Transcript - Day 4

A.I. Generated with guesses for speakers.

Eric Blank: Good morning. Today is, uh, lucky Friday the 13th, and we’ll see—hopefully, we’re back on the record in Public Service Company of Colorado’s JTS solicitation, 24A442E. Thanks again, Commissioner Gilman, for leading us through last night. I think we’re going to start with Mr. Ming, but preliminary matters first. Miss Cutzer, good morning.

Miss Cutzer: Good morning, Mr. Chair. Nice to see you. I have a couple of preliminary matters for Kosia AEU. The first is, with apologies, we made an error when we turned in our final times to the company on the cross-examination matrix. It won’t affect the overall time, but we mistakenly removed time from a witness and need to switch that for another witness with your permission. It’s not going to affect today; it’s going to be later.

Eric Blank: Can you walk us through it?

Miss Cutzer: Yes, with apologies, let me pull up—I’m having a blank on the names, I’m sorry. Bailey and March?

Mr. Larson: Bailey and Martz.

Miss Cutzer: Thanks, Matt. Brain fog this morning. So, we need to swap Bailey for Martz. That’s bad luck when you need Mr. Larson to bail you out.

Eric Blank: You got me. Bailey and Martz, all right. So, Martz, I have zero, and Bailey, I have 30?

Miss Cutzer: Yeah, so it needs to be opposite. Zero for Bailey and 30 for Martz.

Eric Blank: Correct. Thank you, Mr. Larson.

Miss Cutzer: And the second item I have is, with apologies, I have a hard stop today at 4:30. To the extent that we get to witness Bournehoffen, I’m wondering if the commission can accommodate me performing cross before 4:30, or, you know, if the hearing extends until Tuesday, then do it on Tuesday.

Eric Blank: I think we’re looking for Tuesday, but we’ll certainly accommodate that. That’s no problem.

Miss Cutzer: Great. Thank you for that.

Eric Blank: Other preliminary matters? Mr. Dunbar?

Mr. Dunbar: Thank you, Chair Blank. Good morning. Per your directive to collaborate with the parties on a date certain for CCSA’s witness, Mr. Beach, I collaborated with the company first and then emailed all of the parties yesterday afternoon. I would propose that Mr. Beach take the stand on June 20th, and ideally, if Your Honor is open to it, he could take the stand at 9:00 a.m., first thing at the start of the hearing, and just basically interrupt wherever we are in the hearing at that point. If we’re in the middle of a witness and need to wait until that witness is finished, that’s fine, but that’s the request.

Eric Blank: Just remind me, can you say the day? June 20?

Mr. Dunbar: June 20, CCSA witness Beach, and only staff has reserved time for him—15 minutes.

Eric Blank: All right, yeah, we can certainly accommodate that. If you can just remind all of us the day before, that’d be greatly appreciated.

Mr. Dunbar: We’ll do. Thank you so much.

Eric Blank: No problem. Mr. Larson?

Mr. Larson: Yeah, we don’t have any preliminaries this morning. Mr. Eisenberg is going to be presenting Mr. Ming, so we just need a quick switch here.

Eric Blank: Mr. Eisenberg, switching jerseys. Mr. Ming, you out there?

Mr. Ming: Yes, good morning.

Eric Blank: Can you raise your right hand?

Mr. Ming: Yes.

Eric Blank: You swear to tell the truth, the whole truth, and nothing but the truth?

Mr. Ming: Yes, I do.

Eric Blank: Put your hand down. Is anybody with you or communicating with you in any way?

Mr. Ming: No.

Eric Blank: If that changes, you’ll let us know?

Mr. Ming: Yes.

Eric Blank: Over to you, Mr. Eisenberg.

Mr. Eisenberg: Good morning, Mr. Ming. Can you hear me?

Mr. Ming: Yes.

Mr. Eisenberg: Chair, I’ll make this quick. Mr. Ming’s direct hearing’s exhibit, and he’s available for cross-examination.

Eric Blank: Beautiful. Nice job. Mr. Wolsey, I assume you’re doing the cross for CC, and I have 20 minutes, and it’s 9:05.

Mr. Wolsey: Thank you, Chair. Can you hear me?

Eric Blank: We can.

Mr. Wolsey: Good morning, Mr. Ming. I’m Patrick Wolsey, appearing on behalf of the Conservation Coalition. How are you?

Mr. Ming: Good morning. I’m good. How are you?

Mr. Wolsey: I’d like to start, if we could, by referring to your direct testimony, hearing exhibit 109. If we could pull that up, beginning at page 19, line 22. Here, you state that in the prior company PRM study, the loads and resources of directly neighboring utilities were explicitly modeled, with any excess generation above what was needed to serve their own load made available to the company as market purchases. Then, on page 20, line five, you state that the availability of market purchases was an output of the study, driven by assumptions about loads and resources in neighboring utilities. Do you see that?

Mr. Ming: Yes.

Mr. Wolsey: Mr. Ming, you reviewed the previous PRM and ELCC studies from the 2021 ERP proceeding, correct?

Mr. Ming: Yes.

Mr. Wolsey: And you’re aware that in the 2021 PRM study, the modeling set neighboring utility systems’ reliability at a target loss of load expectation of 0.1 days per year, correct?

Mr. Ming: Yes.

Mr. Wolsey: Mr. Ming, are you aware that in the company’s 2021 ERP proceeding, the commission directed that in the current proceeding, the company’s modeling of off-system purchases must not be limited to the company’s immediate neighbors and must not limit future market purchases based on historical purchases from neighboring systems?

Mr. Ming: Can you point me to the specific reference you’re referring to?

Mr. Wolsey: Sure. I’d like to refer to a document in Conservation Coalition’s box folder. This is proposed hearing exhibit 804. This hasn’t been admitted yet, but this is commission decision number C22-0559 from September of 2022. If we could pull that up from box.

Eric Blank: Yes, give me a second. You said Conservation Coalition?

Mr. Wolsey: This is Conservation Coalition’s box. It’s marked as hearing exhibit 804. Sorry, it’s giving me some trouble.

Mr. Wolsey: Well, one thing that we could do also is, I believe that the passage from that decision that I was going to refer to is also paraphrased in Mr. Landram’s supplemental direct testimony. So, if it’s easier to access Mr. Landram’s supplemental direct, which is hearing exhibit 111, we could also look there.

Eric Blank: Sure, I’ve got that, and I’ll keep looking for 804 in the meantime.

Mr. Wolsey: So, that’s hearing exhibit 111, Mr. Landram’s supplemental direct, at page 52. Starting at line three, it says the commission granted in part and modified in part the directive such that Public Service’s PRM must model all WECC regions, not just immediate neighbors, and shall not limit future market purchases based on historical purchases unless doing so is contrary to best practices. Mr. Ming, you see that?

Mr. Ming: Yes, I do.

Mr. Wolsey: So, that is the passage I was referencing. With that in mind, now I’d like to turn back to your direct testimony, hearing exhibit 109, at page 20, where we left off in that exhibit. I’d like to point out quickly that you omitted the key phrase in your initial question, which was “unless doing so is contrary to best practices.” We’ll get to that in just a moment, Mr. Ming, I promise. If we could turn back to your direct testimony, hearing exhibit 109, at page 20, starting at line 7, you state that the 2024 RA study represents available market purchases from neighboring utilities as an explicit input based on historical average available purchases during the times when energy is most needed. Do you see that?

Mr. Ming: Yes.

Mr. Wolsey: So, the 2024 RA study modeled market purchases from neighbors based solely on historical market purchases, correct?

Mr. Ming: I’m sorry, can you repeat what line you’re on?

Mr. Wolsey: I’m just paraphrasing the sentence that we just read from your direct on page 20 there.

Mr. Ming: Yes.

Mr. Wolsey: And the 2024 RA study did not model market purchases from neighbors based on forward-looking projections of load and resource conditions of neighboring systems, correct?

Mr. Ming: That’s correct.

Mr. Wolsey: Okay. So, isn’t the resource adequacy study’s approach inconsistent with the commission’s directive that we just referenced, that the study shall not limit future market purchases based on historical purchases unless doing so is contrary to best practices?

Mr. Ming: No, it’s not. The specific reason is because of that clause around “unless doing so is contrary to best practices.” That’s why, in my RA study, which is hearing exhibit 109, we explicitly performed a review of how neighboring markets actually treat the availability and dependence upon their neighbors. We reviewed several utilities in the West. You can look beyond that. In fact, best practice is to take a much more conservative approach than just modeling neighbors and assuming that any excess capacity that neighbors have would be available for the specific system. In fact, every utility that we reviewed either does not model their neighbors, or if they do model their neighbors, they apply a very significant derate to that based on operator discretion of what they expect to be able to actually get during times of biggest system stress. That discretion, that operator experience discretion, is based on actual experience of what they have been able to purchase during times of biggest system stress. That necessarily is, you know, experience is, by definition, almost a kind of historical-looking act. I think it’s important to note that part of the reason for looking at discretion and experience is because once you start to get outside of your own system, things get really complex and complicated. Your neighbors, they’re neighbors with more than just you. They’re neighbors with other people on the other sides of them, who are neighbors on the other sides of them. Just because they have excess capacity doesn’t mean that they’re going to make it available to you. They could make it available to another neighbor. It gets extremely complex, risky, uncertain. That’s why the best practice is that nobody does that. So, we did not want to apply a practice that was not best practice in this study.

Mr. Wolsey: So, Mr. Ming, a few minutes ago, we discussed the 2021 PRM study, and we discussed that that study did not limit market purchases based on historical purchases, correct?

Mr. Ming: That is correct.

Mr. Wolsey: So, is it your opinion that the 2021 PRM study was contrary to best practices?

Mr. Ming: Yes.

Mr. Wolsey: Okay. Can we please turn to your rebuttal testimony, hearing exhibit 124? Just so you know, I’ve got your folder fixed. It wasn’t syncing, but I’ve got it now. So, if you need anything, I’m good. If we could go to page 10 in your rebuttal. Mr. Ming, here you note that Mr. Stenlick, a Conservation Coalition witness, and other intervenor witnesses recommend that the company expand its modeling of additional market purchases from neighboring systems in the resource adequacy study, correct?

Mr. Ming: What line are you looking at here?

Mr. Wolsey: Sure, I’m looking at lines 9 to 10 and the accompanying footnote.

Mr. Ming: Okay, yes.

Mr. Wolsey: And you’re aware that the company currently has a case in front of this commission in which it is seeking commission approvals related to joining SPP Markets Plus?

Mr. Ming: Yes, I am aware of that.

Mr. Wolsey: And the resource adequacy study in this proceeding does not contain assumptions designed to reflect the market purchases and sales that would be available to the company under SPP Markets Plus, correct?

Mr. Ming: Can you repeat that question, please?

Mr. Wolsey: Sure. The RA study in this proceeding does not contain assumptions to reflect the market purchases and sales that would be available to the company under SPP Markets Plus, correct?

Mr. Ming: So, I just want to clarify that in a market construct, there is no such thing as market sales and purchases in a market construct. Xcel Energy would be part of a broader market. They would be, through some market design and rules, assigned a capacity requirement, and then they would need to procure specific resources to meet that requirement. Unlike in this study, where Xcel, through discretion, can elect to rely on neighbors, that does not exist in a market construct.

Mr. Wolsey: Well, so, I guess I can rephrase the question. Did the resource adequacy study in this proceeding consider a scenario in which the company has joined SPP Markets Plus?

Mr. Ming: It does not.

Mr. Wolsey: Thank you. So, Mr. Ming, you argue in your testimony that modeling market purchases from neighboring systems would be uncertain and speculative, correct?

Mr. Ming: Yes.

Mr. Wolsey: And are you aware that in the company’s pending commission proceeding regarding SPP Markets Plus, the company estimated the costs and benefits of joining Markets Plus?

Mr. Ming: I’m going to need more specifics on that statement.

Mr. Wolsey: That’s okay, we can move on because we don’t have a whole lot of time. Would you agree that the company’s application in the Markets Plus docket shows that the company’s capable of coming up with estimates of how Markets Plus participation may impact the company’s system?

Mr. Eisenberg: Objection, lacks foundation. That’s in another docket, and the documents in that docket would speak for themselves.

Eric Blank: I guess Mr. Ming can answer if he knows.

Mr. Ming: I’m not familiar with that proceeding, but I will add that the aspect of resource adequacy is quite distinct from many of the other monetary benefits of joining a market. Joining a market has benefits in terms of energy dispatch and cost benefits. It has benefits in terms of being able to avoid transmission costs to ship energy across balancing authorities. It extends far beyond just the specifics that would be needed to quantify the cost benefits of resource adequacy.

Mr. Wolsey: So, Mr. Ming, even if you mentioned that it would be uncertain for the company, that it would be difficult to model market purchases because of uncertainty, couldn’t the resource adequacy study account for that uncertainty by considering a range of scenarios for future market purchases from those utilities rather than representing available market purchases as an explicit input based on a historical average?

