Transcript - Day 7

A.I. Generated with guesses for speakers.

I have to break the transcript in to 4 parts for the A.I. to format it (because of the length). For some reason in section 4 it did not bold the speaker’s names. No idea why.

Eric Blank: Good morning. This is Eric Blank. This is the Public Utility Commission's proceeding on Public Service Company of Colorado's Just Transition Solicitation 24A-442E. Today is June 20th and we're back on the record. Preliminary matters, Mr. Rubin?

Danny Rubin: Good morning, Chairman, Commissioners. Danny Rubin for CIA. I wanted to let you know that a conflict has arisen and CIA's witness Mr. William Monson will not be available on Monday morning. Mr. Monson is available afternoon on Monday and can stay late that day, or could testify anytime on Tuesday. But CIA would request to accommodate that conflict Monday morning.

Eric Blank: Okay, thanks. Let me just write that down. Mr. Plo?

Brett Plo: Good morning. Brett Plo on behalf of CEC. Just letting you know that we're going to waive cross of a couple more witnesses. Specifically, staff witness Dr. Steven Dulki, CASA witness Kevin Lucas, CIA witness William Monson, and UCA witness Leslie Henry Seros.

Eric Blank: You can just give me a second. So, did you waive, did you waive, let's see. So there are three witnesses you're waiving cross of?

Brett Plo: There are four, Chair.

Eric Blank: What was, I have Dulki, Monson, and UCA is a Mr. Hey... no, no.

Brett Plo: Chair, CASA witness Kevin Lucas.

Eric Blank: Oh, Kosa. Okay, thank you. Thank you. Mr. Dipman?

Mr. Dipman: Good morning, Your Honor. We had indicated earlier in the, when we submitted our matrix, that Mr. Mendisco would not be available Monday and Tuesday. He is available on Monday now, and we actually prefer he be called on Monday given his availability. He's heading off for a conference on Tuesday, so I just wanted to put that out there.

Eric Blank: Okay. Only Monday. Okay. Mr. Dunbar?

Scott Dunbar: Good morning, Mr. Chairman. Ms. Chong informed me via email on Wednesday evening that staff would be waiving their cross of CCSA witness Tom Beach. Mr. Beach is here and available as planned for Commissioner questions if you have any. If you know that you don't have any now, I'll tell him he can log off. If you think you might have any for him, he's more than happy to stay on and be called. I just thought I'd check.

Eric Blank: I appreciate that. I do not have questions for Mr. Beach. Commissioner Gilman?

Megan Gilman: No, I don't.

Tom Plant: I do not either.

Eric Blank: Mr. Beach may be excused. Thank you, Mr. Dunbar. Thank you. Mr. Feno?

Mr. Feno: Morning, Mr. Chairman. Climax will waive our cross of Mr. Monson, which is the only one we have left.

Eric Blank: Okay, thank you, Mr. Feno. I guess Mr. Larson, I'll get to you in a second. I would just say, I am intending to forgo my questioning of Mr. Spurgeon and Ms. Summers. So with that, they both can also be excused. Mr. Larson, did you have preliminary matters?

Matt Larson: I do. We have some waivers as well, Mr. Chair. So, the Public Service will waive on Kevin Lucas of Kosa, Ms. McDevitt from CC4CA.

Eric Blank: Mr., just let me follow up on Ms. McDevitt. Commissioner Gilman, questions for Ms. McDevitt?

Megan Gilman: I do not.

Tom Plant: I do not.

Eric Blank: With that, Ms. McDevitt, you may be excused. Continuing on, and this will be the same situation as I believe the company's holding the only cross for Conservation Coalition witnesses Mr. Cummings and Mr. Stencel. We're going to waive that as well. Commissioner Gilman, any questions for Cummings or Stencel?

Megan Gilman: No, I don't think so.

Tom Plant: No.

Eric Blank: Those two witnesses may be excused as well. And then just two more, Mr. Chair. KI witness Mr. Stanton, and I believe we are the only ones holding cross-examination for him. We're going to waive that as well. Commissioner Gilman?

Megan Gilman: No. You sure? No, I'm just trying to keep up. Sorry, sorry for those who are working. I don't think I have anything for him. If you change your mind, we can always adjust.

Tom Plant: Yeah, I don't think I do either. I don't think I do either.

Eric Blank: So, Cummings, Stencel, and Stanton may be excused. And the final one, Mr. Chair, is we're going to waive our cross-examination of UCA witness Mr. Neil. I believe others holding cross-ex for him. Yep. So we'll keep Mr. Neil.

Matt Larson: Chairman, have we excused Lucas or do we still have Lucas?

Eric Blank: That's a, I have Mr. Lucas, with the company waiving. I don't have any cross from on the schedule for Mr. Lucas. But do you have, I'm, I don't. I may have questions for him. Yeah, so I just, okay. Yeah, so we're not excusing Mr. Lucas. Okay, thanks. And for today, I'm hoping maybe we can go until 1:00-ish and we'll see where we end up today. But tentatively, let's hold 7:30 to 7:00 on both Monday and Tuesday so we can make sure we get this in and everybody gets due process. And we'll just adjust around everybody's schedule. Witnesses, lawyers, parties, as best we can to make it work. Ms. Kutzer?

Ellen Kutzer: Kutzer, yeah, excuse me. Did I just hear you say Wednesday? And I'm assuming that would be afternoon, maybe held for the hearing. Just want to…

Matt Larson: No, I don't think I said that, and I apologize if I did. I'm saying 7:30 to 7:00 Monday and Tuesday. So long days Monday to Tuesday, and hopefully the goal would be to end the hearing Tuesday.

Ellen Kutzer: Got it. Okay, thank you. And we'll adjust if we need to. Mr. Larson? And we'll have Mr. Aley prepared to go on Monday for our prior discussion.

Matt Larson: Yeah, I think that that's probably where it's headed. Excellent. Thank you.

Eric Blank: Any other preliminary matters? I think we're ready to resume with the redirect of Mr. Bailey. Miss Shields? Well, I'm not... Do you have a phone or something you can call in with, Miss Shields? Or do you want to put on your next witness and come back to Mr. Bailey? Mr. Larson, are you in the same building as Miss Sh...

Matt Larson: Chairman Blank, we've had, we're in the Excel building. We've had some internet and tech problems this morning. I'm fine, but they may be experiencing that.

Eric Blank: Yeah, I don't, I don't think we can proceed without. Miss Shields went down last, yesterday afternoon for a while, so who knows. How's that? There we go. Great, thank you. Ms. Shields, you're up on redirect?

Miss Shields: Yes. And real quick, one last thing. What I did want to let you all know is we have uploaded to Box a public version of Hearing Exhibit 140. And I wanted to call attention that is a redacted version, not just a slip sheet. So that may be of use in the public record, reflecting the large load customers in the updated base load forecast. And then we do have a slip sheet for Hearing Exhibit 141 uploaded in Box as well. Those have already been moved into the record if you'd like me to, to the extent you'd like me to move those in, or the public versions. I would so move. Moved. All right. Fantastic. And we are prepared to move forward with Mr. Bailey. If you all are. Yep, please. All right. Mr. Bailey, good to see you again this morning. To begin, you had several questions from staff and other attorneys regarding how the company would inform the Commission of large load contracts that it enters into during this interim period before a large load tariff is in place. Do you recall that?

Mr. Bailey: Yes, I do.

Miss Shields: Would the company be willing to file either in this proceeding or a miscellaneous proceeding, on a restricted highly confidential basis, electric service agreements and interconnection agreements it enters into with strategic economic development customers and large load customers over 100 megawatts between now and when that tariff goes into effect?

Mr. Bailey: Yes, we are willing to do that.

Miss Shields: Thank you. And on a restricted, highly confidential basis, is that right?

Mr. Bailey: Yes, for the ESAs, excuse me, ESAs and IAs. The strategic economic development customers and those loads over 100 megawatts, on a restricted highly confidential basis. That's accurate.

Miss Shields: You also had several questions about potentially filing an updated model interconnection agreement and ESA that incorporates the large load principles you outlined in your rebuttal testimony. Do you recall some of the questions about whether or not the company would be willing to file those updated model contracts?

Mr. Bailey: Yes.

Miss Shields: Would the company be willing to file model updated versions of those with its statement of position?

Mr. Bailey: Yes, we will, under the statement of position, as stated.

Miss Shields: All right. You had several people yesterday ask questions, I'm sorry, on Wednesday, related to the company's probability table included on page 30 of your rebuttal testimony, Hearing Exhibit 123. I have two areas I'd like to ask you about. And perhaps if we could bring up Hearing Exhibit 123, page 30, just for reference. All right. First, staff counsel asked you some questions about your use or the company's use of the large load principles and how those principles factor into the development of the probability table. Do you recall that?

Mr. Bailey: Yes.

Miss Shields: All right, my first question is, is the company currently using these large load principles, I'm sorry, the large load principles articulated in your rebuttal testimony, including the customer protections and firm commitment obligations, in your current ongoing negotiations with prospective new data center customers?

Mr. Bailey: Yes, we are.

Miss Shields: Okay. And now second, this question refers a little bit more to the probability table. Do you recall an exchange with CEO counsel regarding whether the company would be willing to replace numeric steps for the percentage probability thresholds in the left-hand column?

Mr. Bailey: Yes, I do recall that conversation.

Miss Shields: Okay. Would the company be willing to replace those percentage probabilities with steps? So for example, 10% would become Step One, 20% Step Two, leading through 90% Step Nine, and 100% Step 10.

Mr. Bailey: Yes, we would.

Miss Shields: You also had several questions related to the probability thresholds that would trigger the company's ability to draw generation projects from the proposed incremental need pool. Do you exchange, do you recall some of those exchanges?

Mr. Bailey: Yes, I do.

Miss Shields: Okay. So first, what I'd like to clarify is that the company's proposal, in order to trigger the activation process for a generation project or set of projects from the incremental need pool, a large load customer of 100 megawatts or more must have a 90% probability, or in other words, be at the ninth step in the process?

Mr. Bailey: Yes.

Miss Shields: Next, could you explain for us what some of the downsides may be to approving a load forecast and relying on the incremental need pool to serve new large load customers during the interim period until a tariff goes into effect?

Mr. Bailey: Yes, thank you for the question, and I know we dove into this on several occasions, and I appreciate the overview. As we discussed, and I discussed, the problems are really with the delay. We have customers now, and we've showcasing the exhibit of 140, that want service as soon as possible. Any delay may very well push them out of our state and out of our market. And for the existing customers requesting expansion, that delay could cause them to make decisions that would not be expanding in the state of Colorado, and having the opportunity to increase job base and tax base here. And we really want to avoid that, obviously. In my discussions, additionally, there, there, we have to consider cost. And the cost not only to the customers, but the cost of losing those customers. The incremental need pool process may have more costs associated with it, which Mr. Aley can explain in more detail. But since we have customers ready and waiting, we have a duty to serve and we have an obligation to serve them as soon as we are able to, and is, and it is timely and efficient and cost effective to enable us to procure power for these limited customers during the Phase 2 RFP process, as I've previously stated.

Miss Shields: All right. And will Mr., when he comes back for a second round, be prepared to revisit and walk through the incremental need pool process along with the corresponding large load triggers?

