yes, with with the understanding that the phase one request of the of the nine approximately 950 megawatts is part of that approval. I also believe that the steps we're taking and in full agreement with you is the the steps we're taking in in the three-prong approach of the large load strategy, the incremental need pool helps them think about long-term planning in a different way than they did previously in the previous, you know, phases approach that took three or four or five years. So I think it's a great first step. I think it increases efficiency, but it also sends a signal to the market that the utility, the commission are in lock step and the the state of Colorado is ready to grow appropriately.

Chairman Blank: What if the commission approves the low load forecast, but the the second RA, the strategic reserve fund, and the incremental resource need pool? Why wouldn't the those incremental resource need pool give customers the confidence they need?

Mr. Bailey: Yeah, thank you, Chairman Blank. It's all about timing. I think we've represented. Mr. Goodenough talked about how he would update that low load forecast. It would now including the the 950 megawatts certainly the 600 in the low load in your example. The strategic economic development customers are not in that. And so that that 350 megawatts is would be at risk and certainly the reputation of what we're doing would be at risk. So understand the question and and the guidance, but I think really importantly, I just hammer home the fact that timing and getting these customers speed to market is critical. They've showcased their willingness to be here. Obviously, they are here. But also our work and our prudency on signing new contracts, I think is is indicative of where we're going. So it's really important to showcase our ability to move quickly. And I think the the phase one and two approach with the incremental need pool does that.

Chairman Blank: All right. Last question, last two questions. If I represented to you that there were 30 states that had a manufacturing exemption, the state and local sales and use tax, would you have any reason to doubt that?

Mr. Bailey: Chairman Blank, I don't. And I've I've worked in a lot of those states that do. And so I've been part of those, sometimes I'm helping create and sometimes helping execute those.

Chairman Blank: And is it fair to say that Colorado is not one of those 30 states? Would you agree with that?

Mr. Bailey: Not currently. Colorado does not have that incentive package for specifically for that incentive mechanism.

Chairman Blank: All right. That's all I got. I guess Miss Shields, I'd like to go in the confidential session. And it sounds like just push through and and get through with Mr. Bailey tonight. Do you have a lot of redirect for the public session or should we just go take a quick break and go into confidential session? Mr. Dunbar, do you have a matter?

Mr. Dunbar: Just very briefly, Mr. Chair. You requested that I remind you at the end of the hearing today that Public Service agreed that CCSA's witness Mr. Beech can take the stand on Friday, ideally at the start of the hearing at 9:00. If we're still in the middle of Mr. Bailey, it's fine for Mr. Beech to go after him. But if he could take the stand shortly or take the stand after Mr. Bailey, we would certainly appreciate it.

Chairman Blank: So noted. We will get Mr. Beech on early on June 20th and commit to get to him before lunch, complete him before lunch.

Mr. Dunbar: Thank you so much. I appreciate it. I don't plan to join the confidential session, so appreciate you squeezing that. Thanks.

Chairman Blank: Yeah. Miss Shields, where are you at on redirect?

Miss Shields: Yeah, and Mr. Chair, we do have a fairly significant amount of redirect. But we'd be happy to move into confidential session. And I believe it's highly confidential session.

Chairman Blank: Yeah. How much redirect do you have?

Miss Shields: Probably 30 to 45 minutes. I'd also note that that Commissioner Gilman raised one question about potential identification of the strategic economic development customers. We are working to identify whether we might be able to share that during a restricted highly confidential session pursuant to an existing protective order. That is something that that I don't think we can answer at this very moment, but would hope Friday morning we're able to. And I believe the company is also amendable to starting as as early as everyone's available on Friday morning.

Chairman Blank: Why don't we see if we can knock out the public direct and then maybe we'll start at 8:30 on Friday. So it sounds like it'd be useful to wait until Friday to go into the highly confidential session.

Miss Shields: No, I think what we're specifically asking is we'd prefer to begin with the highly confidential session now, and and then move into the redirect session Friday morning.

Chairman Blank: All right. Let's take a break till 5:45. And then we'll, and then is it Miss Conungle? If we could come back in a highly confidential session, that'd be great.

Miss Conungle: Yes. And before we get back, if Miss Shields, if you can just verify the parties on Zoom are allowed to be in the highly confidential session and then I'll ask again before we get started just to make sure I don't have to remove anyone from the from the Zoom.

Miss Shields: Um, yes, we can do that. And to clarify, I believe that with Mr. Bailey's highly confidential rebuttal testimony and attachments TLB1 and TLB2, those were highly confidential, not restricted highly confidential. But the company will will verify those. We we would certainly ask that parties, everyone who has tuned in, I believe that that means if you have executed a highly confidential NDA, you are authorized to to participate. But but we would certainly appreciate a little bit of self-selection as well.

Mr. Dentman: Yeah, just one question for those of us that don't intend to participate in the highly confidential portion of the hearing. Can we confirm the start time for tomorrow? I I heard 8:30, but not really a confirmation on that.

Chairman Blank: Yeah, let let's just stick to 9 if we could.

Mr. Dentman: Just to clarify, it's not tomorrow, it's Friday. Friday. Sorry, my my apologies. Yeah, thanks.

Chairman Blank: Thanks, Commissioner Gilman. Long day. All right. Let's come back at 5:45 into a highly confidential session. Thanks.