Mr. Ming: Again, I feel like this question is conflating two separate issues. Your question appears to be focused on the appropriate value in this study’s construct of how Xcel should rely on neighbors. This study uses a specific assumption—390 megawatts in the summer, 226 megawatts in the winter—based on discretion of the operators. We could have potentially looked at a range of those values. That wouldn’t have been a very interesting result because the more you rely on the market, the more risk the utility is exposed to, and the planning reserve margin just drops on a one-for-one basis. That’s the mechanics of that. Now, that is an entirely separate question from joining a market because, again, if you join a market, those values that I just mentioned go away. They no longer exist, and everything changes in a market. If you say we could have modeled joining a market, there would have been a number of factors that would have needed to be considered: number one, what is the footprint of the market; number two, what are the rules for how capacity requirements and resource accreditation work in that market. Different markets across the U.S. take very different approaches on that. We could have come up with a couple of different scenarios in that regard, but the question is then what do you do with those? Using those could have gone in either direction. If there’s load changes, resource changes, the market purchases go away. It’s not really clear what different scenarios would have done, just making assumptions that directionally could have gone in either direction. It could have made Xcel’s capacity position longer or shorter depending on those assumptions.

Mr. Wolsey: Can we refer to page 11 of your rebuttal, and at line 10, you state it’s possible or even likely that joining an organized wholesale market may impact PRM and ELCC values. Do you see that?

Mr. Ming: Yes.

Mr. Wolsey: But you argue that the company’s future participation in an organized wholesale market is too uncertain or speculative to model at this point, correct?

Mr. Ming: Correct.

Mr. Wolsey: Is it your testimony that it would be technically impossible for the company to model joining an ISO or RTO ahead of time?

Mr. Ming: We could model Xcel joining a wholesale market, but that doesn’t mean that the wholesale market could unfold in any number of ways. A wholesale market could have very different footprints, and depending on the footprint, that affects the load profile of the market, the resources included in the market, and the market rules for how capacity need and resource accreditation are determined. We could have come up with a scenario, but ultimately, that doesn’t mean that scenario is at all what joining a wholesale market would look like. There’s too much uncertainty of how that process unfolds to make that a useful planning criterion.

Mr. Wolsey: Are you aware that in 2021, the commission hired a consultant to prepare a study of the costs and benefits of Colorado utilities joining hypothetical RTOs before specific market rules were in place for those RTOs?

Mr. Ming: Can you please provide more detail on this consultant?

Mr. Wolsey: Sure. We can refer to a document from Conservation Coalition’s box folder. This is marked as hearing exhibit 805. If we could pull that up, it’s a market alternative study from 2021. If we turn to page 15, there’s an executive summary there explaining that Siemens was contracted by the commission to conduct a study on the costs and benefits to utilities, other generators, and customers of alternative organized wholesale market structures, and that included RTOs among others. Do you see that?

Mr. Ming: Yes.

Mr. Wolsey: Doesn’t the existence of that study show that it is possible to analyze the potential impacts of joining an RTO ahead of time, even if you don’t yet know all the details of the RTO?

Mr. Ming: It’s certainly possible to analyze a specific RTO structure, but again, because there are a number of different RTO structures, even directionally, it’s difficult to know how that would compare to the current Xcel or PSCO planning paradigm. Joining a market generally has an effect of reducing the quantity of capacity that each participant needs to procure because there’s load diversity across the entire footprint that you don’t get when you’re just looking at your own system. That generally results in a cost savings to market participants. On the other hand, when you join a market, you actually have to procure capacity to meet that requirement. You can no longer rely on free capacity from relying on your neighbors, which Xcel does in this case, and that is a best practice, and other utilities do that too. What happens is you have these two countervailing factors: the load requirements go down, that’s a benefit, but you no longer have free capacity. The extent to which those two cancel each other out in moving to a market is actually uncertain in terms of even the sign or direction of how that would impact costs. That’s why it’s very dependent upon the assumptions. Just because you can construct a specific scenario with a specific footprint and market rules and get an answer doesn’t mean that’s necessarily useful from a planning perspective.

Mr. Wolsey: Mr. Chair, I’d like to move to admit into the record Conservation Coalition hearing exhibit 805.

Eric Blank: Can you go back to the top again? Is this the Siemens report that was filed?

Mr. Wolsey: Okay.

Mr. Eisenberg: Not particularly relevant to Mr. Ming’s testimony, but I think it’s in the commission’s file, so no objection.

Eric Blank: So moved. You’re getting close to the time, Mr. Wolsey.

Mr. Wolsey: Thank you. I’ll wrap it up, just a couple more questions here. Mr. Ming, in this proceeding, the company didn’t evaluate interregional transmission as a candidate resource to meet its planning reserve margin requirement, correct?

Mr. Ming: Can you repeat the question, please?

Mr. Wolsey: Sure. In this proceeding, the company did not evaluate interregional transmission as a candidate resource to meet its planning reserve margin requirement, correct?

Mr. Ming: That is correct, yes.

Mr. Wolsey: Are you aware that Mr. Landram’s testimony in this case cites the company’s limited interconnections with its neighbors as a reason for the company’s decision to do capacity expansion modeling with market access turned off?

Mr. Ming: I’m loosely familiar with Mr. Landram’s testimony, but I would refer you to Mr. Landram for more details on that.

Mr. Wolsey: Fair enough, we can move on from that. Couldn’t an evaluation of new interregional transmission in the resource adequacy study quantify potential reliability benefits of additional future interconnections?

Mr. Ming: Again, I think that potentially could be studied. It would require a number of assumptions, but ultimately, all of the same issues that I’ve been discussing in terms of the risks and uncertainties on what actually is on the other side of that line are of critical importance. Just building a line without certainty or a guarantee on the generation that’s on the other side of that line presents a unique reliability risk that needs to be considered.

Mr. Wolsey: But, Mr. Ming, is there any technical reason that additional interregional transmission could not be evaluated either as a change to the PRM or by quantifying an ELCC like you would for a generating resource?

Mr. Ming: When you say is there a technical reason, the technical modeling needs some assumption on the types of resources that are on the other side of that line. There’s a lot of uncertainty on those resources, and that’s something that’s not within Xcel’s planning purview or really control. It transcends just technical modeling. There’s a lot of uncertainty and assumptions that go into something like that.

Mr. Wolsey: Thank you. I think the remaining questions I have, I’ll direct to Mr. Landram because you’d referred me to Mr. Landram on a few of these. Mr. Chair, those are all the questions I have.

Eric Blank: Thank you, sir. Let me just see. UCA, I got 30 minutes, Miss Nelson?

Miss Nelson: Yes. Chairman Blank, UCA has decided to waive cross-examination of Mr. Ming.

Eric Blank: All right, thank you. I’m told commission counsel does not have questions for Mr. Ming. Mr. Bunker, if I could?

Mr. Bunker: This is Mr. Bunker for UCA. I would like to take the time we had reserved for Mr. Ming and, if I need the time for Mr. Bailey, I would appreciate that transfer the time over. A number of questions have been passed by Mr. Wolsey to Mr. Bailey, and we will have a highly confidential session as well with Mr. Bailey, so I’d appreciate that.

Eric Blank: Okay. Commissioner Gilman, questions for Mr. Ming?

Megan Gilman: I do. Good morning, Mr. Ming.

Mr. Ming: Good morning.

Megan Gilman: Certain parties argued that the ELCC modeling should include extreme weather events with the risk of correlated outages. In your rebuttal testimony, you explained that the PRM and ELCC modeling already incorporates such extreme weather by mixing together events, even if they haven’t happened at the same time in the historical record. Given that this is the basis of the planning, if there’s a phase 2 portfolio that can go through E3’s RECAP model and meet the 0.1 LLE threshold, would that portfolio meet the generally accepted industry standard for reliability?

Mr. Ming: Yes, I believe it would.

Megan Gilman: Okay. In his testimony, Mr. Lucas points to the extremely high cost of essentially the final 30 minutes or so of that shortfall. He suggests that being more strategic about developing incremental demand flexibility, like perhaps EV charging and BPPs, could be more cost-effective than expensive additional generators to solve for that same time. I was just curious if you had any feedback on his testimony or analysis, or if you understood there to be any major issues with that analysis.

Mr. Ming: There are a couple of points to unpack there. One is on the economic costs of maintaining reliability. What we see when we look across the industry in terms of adhering to a reliability standard is that economics generally are a secondary consideration compared to maintaining a reliable system. There are too many costs associated with blackouts that commissions, regulatory bodies, and utilities across the country want to plan their systems to have a reliable system. The notion that economics might say we actually want a less reliable system is not really an accepted outcome that we’ve seen in commissions across the country. That’s the first point on the economics of planning for a system. The other point is what’s the most economic way to meet a specific reliability standard. We actually do quantify the ability of potentially demand response resources to contribute to the system. For example, if you look at the RA study, which is exhibit 109, attachment ZM1, on page 66, we quantify the incremental ability of, for example, storage resources and demand response resources to contribute. What we see is that those resources, because they’re limited in how long they can dispatch, actually have a relatively limited and declining capacity value or contribution to reliability. That’s simply because the reliability challenge is moving from one of just a peak concern to one that is addressing prolonged low renewable events on the system. It’s not really a question of having a resource that’s available for one, two, three, or even four hours. We see that even if we look at an eight-hour storage resource, once you add 1,000 megawatts of that, its capacity value falls to less than half. Once you add 2,000 megawatts of that, an eight-hour storage resource is only worth 17%. That’s because the reliability need is longer than eight hours. An eight-hour storage resource is just not capable of meeting reliability needs. The corollary for that, for someone who has an electric vehicle that’s flexible, it’s not really a question of whether they can just not charge at 5:00 p.m. and charge at 10:00 p.m. or 3:00 p.m. It’s a question of whether that electric vehicle can not charge for multiple days in a row to get through the prolonged renewable lull event. That’s where it starts to get more challenging in terms of envisioning a world where customers are saying, “Well, I need to drive somewhere, but I’m not going to be able to charge my car for three days until the wind picks back up next week.” That’s where these energy-limited resources and load-shifting capabilities run into limitations, and where the value of firm resources shows a lot of need and value.

Megan Gilman: Does that assume one block of demand response? What if you had varied and dynamic ability to trigger all sorts of different resources in different tranches or intervals to ensure that you can cover a longer duration, perhaps at a different depth?

Mr. Ming: That does not assume one block. It assumes using demand response as flexibly as you can, for example, chaining different events together. But that doesn’t really change the outcome that the value is still limited. If you have to have, for example, 20 different demand response programs that are chained together to equal the value of one firm resource, then that means the value of each individual demand response customer is still only 5% of what a firm resource would be. Even using them as optimally as possible still shows the same limitations on value relative to a firm resource.

Megan Gilman: Okay. I’m curious what constructs you used in that analysis. In Mr. Lucas’s analysis, it indicates the marginal cost of reliability at something close to $300 a kilowatt-hour. I’m curious if, in modeling demand response and the depth of that market, you’ve modeled anything close to that as an incentive.

Mr. Ming: My study does not incorporate economics. It’s planning to just a reliability standard. We’re looking at, if a customer responds in a certain way, assuming that they will regardless of what you have to pay them to do that, what is the reliability value of them responding in that way? We look at, for example, a customer that is willing to shed load up to 80 hours per year. That’s kind of what’s the basis of the 80 hours per year assumption for a customer. That is based on an existing Xcel demand response program, and it’s kind of the program that has the most value. There are multiple different Xcel demand response programs. Some don’t look at 80 hours per year; they look at 40 hours or 20 hours per year. Those would almost by definition yield less value. There are some programs that are only available during certain hours of the year. For example, an air conditioning demand response program obviously is going to provide no value in the winter, whereas this 80-hour program that we looked at, we assume it’s available during all hours of the year and can be called up to 80 hours per year. It’s setting an upper bound for the value that you could expect a demand response program to provide.

Megan Gilman: Do you know the name of the program you modeled?

Mr. Ming: It’s the DSOC, I believe. Is that interruptible?

Megan Gilman: That’s when they completely shut off the power?

Mr. Ming: Yes.

Megan Gilman: Did you do any analysis on how other customers might respond to much higher incentives that more match the value we’re seeing in that last bit of reliability at about $300 a kilowatt-hour?

Mr. Ming: Again, this study does not look at economics. You could imagine a scenario where customers are being paid enough to where they’re willing to curtail for more than 80 hours. If they’re willing to curtail for more than 80 hours, then we would expect the value to continue to increase. But that’s not a program that we evaluated.

Megan Gilman: Okay. So, you’re looking at this in silos in terms of you look at it with the existing program that you know exists under the constructs that have already happened. This is the reliability impact versus looking at this intentionally and strategically around what is the most cost-effective way to solve for the reliability gap?