Mr. Bailey: Yes, he will.

Miss Shields: Pivoting a little bit. Counsel for UCA, Mr. Bunker, he asked you several questions about the relationship between the large load principles and the company's forthcoming large load tariff filing that it's committed to make. Do you recall some of that exchange?

Mr. Bailey: Yes, I do.

Miss Shields: All right. Can you clarify whether the company is or is not pre-committing to including these interim principles in its large load tariff? The company's not making a pre-commitment here, is that right?

Mr. Bailey: Yes, that is accurate. As discussed on Wednesday, we anticipate versions of those principles to be included, but we are committed to engaging the stakeholder process as I communicated. So currently, we're not making that commitment now, and that all of these be proposed in a tariff as currently contemplated.

Miss Shields: Okay, thank you. Mr. Bunker also asked you several questions about the status with respect to the large load tariff toward current large load customers or those who begin taking service during the interim period. Could you help clarify how large load customers, for instance, those in the updated base load forecast, Hearing Exhibit 140, will be treated from a rate perspective during this interim period?

Mr. Bailey: Sure, that. And I appreciate that question. The proposed large load tariff would apply to customers who first take service after the effective date of that tariff. Any current customers and customers who begin to take service during the interim period would not automatically move into that large load tariff. Mr. Aley, as we've discussed, is the best witness to answer questions about the future applicability of those tariffs.

Miss Shields: Thank you. Mr. Bunker, he asked you a couple questions about the company's stakeholder process, which I think you may have just referred to. And what I want to clarify is, is the company open to engaging and dialogue about all issues related to large load that that stakeholder group identifies and brings forward through the stakeholder process?

Mr. Bailey: Yes, we are.

Miss Shields: One other little bit of a minor point, but just want to make sure we're clear here. And let's see if we could scroll to page 32, footnote 37. All right. Do you recall Mr. Bunker asked you a couple of questions related to two different load figures? A 944 megawatt figure located on page 23 of your testimony, and then a 929 megawatt figure included on page 12 of your testimony. Do you recall some of his questions about those two figures and trying to understand the differential between them?

Mr. Bailey: Yes, I do recall that conversation.

Miss Shields: Okay. And in looking at footnote 37 on page 32 of your testimony, does that footnote explain the discrepancy between those two figures?

Mr. Bailey: Yes, it does. And also outlines this, are good enough as he discussed in his rebuttal testimony.

Miss Shields: Okay. Changing gears a little bit. It appears from some of the questions you received that there could be some confusion in the record about what large loads are specifically in the company's updated base load forecast. Could you describe the categories of large loads that are in fact included in the company's updated base load forecast?

Mr. Bailey: Yes, I can. And I know Mr. Goodenough touched on this as well. There are three categories. Existing customers that have large load and are seeking to add load or expand. The new large data center loads that I outlined in a deep discussion. And then the strategic economic development customers and their loads.

Miss Shields: Okay. And again, Hearing Exhibit 140 would be the exhibit that reflects those particular loads, correct?

Mr. Bailey: Yes.

Miss Shields: Of the approximately 900 megawatts of large load included in the company's updated base forecast, approximately how much of each of those categories of customers are reflected within that approximately 900 megawatts of large load?

Mr. Bailey: Yes, thank you. Each customer category makes up approximately a third of that 900 megawatts. Obviously, we have focused, and there's been a lot of conversations throughout this hearing, about the impact of data center customers on that load. I just want to be very clear and make sure that this is coming through, that the vast majority of the requests in those customer categories of large loads is made up of existing customers and their expectation to expand their existing businesses in the state of Colorado.

Miss Shields: All right. And we specifically walked through and identified who those strategic economic development customers are during the restricted highly confidential session last week, correct?

Mr. Bailey: I'm sorry, last Wednesday, yes. At the end of the day, we had that restricted session and defined those customers and named them.

Miss Shields: Okay. Now, counsel for specifically asked you to define what a strategic economic development customer is. And I believe you had had some similar dialogue with Commissioner Gilman. Now, for clarity and purposes of this proceeding, is the company proposing that the strategic economic development customers for which load is going to be procured through Phase One, are those five customers included in Hearing Exhibit 140?

Mr. Bailey: Yes, they are.

Miss Shields: And so to be clear, would the company use additional strategic economic development customers or include strategic economic development customers beyond those five customers as a reason to activate the incremental need pool?

Mr. Bailey: No, Public Service would not. And again, I'd point to Mr. Aley as the witness to ask and to outline that framework.

Miss Shields: Okay. Commissioner Gilman asked you a couple of questions about where within the 50 to 79% probability each of those strategic economic development customers are, in the stage-gate process with the company. Do you recall that?

Mr. Bailey: I do, yes.

Miss Shields: Might you be able to elaborate as to where in the stage-gate or stepped process those five economic development customers are within the current process, within that probability table in your testimony?

Mr. Bailey: Yes, thank you. Appreciate the question clarification. We are in preliminary contract discussions with those customers, which aligns with the 70th percentile or the Range Seven in the new step process we discussed today. We have paused those negotiations until we can get a very clear understanding of our ability to procure generation as we've outlined in this case.

Miss Shields: Now, Commissioner Gilman asked you a question about whether the company would be willing to accept risk associated with generation assets that may be added to support new load. And in the event, what happens if that load does not actually materialize? Are you authorized to speak for the company with respect to that kind of risk decision for the company?

Mr. Bailey: No, I am not.

Miss Shields: Is there a better witness who would be prepared to opine on that?

Mr. Bailey: Yes, Mr. Aley.

Miss Shields: Okay. I think we're almost done, getting in the home stretch. Chairman Blank raised the question about whether the company's current tariffs are sufficient to cover the cost to serve large load customers. Do you recall that exchange? I think it was near the end of our dialogue on Wednesday.

Mr. Bailey: Yes, I do.

Miss Shields: Is it the company's position that its existing TG tariff is sufficient vehicle to address the nine large load customers and strategic economic development customers contained in the updated base load forecast?

Mr. Bailey: Yes, it is. And to further define and clarify, I would add that seven of the nine customers that we reviewed are existing customers taking service under an existing Public Service Company tariff.

Miss Shields: All right. And to the extent they were taking service under the PG tariff, would you similarly agree that that tariff would be sufficient?

Mr. Bailey: Yes.

Miss Shields: Would Mr. Martz be the appropriate witness to discuss the system impacts associated with these nine customers? I believe that at least Commissioner Gilman raised a couple of questions about potential system impacts or network costs. And just want to confirm if Mr. Martz would be the appropriate witness.

Mr. Bailey: Yes, he would.

Miss Shields: Okay. And then coming back to the question that we were just talking about, as far as existing tariffs, particularly the existing TG tariff, would Mr. Aley be the appropriate witness to also discuss the appropriateness of using that tariff on an interim basis for the large load customers that the company proposes to bring on?

Mr. Bailey: Yes, he would. With that, I have no further questions, Mr. Bailey.

Eric Blank: Thank you, Miss Shields. Thank you, Mr. Bailey. You may be excused.

Mr. Bailey: Thank you, Chair Blank.

Eric Blank: Mr. Irby, can we call your next witness?

Mr. Irby: Yes, thank you, Mr. Chairman. Public Service calls Mr. Alexander Kangas.

Eric Blank: Kangas, there you are, sir. Can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Dr. Kangas: I do.

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

Dr. Kangas: No.

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

Dr. Kangas: Yes.

Eric Blank: I have 15 minutes for Moffat County. I think you're muted. There you go. Thank you.

Laura Chartrand: Good morning, Dr. Kangas. My name is Laura Chartrand and I represent Moffat County and the City of Craig. And thank you for your time today. Today I'd like to discuss with you your direct testimony, which is Hearing Exhibit 108 on workforce transition planning and the company's updated workforce transition plan, Attachment AK-1, as well as discovery responses that you sponsored. And I may also reference other testimonies, which we can put up on the screen to assist you. As a foundational matter, I would like to discuss Moffat County and the City of Craig's interest in the company's workforce transition planning for Hayden Station. I would like to ask Commission staff if you could bring up Hearing Exhibit 216, which is located in Moffat and Craig's Box folder. Sorry, that's just taking a second to open. And Dr. Kangas, this is company's response to Discovery Request MNC5-1. Are you the sponsor of this response?

Dr. Kangas: Yes.

Laura Chartrand: And through this response, you indicated that there are 38 Public Service employees at Hayden Station who are Moffat County residents as of May 29th, 2025. Is this correct?

Dr. Kangas: Yes.

Laura Chartrand: Chairman Blank, I move for the admission of Hearing Exhibit 2106, the company's response to Moffat County in the City of Craig 5-1. Mr. Irby, any objection?

Mr. Irby: No objections, Your Honor. So moved. And now if Commission staff could please bring up Attachment CN-10, which is an attachment to Hearing Exhibit 21101. Sorry, things are opening slowly today.

Laura Chartrand: No problem, 'cause it's Friday. And Dr. Kangas, this is discovery response from the company MC1-7, and you indicated that there are 63 employees at Hayden Station as of mid-February 2025. Is that correct?

Dr. Kangas: Yes.

Laura Chartrand: Would you agree then that the majority of Hayden Station employees reside in Moffat County?

Dr. Kangas: Yes.

Laura Chartrand: And Dr. Kangas, is it accurate that the average salary of Hayden Station employees is approximately $118,000?

Dr. Kangas: Yes.

Laura Chartrand: And would you agree that Hayden Station employees who reside in Moffat County, the employees and members of their households, would rely upon or use at least one or more public resource located in Moffat County, such as schools, roads, hospitals, fire protection, libraries, water?

Dr. Kangas: Yes.

Laura Chartrand: And would you agree then that these Moffat, these employees of Hayden Station who reside in Moffat County and members of their household also frequent local businesses, at least ones such as restaurants, gas stations, retail stores, auto repair stores, grocery stores in Moffat County?

Dr. Kangas: Yes.

Laura Chartrand: And Dr. Kangas, your testimony discusses the company's plan to transition the workforce at Comanche, Hayden, and Pawnee Stations, correct?

Dr. Kangas: Correct.

Laura Chartrand: And if we could bring up Hearing Exhibit 108, Dr. Kangas' direct testimony, and if we could go to page nine, starting at line nine. And Dr. Kangas, here you've testified that the company acknowledges the significant impact the transition away from coal will have on jobs, tax revenues, and economic activity in the Pueblo and Hayden communities. Is that accurate?

Dr. Kangas: Yes.

Laura Chartrand: Dr. Kangas, in light of the number of Moffat County residents employed at Hayden Station, would you agree then that Moffat County and Craig Station are part of the Hayden communities, or Hayden area?

Dr. Kangas: Yes.

Laura Chartrand: And Dr. Kangas, prior to the company's 2021 ERP proceeding, what were the retirement dates for Hayden 1 and Hayden 2? And if you don't recall, we can go to page 22, starting at line seven. And I just repeat the question, what were the retirement dates for Hayden 1 and Hayden 2?

Dr. Kangas: The original retirement dates were 2030 and 2036.

Laura Chartrand: And Dr. Kangas, what are the current retirement dates for Hayden 1 and Hayden 2?

Dr. Kangas: 2027 and 2028.

Laura Chartrand: So Hayden 1's retirement date has been moved up three years, and Hayden 2's was moved up eight years. Correct?