Mr. Ming: Right. We look at it statically. We look at all of the programs on Xcel’s system and quantify the value of those. That’s in the base system. Then we look at what’s the future potential of demand response, and when we scale that up to 4,000 megawatts—obviously more than any demand response program could actually scale to—we’re scaling the most valuable demand response program, which is a customer that’s willing to curtail up to 80 hours per year, any hour of the year.

Megan Gilman: So, you modeled the most effective program that you’ve seen on Xcel’s system currently with current incentive levels, current assumptions?

Mr. Ming: Yes.

Megan Gilman: Let me switch gears a little. In your rebuttal testimony, you indicated that while it is possible or even likely that joining an OWM may impact PRM and ELCC values, such a scenario is purely speculative at this point. I want to understand a little bit more what you meant by purely speculative, especially given the statutory directive that Public Service must join an OWM before January 1st, 2030.

Mr. Ming: What I meant by that was not that joining the market was purely speculative, but the characteristics of the market—what is the footprint, what are the market rules that govern need and resource accreditation—that’s what would require a significant number of assumptions. Just to give an example, if you look at RTOs across the country, SPP versus MISO, for example, the way that they determine capacity requirements are different. The way that they accredit resources, whether they’re using a marginal construct or an average construct, those are different. Making assumptions about that and applying it is something that would be speculative without direction from a market on how that’s going to work.

Megan Gilman: Okay. In looking at 2030 occurring within the window that we’re planning to, I don’t think there’s anything to scream about that and the statutory directive. I’m curious—I understand that the idea of which market could be speculative and the certain details that would fall from that, but it strikes me that market A versus market B is likely a smaller differential in how you model it and in the outcomes of the modeling than no market to either of those markets. Would you agree with that concept?

Mr. Ming: I actually wouldn’t. Assuming they’re all RTOs or ISOs, I guess.

Megan Gilman: Right, yeah.

Mr. Ming: The reason why I would not agree with that is because, right now, in Xcel’s planning paradigm, they assume reliance on neighbors. That is kind of a proxy for the benefits of a market. Right now, Xcel is not part of a market, but they recognize that physically they’re still connected to their neighbors, and there’s some benefit of that. What joining a market does is create a moment of truth to say, “Is that assumption that we were using for our neighbors—were we being too generous, were we being too strict?” It could go either direction. That’s why it’s not just like joining a market is going to provide definite benefits of procuring less capacity because this reliance on neighbors goes away once you join a market, and it’s fully rationalized in saying, “Was I being too generous or too strict in how much I was relying on neighbors?” That’s a function of, again, the two big uncertainties: the footprint and the market rules. I can’t underscore how important the market rules are in terms of determining that as well.

Megan Gilman: Okay. Looking at a lot of the testimony and analysis about the extraordinary cost of marginal improvements in resource adequacy, it seems to indicate that small modifications in the PRM, even if it’s not a massive shift, could have a pretty significant impact on the amount of capacity needed to satisfy the reliability target. Assuming the commission would order the company to model at least one portfolio in phase two in which the company has joined an ISO or RTO by 2030, do you have any indication of what changes to the PRM or ELCC values you would recommend as a decent proxy?

Mr. Ming: I might need you to rephrase that question a bit. You’re saying, what is the impact on the PRM and ELCC of joining a full RTO or ISO?

Megan Gilman: Yes.

Mr. Ming: Again, the three big changes that would happen if Xcel joins a market are: generally, the capacity requirement goes down because there’s load diversity. Xcel is not just procuring for their own peak; they’re procuring for their share of the broader footprint peak. At the same time, the ability to rely on neighbors goes away. Those counteract each other, so it’s very difficult to speculate on how those would affect each other. Then, the third change is that the ELCC of resources changes. That’s also difficult to speculate on because that’s a function of what all the other resources of the other participants in the market are, what their loads look like, and how all the resources stack up. That’s probably not a very satisfying answer, but it goes back to the fact that more specificity on the details of the market is needed to really understand the impact on resource adequacy.

Megan Gilman: Wouldn’t the ELCCs—assuming, let’s say, going east—wouldn’t there be much more diversity in the geography of the wind that would be included, which could impact ELCC value? Is there any instance where ELCC would get worse with that sort of geographic diversity?

Mr. Ming: It’s possible. For example, you could consider a scenario where, because the more renewables you add, the ELCCs decline. That’s a well-accepted dynamic. If Xcel were to join a market where the participants have a lot of renewables, then renewables within that system are going to be accredited kind of further down the curve than Xcel might be accrediting them for themselves. It’s not really a likely circumstance with the sort of renewable penetration where we’re at. I’m not talking hypotheticals; we’re getting to very high levels of renewable penetration already in this plan.

Megan Gilman: That’s true, but looking at SPP, it’s one of the highest penetration wind areas in the country.

Mr. Ming: Yeah, and most of that wind is located in a different geographic region than most of Xcel’s currently.

Megan Gilman: Right.

Mr. Ming: So, then it would be a question of how that diversity counteracts versus the increased penetration of all the wind that Xcel’s resources are now being accredited within.

Megan Gilman: And is there any—as we look at the modeling that’s been done by the PUC and other parties on the potential costs and benefits of RTO or ISO participation—a significant amount of the benefits appear to come from that lowering of PRM values. Are you contradicting what most of those studies indicate, that it’s likely that the PRM value would reduce in such a circumstance?

Mr. Ming: I think there are counteracting factors there. It is true that the need will go down, but also this free capacity of being able to assume that you can rely on neighbors goes away. The extent to which those—you end up in a better or worse position—is uncertain. If those neighbors all end up in that same market, they’ve already said they’re going to a market.

Megan Gilman: Right, right.

Mr. Ming: Okay. I don’t have any more questions.

Eric Blank: Commissioner Plant?

Tom Plant: Thank you. Good morning, Mr. Ming.

Mr. Ming: Good morning, Commissioner.

Tom Plant: I think Commissioner Gilman got a lot of my questions, but I was confused by a couple of things that I’d like to get some clarification from you. I kind of heard some different answers. One of the things you said is, when PSCO joins a regional market, three things happen: one, the capacity requirement goes down; two, the ability to rely on neighbors goes away. But what I heard you answering to Mr. Wolsey earlier, when he was asking about relying on neighbors, you said you can’t really rely on neighbors because you don’t know that they’re going to sell that capacity to you; they might sell it to one of their neighbors. It sounds like your argument with Mr. Wolsey was that you can’t rely on your neighbors, and when you were talking to Commissioner Gilman, you were saying if we join a regional market, you can’t rely on your neighbors, and we can now. I just wanted to get some clarification on that.

Mr. Ming: Great question, thank you. To be clear, in our study, we do assume that you can rely on neighbors. Specifically, we assume that Xcel can rely on 390 megawatts from neighbors in the summer and 226 megawatts from neighbors in the winter. If you look at that as a percentage of Xcel’s peak load, that’s actually on the higher end relative to what many utilities in the West and in organized markets across the country assume. That’s a pretty generous reliance on neighbors. What I was pushing back on against Mr. Wolsey is the notion that there should be even more reliance on neighbors that’s based on a modeled value that assumes all of the excess energy that they have in any given hour would be made available to Xcel. That’s kind of what a modeling exercise might be able to quantify. Of course, baked into that modeling exercise is a lot of assumptions around future uncertainties, such as what are the loads and resources of your neighbors, and then it obscures a lot of the complexities of—are your neighbors willing to sell that energy to you, or are they going to sell it to their other neighbors on the other side of them? This study does very much assume reliance on neighbors, but it doesn’t assume a reliance on neighbors that would be unduly risky of just modeling all neighbors at a certain portfolio and assuming that all excess energy they have would be made available to Xcel. Our approach in that is in line with industry best practices and how other utilities across the West and even organized wholesale markets treat this particular aspect of resource adequacy.

Tom Plant: In an organized wholesale market, wouldn’t that capacity be sort of combined? You’re saying right now you can’t rely on the state that might have excess capacity selling to you because they might sell it to the neighbor, but doesn’t that excess capacity basically become managed by the wholesale market? While you’re saying right now there’s no rule that says they need to sell it to us, in an organized market, there would be rules around that capacity, and you would know what those rules are, and you’d be able to go to the market to get that capacity?

Mr. Ming: Well, the difference is that in an organized wholesale market, it is true that you can assume all of the resources are available to meet all of the loads, but that doesn’t necessarily mean that all of the loads and resource benefits are going to accrue directly to Xcel. If you just model neighbors and say we assume we’re going to be able to get all of their excess energy, it’s kind of ignoring the fact that that excess energy might actually be needed by somebody else, and it’s going to go in that direction.

Tom Plant: But isn’t it true you’re not just looking at that one neighbor? You’re looking at the whole system, right? So that one neighbor is putting capacity as available into the system, but so are their neighbors, and so is another neighbor, and so is—you know, you’re talking about a much larger pool basically putting capacity into the system that would be available to Xcel.

Mr. Ming: To be clear, when these types of modeling studies are done, they generally don’t go farther than kind of next-door neighbors or maybe next-next-door. But obviously, the system continues on further and further, right? The West—

Tom Plant: You mean if you’re not modeling it within a wholesale market, or do you mean even if you are modeling it within a wholesale market, you’re only looking at your neighbor’s capacity?

Mr. Ming: I’m talking about not in a wholesale market and how you assume the ability of neighbors to contribute. It’s not necessarily the case that if you are modeling it not in a wholesale market and you’re looking at the excess capacity that your neighbors have during specific hours, that is not necessarily the value that would accrue to you in a wholesale market because everybody might be needing that capacity within the market as well. You don’t exactly know where it’s going to go. You would have to look at that.

Tom Plant: I guess that was kind of the point. The way that it’s being modeled now, you’re looking at your neighbor’s available capacity, and you’re saying you’ve got a certain amount of capacity you can rely on from your neighbors, but above that, you don’t know what they’re going to do. They may sell it to somebody else; you can’t really rely on it. Within a larger market, you aren’t constrained by just that neighbor. You’ve got all the capacity of the various participants in the market, which may be next door, it might not be next door—it’s all part of that larger wholesale market. You’re looking at a larger pool of potentially available capacity resources, which, as you said, might be required by somebody else, and there may be various different people dipping into the pool, but it’s a bigger pool. As Commissioner Gilman was saying, you’ve got diversity of generation resources, you’ve got diversity of capacity resources, you’ve got a higher level of diversity in whole, and a larger pool of potentially available capacity. I would think that would actually benefit—I know you don’t do an economic model, but I would think that would benefit an economic analysis of what capacity was required for resource adequacy.

Mr. Ming: I would just reiterate my point that, from an economic perspective, right now, Xcel assumes that they’re able to get that reliance and the benefits of markets for free. That’s the representation of seasonal imports that they just reduce the amount of capacity they need to procure for free. In a market, that goes away. You might expect that value to manifest itself through lower capacity requirements due to the load diversity, but what joining a market really does is provide a moment of truth to understand—was the assumption that they’re assuming for reliance on neighbors through imports, how accurate was that compared to what the modeled market or the market rules actually show them?

Tom Plant: The only observation I make is the neighborhood is bigger in an organized market as opposed to just what we have right now.

Mr. Ming: Right, and the assumed values for the imports, those are based on actual operator experience, which is based on what Xcel has actually been able to purchase when they actually need it. That’s not a function of just the next-door neighbor; that’s a function of what they can actually get, which goes as deep away from the system as they can get it, accounting for all of those factors. That does bake in this—what do neighbors have available? It would be made more organized, obviously, in an organized wholesale market, but I do think that value is not being ignored today. It’s being attempted to be accurately reflected.

Tom Plant: Okay. As it relates to the evaluation in resource adequacy, you don’t do any sort of economic test. You’re not doing any kind of stress testing of PRM against resource adequacy and system cost and all that sort of thing, right? You’re doing a stochastic, like a 40-year weather model or something like that?

Mr. Ming: I might need you to unpack that question a little bit because we do a lot of stochastics. We not only look at 40 weather years, but we actually run that multiple times with different renewable availabilities and different random dispatchable generator forced outages. We ultimately end up with a dataset of hundreds of years of potential conditions. That hundreds of years of data is what we calculate all the metrics on that look at what the peak loads could be and what the resource availability is during the most stressful times. Those determine the need and the ELCC values.

Tom Plant: Is that set on one PRM, or are you running it with various PRMs trying to optimize that?

Mr. Ming: The planning reserve margin is an output of that, so it’s not an input. We calculate those 200 years, and then we add or subtract capacity to those conditions until we get the system to a target level of reliability. Then we look at the amount of capacity on that system that’s at target reliability, and that is the planning reserve margin output of the model that we calculate. For example, the 6% that we use in this study is an output calculated value.

Tom Plant: And that’s not measured against any value metric, like value of lost load or anything like that? There’s no economic analysis on that?

Mr. Ming: That’s correct. That planning reserve margin is the planning reserve margin that’s needed to meet the reliability standard of assuring that there’s no more than one day every 10 years with loss of load, and it’s not based on an economic value for how often loss of load should occur.

Tom Plant: So, if I understand you correctly, when you’re doing your resource adequacy evaluation, the PRM is not an input; it’s an output?

Mr. Ming: Yes.

Tom Plant: You’re taking all the various stochastic scenarios that you described and running it, assuming a certain amount of capacity that might be needed as excess, and then you’re trying to find whatever PRM calculation would get you to your 0.1?

Mr. Ming: Exactly right. The stochastics that we’re running are what are the different load levels that we would expect to see, primarily driven by weather. When it gets hot or cold, loads go up. There are some extreme years that have extremely hot and extremely cold temperatures, and that causes loads to be much higher than average in those years. There’s some planning reserves that are needed to account for those much higher-than-average loads. Then there’s also a need to hold operating reserves on the system above and beyond that load variability. That is what sets the total system planning reserve margin need. We calculate how much capacity is needed to meet all of those extreme loads, and that’s an output of the study.

Tom Plant: You came out with a different PRM seasonally, right?

Mr. Ming: Correct.

Tom Plant: Is that based on different ELCCs for different resources in different seasons?

Mr. Ming: No, that’s actually primarily based on the load variability of peak loads in different seasons. For example, in the summer, the difference between an average year and a hot year and a not-quite-as-hot year is not that different. It might be 98 versus 102 versus 96, or whatever it is. Those temperatures are relatively close, and so the amount of excess reserves that you need to hold for an average peak in the summer versus an extreme peak in the summer is not that different. That’s where we get a 6% planning reserve margin for the summer. In the winter, however, an average cold year might not be that cold, but a really cold year might be 20 or 30 degrees below an average peak year. That can cause loads in the winter during an extreme year to be much higher than the level of variability that you see in the summer. A planning reserve margin is really how much excess do you need compared to an average peak. In the winter, we see much higher variability of what peak loads could be, and that’s what drives higher planning reserve margins in the winter. I will add that if you have a system where most of your heating comes from natural gas, then you don’t really see electric variability in the winter because when it gets cold, that doesn’t increase electric demand; it increases natural gas demand. But Xcel is moving toward a system where there is more electric heating as buildings become electrified and move away from natural gas heating. That creates precisely the type of winter load variability that I’m referring to, and that’s why that value grows over time because the load variability of winter is going to continue to increase as building electrification for heating increases as well.

Tom Plant: So, to get back to the original question, the value of the capacity accreditation of the resources doesn’t differ by season in your model?

Mr. Ming: Sorry, the capacity accreditation for resources also differs by season, but that’s separate from the planning reserve margin. The planning reserve margin is calculated based on how much perfect capacity do you need to meet target reliability in each season. That’s just a function of load variability. Then, perfect capacity—perfect capacity is basically 100% availability, correct?

Tom Plant: It’s kind of a fictitious benchmark resource that is always available, turn it on whenever you need it, run it for as long as you need it, never breaks, no forced outages?

Mr. Ming: That’s the requirement. Once we calculate that requirement for each season, we get a winter and a summer planning reserve margin. Then we can credit resources through ELCC that show how much perfect capacity each resource is worth. That’s what all the ELCC values are, and we can do that for not only thermal resources but renewables, storage, all of that. Then you can just stack up those ELCCs to get to that total perfect capacity requirement in each season. If you do that, then you’re at exactly the target reliability metric of one day in 10 years.

Tom Plant: One of the questions that Commissioner Gilman was asking, as it relates to the distributed resources, that’s not seen by the company really as perfect capacity based on the amount of time that it’s available. For example, if you had a 10-megawatt, 4-hour battery, you would look at that 4 hours as being the constraining piece. You’d look at it at maximum dispatch for 4 hours as how it would go into the model, or would the model consider that, you know, five megawatts at eight hours? Does it reduce the output and extend the time to match whatever the perfect capacity is that you’re looking for, or does it just look at that maximum output for the rated number of hours of the battery?

Mr. Ming: The model uses resources as optimally as it can. For example, let’s say there is a loss of load event that lasts eight hours. A perfect capacity resource would be able to avoid that and would, by definition, have a 100% ELCC. Just to be clear, no resource in existence on planet Earth actually is perfect. Even thermal resources are not 100%, and we calculate the ELCC value of thermal resources. But let’s say you have an 8-hour loss of load event. A perfect capacity resource would be able to 100% avoid that loss of load. Let’s say you have a 4-hour battery. The way the model would handle that is it would say, “Well, a 4-hour resource cannot last across a full eight-hour period.” So, it would dispatch the battery at 50% to make four hours last eight hours, and then it would see that the 4-hour battery has a 50% ELCC. If you built two of those 4-hour batteries and stretched them both across eight hours, then you would get to a perfect capacity resource. That’s where the ELCC of storage comes into play, and you can make that analogy for any resource—demand response, storage, hydro—it’s all being used optimally by the model to meet loss of load as best it can, given the constraints of the resource.

Tom Plant: If I understand correctly, you’re using storage as a proxy for distributed resources?

Mr. Ming: We are looking at demand response, and we calculate the ELCC of demand response separately from storage. It turns out that value is relatively similar to storage because, from a system perspective, they look the same. They’re both what we consider to be energy-limited resources, which means you can use them more or less whenever you need to, but you can’t use them for as long as you need to. They both suffer from that similar limitation. But we are modeling them separately. From a distributed resource perspective, we’re also modeling distributed solar, so we have ELCCs for that as well.

Tom Plant: You were talking a little about if you stack the two batteries together, you’d end up with that 100% perfect capacity. I would imagine if you increased your levels of demand management across more units, more things that are available, whatever those things are that are acting similarly to batteries, then you would be able to achieve that perfect capacity with those resources. Did you ever calculate what that would be—how much capacity would that be of managed distributed energy resources that could deliver that perfect capacity that the resource adequacy model is looking for?

Mr. Ming: We are calculating that. When you talk about distributed energy resources, a demand response program that is available for 80 hours per year is on the upper end of some of the most flexible demand response. There aren’t many loads that are willing to curtail for more than that, that are willing to curtail any time you need, any time of day, any season of the year. So, 80 hours any time throughout the year that you need it is pretty valuable. We look at if you could scale that up to thousands of megawatts, how much would that be able to avoid the need for firm capacity? That’s the ELCC of demand response that we calculate. We show that initially, for the first 500 megawatts, it’s worth 40%. For the next 500 megawatts, it’s also worth 40%. Then, after that, it starts to fall off a cliff—goes down to 12% and ultimately 0% when you get above 2,000 megawatts. The reason for that is just because there’s only so much value that energy-limited resources have. Unless you get a resource that’s willing to dispatch for weeks on end to get through renewable lull events, just being able to rely on those resources for firm energy, there’s a limitation to that.

Tom Plant: I think you’re looking at it as sort of an on-off kind of thing. If you spread that out over thousands of customers or thousands of participants, and you had some being on, some being off, you’re basically managing that resource in a much more dynamic way. That kind of distributed energy resource management is not contemplated in this model, right? It’s more of a demand response on-off ISO kind of model that you’re using?

Mr. Ming: No, what you just described, the management is assumed in our study. We’re not just assuming a 30,000-megawatt block of demand response that’s all on or all off. It actually can spread itself out through management. In fact, the spreading itself out is precisely what causes the reduction in capacity value because when you have to spread yourself out, that lowers the value relative to if everybody’s on at the same time. Maybe the need is one that’s spread out, but that is precisely how the model is using those resources. It’s using them in an optimized, managed way.

Tom Plant: Okay. Thank you very much. I don’t have any further questions.

Eric Blank: I do not have any questions for Mr. Ming. Mr. Eisenberg, redirect?

Mr. Eisenberg: Yes. Thank you, Chair. Just going back to the conversation you were having with Commissioner Plant, Mr. Ming, you mentioned the use of the company’s ISOC program as an input?

Mr. Ming: Yes.

Mr. Eisenberg: The ISOC is the most—that’s a conservative input. It’s taking the most conservative program from the programs the company currently has, right?

Mr. Ming: If you’re using conservative to mean most valuable of all the demand response options, then yes.

Mr. Eisenberg: And a corollary to that is ISOC is also the most generous in terms of the payments because of what it asks customers to do, is that right?

Mr. Ming: Yes.

Mr. Eisenberg: With respect to—you had several questions from Commissioner Gilman, I believe, as well as from Commissioner Plant about the value of unserved energy or the value of reliability. Those questions would be best addressed in terms of dollar values by Mr. Landram, is that where they could ask questions of?

Mr. Ming: Yes, I believe so, because our study does not look at economics or dollar values.

Mr. Eisenberg: There was some discussion with several commissioners as well as with Mr. Wolsey about the reliance on neighbors, and you mentioned the word “risk.” Can you just describe a little more, unpack why more generous assumptions about reliance on neighbors has risk?

Mr. Ming: There’s two components to risk: a physical component and a financial component. From a physical component, we have forward-looking projections of the loads and resources for 2031, which is the time period that Xcel is looking to procure resources for. From a neighbor’s perspective, there’s a lot of uncertainty around what their systems are going to look like in 2031, particularly in the present circumstances that the industry sees itself in—very high load growth, very fast resource transformation. There’s uncertainty about whether the neighbors are going to actually have excess capacity or if they’re going to be catching up from behind on resource adequacy as well. Even if they’re at a target level of reliability, the portfolio of resources they have—are they meeting that target level of reliability with all firm resources, or are they relying a lot on renewable and storage resources? That impacts how much excess capacity they might have available. (Note: The original transcript truncates here, but this appears to be the end of Mr. Ming’s testimony based on context.)

Eric Blank: Thank you. (Transition to next witness, assumed to be Mr. Landram, based on later context.) Let’s move to Mr. Landram. Can you raise your right hand?

Mr. Landram: Yes.

Eric Blank: Do you swear to tell the truth, the whole truth, and nothing but the truth?

Mr. Landram: Yes, I do.

Eric Blank: Is anybody with you or communicating with you in any way?

Mr. Landram: No.

Eric Blank: If that changes, you’ll let us know?

Mr. Landram: Yes.

Eric Blank: Over to you, Mr. Eisenberg.

Mr. Eisenberg: Good afternoon, Mr. Landram. Can you hear me?

Mr. Landram: Yes.

Mr. Eisenberg: Chair, Mr. Landram’s direct hearing exhibit is submitted, and he’s available for cross-examination.

Eric Blank: Thank you. Mr. Foot, I believe you’re up for Healthy Air and Water Colorado?

Mr. Foot: Thank you, Chair. Can you hear me?

Eric Blank: We can.

Mr. Foot: Good afternoon, Mr. Landram. I’m John Foot, representing Healthy Air and Water Colorado. How are you?

Mr. Landram: Good afternoon. I’m well, thank you.

Mr. Foot: I’d like to start with a few questions about emissions from gas plants, as discussed in your testimony and related to Healthy Air and Water Colorado’s answer testimonies. Would you agree that emissions from fossil fuel power plants can be harmful to human health?

Mr. Landram: I think that’s general enough that I have no problem agreeing to it.

Mr. Foot: Putting it a little more specifically, you would agree emissions from gas plants can be harmful to human health?

Mr. Landram: They can be.

Mr. Foot: Emissions from gas plants include, but are not limited to, nitrogen oxides or NOx and particulate matter, correct?

Mr. Landram: Those are some of the emissions from power plants.

Mr. Foot: That’s in addition to carbon dioxide, a totally different emission, though, right?

Mr. Landram: Right.

Mr. Foot: You would have no reason to disagree with Dr. Krooks’s answer testimony that adverse human health impacts of gas plant emissions can include cardiovascular and respiratory health impacts?

Mr. Landram: I have no specific subject matter expertise in this area. I have no reason to agree or disagree, quite honestly, with his assessment. It’s simply not my area of expertise.

Mr. Foot: So, I’m assuming the same answer would be for other impacts, like neurological disorders such as Parkinson’s and Alzheimer’s?

Mr. Landram: That’s correct. I have a layperson’s ability to read what other people write and no other particular knowledge beyond that.

Mr. Foot: Referring again to the Healthy Air and Water Colorado answer testimonies, you don’t have any reason to disagree with Dr. Krooks that the social cost of carbon does not cover the cost estimates of any of those types of health impacts that we just discussed?

Mr. Landram: I do agree with that. The social cost of carbon is exclusively related to carbon dioxide and other greenhouse gases.

Mr. Foot: Right. So, it may cover something like premature death from a heat wave or some kind of excessive heat, but that would be it when it comes to health impacts?

Mr. Landram: I think there are other health impacts that are modeled under the social cost of carbon framework, but to your earlier point, things such as NOx, benzene, etc., are not contemplated under the social cost of carbon.

Mr. Foot: And that would include health impacts from particulate matter as well, correct?

Mr. Landram: That’s correct.

Mr. Foot: You don’t have any reason to disagree with Dr. Krooks’s answer testimony that building a gas plant in a place like the ozone nonattainment area could cause more adverse health impacts than if the same unit was built outside of the ozone nonattainment area?