Dr. Kangas: Yes.

Laura Chartrand: And if we could go to page 13, line 3 through 7. And here in your testimony, you indicate that Xcel Energy has not needed to implement a layoff or forced workforce reduction. Is that correct?

Dr. Kangas: Yes.

Laura Chartrand: And if we could go to page 23, line 8. Here, Public Service, you testify that Public Service is working closely with the affected communities, stakeholders, and employees to explore new uses of Hayden site that will promote clean energy innovation and economic opportunity in the Northwest Colorado region. Is that correct?

Dr. Kangas: I do state that, yes.

Laura Chartrand: And if we could bring up Attachment AK-1, Updated Workforce Transition Plan Report, and go to page seven please. And if we could scroll up so we could see Table One in its entirety. It's on that page seven. Thank you. Dr. Kangas, looking at Table AK-1, the company predicts that 54 Hayden Coal employees will need to transition. Is that correct?

Dr. Kangas: Yes.

Laura Chartrand: And could we now turn to page 15, to Table Four please. And Dr. Kangas, Table Four shows that there will be no Xcel Energy job opportunities within 50 miles of the Hayden area for those 54 transitioning coal plant employees. Correct?

Dr. Kangas: Those are the current estimates, yes.

Laura Chartrand: And what would change those estimates, Dr. Kangas?

Dr. Kangas: The development of company facilities in those areas.

Laura Chartrand: Would you agree that in order for Hayden coal plant employees, absent the company developing replacement resources, in order for those employees to remain working for the company, they will need to leave Northwest Colorado to do so?

Dr. Kangas: That is one possibility, yes.

Laura Chartrand: And what are the other possibilities?

Dr. Kangas: If there are developments through this proceeding for new company facilities in those areas.

Laura Chartrand: Meaning that if there are additional development opportunities in the area that might be opportunities for those employees to continue to work for Xcel within a 50-mile radius, correct?

Dr. Kangas: Yes.

Laura Chartrand: Dr. Kangas, when drafting the company's Workforce Transition Plan Report, did you consider the fact that the majority of Hayden Station employees reside in Moffat County?

Dr. Kangas: No, we did not.

Laura Chartrand: And if not, when did you first discover that the majority of Hayden Station employees reside in Moffat County?

Dr. Kangas: It's not a number that I actively track, and so it was through the discovery process this spring.

Laura Chartrand: And so it was because Moffat County and the City of Craig specifically requested is when you were first alerted as to where the majority of Hayden Station employees reside. Is that correct?

Dr. Kangas: That's correct.

Laura Chartrand: If we could go back to Hearing Exhibit 108, page 14, Figure AK-D-1. And Dr. Kangas, this chart shows the company's steps in developing its workforce transition planning. Correct?

Dr. Kangas: At a high level, yes.

Laura Chartrand: And Step One includes communicating regularly with employees and stakeholders. Correct?

Dr. Kangas: Correct.

Laura Chartrand: Did you confer with Moffat County and the City of Craig in the drafting of the 2024 workforce transition plan?

Dr. Kangas: It's possible I personally did not, but it's possible that other representatives of the company did.

Laura Chartrand: And so, help me understand, Dr. Kangas, if you had not considered before the discovery request, which was after the time in which the workforce transition plan was authored, that you had not considered that the majority of Hayden Station employees were residing in Moffat County, what would have led you then to confer with Moffat County and the City of Craig here in the design of the workforce transition plan?

Dr. Kangas: The focus of my testimony and of the workforce transition plan is on the company's plan to transition its workforce to other company jobs because our facilities, our facility is within Hayden. That is what drove our focus. And in our workforce planning efforts, the other company locations across the state of Colorado.

Laura Chartrand: And I just want to confirm that I heard you correctly, you don't know whether the company conferred with Moffat County in the City of Craig in the drafting of the workforce transition plan.

Dr. Kangas: That's correct, I do not know.

Laura Chartrand: And do you think in light of the fact that you didn't know that the majority of the workforce resided in Moffat County, that it's probably less, it's less likely that the company in fact did confer with Moffat County and the City of Craig?

Dr. Kangas: I can't speculate as to the likelihood.

Laura Chartrand: Do you know, Dr., Mr. Kangas, if as a courtesy, you provided a copy of the 2024 workforce transition plan to Moffat County in the City of Craig?

Dr. Kangas: I do not believe so.

Laura Chartrand: In comparison, did you confer with Pueblo County, Routt County, and Morgan County in the drafting of the 2024 workforce transition plan?

Dr. Kangas: Can you repeat the question?

Laura Chartrand: In comparison, so you just indicated that you didn't provide a copy, and that you're uncertain whether you conferred, whether the company conferred with Moffat County in the City of Craig. And I'm trying to draw a comparison and understand what actions the company took. And the first question of that is, did you confer with Pueblo County, Routt County, and Morgan County in the drafting of the 2024 workforce transition plan?

Dr. Kangas: I don't believe that directly we did, no.

Laura Chartrand: Were you listening to the company's witness Jackie, who testified earlier in this hearing?

Dr. Kangas: Yes.

Laura Chartrand: And do you recall him saying that the Just Transition of coal communities is a team effort?

Dr. Kangas: I don't recall that specifically.

Laura Chartrand: Okay. Do you think it's a team, do you, Dr. Kangas, think it's a team effort?

Dr. Kangas: I do.

Laura Chartrand: Would you oppose the Commission directing the company to communicate regularly with Moffat County in the City of Craig on the workforce transition planning?

Dr. Kangas: I would not.

Laura Chartrand: Thank you, Dr. Kangas. No further questions on our part.

Eric Blank: Thank you, Ms. Chartrand. Let me see, I think that's it. Commissioner Gilman, questions for Mr. Kangas?

Megan Gilman: I don't have any questions, thanks.

Tom Plant: I don't either, thank you.

Eric Blank: Nor do I. Redirect, Mr. Irby?

Mr. Irby: Thank you, Mr. Chairman, just a couple. Mr. Kangas, was your testimony primarily an update to the workforce transition plan that was filed and approved by the Commission in the 2021 ERP proceeding?

Dr. Kangas: Yes.

Mr. Irby: And Mr. Kangas, does the company have a local and community affairs group that primarily is responsible for communicating with our communities?

Dr. Kangas: Yes.

Mr. Irby: And are you part of that, that organization within the company?

Dr. Kangas: I am not.

Mr. Irby: That's all I have, Mr. Chairman. Thank you very much.

Eric Blank: Thank you. You may be excused, sir. Thank you. Mr. Pollock, are you out there? Can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Mr. Pollock: Yes.

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

Mr. Pollock: No, they are not.

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

Mr. Pollock: Yes.

Eric Blank: Back to you, Mr. Larson.

Matt Larson: Thank you, Mr. Chair. Good morning, Mr. Pollock.

Mr. Pollock: Morning, Mr. Larson.

Matt Larson: Can you please state and spell your name for the record, please?

Mr. Pollock: Sure. My name is Zachary, Z-H-C-Z-C-H-A-R-Y, Pollock, P-O-L-L-O-C-K.

Matt Larson: And what is your role at the company?

Mr. Pollock: My role is Director of Grid Strategy and Emerging Technology, and I work on behalf of Xcel Energy Services.

Matt Larson: And do you have before you what's been marked as Hearing Exhibit 125, which is your rebuttal testimony in this proceeding?

Mr. Pollock: Yes, I do.

Matt Larson: And if I asked you those same questions today, would your answers be the same?

Mr. Pollock: Yes.

Matt Larson: And was that testimony prepared by you or under your direction?

Mr. Pollock: Yes.

Matt Larson: With that, Mr. Chair, Mr. Pollock's available for cross-examination. I have 25 minutes for KOSA, and it's 9:47. Thank you, Mr. Chair.

Ellen Kutzer: Good morning, Mr. Pollock. How are you?

Mr. Pollock: Good morning, Ms. Kutzer. Doing well. Hope you're well as well. Thank you.

Ellen Kutzer: Thank you. I'm going to spend some time with you working through an exhibit that came in last week. Were you on the line when counsel for UCA, Ms. Singer Nelson, cross-examined Mr. Landrum?

Mr. Pollock: Yes, I believe for most of it, and believe I understand the exhibit you're referencing.

Ellen Kutzer: Okay, great. So let me represent to you, just to level set for everyone on the line, that Ms. Singer Nelson asked Mr. Landrum about his rebuttal testimony and the company's commitment in rebuttal to provide the distribution credit of $69 per kilowatt year per year to eligible distribution connected bids in the ERP. Is that correct?

Mr. Pollock: That's correct.

Ellen Kutzer: Okay, great. And in this line of questioning, Mr. Landrum's exchange explained that the support for this distribution credit amount comes from the Virtual Power Plant case or VPP case. Is that also correct?

Mr. Pollock: Correct.

Ellen Kutzer: And just to confirm, you are the company's architect of the VPP offering, correct?

Mr. Pollock: Not sure I've been referred to as architect, but I'm one of the people that helped develop that.

Ellen Kutzer: You're familiar with it, is that correct?

Mr. Pollock: Yes.

Ellen Kutzer: Okay, great. And you know this already, but just again, to level set, this is now relevant to this case because the company has agreed to provide the distribution credit derived in the VPP case to eligible distribution connected bids in this ERP.

Mr. Pollock: Yes, and I'd add that this is really one of the best examples we have of how we're working across our planning. While they may not neatly align in dockets, this is a great example how we've been able to integrate planning across generation, transmission, and distribution.

Ellen Kutzer: Okay. And you know this already, but just again, to level set, during her questioning of Mr. Landrum, Ms. Nelson asked some questions about the calculation of the distribution credit, as well as the feeders and banks that would be eligible for that distribution credit. Did you hear that part?

Mr. Pollock: Yes.

Ellen Kutzer: Okay, great. Let me represent to you that Mr. Landrum agreed that the list of affected feeders that are eligible for the distribution credit in this case matches the list of feeders that was originally filed as Attachment ZDP-2C in that VPP proceeding. Do you agree?

Mr. Pollock: I believe that should be the case.

Ellen Kutzer: Okay. And I'll further represent that that list is now in this case as Hearing Exhibit 310. Do you, can you confirm that you were the sponsor of that exhibit when it was originally filed in the virtual PowerPoint case?

Mr. Pollock: Yes, that should be in my direct testimony, I believe that table.

Ellen Kutzer: Okay, great. And so you're quite familiar with that, that table in that list?

Mr. Pollock: Relatively familiar, yes.

Ellen Kutzer: And then just to confirm, you agree with Mr. Landrum's testimony that this is the correct list that the Commission should rely upon to provide the distribution credit to bidders that bid in a DER into this ERP?

Mr. Pollock: I think potentially, and this is an issue that's come up I think with Mr. Aley and his cross-examination, the timing of these cases may be that the, that list may be modified depending on the outcome of the VPP proceeding. So it's possible we may have a different list depending on the outcome of that case, which could be reflected in the Phase 2, as I think Mr. Landrum alluded to.

Ellen Kutzer: Okay, great. I'm going to get to that in a little bit, but I want to talk first about how bidders are going to access the list. So as of this moment, this list of feeders was not submitted by the company. It's only in this record as a hearing exhibit. Correct?

Mr. Pollock: Correct.

Ellen Kutzer: Okay. And UCA and the company stipulated that this Hearing Exhibit 310 is confidential. Correct?

Mr. Pollock: Yes.

Ellen Kutzer: No other parties were part of that stipulation between the UCA and the company, correct?

Mr. Pollock: I'm not aware of those discussions, so that would be something for our counsel or another witness.

Ellen Kutzer: Okay. Subject to confirmation, let's assume that that's the case right now. So I want to confirm that in the VPP case as well, the company has filed this Attachment ZDP2 as confidential. Correct?

Mr. Pollock: Correct.

Ellen Kutzer: So when the company files a document as confidential rather than highly confidential under the Commission's rules, it does not file a motion for extraordinary protection to request that designation from the Commissioners. Correct?

Mr. Pollock: That's my general understanding. I'm not a lawyer, but yes.

Ellen Kutzer: Okay. So you've not sought or received any Commission approval to designate that list as confidential at this time. Correct?

Mr. Pollock: Again, I haven't been directly involved in those conversations, but...

Ellen Kutzer: So let's, let's shift gears a little bit and talk about how the companies that might be interested in developing DERs, bidding those into this ERP, might be able to access that feeder list. We both agree that the list is currently not public. Correct?

Mr. Pollock: Correct.

Ellen Kutzer: And we also agree that the feeder list can only be accessed by parties to either the VPP case or this ERP case who have executed the Commission's standard non-disclosure agreement. Correct?

Mr. Pollock: I think that's the current state. Well, it is the current state for the actual solicitation process. The company has every intention of disclosing that information to bidders, even though they may not be bound by the current confidentiality of this case.

Ellen Kutzer: But those bidders aren't necessarily parties to this proceeding, correct?

Mr. Pollock: I can't definitively say yes or no. I think there's trade groups, but I don't know if there's direct developers that may be interested in bidding in this case.

Ellen Kutzer: Okay. Let's, let's talk about that a little bit more. What's the intended timing that the company is proposing to provide this list to prospective bidders?

Mr. Pollock: I think that depends on the outcome of this case, as well as the outcome of the DSP and the combined ABP case. So roughly, I think we've estimated we'd get a decision in that case around November. And as soon as we have a final decision, I think we'd make that information available as part of the Phase 2 solicitation.

Ellen Kutzer: So it's your intent to provide that list as part of the Phase 2 solicitation, say with the RFP that goes out?

Mr. Pollock: We haven't definitively determined the exact timing, but generally it would be in or around that timeframe of the Phase 2, potentially in advance of it.

Ellen Kutzer: So best-case scenario, we're talking about prospective bidders having access to that list starting at the time in which the RFP is released?

Mr. Pollock: I said potentially. So there's an opportunity, maybe disclosed prior to that. Again, it's hard to speculate given the timing, unknown timing of the decisions in that case.

Ellen Kutzer: Do you and I agree that that list contains named feeders that have specific geographic locations?

Mr. Pollock: Yes.

Ellen Kutzer: And do we also agree that those geographic locations are quite important for potential bidders who would like to take advantage of this new company agreement to allow for the distribution credit to be paid?

Mr. Pollock: They're relative. I mean, the distribution credit is a small portion of the overall compensation and credits that would be applied in the Phase 2 modeling. So yes, there's some importance to the distribution component, but there's also the generation and transmission credits would be applied in the modeling as well.

Ellen Kutzer: Understood. But it could be a pretty, pretty important component that could affect the overall ability of a project to pencil, could it not?

Mr. Pollock: I, I can't speculate on whether or not a developer's projects would pencil or not with that credit or without it.

Ellen Kutzer: Okay. It would certainly help it.

Mr. Pollock: I can agree to that.

Ellen Kutzer: And my point is, developers aren't really going to know where those feeders are until the RFP launches. Correct?

Mr. Pollock: Or potentially before. Again, it's all contingent upon a decision in that case that will memorialize the methodology for distribution credit. But as of this moment, that document is confidential, yes.

Ellen Kutzer: Can you explain the reasons why that document's been designated as confidential?

Mr. Pollock: Generally, that document indicates parts of our distribution system that are highly loaded. So that's something that we've taken a relatively uniform stance on as far as not disclosing that information publicly. There are other avenues where we have been able to disclose parts of our distribution system. I believe you're familiar with the company's secure web portal that we use or developed as part of the DSP. That's one avenue where we've disclosed information like that by asking folks to sign an NDA.

Ellen Kutzer: You've anticipated my next line of questions, Mr. Pollock. So let me represent to you that I've compared the Grid Needs Assessment that is accessible through the mechanism you just described and the list of affected feeders that are contained on Hearing Exhibit 310. And I have found that there's significant overlap between the list of affected feeders on Hearing Exhibit 310 and the list of feeders in the Grid Needs Assessment. Do you have any reason to disagree with that conclusion?

Mr. Pollock: Sounds reasonable.

Ellen Kutzer: And let me further represent that the majority of the feeders that are on the VPP list are also on the Grid Needs Assessment. Any reason to disagree with that?

Mr. Pollock: No.

Ellen Kutzer: Let me further represent there are more feeders on the list of the feeders in the Grid Needs Assessment than there are in the VPP list of affected feeders. Any reason to disagree with that observation?

Mr. Pollock: No. And I'd be happy to explain why that may be the case.

Ellen Kutzer: That's my next question. Tell me why there's a difference.

Mr. Pollock: So the methodology the company used, and this is really getting into the ABP record, but I think it's helpful context here. We looked at the feeders and associated banks of our entire system, which under our current methodology, resulted in about 371 feeders, I believe. Most of those were dedicated feeders that were over our 75% planning threshold, which we used to consider and prioritize capacity projects. We also brought in, I think it was around 60 or so additional feeders, or rather, 60 feeders that corresponded to banks that were over that limit. But we did remove feeders where we are anticipating or working on a project that will be completed by 2025. So it's a smaller subset than the feeders that would be available in the Grid Needs Assessment, which is inclusive of 25 through 29.

Ellen Kutzer: Do you agree with me that the company still gets significant distribution value if a DER is interconnected to one of the feeders listed on the Grid Needs Assessment, but not the VPP affected feeders?

Mr. Pollock: I think you, I would ask you to rephrase that question with a little bit more specificity as far as timing.

Ellen Kutzer: Sure. I think when I speak to value, I'm talking about this distribution credit that you've agreed to in your rebuttal case. And I'm trying to parse out why you are distinguishing those feeders on the VPP list from getting that credit from those remaining feeders on the Grid Needs Assessment that are also slated for upgrade in the distribution system plan.

Mr. Pollock: Yeah. So again, going back to the removal of the 2025 feeders that were indicated, we need to serve those loads now or in the relatively near future. Doing that requires executing projects in 2025. A lot of the work for those projects begins before that, so there is a significant risk that the company is not willing to support with potentially waiting for VPP capacity to potentially show up or not show up on those feeders. I think that's one of our overlying concerns. We're not sure of where aggregators and developers may choose to develop resources, but that timing component with 2025 is a real challenge and risk for the company. And that's not too dissimilar to the way the company approached NWA screening. NWAs are obviously a bit more specific. That's where we've identified a specific project that is slated to go into service and we have a specific need date that we're trying to leave or defer that project with DERs or other non-traditional solutions. But it's the same type of challenge where if you have a very near-term need and aren't sure whether you're going to get that capacity in a spot you need it, it becomes really difficult to plan around that and create significant risk of not being able to serve customers on the distribution system.

Ellen Kutzer: So you're only, let me make sure I heard you correctly, you're only offering the distribution credit for those feeders that are slated for upgrade in 2025? Is that accurate?

Mr. Pollock: No, it's the inverse of that actually. We're offering, offering the credit for, so our distribution budget in the DSP covers five years. Generally those projects are expected to occur in that timeframe. We have removed 2025 given the near-term nature of those needs and the requirement to have those projects in service. So the credit would apply for all years beyond 2025 through the 29 budget.

Ellen Kutzer: Okay, got it. Let me, let me reframe a question I've already asked you. Do you think that a distribution-sited asset on one of the 2025 feeders, those slated for upgrade in 2025, would still have a potential to provide significant value to the company system, maybe even offsetting the need for an upgrade?

Mr. Pollock: Potentially, but it's, it's hard to say definitively. It would depend on the type of DER and whether it shows up in a bid that is cost effective relative to the other resources that we see in the ERP bids.

Ellen Kutzer: Got it. But again, you're not providing the list of affected feeders to bidders until the RFP is launched in this case. Correct?

Mr. Pollock: I, I don't think I said that. I think I said that the stop gap would be providing it with the RFP. There's a possibility depending on when we get a final decision in the DSP and ABP case, we could provide it earlier.

Ellen Kutzer: Mr. Pollock, let me ask you directly, why not provide that list right now through a similar mechanism that you're providing folks access to the Grid Needs Assessment if it's essentially the same list of feeders?

Mr. Pollock: Well, I think that's, it's a possibility, but the challenge there is that the methodology for determining those feeders is something that was proposed and will be litigated as part of the DSP and ABP case. One of the challenges right now is we're looking at different windows and we've been asked about this in the record of that case, that correspond to the bulk system peak. To the extent those windows may change, that there may be consensus around moving to distribution feeders that have a forecasted peak versus a historical observed peak, those are all things that would need to be reflected in the final set of materials that are provided to bidders.

Ellen Kutzer: So I definitely, I definitely understand, sorry to cut you off, definitely understand that there's a lot up in the air because we're litigating this issue in another case. But don't you agree with me that it would be useful for potential bidders to have the access to geographic locations now so they could choose whether or not to potentially invest in a DER asset in that location, understanding the risk that that location may not make the final cut?

Mr. Pollock: Yeah, I can attempt to answer that. I think you're deeming this information very critical based upon the assumption that it's not modified in the actual case. To put my developer hat on for a second, I can say this, having worked for infrastructure funds that purchase and supported transactions in the DR space. I would not want to be making financial or economic decisions based upon information that is subject to change in the future.

Ellen Kutzer: Fair enough. But that's the developer's risk to take on or not, correct?

Mr. Pollock: Sure, that's, that's fair.

Ellen Kutzer: Okay. So, let me just look at my questions here. I've got only a couple of additional ones for you. You mentioned that there may be changes to this list of feeders. Is one of the changes being contemplated adjusting the feeders on the VPP list based on a change of the peak times that in the time-of-use case?

Mr. Pollock: It's under consideration or has been asked about in development of the record in the DSP and ABP case. The company has no definitive plans right now to make that change, but we're open to considering alternatives.

Ellen Kutzer: So you're not making that change in light of the fact that the this Commission has changed the TOU peak in its recent ruling?

Mr. Pollock: That's correct. We haven't proposed making that change in the ABP case at this juncture.

Ellen Kutzer: Okay. Just another moment, Mr. Pollock. Let me just close with this. What would the process be if developers had an interest in accessing this list? How could they request it from you and get a decision one way or the other as to being able to access it?

Mr. Pollock: I'm not sure we've decided that right now. You know, the secure portal is one potential opportunity. I think what would be more efficient is to work with Mr. Landrum's team that conducts the Phase 2 solicitation to figure out a way to combine that with the RFP process or again, potentially ahead of the process if we have some finality on that decision. But I don't think using a separate channel, separate from the Phase 2 process or supporting processes of the RFP, makes a lot of sense.