Mr. Eisenberg: Objection, scope, cumulative. All these questions were already asked to Mr. Ihle.

Eric Blank: It’s certainly within the scope, Mr. Foot, since we’re talking about health impacts and answer testimonies. This is a different witness, and I’m trying to confirm that this witness thinks the same thing as Mr. Ihle did in this particular area.

Mr. Eisenberg: If I could respond, Mr. Chair, the scope of the answer testimony does not define the scope of Mr. Landram’s rebuttal testimony. He’s the director of resource planning; he focuses on the modeling and the way that the carbon proxies flow through that model. This has gone well beyond that to the health impacts that the social cost of carbon is intended to cover.

Eric Blank: I sort of agree, Mr. Foot. You can keep going, but let’s see where you’re going. Can you get there quickly?

Mr. Foot: Sure. Let’s do this, Mr. Landram. Switching back to your testimonies, your direct testimony proposes several locational considerations for new generation facilities, right?

Mr. Landram: Yes. We’ve talked about that, in particular, with the Just Transition credit that’s been discussed a lot.

Mr. Foot: Correct. When I say locational consideration, I’m talking about some kind of incentive or disincentive to locate or not locate certain types of generation facilities in certain places. Does that sound like it describes some of the proposals in your testimonies?

Mr. Landram: It does.

Mr. Foot: Other locational considerations you proposed include avoiding transmission constraints and potentially avoiding new solar facilities in Pueblo, correct?

Mr. Landram: Correct.

Mr. Foot: But your testimonies did not propose any kind of locational consideration for new generation facilities to be built within the ozone nonattainment area, right?

Mr. Landram: It didn’t because it’s not necessary. That’ll take care of itself in the bidding process. All of these generators are bound by permits, and the Air Quality Control Commission will determine what appropriate levels of emissions are allowed in various regions. To get to the chase, a unit in the nonattainment area is going to be permitted at a much lower capacity factor than a unit that is not. That will show up in the bid evaluation process. To my knowledge, there’s not an outright ban on certain resources in the nonattainment area, but there are definitely handicaps that are put into the permit that restrict the operations of that unit and ultimately will make it look less economical. Unless there are other countervailing factors that make that bid attractive, all else being equal, a gas generator in the nonattainment area will be looked at less favorably than a gas unit that’s not in the nonattainment area. I don’t think it’s necessary for us to put exogenous factors in when the permitting process itself and the bidding process itself are going to naturally tease that out.

Mr. Foot: But, Mr. Landram, when you’re talking about submitting an APEN, for example, to the APCD, the APEN itself has the applicant lay out what kind of emissions they are expecting, and then the requirement is you can’t go beyond those particular emissions. That’s the whole point of the APEN, right? So, it doesn’t set a ceiling?

Mr. Landram: I’m not an expert in the permitting process, so I’m not going to go with you into what different stages of that process do or don’t do. I have direct experience with looking at resources in various areas around the Denver area—it’s kind of my job—and I’m well aware of the fact that getting a unit permitted inside the nonattainment area would come with a maximum capacity factor limitation that is less than the allowed capacity factor allowance for a unit that’s not in the nonattainment area.

Mr. Foot: Okay. Don’t you think the commission should have access to that kind of information when it comes to, say, the 120-day report or phase two of this proceeding?

Mr. Landram: They will. That’s part of the bid evaluation process. Environmental permitting and environmental assessment are part of our due diligence process. Part of the bid is, what is my allowed energy, what is my maximum capacity factor? That’ll be an integral part of the bid, and I can assure you, if there’s a gas bid inside the nonattainment area, our environmental people will take a close look at it and make sure that the assumptions regarding that unit that were provided by the bidder are realistic and actionable.

Mr. Foot: So, for certain types of generation facilities like gas plants, you monitor emissions such as sulfur dioxide, NOx, particulate matter, mercury, and carbon dioxide, right?

Mr. Landram: My general understanding is there are continuous emission monitoring devices at various plants measuring different pollutants, and my understanding is it varies from plant to plant and permit requirement to permit requirement. Again, not my area of specific expertise.

Mr. Foot: So, you do measure particulate matter, or does that just depend, according to what you’re saying today?

Mr. Landram: I’m saying I do not know with specificity which plants have continuous emission monitors for particulate matter and which ones do not.

Mr. Foot: Whatever the emissions that are monitored at a particular facility, you do report those emissions to the commission, though, right?

Mr. Landram: I believe so. Again, not specifically in my area of responsibility as far as reporting requirements, so I can’t really tell you for sure if historical emissions are reported to the commission. I know we provide forward-looking emissions for our generic portfolios as part of our phase one requirement in our ERP filing. I’m not the person to ask for what we file on a historical basis.

Mr. Foot: During those occasions where the company is required to monitor particulate matter, it sounds like the company has interpreted that to include monitoring only PM10, correct?

Mr. Eisenberg: Same objection as before—scope, cumulative. Same discussion as with Mr. Ihle.

Eric Blank: We didn’t get into this with Mr. Ihle, Mr. Chair. This also relates to an answer that Mr. Landram gave in one of his discovery responses that’s already been admitted into evidence. Overall, you can keep going.

Mr. Foot: Thank you. My understanding is, where we do have continuous monitors, it’s for PM10. That’s subject to check, and I believe that is probably what was supplied to that discovery request.

Mr. Landram: Okay. So, your understanding is that PM10 and PM2.5 are two different types of emissions, right?

Mr. Foot: I disagree. PM2.5 is a subset of PM10.

Mr. Landram: Okay, different. So, PM2.5 is 2.5 microns, PM10 is 10 microns, does that sound right?

Mr. Foot: It’s less than or equal to those numbers, is my understanding. That sounds fair.

Mr. Landram: Okay. You don’t have any reason to dispute testimony filed by Dr. Krooks that the adverse health impacts of PM2.5 are much greater than the adverse health impacts of PM10, do you?

Mr. Foot: I have no reason to support or rebut that. Health impacts of various pollutants are outside of my area of knowledge.

Mr. Landram: So, what is exactly keeping you from monitoring and reporting this type of particulate matter, that is, PM2.5?

Mr. Foot: I have no idea. I don’t know if it’s even possible to monitor PM2.5. Again, probably the wrong person to ask, and I’m not sure that we have a witness in the case that’s much more versed than I am in these kinds of technical matters.

Mr. Foot: Could we pull up hearing exhibit 1400, attachment JLC3, please? I believe it’s a two-page exhibit. If we could go down to the next page, that would be helpful. Well, I guess the bottom of page one. Mr. Landram, if you want to take a look at this, that’s fine, but I can direct you to the part of the answer that says, “The company has not been required to report the smaller particulates, thus the company followed past practices for this proceeding.” That’s an accurate paraphrase, okay?

Mr. Landram: Right.

Mr. Foot: You didn’t provide any reason as to why the company’s technically incapable of doing so; you just haven’t done it because the commission hasn’t ordered it, right?

Mr. Landram: There’s other discovery on this that goes into more detail. I think this may have been our first answer to a series of questions along this line. The reason we don’t report, aside from the fact that no one’s ever asked us to report PM2.5, is there’s no actual requirement to do so, to my knowledge. We never really even thought about why we would change this time over what we’ve done in the past and been required to do. That’s frankly the real reason—it never even crossed our mind that we should or needed to. Based on other responses that we’ve supplied to you, where our environmental professional people have responded, we don’t have continuous emission monitors for PM2.5. We don’t really test a lot for it. There’s a vacuum of data regarding PM2.5 emissions from specific units, so we really don’t have data to model. For your education, how we report emissions is we put, basically, a meter-ish, if you will, in the data such that for every megawatt-hour of generation, you get X of whatever pollutant. We don’t know that for PM2.5. For a variety of reasons, that’s why we didn’t and haven’t in the past.

Mr. Foot: To wrap this thread up, even though the requirement is that you’re supposed to monitor particulate matter, the company has interpreted that as just monitoring PM10 instead of both PM10 and PM2.5 up to this point, is that correct?

Mr. Landram: I’m not in a position to comment on what the company’s interpretation is. We follow the requirements of the permits that we have and are in compliance with those permits, and that governs our compliance activities.

Mr. Foot: We can take this exhibit down and would ask to pull up hearing exhibit 1403 from the Healthy Air and Water Colorado box, please. You said 1403?

Eric Blank: Yes, thank you.

Mr. Foot: There are several 1403s. There should be a 1403 and then several attachments. Oh, I’m sorry, the attachment number is still in the 1403, so that’s why I thought that was also an attachment. Got it, sorry about that. Mr. Landram, do you recognize this that’s been put in front of you as hearing exhibit 1403?

Mr. Landram: I do.

Mr. Foot: Is this your discovery response to HAWC’s discovery request 4-1, produced on June 2nd?

Mr. Landram: It appears to be. I’ll let you avoid going down to the signature line and take your word for it.

Mr. Foot: Mr. Chair, at this point, I would move to admit hearing exhibit 1403.

Eric Blank: Any objections?

Mr. Eisenberg: No objection, assuming Mr. Landram sponsored these responses.

Mr. Foot: If we could scroll to the bottom, we can just confirm that, but that is the case.

Eric Blank: Great, thank you. No objection, so moved.

Mr. Foot: Thank you. Mr. Landram, we can pull up the individual attachments if you’d like, or if anybody would like, but you indicated at the bottom of this exhibit that there were three attachments—HAWC 4-1.A1, HAWC 4-1.A2, and HAWC 4-1.A3—attached to your discovery response, is that correct?

Mr. Landram: That’s correct.

Mr. Foot: Would you like me to pull them up so you can identify them, or should we just move to admit at this point?

Mr. Landram: That’s up to my lawyer.

Mr. Foot: I guess that wasn’t a fair question for you. I would just move to admit HAWC 4-1.A1, A2, and A3, the three attachments to hearing exhibit 1403 at this point.

Mr. Eisenberg: Mr. Larson, we can stipulate to the admission of those attachments.

Eric Blank: So admitted.

Mr. Foot: Okay, thank you. Hearing exhibit 1403 overlaps with your rebuttal testimony, Mr. Landram, and I think it would be easier to follow along with my questions if we pull up your rebuttal testimony. If we could take this one down and pull up hearing exhibit 118, that would be appreciated. Then go to page 88 of hearing exhibit 118. I assume you meant page 88?

Mr. Landram: Yeah, I’m sorry, yeah, page 88, starting with line six. Mr. Landram, I’d like to ask you a couple of questions about what’s contained on page 88, lines 6 through 16. Did you want to take a second to review that?

Mr. Foot: I can see the first part. Can you please scroll down a couple more to let me see 16?

Mr. Landram: Thank you.

Mr. Foot: Okay, so this is the part of your rebuttal testimony that summarizes your understanding of the answer testimonies of Healthy Air and Water Colorado, right?

Mr. Landram: One part—can you please scroll back up? Looks like from line eight and below is not relevant to this discussion. Thank you. Yes, this part of my testimony is responsive to the issues that your client raised.

Mr. Foot: Great. Okay. I’d like to split this up into four areas for my questions. The way that you summarize HAWC’s answer testimony is, number one, to measure and report primary PM2.5 at its existing facilities, right?

Mr. Landram: Yes, I believe that’s correct.

Mr. Foot: Number two, project primary and secondary PM2.5 for all new gas assets, right?

Mr. Landram: Right.

Mr. Foot: Number three, complete a health impacts analysis related to new gas generation, right?

Mr. Landram: Correct.

Mr. Foot: And four, incorporate the results of a health impacts analysis into Encompass, correct?

Mr. Landram: Correct.

Mr. Foot: Moving down to lines 17 through 22, you gave the company’s response to those recommendations, correct?

Mr. Landram: I’m not sure we’re looking at the same thing. On what I’m looking at, 17 through at least 20, it’s talking about IE communications.

Mr. Foot: Let me look at page 87. Maybe we’re off by one page. Page 87, line 17.

Mr. Landram: Okay, I’m there. Does that look like your response to the recommendations?

Mr. Foot: Yeah, line 17 is the beginning of the question that introduces the company’s response.

Mr. Landram: Great, sorry about that.

Mr. Foot: Okay. In the second line there, you indicated, “Overall, the company believes these recommendations should be directed to state and federal air quality regulators,” right?

Mr. Landram: That’s correct.

Mr. Foot: So, your recommendation is basically that Healthy Air and Water Colorado, or anyone else concerned about health impacts of new fossil fuel facilities, should just direct their concerns to the CDPHE?

Mr. Landram: I’m saying if you want to introduce studies of impacts of emissions on health and that sort of thing, the company does not believe that this is an appropriate forum, much less case, to do that. If you have concerns about the allowable amount of various effluents, that’s better directed to the air quality regulation organizations.

Mr. Foot: So, are you saying it’s just not relevant then to this proceeding here for all these new generation facilities?

Mr. Landram: You’re certainly—the company’s saying anyone’s certainly able to advocate for whatever they desire based on their positions. The company’s position is that a lot of the issues that you raised are best addressed in a different forum.