Ellen Kutzer: All right, Mr. Pollock. Thanks for your time. No further questions for me. Thank you.

Eric Blank: Thank you. I have 10 minutes from CCSA. Mr. Dunbar.

Scott Dunbar: Thank you, Mr. Chair. And before I get started, I apologize for not noting this at the outset. I'm going to be excusing myself from the hearing on Monday and Tuesday, much as I will miss spending 11 hours with you all on those days. I'll be in a different hearing, probably for the same amount of time. So we will most likely waive our cross of UCA witness Neil. So if I'm, if I'm not present, then we're waiving him. I can't imagine we'll get to him today. The only other witness we have cross reserved for is Ms. O'Neal, and with staff. So hopefully she will come up today and we'll get to do that. But if it's Monday, I won't be there, so I think it's very unlikely we're going to get to Ms. O'Neal today. Okay. Yeah. So if, if we don't, then we will so waive. So, I will try to stick to my 10 minutes, but if I go over, I'll take the time out of, out of those, if that's all right.

Eric Blank: Okay.

Matt Larson: Mr. Dunbar, Mr. Chairman, just to clarify, did you definitively waive cross of UCA witness Mr. Neil, or did you not? I'm not sure I followed that. I think he did.

Eric Blank: I, I, since he's not available Monday and Tuesday and there's no way Mr. Neil is getting on before Monday or Tuesday, is it fair to say Mr. Dunbar, you're waiving cross?

Scott Dunbar: I'm fine with that conclusion, yep.

Matt Larson: Thank you. I appreciate the clarification. Sorry for the interruption. Mr. Larson was looking puzzled, but...

Scott Dunbar: No, we were hearing feedback. I was trying to figure out where it was coming from. I think it may be coming from Mr. Pollock, but that was, that was the puzzlement.

Scott Dunbar: Okay. Yeah, no, no worries. Okay, thank you. So, Mr. Pollock, it's good to meet you. I'm CCSA counsel. My name is Scott Dunbar. I don't think we've met before. I'd like to talk to you about the proposed distribution credit. I will try not to overlap with Ms. Kutzer's questions, but just to lay the groundwork, it was the company that first proposed the concept of using a, or excuse me, of applying a distribution credit to bids that connected distribution voltage in Mr. Landrum's supplemental direct. Correct?

Mr. Pollock: Yes.

Scott Dunbar: And just for additional clarity on the record, it's specifically a subset of the distribution circuits that were identified in the Grid Needs Assessment in the company's distribution plan. Okay. And do you recall that CCSA witnessed Mr. Beach provided some comments and recommended improvements to that concept in his answer testimony?

Mr. Pollock: I, I briefly skimmed his testimony, so I have a general sense of what he recommended.

Scott Dunbar: Okay. And so after proposed, after Mr. Landrum proposed using these values in his supplemental direct, now in your rebuttal testimony, or rather then in your rebuttal testimony, you argue that these values should actually be litigated in the VPP docket and not in this docket. Correct?

Mr. Pollock: That's correct.

Scott Dunbar: Okay. So on page 12, starting at line nine of your rebuttal, you state that you don't agree with Mr. Beach's recommendations, which you just said you only skimmed. But do you recall that Mr. Beach recommended increasing the value of the distribution credit that is applied to distribution connected bids on constrained circuits?

Mr. Pollock: No. And I believe in that same question or shortly around it, I made the distinction, recommendation that that specific issue be taken up in the AVP proceeding given that there's nothing else in the record in this case relating to those values.

Scott Dunbar: Okay. And so no other Public Service witness addressed this recommendation?

Mr. Pollock: Not that I'm aware of.

Scott Dunbar: And I know you just skimmed it, but do you recall that Mr. Beach also recommended that the Commission approve a base distribution credit of $65 per kilowatt year that Mr. Beach says should be attributed to all distribution connected resources? Do you recall that?

Mr. Pollock: Yes.

Scott Dunbar: But neither your testimony nor the testimony of any other Public Service witness addressed that recommendation of Mr. Beach. Correct?

Mr. Pollock: That's correct.

Scott Dunbar: Okay. And on page 13 of your rebuttal, you state, quote, "Any updates to the locational value methodologies that underpin the company's AVP proceeding could be incorporated into the Phase 2 bid evaluation process under the JTS Phase 2 framework discussed by company witness Mr. Aley," end quote. And do you see that there?

Mr. Pollock: Give me a minute to get there. What page was that, Mr. Dunbar? That was page 13, starting line one. If you can pull it up, that's even better. Perfect. Yes.

Scott Dunbar: So just to put a finer point on the distinction between the distribution credits that issued in this docket and in the AVP docket, in this docket, all of the adder and credit values that we've been discussing, including the distribution credit that you address, those are simply inputs into the Encompass software model, right?

Mr. Pollock: That's correct.

Scott Dunbar: So they're, they're not actually paid to bidders. Correct?

Mr. Pollock: Thank you. So in this respect, the distribution credits that we're talking about are fundamentally different from the distribution credits at issue in the VPP docket because in the VPP docket, at issue are credits that are actually paid to VPP providers. Correct?

Scott Dunbar: Yes.

Mr. Pollock: Would you agree that this concept of a distribution credit is intended to send a market signal that distribution connected bids provide value to the system?

Mr. Pollock: I think that's generally fair.

Scott Dunbar: Great. And do you agree that all else equal, market signals are more effective when the market has more time to respond to those signals?

Mr. Pollock: That's, that's a complicated question, so I'm not sure I would fully admit that's true. My understanding, again, having some previous experience in the industry, is that developers often have a pretty active pipeline. So while yes, having more time is always great, I'm assuming that there's active development work going on in these areas that apply to about 50% of the company's distribution system. I think you agreed with Ms. Kutzer that it's important to communicate to bidders the location of the constrained distribution credits. Excuse me, the location of the constrained feeders at which bidders will receive distribution credits. Correct? I think we agree that it's important to disclose that, and that also the company is committed to providing that information. Would you agree that, all else equal, bidders are more likely to submit higher quality bids if they receive this information sooner rather than later?

Mr. Pollock: I can't speculate on that, and I would argue that the phrasing of "high quality" is a bit ambiguous. You'd have to further define that for me.

Ellen Kutzer: Okay, we can move on. So, hopefully, it's clear to you that CCSA believes that the distribution credit values are a live issue in this docket, and the commission can establish those values in this docket. But just to clarify the company's position: that these distribution credit values should not actually be established in this docket. Correct?

Mr. Pollock: That's correct. That's what my testimony says. And I also point out that in addition to the distribution credit, DERs are avoiding the transmission adder. They are qualifying, regardless of where they may be on distribution, for the transmission credit as well as whatever their actual bid price may be for the energy value in the JTS. As I said to Miss Kutzer, the distribution component is a small piece of the overall benefit stream that will be modeled for DER bids.

Ellen Kutzer: Well, if the commission adopts Mr. Biech's recommended value of $276 per kilowatt-year for resources located on constrained bids, that would be a pretty meaningful value, wouldn't you say?

Mr. Pollock: The value is higher than what the company proposed, but there's not, in my opinion, a sufficient record to take that credit and apply it in this proceeding, even though the company was the one that introduced this concept in this docket.

Ellen Kutzer: Correct. It cross-referenced another proceeding where that concept is developed and expected to be litigated. So yes, we introduced it, but there was never an expectation it would be litigated in this docket. Okay, and the company is also committed to updating any potential outcomes that come out of that proceeding in this docket. So again, I will reiterate what my testimony says: we don't feel it's appropriate to litigate this issue in this docket given that the timing works out where we'd be able to incorporate any outcomes of the AVP proceeding into this docket.

Ellen Kutzer: Okay. So, I think we're clear on what we disagree about there. I appreciate what you just said, that the company is committed to, if CCSA's advocacy is unsuccessful in getting the commission to adopt an avoided distribution value in this docket, at the very least, the company's committed to transferring the values that are decided in the VPP docket into this docket and using them in the Phase 2 modeling. Did I hear that correctly?

Mr. Pollock: Yes, absolutely.

Ellen Kutzer: Okay. So, if the commission approves a higher number for the avoided distribution credit on constrained feeders than what the company's proposed, that's the number you'll use in the Phase 2 modeling in this docket. Correct?

Mr. Pollock: Any change coming out of that proceeding, higher or lower, we would propose to bring into the JTS Phase 2.

Ellen Kutzer: Okay. And just to underline that, if the commission approves a concept that the company hasn't proposed, which is an avoided distribution credit that's a base credit that applies to any feeder, even if it's unconstrained – if the commission approves that concept in the VPP docket, you would also transfer that value and use that in your Phase 2 modeling here?

Mr. Pollock: I think whatever the commission elects to approve in that proceeding, the company is committed to bringing over. So, I won't speculate on specific concepts introduced by CCSA, but the general intent is to follow commission order out of that proceeding in this proceeding.

Ellen Kutzer: Okay. And how confident are you that there's sufficient time between when the VPP will be completed to bring those numbers over to the JTS and include them in the RFP documents?

Mr. Pollock: I don't think that's a big lift. So again, there's a lot of uncertainty around timing and decisions and requests for rehearing or re-argument, but I believe there should be sufficient time if everything is relatively on schedule.

Ellen Kutzer: Okay, that's all I had. Thank you, Mr. Pollock.

Mr. Pollock: Thank you, Mr. Dunbar. Thank you, Commissioners.

Mr. Dunbar: Thank you, Mr. Dunbar. I don't think Commission Counsel has any questions.

Commissioner Gilman: Good morning, Mr. Pollock.

Mr. Pollock: Morning, Commissioner Gilman.

Commissioner Gilman: I just have a few for you. First is regarding cost assumptions around distributed storage. Mr. Turner criticized the company's cost assumptions for distributed storage. For those cost assumptions, you assumed the full cost of the asset. Is that accurate?

Mr. Pollock: I wasn't directly involved in that modeling, but my understanding from speaking with Mr. Landram is that the full cost of the asset based upon the ENL ATB was used.

Commissioner Gilman: Okay. And are there examples of either company programs or other utility programs where the utility would cover just a portion of the cost of the asset for the ability to control it?

Mr. Pollock: I think we're looking at that, and as I alluded to in my testimony, we're open to updating our modeling assumptions in the future. Those are recommendations both Mr. Turner and I believe Miss Valentine made. One of the challenges is that there's not a lot of information out there today, so I believe the modeling exercise Mr. Landram's team conducted is still analytically valid, but it definitely creates sort of the top end of the bookend of what we'd expect. We're absolutely open to exploring and looking for opportunities to leverage those resources in a way that may be lower cost. But as I noted in my testimony, there's also trade-offs with that. Today, for example, with our Renewable Battery Connect program, we only have the ability to dispatch that 60 times a year for up to three hours. So we're talking something that's effectively a 2% capacity factor on an energy-limited resource. So there's definitely trade-offs, and I think as we continue to refine our programs and better understand from a capacity accreditation factor what the opportunity is to potentially model different costs moving forward in any future Phase 1 modeling.

Commissioner Gilman: Okay. And I know you've brought up kind of those restrictions around the 60 occurrences, three hours a piece. Who set those terms?

Mr. Pollock: That's going back a few years ago. I think that was largely a combination of our regulatory team and our customer program team when we developed the RES plan, and I believe that was based upon some benchmarking that we did with some other utility battery programs at the time.

Commissioner Gilman: So that's at the company's discretion that the terms are set as that in your program, right?

Mr. Pollock: Generally, yes. And I'll note that we did propose in the AVP proceeding – that's a mouthful – moving that up to a four-hour dispatch and being able to call 100 events a year. So putting it much more in line with what we anticipate and hope to be more of the accredited capacity that we would see from a four-hour lithium-ion battery, so much more useful from a system perspective.

Commissioner Gilman: And is kind of the added usefulness of a longer duration paired with a higher number of occurrences modeled at all in the JTS proposal in another proceeding?

Mr. Pollock: My understanding is that's exactly the methodology Mr. Landram used in modeling aggregated DERs as a four-hour battery. It's very similar to what the company proposed in the AVP proceeding. What's unique and different and will be developed as part of that case is the company is not putting our thumb on the scale as to what technologies may be able to bring that capacity. So if we get a bunch of four-hour batteries, we can aggregate those. If that means we need several hundred megawatts of thermostats, given that thermostats typically have a lower impact on peak and they are typically not sustained reductions, that's good too. But we're trying to move away from picking technologies and just defining the attributes that are useful from a system planning perspective.

Commissioner Gilman: Okay. And this goes back to some of your discussion with Miss Kutzer, but I want to make sure I understand. So the company proposes to provide DERs located in certain feeders an avoided value of distribution credit as it would be calculated in AVP proceedings. So how may I just understand the current proposal for how the company anticipates the locations and values will be provided to potential bidders in the JTF?

Mr. Pollock: I think that would likely be consolidated as part of the Phase 2 bidding process. So either directly with the RFP, I think that would be the latest period that we would release the information. Ideally, if we have a decision earlier in the AVP case, that's something we could explore providing to DER developers and aggregators ahead of the actual RFP issuance.

Commissioner Gilman: Okay. And then, in your rebuttal testimony, you had brought up a Brattle study that you're working on a new study to lead a cross-jurisdictional load flexibility study. Those were the exact words. Is that study for use in a certain proceeding coming up?

Mr. Pollock: That's internal work the company is doing, but we anticipate that the outcomes of that may influence or may be reflected in future proceedings.

Commissioner Gilman: Okay. What's the anticipated timetable of that report or study?

Mr. Pollock: That's a good question. I think it's, I want to say, somewhere between six and nine months, subject to check.

Commissioner Gilman: Okay. Is that something that would be made available to the commission in any way once it's complete?

Mr. Pollock: I'm not sure. I mean, I certainly don't think we'd have a problem disclosing that, but I'm also not the one working on and leading that study, so we'd have to check with that team.

Commissioner Gilman: Okay. And can you help me understand just in any sense kind of what technologies or variations of load controller incentives are being looked at as part of that study, just so I can understand kind of the breadth that you're going on that?

Mr. Pollock: I will do my best. Again, I'm not directly involved in it. I think we're looking at a pretty broad array of technologies, and it includes not just technology adoption, technical potential, economic potential, but also looking at human behavior interaction, so thinking about customer fatigue, things like that. I believe Brattle is also planning to look at distribution feeder archetypes to understand the applicability of those load flexibility technologies both in a bulk system context, but also in a distribution context.

Commissioner Gilman: Okay. And do you think it's going to in any way test — and I'm sorry, I know you said you're not directly involved with it, but it's from your testimony, so you're the only one I have to ask here — do you think it will test at all different incentive levels to understand kind of the depth and ability of customers to respond to a varying degree of company incentive signal?

Mr. Pollock: I believe something along those lines is in scope, subject to check.

Commissioner Gilman: Okay. And you had mentioned like six to nine months, roughly. Is that work already underway, or has the six to nine months not commenced yet?

Mr. Pollock: We coincidentally had the kickoff meeting yesterday, so it's already underway.

Commissioner Gilman: Okay, awesome. Thank you so much. Those are my only questions. Thank you, Commissioner.

Commissioner Plant: Thank you. Good morning, Mr. Pollock. How are you doing?

Mr. Pollock: Morning, Commissioner Plant. I can see you. Good to see you too.

Commissioner Plant: So I just had a couple of quick questions around some of the assumptions on distributed generation and how it's being handled, as well as some of the proposals that we've heard from others in the case and how we might think about it. And obviously, as we've talked about, this is sort of going on simultaneously with the VPP case and the DSP case, so we're trying to juggle these decisions a little bit. So I apologize for crossing back and forth.

Mr. Pollock: No worries.

Commissioner Plant: But on page 85 of Mr. Landram's rebuttal testimony, he discusses the modeled 100 megawatts of distributed demand resources through 2030 and 25 megawatts of incremental acquired distribution demand resources after that. Is that, to your knowledge, just the Renewable Battery Connect program that he's referencing there?

Mr. Pollock: I'm not certain what he's referencing. If you are able to pull it up, I might be able to provide a little bit more clarity, but I'm not sure I can answer that.

Commissioner Plant: I think it's coming up right now. So it'd be page 85. Thank you, I appreciate that.

Mr. Pollock: I'm sorry, what line did you need?

Commissioner Plant: I'm looking right now. Okay. Maybe go down a little bit. Okay, I see the line you're talking about here, 11 to 13-ish.

Mr. Pollock: Yeah, yeah. I believe that's reflective of the 50 megawatts in 2026 and 50 megawatts in 2027 of dispatchable distributed generation that was a byproduct or outcome of Senate Bill 24-207.

Commissioner Plant: Okay. And is that so that would be all, you know, technology neutral, not just the Renewable Battery Connect program? Is that correct?

Mr. Pollock: I think the way that companies approach that, and this is something that's filed in our Renewable Energy Plan, we filed a few months ago, we're looking specifically for that program to meet that requirement: front-of-the-meter distributed battery storage with, I believe, we specified a four-hour requirement. So it would be separate from any contribution of Renewable Battery Connect.

Commissioner Plant: Okay, but it would be batteries, correct? Or it would be just modeled like a battery?

Mr. Pollock: Correct. That's my understanding.

Commissioner Plant: So I just wanted to clarify between the two of those. It would be modeled as a battery, or it would actually be batteries?

Mr. Pollock: I can't speak with certainty to how Mr. Landram would model it, but what the company is seeking in the Renewable Energy Plan to meet the DTG requirement is four-hour batteries that are specifically front-of-the-meter distribution connected.

Commissioner Plant: Okay. So those would be front-of-the-meter. Gotcha. Correct. And just to clarify for me, the two phases of the VPP development...

Mr. Pollock: You can take that attachment time, or the hearing time. Thank you.

Commissioner Plant: There's the first is the Aggregator DERMS, and the second is the Grid DERMS. Correct?

Mr. Pollock: Correct.

Commissioner Plant: And what is the current status of the Aggregator DERMS project?

Mr. Pollock: We selected a vendor several months ago. We are quickly moving into testing and moving towards, I believe, an end-of-summer go-live date on that, specifically for the Renewable Battery Connect capability. And then we are also... it's interesting, we've kind of evolved that platform from what we originally proposed in the previous DSP as our demand response management system to really be a platform that will support leveraging DERs for system benefits in a variety of ways. So we're planning to bring in a lot of our legacy demand response programs as well as use it to support the AVP functionality that we proposed in that proceeding.

Commissioner Plant: Okay. So they would be sort of subsumed all into the VPP program?

Mr. Pollock: The resources would be managed through the same technology platform, but they would be separate programs, at least for the time being. So Renewable Battery Connect would still stand by itself. I think as we proposed in the RES plan, depending on the outcome of the AVP case, that capacity would likely be separate from the RBC capacity. So a lot of similar initiatives, but we're hoping to use the same technology platform to be able to manage all that.

Commissioner Plant: And then what's the timeframe for the Grid DERMS project?

Mr. Pollock: We've just begun some work on that, working with our vendor that we are using for that, as well as some internal consulting work around the business process and corresponding change management that's needed to support the technology deployment, but we're anticipating standing that up by the end of Q1 2026, as was, I think, required by the VPP docket.

Commissioner Plant: Okay. And would that be fully operational at the end of the first quarter of 2026, or would there be a process of putting out bids for aggregators and bringing them into the program and all that sort of thing?

Mr. Pollock: It's a good question. The way we're approaching it, in our experience, it doesn't make sense, and there's also significant cost disadvantage to roll out a system for the entirety of the distribution system. So as we've noted in our Distribution System Plan, we're really focused on a couple of key use cases, like flexible interconnection and flexible load energization, and would plan to deploy that on a more limited scale for parts of our system. And then there's also a customer element as well. We need to find developers or new load connections that are interested in being a part of that, and the timing and financials make sense for them. So the technology is intended to be ready to go by the end of Q1 2026. Whether or not we are able to find customers that want to participate in that timeframe, I think is still a bit of an open question.

Commissioner Plant: And you're going to be, if I understood you correctly, you're going to be prioritizing those parts of the distribution system that are currently at high need, basically reaching that 75%?

Mr. Pollock: Not quite so. So flexible interconnection on the load side, yeah, I think that's probably fair. We'd be looking to use that technology capability to bring on loads more dynamically if there is a constraint, but not breaching the 75%. And on the generation side, it's sort of the inverse of that. So using either real-time control or forecasted scheduling to be able to manage DERs in relationship to grid constraints, rather than just sort of the typical set-it-and-forget-it approach you have for interconnections today.

Commissioner Plant: So my understanding is that both of these systems, the Aggregator DERMS, which in my mind – and you correct me if I'm wrong – is sort of differentiated by this is a grid-level dispatch, it's not based on conditions at the distribution level, it's more of a grid dispatch, more like the DR kind of example you were talking about. And then the Grid DERMS that integrates with the ADMS and the SCADA systems and can be actually triggered by distribution-based needs. Those are both going to... the Aggregator DERMS is going to kind of get launched first. Grid DERMS would then be sort of feathered in after that. And the guess is that both would be kind of up and operational fully with participants by what, 2027, 2028?

Mr. Pollock: I think that's generally a fair assumption. Yeah, I might have to get back to you on that, but the technology piece we're aiming for in 2026. And then again, I think the ability to bring on customers into the technology and the supporting business process changes we need to make, I think that'll be something that's ongoing for the next three to five years. But the end vision is to bring those two systems together.

Commissioner Plant: So we were talking a little bit about, and I think you were talking with some of the other parties, about the distribution value and the allocation of distribution value within the VPP system, and basically how that gets modeled. And I'm curious, because it seems to me that that value is really optimized when you're in that full Grid DERMS, because you're actually able to dispatch based on the distribution system conditions as opposed to the bulk conditions, which are kind of sent out across the entire system and might not be aligned – could be aligned, but might not be aligned – with the capacity constraints on a specific distribution feeder. Is that correct?