Mr. Foot: Let me go back and take a look at the recommendations that you summarized here and ask questions about those again. The first part of HAWC’s recommendations, as you summarized them, is for the company to measure and report primary PM2.5 emissions at its existing facilities, right?

Mr. Landram: I do.

Mr. Foot: You agree that the company’s required to measure and report some kind of particulate matter by the PUC already, right?

Mr. Landram: I don’t agree. I think I commented earlier that I’m not involved with that part of the regulatory process, and I can’t tell you if we do or do not submit historical emission data to the Public Utilities Commission.

Mr. Foot: So, you don’t know if the PUC requires that at all?

Mr. Landram: I don’t. On a historical basis, I’m certainly aware of the applicability in the resource planning space as far as reporting requirements of historical information, but that’s completely outside of my purview.

Mr. Foot: Let’s move on to the second part of the recommendations from Healthy Air and Water Colorado, as you summarized them, and that’s for the company to project primary and secondary PM2.5 for all new gas assets, right?

Mr. Landram: Correct.

Mr. Foot: Wouldn’t that be a requirement of a resource plan submitted to the PUC?

Mr. Landram: Not currently, it’s not.

Mr. Foot: What about just particulate matter then?

Mr. Landram: I believe that is a requirement. It’s certainly a requirement in phase one, and we do it in phase two as well.

Mr. Foot: So, obviously, resource plans are squarely within the PUC’s purview, not the CDPHE’s purview, correct?

Mr. Landram: The third part of HAWC’s recommendations, as you’ve summarized them for the company, is to complete a health impacts analysis related to new gas generation, right?

Mr. Foot: Correct.

Mr. Landram: Is it your understanding that the CDPHE doesn’t order permit applicants to conduct an analysis of health cost impacts of the projected emissions in the permit, do they?

Mr. Foot: I’m not aware of what’s required in the CDPHE process, as I’ve said earlier.

Mr. Landram: You testified earlier that you believe that, when it comes to resource plans, the PUC has pretty wide discretion as to what they’re going to order, right?

Mr. Foot: It’s fair.

Mr. Landram: So, this is something that you think would be in the PUC’s purview to order if they found it to be appropriate, correct?

Mr. Eisenberg: Objection, calls for a legal conclusion.

Mr. Landram: I don’t know, honestly, whether it would be or not. I think it might not be a very effective order if it asks for something that we don’t have data on and don’t really have a viable means of complying with. That would be my one comment on that. I’m not going to venture into territory of what the commission can or cannot order.

Mr. Foot: The fourth recommendation was for the company to incorporate the results of the health impacts analysis into Encompass to inform the selection of new gas bids in locations to minimize health impacts, right?

Mr. Landram: I understand that’s your recommendation.

Mr. Foot: So, you would agree that informing what Encompass considers is within the PUC’s purview, right?

Mr. Landram: In that general sense, yes. In the specific sense, I’m not sure what you want modeled. The Encompass model is a numerical model, so you need to quantify that. If you can come up with a social cost of PM2.5 emissions that can be quantified, measured, and valued, that’s something you could model. If it’s a broad health impacts, that’s not something that’s able to be captured in the model. Similar to some of the other things, the company is opposed to this, largely because it’s outside of the purview of what we believe is our responsibility and the existing process, but also because we don’t know what that is exactly and what we’re supposed to be doing to comply with that.

Mr. Foot: I understand that. My questions here are going toward more jurisdiction as opposed to substance because your testimony wasn’t that this is something that should be directed toward the CDPHE and not the PUC, right?

Mr. Landram: We’re saying that if there’s some sort of ban or restriction on adding certain types of technology in certain areas, we believe that the commission should follow the guidelines set forth by the relevant agencies that may already have responsibility in that jurisdiction. To put it bluntly, if you can get a valid air permit from the air quality regulators with certain conditions put on it, we believe that’s the standard of whether a unit could or could not be placed in a certain area.

Eric Blank: We’re about time, Mr. Foot, so if you can wrap up, that’d be great.

Mr. Foot: Thank you. To wrap it up, Mr. Landram, it sounds like these recommendations are something the PUC could consider. It’s just that you’d rather they not consider it, right?

Mr. Landram: Not sure I would characterize it that way, and it’s also getting into a sort of legal opinion. I would say that the commission can make their own conclusions as to what they can and cannot order. I think the company’s position on these is clear in our testimony, and we stand by those positions.

Mr. Foot: Thank you very much, Mr. Landram. I have no further questions.

Eric Blank: Thank you, Mr. Foot. We have 30 minutes for WA and SWEEP, Mr. Barroso?

Mr. Barroso: Thank you, Chair. Can you see and hear me?

Eric Blank: We can.

Mr. Barroso: We both don’t have audio and visual problems now. Good to hear. Good afternoon, Mr. Landram.

Mr. Landram: Good afternoon.

Mr. Barroso: For the record, my name is Park Barroso, and I’m representing WA and SWEEP in this proceeding. Mr. Landram, I’d like to start with just a few lines of questions for you related to modeling assumptions for new thermal units.

Mr. Landram: Can you repeat that last part, please? Modeling assumptions for what?

Mr. Barroso: For new thermal units. Thank you. I’d like to start by discussing the modeled capacity factor for new gas bids in phase two. Do you recall addressing this in your rebuttal testimony in response to Miss Valentine?

Mr. Landram: I do.

Mr. Barroso: Do you also recall that Miss Valentine’s recommendation was to limit the modeled capacity factor to 40%?

Mr. Landram: I do.

Mr. Barroso: The justification for that was that current EPA regulations require certain emission reduction controls for base load units, which are gas units that have a capacity factor above 40%. Does that sound right?

Mr. Landram: Yes.

Mr. Barroso: The company does not agree with including a 40% capacity factor in the modeling?

Mr. Landram: I don’t necessarily agree with that. The company believes in enforcing appropriate capacity factor limits based on whatever regulations are in place at the time that we do this. As of currently, those regulations are in place. I think the company’s response is more nuanced in that we don’t necessarily believe that we should put those in the model as hard constraints at first. Let’s see what happens, and if there is a situation where a unit is running at a capacity factor that is above the threshold where it would, for instance, require carbon capture and storage, loop back and either put the capacity factor limit in at that point in time or perhaps put in a carbon capture and storage unit, although I think the former is the most likely outcome. The reason for that is purely modeling efficiency. Constraints add complexity to the model, and complexity adds time. Adding in a constraint that’s actually not binding just slows down the model upfront for no gain. Our approach is, let’s start, and we do this for a variety of things like this where we have non-binding constraints. We have existing units that have permit limits and operations; we do the same thing—start without it, see if it’s a factor, if it’s a factor, go ahead and add it in, somewhat begrudgingly because it penalizes runtime, and rerun the model.

Mr. Barroso: Thank you for that clarification. Picking up on one phrase you mentioned in that example, which was a non-binding constraint, I think you gave the example of a permit limit that might impose a particular constraint on a unit, and that if that limit were triggered, you would go back and rerun the modeling, is that right?

Mr. Landram: That’s exactly right. By non-binding, I mean a constraint that’s there, but the unit never gets there anyway, so adding the constraint into the structure of the model does nothing except slow things down.

Mr. Barroso: If the company takes the approach that you’re talking about, which is not adding the constraint in the first instance but going back and adding it if something happens when the model tries to run, how would the company communicate to the commission and to the parties that it had done the modeling in that way?

Mr. Landram: That’s purely an internal modeling process that I don’t think is even close to worthy of notifying anybody about. At the end of the day, the modeling that we produce would be in compliance with applicable limitations in current regulation. How we get there is, quite frankly, our business, in my opinion, certainly in an instance like this where we’re talking about a modeling technique to get to a desired outcome.

Mr. Barroso: So, you wouldn’t be providing notice of that, but can you commit here now that if a unit is hitting the 40% limit, the company is going to go back and remodel with that capacity factor limit?

Mr. Landram: Yes, we’re going to provide results that are compliant with current regulation and law.

Mr. Barroso: Great, thank you. A question related to this, but in the phase 2 framework scenario, and I’m assuming your answers are going to be the same, would the same capacity factor approach apply to the incremental need pool modeling and to the supplemental RFP?

Mr. Landram: Again, the incremental need pool and everything else will be subject to current regulation and law. Through the incremental need pool, if the company’s activating a bid or multiple bids to meet a large customer’s needs, the company would also impose a 40% capacity factor limit on any new gas resources that are activated?

Mr. Barroso: I’m not going to agree with you, probably ever, on this 40% hard number. I’m going to continue to emphasize “as current law” because, as we both know, things are constantly changing. We will absolutely present any analysis in accordance with appropriate regulation and law, and we’re not going to present results that are inconsistent with something that actually achieves. If the 40% or carbon capture provision is still in place when we’re doing the incremental need pool, absolutely, we’re going to either limit it to 40% or we’re going to put carbon capture, if that’s what the law is at that point in time.

Mr. Barroso: That is helpful, thank you. Changing topics slightly now, Mr. Landram, you discussed the company’s assumptions related to hydrogen with Miss Vitali, so I just have, I think, two questions for you here. Question one: Is it your or the company’s position that hydrogen transportation costs in reality will be zero?

Mr. Landram: It’s the company’s position that we have no idea if hydrogen will even be transported, much less what the cost of it will be. From an engineering perspective, I can envision—in fact, I would think the preferred design might likely be an on-site electrolyzer. As I said before, transporting electricity to run the electrolyzer uses known technology, and, you know, I know we’re talking about transmission costs a lot, but compared to hydrogen pipelines, it’s a relatively reasonable cost. If that is the case, that you build an on-site electrolyzer and transport the electricity instead of the hydrogen, zero transportation costs.

Mr. Barroso: Maybe let’s put it a different way. On balance, do you think it’s more reasonable to assume that the costs will be zero or that there will be some level of cost for hydrogen transportation?

Mr. Landram: For the reasons I laid out here and before, I think zero is an appropriate assumption for this exercise of what we’re doing here.

Mr. Barroso: Speaking of this exercise, are you aware that other Colorado utilities, Tri-State for example, do include the transportation cost for hydrogen in their generic modeling?

Mr. Landram: I’m aware because of reading your testimony, not because I read it myself.

Mr. Barroso: Glad to hear that you read it, thank you. If we could please pull up hearing exhibit 1307 from SWEEP’s box. Mr. Landram, this is the company’s response to discovery request WA-SWEEP 1-35. We can zoom in if we need, but do you see there that you’re the sponsor of this response?

Mr. Landram: I am.

Mr. Barroso: Mr. Chair, I’d like to move for admission of hearing exhibit 1307.

Eric Blank: Any objection?

Mr. Eisenberg: No objection.

Eric Blank: So moved.

Mr. Barroso: Great, thank you. Changing topics now, Mr. Landram, to talk about the load forecast. You’ve testified that the company views it as important to settle on a single load forecast to use in phase two here in phase one. Does that sound right?

Mr. Landram: That does.

Mr. Barroso: Are we still talking about this discovery response?

Mr. Landram: Oh, we are not. We can pull this down, thank you.

Mr. Barroso: Yes, great. Specific to the large load component of that load forecast, the company’s preference is that the commission approve now a particular level of load in phase one based on the number of expected large load customers and the company’s assigned probability to each of those customers, is that right?

Mr. Landram: That’s basically correct. Our position has continued to evolve. The most recent and relevant position is in the tri-party framework, I think we’re calling it. But my rebuttal testimony, where I’m advocating for deciding the load forecast now, absolutely stands.

Mr. Barroso: Great, thank you. On that point of deciding now, what do you envision happening if a customer or customers drop out—customers that were included in the load forecast in this phase one decision—they drop out between the phase one decision and some point in phase two?

Mr. Landram: Good question. First of all, we’ll refresh the load forecast using the methodologies agreed upon in this phase one as close as possible to the release of the RFP. It’s in our interest to be as accurate as we can, and accuracy is timeliness in this case. There will be a refresh of the load forecast. If something changes between now and, I don’t know, whenever we release the RFP—call it January, February—that’ll be captured. I think Mr. Ihle has already talked about the fact that, if we go in with a lower probability assessment for the forecast than what we originally had in our direct case, we’re proposing to use the 80% or higher. Based on updating right before the RFP, we feel we’re reducing the chances of having a load drop out. I agree with Mr. Ihle that, if a load does drop out and we end up somehow getting all the way through the phase two process of the base RFP, and we end up a little bit long, remember that long is going to be two, three, four years from now because we have to build the thing, go through CPCN, CPA negotiations, and all that. To me, the risk, if a load or two drops out, by the time that resource finally comes online, you’re going to regret that decision, I think, is low. I think the worst-case scenario is that we would grow into that over a period of one to two, maybe three years. More likely, another large load would come along and snap it up as soon as it’s available. We’re not talking about stranded costs here. We’re talking about, worst-case scenario, getting a little bit ahead of the reliability curve, which, from my experience, would be exceedingly refreshing and for a limited period of time until you would grow into it in very short order with our forecasts of electric vehicle growth, beneficial electrification, and else. There isn’t going to be a stranded cost for very long from being a little bit long. In addition, joining a wholesale market gives a great opportunity to monetize that length via sales to other entities, thereby even further reducing the risk of being a little bit long for a while.

Mr. Barroso: A lot to unpack there. Going back to the forecasting mechanics, you said something to the effect of, if there’s a change before the RFP is issued, that will be captured in the forecast. If a load drops below the 80%, if that’s the approved threshold, it would not be included in the forecast?

Mr. Landram: That’s correct. With a reasonable timeframe—if they literally drop out the day before we issue the RFP, there just may not be time. But the intention is to absolutely update that forecast to the best of our current information as close as possible to issuing the RFP.

Mr. Barroso: Following up on that, is the issuance of the RFP when you envision that would be the last point at which you would update the forecast for that particular RFP?

Mr. Landram: Yes. It would not happen, for example, when you go to do computer-based modeling of bids that come back. That’s not the intention. There is an opportunity to do that through consultation with the IE if there was something that was so meaningful that had changed, that we had information on, where we would just be wasting our time going through the evaluation process. We could work with the IE to come up with a resolution to that and do a kind of contemporaneous load forecast adjustment, I guess. But that is by no means expected or contemplated. That would be more of a “break glass in case of emergency” approach in case something happened that was very unforeseen.

Mr. Barroso: Sometimes it’s good to have that glass there to break. Let’s say, in terms of a meaningful change, a 300-megawatt customer drops below 80% after the time the RFP has been issued. Would that be a meaningful change?

Mr. Landram: I hate to speculate on exact numbers here. It kind of depends, so I’m not prepared to issue a bright line as to where we would or where we wouldn’t at this point.

Mr. Barroso: Could the commission provide guidance on at what point the load forecast should be updated after issuance of the RFP?

Mr. Landram: They could, but understand that if you change the load forecast, you basically start over on the 120-day clock because—well, it depends on where you are in the modeling process. We have the initial work of due diligence and all, which doesn’t have to start over, but if you’re modeling and you change the load forecast, you go right back to day zero of the modeling process. That’s going to be something that we’re not going to undertake half-hazardly. It’s got to be something that fundamentally changes it for us to do that. At the end of the day, it might end up being better to just go through the evaluation process and talk about it in the 120-day report.

Mr. Barroso: Fair enough. When you say talk about it in the 120-day report, that doesn’t mean remodeling portfolios based on a different forecast, right? That means comments back and forth between the company and parties?

Mr. Landram: It may vary. It depends on the situation. We’re talking about complete hypotheticals here, right? How big is the change, when does it happen, is it a delay, is it a cancellation? There’s so many hypotheticals there, it’s hard to nail things down. But I think we’d be open and transparent, and if we’re presenting portfolios that, for some reason, aren’t relevant to the world that we know as of that time, of course, we would be open and transparent about it and propose options of how to move forward.

Mr. Barroso: I think you and I will probably have a difference of opinion on the conclusion to draw from this, but would you agree that, because of the modeling time and some of the impacts downstream that we’re talking about, it’s important to get the forecast right, whatever that forecast is, before the RFP is issued?

Mr. Landram: I think it’s important to get it as right as you can. I would put back to you that we’re never going to get the forecast right—never have, never will. We do the best effort we can based on the information we have at the time, and we move forward to actionable steps to implement the priorities of the state, the commission, the company, and the stakeholders. We’re never going to get it right.

Mr. Barroso: Thank you, Mr. Landram. Don’t undersell yourself.

Mr. Landram: I’m appreciating the humility, Mr. Barroso. Believe me, if I could get it right, I could find a lot of better ways to make money than here.

Mr. Barroso: Just trying to keep it light here. Thank you, Mr. Landram. Same questions here for the supplemental RFP as part of the phase 2 framework. Would you expect the same timing to hold for updating the load forecast for that?

Mr. Landram: Absolutely. We’ll update the assumptions, update the load forecast as close as practicable to the start of the issuance of the RFP. Consistent with past practices and the base RFP, we would file our updated assumptions at the time of, or very near the time of, issuing the RFP. Very similar timeline, just for the next RFP as well.

Mr. Barroso: Okay, thank you. Last line of questioning here, moving to the incremental need pool portion of the phase 2 framework. Were you listening to Mr. Ihle’s testimony earlier in the hearing?

Mr. Landram: Yes.

Mr. Barroso: You might not have a perfect recollection of all of it, but as a refresher, I had a discussion with Mr. Ihle on the portfolio or the bid modeling that will happen through the INP.

Mr. Landram: Yes.

Mr. Barroso: In that discussion, Mr. Ihle confirmed that the company’s intent is to not model or to not present multiple portfolios when it’s activating the INP. Does that match your understanding?

Mr. Landram: Generally.

Mr. Barroso: Thank you. I asked in that same discussion what action the commission would take in response to the INP, and Mr. Ihle’s answer was that, presumably, the commission could either approve, deny, or modify that portfolio. Does that also match your understanding?

Mr. Landram: It does.

Mr. Barroso: Great. I want to ask you a few questions about that “modify” piece. Let’s say the INP is being activated in response to a large load customer, and that customer is interconnecting on a particular part of the system. For a portfolio that’s modeled through the INP process, would the company be optimizing the selected bids for reliability and for locationally specific needs?

Mr. Landram: Optimize—I’m struggling with optimize. Are you talking about running the Encompass model, or what do you mean by that?

Mr. Barroso: Sure, I can ask it a different way. When constructing the portfolio of bids to meet that customer’s need, would you be selecting bids based on location on the system?

Mr. Landram: Potentially, yes. If there is a bid that was located nearby to the load, that would most likely avoid some portion of transmission costs. That absolutely would be a factor in our decision-making as to where to activate a bid—not the only one, but certainly a factor.

Mr. Barroso: Could you walk through what those other factors might be?

Mr. Landram: Cost is a high one. Matching the need as reasonably close as possible without being under, so, in other words, not over-procuring any more than necessary. Minimizing emissions impacts—we’ve already talked about cost, so that goes hand-in-hand with customer costs. Ultimately, the reliability, which would be that the accredited capacity needs to equal the amount of accredited capacity necessary to bring the load and resources table back into balance.

Mr. Barroso: Thank you. On that reliability factor, it’s more of a—you’re matching the load and resource table to this new load. In other words, you’re adding resources to make the load and the resources equal out, is the intent?

Mr. Landram: Yeah. To put it simply, if the incremental load or the bid failure causes us to be under the reliability target, there’s a certain amount of megawatts of firm capacity that are required to bring you back to that target, and we would ensure that we bring forward enough accredited megawatts to equal that requirement.

Mr. Barroso: The question I’m trying to get to here is, if the commission is in a position where it’s modifying the INP portfolio, would the commission be able to select different bids so long as they add up to that right number?

Mr. Landram: That’s our proposal, yes.

Mr. Barroso: Sorry, that was a yes? I didn’t mean to talk over you.

Mr. Landram: Yes, I’m sorry if I interrupted you in the middle of your question.

Mr. Barroso: Thank you. Just to confirm, yes, the commission could select a different bid if capacity was sufficient, correct?

Mr. Landram: Okay.

Mr. Barroso: Just looking at my notes here, I think last clerical matter for you, Mr. Landram. Could we please pull up hearing exhibit 1310 from WA and SWEEP’s box? While we’re pulling that up, this is the company’s response to discovery request SWEEP 1-43.

Eric Blank: Great, thank you.

Mr. Barroso: Scrolling quickly to the bottom here, Mr. Landram, do you see that you’re the sponsor?

Mr. Landram: Yes.

Mr. Barroso: I move for admission of hearing exhibit 1310.

Eric Blank: Any objection?

Mr. Eisenberg: No objection.

Eric Blank: So moved.

Mr. Barroso: Thank you. We can pull that down, and Mr. Landram, I have no further questions for you. Thank you for your time.

Mr. Landram: Thank you.

Eric Blank: Thank you, Mr. Barroso. I have 30 minutes for UCA, Miss Nelson?

Miss Nelson: Yes, thank you, Mr. Chair. Good afternoon, Mr. Landram. Good to see you.

Mr. Landram: Good to see you too, Miss Nelson.

Miss Nelson: I have the unenviable position of standing between all of us and the weekend, so I’m going to keep it short. I’m going to go through three different topics with you real briefly: the transmission adder, some of the modeling issues that UCA ran into with the Encompass model, and then the distribution credit that was addressed in your supplemental testimony. Do you have those in mind?

Mr. Landram: No.

Miss Nelson: Okay, so real quick on the transmission adder. You’ve had so much discussion over the day on how it works, the purpose of it, etc. There was a key theme that I thought came through that I would like to have succinct in the record. I just have two questions. One, do you agree that Public Service’s ratepayers benefit from cost savings associated with avoiding new transmission?

Mr. Landram: I do.

Miss Nelson: Following up on that, do you also agree that Public Service’s ratepayers benefit from avoided costs when generation is located where it avoids the need for new transmission?

Mr. Landram: I also agree with that.

Miss Nelson: Thank you. That’s all I had on that topic. Now, as far as UCA’s issues with running the Encompass model, have you heard the idiom “two pairs of eyes are better than one”?

Mr. Landram: I have.

Miss Nelson: Do you understand it generally to mean that observation by two or more people is better than one?

Mr. Landram: I understand that’s the meaning of the idiom.

Miss Nelson: The idiom “two heads are better than one” conveys a similar message, doesn’t it?

Mr. Landram: It does.

Miss Nelson: We don’t have to pull these exhibits up as I talk, but if you would benefit from it, we’re happy to pull them up. I just thought it’d save time if we didn’t. Is it true that you have reviewed the answer testimony of UCA witness Chelsea Hotailing?

Mr. Landram: It is.

Miss Nelson: Did you happen to review Miss Hotailing’s CV?

Mr. Landram: Yes.

Miss Nelson: Are you aware that her education includes a bachelor’s degree in accounting and economics?

Mr. Landram: I don’t remember her CV specifically, but I will take your word for it.

Miss Nelson: She also has master’s degrees—three master’s degrees, including an MBA in environmental management, an MBA in environmental policy and governance, and a master’s in data analytics?

Mr. Landram: I’ll assume that’s correct.

Miss Nelson: Are you aware that her current work is focused on integrated resource planning, including capacity expansion, production cost modeling, and load forecasting?

Mr. Landram: Yes.

Miss Nelson: You’re aware that she’s experienced in running the Encompass model, correct?

Mr. Landram: I don’t know the depth of her experience. I do know that she has had some experience. I’ve actually worked with Miss Hotailing in the past and in other jurisdictions.

Miss Nelson: Are you familiar with Miss Hotailing’s observations in her testimony that Public Service’s new capacity expansion planning process requires additional time for modeling?

Mr. Landram: I am.

Miss Nelson: Are you familiar with her observations that alternative model runs for the company’s Encompass model in this case involved long run times?

Mr. Landram: Yes, I’m aware that she experienced run times that appeared to be in excess of ours, and ours aren’t necessarily short to start with.

Miss Nelson: She observed a single capacity expansion model run took almost a week?

Mr. Landram: That’s not out of the realm of expectations for us either. It’s not necessarily that all of them take a week, but it’s not unexpected that at least some of them will.

Miss Nelson: Would you recall that she testified that Public Service’s new modeling approach and its associated runtime represented a barrier for her being able to develop alternative modeling runs that explored changes to the modeling inputs presumed by PSCO?

Mr. Landram: I’m aware that she ran into challenges because the model runs were so long for her to prepare alternative runs representing UCA’s inputs.

Miss Nelson: Are you also aware that Miss Hotailing provided Encompass datasets as attachments to her original answer testimony and asked Public Service to prepare the alternate model runs to help expedite the process for performing the runs?

Mr. Landram: Yes, I’m aware. Unfortunately, we had 30 days between answer and rebuttal, and there’s just simply not enough time to first understand what she’s asking, much less run it and write it up. The 30 days is just not enough to go through that process.

Miss Nelson: Miss Crane, can you pull up hearing exhibit 312 from UCA’s box folder? Could you make it a little bigger? Thank you. Mr. Landram, would you identify this document?

Mr. Landram: This is the company’s response to Kosia AU15-1.

Miss Nelson: Are you the sponsor of this exhibit?

Mr. Landram: I am.

Miss Nelson: Mr. Chair, I move for admission of UCA hearing exhibit 312.

Eric Blank: Any objection?

Mr. Eisenberg: No objection.

Eric Blank: So moved.

Miss Nelson: I’m going to focus on—let’s start with subpart A. The question asks PSCO to confirm that to produce additional data beyond what the company has provided with the provided Encompass database requires an intervenor to purchase an Encompass license. If denied, please explain. Your answer there is “confirmed,” that’s correct?

Mr. Landram: That’s correct.