Mr. Pollock: It's a really good question. So the way I think about it is there's a spectrum of distribution value. If you want to go to the most specific, detailed value, you're really talking about a non-wires alternative where you're specifically seeking to load match using DERs or other non-traditional resources so that you can defer or avoid a known project that's slated to be built. I do think there is quite a bit of value in a more broader but less surgical approach, which is similar to what the company's proposed in the AVP proceeding, where we try to at a higher level create more of a generic value for distribution capacity where we may not know whether aggregators will actually show up and develop capacity there, customers there. But you would see the impact of that in the company's load forecast rather than forecasting that in as an NWA and saying that we can definitely defer this project if we get a bid there. I think that's much more of a, kind of, wait and see and see the impact of that in the load forecast. But the idea is you're spreading those load reductions across a much broader area of the system. So one, you've got more coverage, and two, you have the opportunity to more incrementally chip away at some of those grid needs over time, as opposed to the very specific load following that's typically required by NWAs in a very specific window in order to defer a project.

Commissioner Plant: Are you talking there – and you made this distinction in the last discussion – are you talking there about the difference between what you're offering to the aggregators as sort of an avoided capacity payment versus what's being modeled in the JTS? Are we modeling that value in the JTS?

Mr. Pollock: We are. We're taking the AVP avoided distribution value and applying that, or proposing to apply it as a credit in the Encompass modeling. Okay, so any DER bids would have their energy price or levelized cost as their bid, and then they'd also have that distribution value applied to make the bid effectively look better given that it's distribution site. If it's located on one of those feeders...

Commissioner Plant: Would anybody who's enrolled or any aggregators that are enrolled in the Aggregator DERMS project, would they then be automatically enrolled in the Grid DERMS project, or would there be some sort of a, can we assume that those are sort of overlapping?

Mr. Pollock: They're sort of running in parallel but separate paths at the moment. So right now, the company is proposing to leverage the Aggregator DERMS platform. There is a potential in the future that we may seek to manage some of those resources through Grid DERMS as we get more experience and capability with that.

Commissioner Plant: Is the objective here really to be able to dispatch a signal, "we need this much capacity," get it out to the aggregators and then capacity delivered at that signal?

Mr. Pollock: I think that's one potential outcome. Again, right now we're focused on reducing as much loading as we can in areas that we know are constrained, whether or not it leads to an actual project deferral or avoidance of a project, I think is yet to be determined. But certainly in the future, I could envision more of a load-following type approach for certain parts of our system. I think one of the other challenges there, and I think we've spoken about this in the VPP docket, the technology piece of DERMS is solvable. There are technologies you can buy today. The concept that you take that exists on the bulk system of having a single operator dispatching more or less to a single objective of keeping the grid at 60 hertz – you're taking that same concept and now creating a new role that doesn't exist in distribution, where somebody's got to be monitoring 800 distribution feeders and making sure they're doing what you want. So the technology piece is certainly a part of it, but we're also working to develop our internal capabilities from our organization and skill set perspective to be able to effectuate that type of management, and that's something that's going to take some time to do.

Commissioner Plant: How, considering those various different barriers and also increasing numbers of participants, how should the commission think about the ELCC for those resources? It sounds like one of the things certainly that in resource adequacy they're looking for is this idea of a perfect capacity resource, which I think Mr. Landram said doesn't exist, but it's kind of a modeling thing. But if you've got all these resources through aggregators that are available on the system, and you can dispatch and get that load reduction, should that be considered a perfect capacity resource, or should the ELCC somehow reflect that capability of dispatch?

Mr. Pollock: It's a great question, and this sort of speaks to how we actually developed the AVP proposal, as I was talking with Commissioner Gilman here a minute ago. We got our resource planning team, our commercial operations team that dispatches, our customer team in a room, and we started to think, "What would a more ideal product look like?" I wouldn't describe it as being a perfect VPP product, but we aligned around the idea of, we need more duration in terms of resource availability across a broader swath of hours given some of the challenges that Mr. Ming and Mr. Landram highlighted, and we need more availability of the resource across more hours in the year. So that's how we landed on the four-hour, 100-event duration for what we're proposing in the VPB tariff. That would effectively get the same ELCC that would be applying to a four-hour battery in the bulk system. So there's a lot of value for something that is energy-limited. Obviously, that value steps down over time as you add more resources to the system. But we think that is necessary to move consideration of DERs away from just being something that's a carve-out in a DSM plan or Renewable Energy Plan into something that helps improve our resource adequacy position in a way that we consistently and reliably can rely on them.

Commissioner Plant: Do you see the creation or the method of determining what an appropriate ELCC, as opposed to a proxy, for that system, do you see that coming out of the VPP DSP case?

Mr. Pollock: I think in many ways we already have it from the modeling our resource planning team is doing. If it has similar parameters to a large-scale four-hour lithium-ion battery, I think it's reasonable to apply a similar ELCC. What's interesting, at least in my view, about how we've approached the AVP proceeding, is we're not specifying specific technologies. As long as an aggregator can bring us four hours of sustained dispatch for 100 times a year, they will get the full compensation. If that means a more limited number of batteries to reach that performance threshold, or higher level of things like EV chargers or thermostats, I think that's on the aggregators to figure out. But we feel like we're approaching this in a way that's very technology neutral and more focused on seeking attributes that will give us the biggest capacity and resource adequacy value versus picking and winning and losing technologies.

Commissioner Plant: Is there any sort of basis for that other than the proxy of a battery?

Mr. Pollock: I think the four-hour duration that's pretty well studied in the resource planning side of the world. I say this not just from my experience with PESCO and Excel, but that's sort of the bare minimum in organized wholesale markets for a resource like a battery. You want a minimum duration of four hours. As you add more to the system, the ELCC steps down, so you're actually looking to bring on six-hour and eight-hour duration batteries.

Commissioner Plant: No, but I was just wondering, as it relates to distributed resources, other than the proxy of the battery, is there any reason that that four hours is sort of what you're targeting?

Mr. Pollock: Again, I think it goes back to what does the system need from a resource adequacy perspective? It's challenging to straight face say that a couple kW reduction for an hour from a thermostat by itself is going to provide a lot of value from a resource adequacy perspective, and we expect to see a similar discounting in terms of ELCC in applying that as a resource model in the overall Encompass modeling or an ELCC study. So...

Commissioner Plant: Okay, not sure if I'm answering your question. Trying to get there though. Yeah, no, I appreciate it. The last couple of questions I have. In the Aggregator DERMS program, are there vehicle companies that are basically serving as aggregators using their charging infrastructure or their vehicle infrastructure and proposing to participate in that way?

Mr. Pollock: We haven't had any direct conversations, but I'm aware of companies that are, especially on the demand response side, doing load reductions that they're either bidding into a market or part of utility programs. So I wouldn't be surprised if we see some interest there.

Commissioner Plant: Is there the opportunity that those could become a part of a managed charging program, or would that only be considered managed charging if it's basically initiated through the utility Excel system?

Mr. Pollock: It's an interesting question. I think so. My understanding of managed charging today is that it's mostly load smoothing out over the overnight hours where we have excess capacity available in the system that is probably not going to meet the more stringent requirements from a resource adequacy perspective that we've modeled this AVP program around. So it's possible that we could either modify our managed charging and make more onerous or stringent requirements around that. It's possible we could have aggregators that try to come in as part of the JTS bid or part of the AVP proceeding. It's just hard to say right now, honestly.

Commissioner Plant: But it is possible that that aggregator program could help to essentially increase the managed charging capabilities of the company going out into the future as it's getting implemented?

Mr. Pollock: From a resource perspective, I think that's a possibility. I think the other distinction I'll make is that managed charging today is more of a load management tool, not necessarily a supply-side resource. So it can do a lot to reduce peak, and I think Mr. Goodenough highlighted, our managed charging modeling shows a two-gigawatt reduction in peak through 2050. I think what you're talking about is, could you use managed charging through an AVP construct to actually be a supply-side resource? I think the company has been pretty open to, as long as you meet the attributes of the program from a duration, a dispatch, and a performance perspective, we don't really care what technology it is, as long as you meet those requirements.

Commissioner Plant: Yeah, I mean, I think it's really a modeling question in terms of the resource need and how much of the EV charging should be attributed to peak. If we're able to get our managed charging above the current 10% and increasing it two and a half percent per year, if the aggregator program can help to do that, then that would be something that would be considered within the model potentially. I don't want to speak for Mr. Landram, but I think it's worthy of exploration. One final question. I don't know if you're familiar with DOE. It came out with a sort of best practices in IRP planning report last year. I think it was done by Synapse and LBNL.

Mr. Pollock: Sounds familiar. There's a good chance I may have skimmed it at one point.

Commissioner Plant: And in that, they have a number of different best practices, and within the demand-side resource inputs, they identify two practices. One is the load modifier approach, which they call the most common, and it's, I think, what has been proposed by a number of the parties in this proceeding to basically just reduce your load numbers by the available demand management. And the other is the competitive resource approach, which I think sort of incorporates demand-side resources in the capacity expansion model as priced competitive resources that can be selected as a part of the capacity expansion in optimized decisions. It seems like that's sort of the way that the company is proposing to use demand resources in this case. Does that seem a fair characterization?

Mr. Pollock: I think that's a fair approximation. This actually goes back to, I think, an exchange that either Mr. Goodenough or Mr. Landram had with Chair Blank. Part of the reason we subtract solar out and then add it back in is because we're not modeling it as a load modifier. We actually model it as a resource with an accredited ELCC. So it may be counterintuitive that we're sort of taking a resource out and then we show a higher peak, but that's because we're modeling it as a supply-side resource. So I think the company's already taken steps to go in that direction, and the AVP tariff and the corresponding bidding opportunity in the JTS and some of our other programs are all just additional steps we're making to go in that direction.

Commissioner Plant: Understood. So, would it make any sense for the commission to treat the demand resources as a load reduction until the point where the Phase 2 DERMS program is really fully up and running and applicable, so that you can actually get that capacity value directly through that program, as a sort of interim step to getting to capabilities that are contemplated under the VPP proceeding?

Mr. Pollock: I'm not sure I'm totally following. Can you help me understand what you mean by "treated as a load modifying resource"?

Commissioner Plant: Yeah. So take your basically your expected load, subtract out your demand management capacity directly, until that point, whether it's 2027, 2028, when your full Phase 2 DERMS program is implemented with your aggregators, et cetera, so that you're actually achieving those ELCC and capacity values that you're modeling within the program. It seems like we have a ramp period where we're applying this capacity value, but we don't actually have the program up and fully running yet. And I'm wondering if it would make sense to use basically the simplified load modification model to a point and then apply whatever ELCC is deemed appropriate through the AVP process.

Mr. Pollock: I think I might defer that one to Mr. Landram, just because that's starting to get into a little bit of resource planning and resource adequacy territory. And I do, as I noted a minute ago, we are modeling many demand-side resources from a supply-side perspective to understand that impact, so I'm not sure we want to go backwards in some regards there.

Commissioner Plant: Understood. All right, thanks. That's all the questions I have. Thank you.

Unknown Speaker: I don't have any questions. Redirect, Mr. Larson?

Matt Larson: Yeah, just if I could have one moment here, just to run through my notes. I wouldn't mind a five-minute break for eight minutes.

Eric Blank (Chair): Yeah, we could. Why don't we take a break till 11, and then we'll come back with redirect? Sounds good. Thank you. All right, Mr. Larson.

Matt Larson: Thank you, Mr. Chair. Good morning again, Mr. Pollock.