Miss Nelson: In part B, you state that the company did not provide Encompass licenses to any party in this proceeding, correct?

Mr. Landram: Correct.

Miss Nelson: Finally, in response to how much the company pays for its Encompass license, you state that the company paid $65,000 for its most recent annual subscription to Encompass, and it’s not a per-user fee, correct?

Mr. Landram: Correct.

Miss Nelson: Just as an aside, is that cost recovered from Public Service’s ratepayers?

Mr. Landram: I believe—I don’t know the accounting treatment of it. I’m going to leave it at that. I honestly don’t know.

Miss Nelson: How many total users does PSCO have to run the Encompass model?

Mr. Landram: It varies with employee churn. Typically, we have between six and eight analysts that are on the team whose primary job function is to run Encompass. That covers all Xcel Energy operating companies.

Miss Nelson: I want to clarify—that was going to be my next question. You’re breaking up a little bit for me, Mr. Landram. Could you just repeat what you said?

Mr. Landram: Sure, I think we might have been talking over each other a little bit. The six to eight people is for all of Xcel Energy operating companies. It’s not strictly focused on Colorado or PSCO.

Miss Nelson: For this proceeding, did you have those six to eight people available to run model runs?

Mr. Landram: We had two, plus a leader who was partly engaged, but actual analysts preparing data and running models, there were two of them who were primarily assigned to this function.

Miss Nelson: You said that the company did not run Miss Hotailing’s alternate model runs with the inputs that she provided in her answer testimony, that’s correct?

Mr. Landram: That’s correct.

Miss Nelson: Do you recall that Miss Hotailing also made recommendations regarding how to address her concerns relating to long run times in future proceedings?

Mr. Landram: I do.

Miss Nelson: She asked that PSCO provide datasets to accompany the Encompass database, similar to what was provided in response to discovery in this proceeding?

Mr. Landram: I do, and I can say that the company is happy to do so.

Miss Nelson: Actually, in your rebuttal testimony, you agree with that recommendation, correct?

Mr. Landram: That’s correct.

Miss Nelson: You also agree with the recommendation from Miss Hotailing that if Public Service developed any datasets to address infeasibilities that occurred in its modeling runs, PSCO would note that information in the workpapers so that intervenors can easily identify those datasets in the database, correct?

Mr. Landram: That’s correct.

Miss Nelson: Since you agreed to these recommendations in your rebuttal testimony, would you state whether the company would have an objection to the commission including these two requirements in its order in this case for future proceedings?

Mr. Landram: No, we have no objection to that. I think it’s a relatively narrowly focused issue that may or may not have repeatability associated with it. I’ll leave that to the commission to determine. We have no objection either way.

Miss Nelson: Thank you, Mr. Landram. My last line of questioning, and hopefully it’ll go quick—distribution credits. I would like to pull up your testimony for this line of questions, hearing exhibit 111. It’s your supplemental direct testimony. Please go to page 23. Thank you. Can you just blow it up a little bit and scroll up? I’m going to focus on lines nine and lower. Thank you, Miss Crane. Here, Mr. Landram, you talk about new proposed locational factors that you provided for the first time in your supplemental direct, correct?

Mr. Landram: That’s correct.

Miss Nelson: You state, starting on line 12, that subsequent to the filing of the direct case, the company has filed its proposed VPP tariff in proceeding number 25A0061E, correct?

Mr. Landram: Correct.

Miss Nelson: What does VPP stand for?

Mr. Landram: Virtual power plant. It goes by various names—aggregated distributed energy resources are synonymous.

Miss Nelson: For purposes of my questions, I’m just going to refer to it as the virtual power proceeding. Is that okay?

Mr. Landram: That’s fine with me.

Miss Nelson: You say, consistent with the methodology in that filing, the company is now proposing that the distribution credit of $69 per kilowatt per year used in the cost development of the VPP tariff also be used for eligible distribution-connected bids in phase two in this proceeding. Did I read that correctly?

Mr. Landram: You did.

Miss Nelson: As in the VPP tariff, this credit would be applied for the first five years of operation and would only be used for bids on the affected feeder list and subject to the criteria discussed in the VPP tariff filing, correct?

Mr. Landram: Correct.

Miss Nelson: You propose using the same feeder list in this proceeding that is used for that tariff, right?

Mr. Landram: Correct.

Miss Nelson: You say the list is not finalized yet but should be finalized by phase two, correct?

Mr. Landram: Correct.

Miss Nelson: The feeder list will be made accessible to bidders through the same process that supports the VPP tariff, correct?

Mr. Landram: Okay. In other words, the feeder list that’s included in the VPP proceeding is the same list that’s going to be available for bidders to see where the distribution credits are going to be available for the bidding in this proceeding for the JTS?

Miss Nelson: I think I generally agree. What we’re proposing is that there’s going to be a methodology in place for entities that wish to procure service under the VPP tariff to acquire this information. Rather than duplicating that process, we are going to direct potential VPP bidders in phase two to acquire the information through the exact same channel and process that works for the VPP tariff.

Miss Nelson: Is the support for the $69 per kilowatt per year distribution credit included anywhere in this proceeding?

Mr. Landram: No, we’re referring to the proceeding that’s listed here, 25A0061E, for the foundation for that. In addition, Mr. Zachary Pollock, who is one of our lead witnesses in that and was directly responsible for leading the effort leading up to that tariff filing, we have added to the witness list in this proceeding. I think through rebuttal testimony—I don’t think he had supplemental direct. He is a witness in this case now, and he is definitely one of our company’s leading experts on all things VPPs and distribution-related. We added him to the case specifically to be able to answer questions on the support for the $69 distribution credit amount.

Miss Nelson: The feeder list that you refer to here in your testimony is not anywhere in this record yet, is it?

Mr. Landram: It is not.

Miss Nelson: Can we pull up hearing exhibit 310 from UCA’s box?

Eric Blank: We can go right to—

Miss Nelson: Mr. Landram, would you identify this for the record, please?

Mr. Landram: This is hearing exhibit 310, direct testimony of Mr. Zachary Pollock in proceeding 25A0061E.

Miss Nelson: That’s the VPP proceeding that you talk about in your testimony in this section we’ve been discussing, correct?

Mr. Landram: Can we turn to page 26, please, line 16, and yes, then continuing at the top of page 27? The Q&A that starts on line 16 on page 26 talks about how the company developed the distribution credit that you allude to and refer to in your testimony, correct?

Miss Nelson: Correct.

Mr. Landram: Can we move to page 26? There’s a table, ZDP-D2. Mr. Landram, would you confirm that this table talks about or outlines the feeders and banks eligible for the distribution credit that you’re referring to in your testimony?

Miss Nelson: The title of this chart leads me to believe that’s correct. I really can’t verify one way or the other. This is not my testimony; I’m not a witness in this case. I will say that these questions might be best asked to Mr. Pollock, who not only is this his testimony, he’s a witness in this case, and he’ll be coming up later.

Mr. Landram: All I was trying to do was put some information in the record that actually supports the testimony that we just walked through with you on page 23 of your supplemental direct testimony. That’s just the point of why I’m going through this. In lines 3 through 6, Mr. Pollock states that the feeders and banks that would be eligible for the distribution system capacity value would be included in confidential attachment ZDP-2C, correct?

Miss Nelson: Correct.

Mr. Landram: Is that the list of feeders that you refer to on lines 19 through 21 of your testimony on page 23?

Miss Nelson: This attachment is the current list of feeders. Whether that’s exactly the list that would be used in phase two or not depends on how this list may or may not evolve and, frankly, the outcomes of the VPP tariff proceeding. But in general, yes, when I’m talking about an affected feeder list, this is the information that I’m talking about that would be the reference data for that.

Miss Nelson: Thank you, Mr. Landram. Mr. Chair, during the lunch hour, I conferred with Public Service’s attorneys, and they’ve agreed—they’ve stipulated to the admission in this record of confidential attachment ZDP-2C from Mr. Pollock’s testimony in proceeding number 25A0061E. So, I move for admission of that exhibit. It’s in our box, marked as—

Eric Blank: I’ll help you out. I think it’s 311.

Miss Nelson: Thanks, yeah, it is 311. Thank you, Miss Crane.

Eric Blank: Any objection?

Mr. Eisenberg: No objection. Just one thing—we’re only doing the attachment, correct? We’re not doing the testimony we just looked at?

Miss Nelson: That’s correct.

Mr. Eisenberg: Subject to everything that Mr. Landram said around that list, in terms of potential for future change as we go through the process Mr. Landram discussed, but subject to that, we’ll stipulate to the admission.

Eric Blank: Thank you. So moved.

Miss Nelson: Is it true, Mr. Landram, that the bids in the locations of each of the eligible feeders would receive the same amount of distribution credit, that $69?

Mr. Landram: That’s correct. We would have the same value as long as you’re on an affected feeder. It doesn’t matter which feeder.

Miss Nelson: Would you agree with me that the feeders identified in the list and eligible for the distribution credit may have different costs of construction?

Mr. Landram: I’ve never even seen that attachment, much less being able to comment on implications of it. I would again direct you to Mr. Pollock, who’s downstream of me on the witness list.

Miss Nelson: That’s fair. Thank you. Finally, just generally, would you agree that it would be important for bidders to be given a list of eligible feeders with information of where they’re located?

Mr. Landram: Yes, I completely agree.

Miss Nelson: Do you agree that it would be helpful for those bidders to have a map of the eligible feeders?

Mr. Landram: I don’t know one way or the other. I would assume a map would be helpful. I really can’t comment.

Miss Nelson: Will the finalized list given to bidders in this proceeding in phase two contain any information that identifies the location of the feeders?

Mr. Landram: Just to clarify, the list is not going to be given to the bidders. Bidders can request access to the list and follow the confidentiality provisions and the processes laid out in the VPP tariff. It’s not going to be part of the RFP, and it’s not going to be freely distributed to all bidders. It’s something that a VPP or ADER bidder would acquire by going through the process. As to the contents of that list, our proposal is that they would get the same information that bidders in the VPP tariff—or, actually, I guess prospective customers under the VPP tariff—would get. I’ve never seen that attachment, so I don’t know what is contained in it or not.

Miss Nelson: Do you think, again, the location would be helpful? Wouldn’t it be?

Mr. Landram: Certainly. They need to know where the feeder is to be able to know whether their project is eligible or not. I’m sure that’s part of the list; I just haven’t seen it to verify that for you.

Miss Nelson: Thank you, Mr. Landram. I have nothing else.

Eric Blank: Thank you, Miss Nelson. I know you created an expectation that you would be the last, but I think commission counsel has now—they’re in the unenviable position. Mr. Denzo?

Mr. Denzo: Yes, thank you, Chair. We’ll keep it very brief here. Good afternoon, almost evening, Mr. Landram. My name is Mitchell Denzo, and I’m with the commission’s counsel. Today, I’ll be asking some questions on behalf of the commission advisers. It’s nice to meet you.

Mr. Landram: Nice to meet you as well.

Mr. Denzo: Mr. Landram, I think you’re aware, but commission counsel does not represent a party in this case. Rather, we’re just asking a few questions on behalf of the advisers today. The questions I have for you deal with the company’s proposed portfolios for phase two of this proceeding. In your rebuttal testimony, the company proposes two new checkpoint portfolios for phase two that would have no emissions reduction constraints. Do you recall this?

Mr. Landram: If not, I’m happy to point you to the testimony. I do.

Mr. Denzo: Commission staff raised an issue in their answer testimony that the company still needs to identify incremental clean energy plan activities for inclusion in the company’s clean energy plan. Commission advisers have flagged the same issue and seek some clarity from the company on this topic. Are either of the company’s proposed checkpoint portfolios intended to serve as the reference case plan that may be used for purposes of calculating the CEP rider?

Mr. Landram: I personally have not contemplated that. If anyone, it probably should have been Mr. Ihle, because he leads the rate side as well, or at least works with the rate side here in the company. I apologize; I don’t think I’m in a position to make an informed opinion as to what’s appropriate for rider recovery determination purposes.

Mr. Denzo: Okay. Perhaps if Mr. Ihle joins us again at the end, we can ask him, but that might be something we can address in our SOP as well?

Mr. Landram: I’m just not knowledgeable enough in the area of the specific requirements, what the demonstrations need to be, to be able to answer you at this moment.

Mr. Denzo: Okay. I think addressing it in the SOPs would be very helpful for us if that works.

Mr. Landram: Okay.

Mr. Denzo: Well, that’s it for me. Appreciate it, Mr. Landram. Thanks.

Mr. Landram: That was easy.

Eric Blank: I think that’s it. We’ll start Tuesday morning with commissioner questions of Mr. Landram. Any final thoughts before we break?

Mr. Eisenberg: Nothing further from Public Service.

Tom Plant: Commissioner Plant?

Megan Gilman: Commissioner Gilman?

Eric Blank: All right, thanks all. Hope everybody has a great weekend, and we’ll see everybody Tuesday morning at 9. Thanks.

All: Thank you.