Mr. Pollock: Morning, Mr. Larson.

Matt Larson: So, just a few quick questions with respect to the cross-examination and commissioner questions that you had. I want to start with the discussion about Hearing Exhibit 310, the feeder list. When would that information be provided? You discussed that with Miss Kutzer, Mr. Dunbar, and on commission questions. Do you recall that?

Mr. Pollock: Yes.

Matt Larson: And so the company could provide an updated version of that information contemporaneous with the RFP or potentially before? Is that right?

Mr. Pollock: Yes. And it potentially could be provided as part of the modeling inputs and assumptions filing that comes in prior to the RFP solicitation commencing. I think that's absolutely an outcome as well.

Matt Larson: And are you familiar with the bidders' conference that Public Service hosts, and the fact that developers could potentially ask questions about that document at that high level?

Mr. Pollock: Yes, thank you.

Matt Larson: You had an exchange with Commissioner Gilman about the Renewable Battery Connect and the dispatch events. Do you recall that?

Mr. Pollock: I do.

Matt Larson: And you talked about the fact that there are up to 60 annual dispatch events associated with that particular program. Do you recall that?

Mr. Pollock: Yes.

Matt Larson: And is that the outgrowth of a settlement agreement in proceeding number 21A-0625 EG?

Mr. Pollock: Yes, so it was several years ago, but I believe that was something that was negotiated as part of a settlement agreement. It may actually have been KOSA that recommended that number of events.

Matt Larson: Yeah, I'll represent to you that it was KOSA that proposed 60 events, and the settlement agreement effectuated Public Service aligning with that 60. Does that sound right to you?

Mr. Pollock: Yes.

Matt Larson: And that's the 2022 to 2025 Renewable Energy Standard Plan case?

Mr. Pollock: It is.

Eric Blank (Chair): And Mr. Chair, we have that decision marked in our box. If you want in the record, we can move it now. If not, we can keep going. No, you just move it into the record. Any objections? So moved. Yeah, and that's Hearing Exhibit 143.

Matt Larson: That was going to be my question. Yeah, in Pasco's box. Thank you. Coming to some of the discussion you just had with Commissioner Plant prior to the break, Public Service has about 600 megawatts of DR programs on the system today. Does that sound correct to you?

Mr. Pollock: Yes.

Matt Larson: And just a question about the RA study. Did the RA study consistently model and evaluate all different types of resources alongside one another?

Mr. Pollock: That's my understanding, and it's important that we have that modeling in the RA study given the complexity of the system we operate today and the increasing complexity of that as we move to an even higher renewable penetration system in the future.

Matt Larson: And you also had a discussion, coming back to the very beginning of your examination with Miss Kutzer, about the benefits stream. I think was the term you used in describing what's available to DERs that bid into this JTS, these two competitive solicitations. Do you recall that?

Mr. Pollock: I do.

Matt Larson: And can you just describe for the record what that benefit stream is from your perspective?

Mr. Pollock: Yes, so there are multiple benefits available across generation, transmission, and distribution. Generation will obviously be reflected by the bidder's bid, but we are also proposing that any distribution-connected bids would avoid the transmission adders that would apply to bids on the transmission system. So there's a benefit there in terms of an avoided cost. In addition, we're proposing to apply the metro constraint adder in those impacted areas for transmission, as well as the distribution adder in the modeling and Encompass that would apply to bids on the feeder list that I discussed with Miss Kutzer, pending the outcome of that case where that final list is determined.

Matt Larson: And just going up to a much, much higher level than that, is the JTS just one way that DERs can participate and provide system value?

Mr. Pollock: Yes, absolutely. And the company's making a lot of strides to not only create new opportunities but create opportunities for DER to provide system value given the changes and opportunities, new demands we're seeing in our system. So a few of those other opportunities include the Dispatchable Distributed Generation proposal that the company filed in the RES plan where we're seeking up to 100 megawatts of dispatchable storage. We also have the AVP proceeding, which we talked about extensively here, as well as the opportunity to bid into the JTS with those credits applied to the DER bids. So I think it's fair to say we're creating a multitude of opportunities for DERs to be a part of the solution in solving resource adequacy and other system challenges.

Matt Larson: Thank you for your time, Mr. Pollock. Mr. Chair, I do not have anything further.

Eric Blank (Chair): Mr. Martz, are you out there? Mr. Martz, good morning. Can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Stephen Martz: I do.

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

Stephen Martz: No.

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

Stephen Martz: Yes, I will.

Eric Blank (Chair): All right. Back to you, Miss Shields.

Miss Shields: All right. Good morning, Mr. Martz. Could you please state your name and title for the record?

Stephen Martz: Yes, Stephen Martz. My title is Vice President, Integrated Planning, and I'm an employee of Excel Energy Services.

Miss Shields: And are you the same Mr. Stephen Martz who adopted Hearing Exhibit 105, Revision 1, the direct testimony of Mr. Andrew Svener?

Stephen Martz: Yes, I am.

Miss Shields: And also the same Mr. Martz who provided Hearing Exhibit 113, supplemental direct testimony, and Hearing Exhibit 121, rebuttal testimony, along with all corresponding attachments in this proceeding?

Stephen Martz: Yes, I am. And if I were to ask you those same questions today, would your answers be the same?

Miss Shields: Yes, they would. All right. With that, the witness is available for cross-examination. I have 30 minutes for Trial Staff, and it's 11:07. Miss Chong?

Ailen Chong: Thank you. Good morning, Mr. Martz.

Stephen Martz: Good morning.

Ailen Chong: For the record, my name is Ailen Chong, and I am an Assistant Attorney General representing Trial Staff in this proceeding. It's nice to meet you.

Stephen Martz: Likewise.

Ailen Chong: To start off, you have adopted company witness Andrew Svener's testimony attachments in this proceeding. Correct?

Stephen Martz: Correct.

Ailen Chong: And you are now the witness to answer questions about the JTS transmission study. Correct?

Stephen Martz: Correct.

Ailen Chong: To level set here, would you agree that one purpose of the transmission study is to identify meaningful similarities and differences in transmission needs across plausible resource portfolios?

Stephen Martz: Yes, I would.

Ailen Chong: And you'd also agree that another purpose of the transmission study is to provide guidance on identifying transmission improvements that may be needed to ensure the reliable delivery to Public Service's system under varying conditions?

Stephen Martz: Yes, I would.

Ailen Chong: I want to walk through the four generation resource portfolios within the JTS transmission study report that was provided as Hearing Exhibit 105, Attachment AWS-1. The four generation resource portfolios include: one, the Baseline; two, Bookend One, or High Renewable; three, Bookend Two, or High DER; and four, Joint Bookends, High Renewable and DER. Correct?

Stephen Martz: Correct.

Ailen Chong: And these generation resource portfolios were not Encompass model outputs. Correct?

Stephen Martz: That's accurate. We provide a review of what we felt was necessary to estimate, as well as our estimation methodology as part of that report, and I believe that's also represented in Mr. Svener's, now my adopted, testimony.

Ailen Chong: Okay. So these portfolios were constructed to represent a range of potential outcomes. Correct?

Stephen Martz: No, I would disagree with that characterization. We constructed these with guidance from the resource planning team. But I wouldn't say that that was the intended outcome from the get-go. It was additionally intended to identify what could be particularly stressful generation portfolios to our transmission system to better assess what I will call a set of guardrails on transmission projects that could be necessary to deliver various portfolios.

Ailen Chong: Okay. So these portfolios, in the manner that you described, were constructed before the company conducted its Phase 1 Encompass modeling. Correct?

Stephen Martz: Correct. And again, we provide conversation on that in the direct testimony as well as in the report. The reason for that is primarily due to timing, given that our desire was to present a proactive review of transmission solutions that could be necessary. It required us to start that transmission study evaluation in parallel with the Phase 1 Encompass modeling.

Ailen Chong: Okay. Could we please pull up Hearing Exhibit 2601? This is the answer testimony of staff witness Aaron O'Neal. And if we could please scroll down to page 65, and we'll be looking at that Table ETO3. So, Mr. Martz, I will represent to you that this is a table prepared by staff witness O'Neal, and is a representation of the generation resource portfolios used in transmission modeling as seen in company witness Svener's direct testimony, Hearing Exhibit 105, Attachment AWS-1. You don't have any reason to dispute these numbers, do you?

Stephen Martz: No, I don't. And they're all highly verifiable, so I will take your representation.

Ailen Chong: Okay. And we'll use this to guide our discussion today. So we'll focus on the first two columns, the Baseline and the Bookend One. Starting with the Baseline portfolio, this portfolio applies a balanced approach of clean energy resources and natural gas generation in addition to incremental DER. Correct?

Stephen Martz: I'm not sure what you're referring to at that last statement. Is that a quotation from my testimony or from Miss O'Neal's?

Ailen Chong: It's a quotation from the transmission study, which we can pull up if you'd like to verify that.

Stephen Martz: I accept your representation.

Ailen Chong: Okay. So it has a moderate renewable level. Correct?

Stephen Martz: I think the point of "moderate" is in comparison to the other portfolios. So as an example, you'd see the level of wind and solar identified within the Baseline or the BL column. And "moderate" is meant to be taken relativistically in contrast to the other portfolios that are constructed here.

Ailen Chong: Okay, great. And so moving on to Bookend Portfolio One then, that model is a high renewables resource procurement, relative to the other portfolios. Correct?

Stephen Martz: I heard "two," I apologize. Correct.

Ailen Chong: Okay. So between the Baseline portfolio and the Bookend One portfolio, would you agree that the Baseline portfolio has a higher level of gas resources, whereas Bookend One has a much higher level of renewables resources?

Stephen Martz: I would.

Ailen Chong: Okay. And Bookend One has almost double the total nameplate capacity at 14,400 megawatts compared to the Baseline portfolio, which has a nameplate capacity of 7,900 megawatts. Correct?

Stephen Martz: Correct.

Ailen Chong: Okay. And we can pull this exhibit down. And Mr. Martz, I'm happy to bring up any exhibits as needed. But to start off, in the transmission study, the New Harvest Mile Cherokee 230 kilovolt line solution is needed in every set of transmission solutions, in every scenario. Correct?

Stephen Martz: Well, it depends on which representation of that line you're referring to. We talk and present both what I'll call, for simplistic purposes today, the base 230 line. There are different names used for that throughout this proceeding, both by the company as well as parties to the case, but I think we all know what we're referring to. So that's the 230 KV line from New Harvest Mile to Cherokee at 230. But then we also present an alternative, which is essentially a similar flow pathway. However, we've essentially added on a 345 section to that. So I wouldn't... I think I can't recall the exact word you used, Miss Chong. I think you said "all" very distinctly. In that sense, I'd say that we look at both the 230, the base 230, as well as the alternative, and a version of that shows up in various portfolios.

Ailen Chong: Okay, yeah. I think that was my question. A version of those show up in all the portfolios. Correct? Just to verify that.

Stephen Martz: That's accurate, and that's also represented in my testimony as well.

Ailen Chong: Okay, great. So the company has not identified any portfolios in its transmission study that might avoid that New Harvest Mile, either option, in this proceeding. Correct?

Stephen Martz: Do you mind restating your question? I think I heard, "The company has not identified any portfolios..."

Ailen Chong: ...folios in its transmission study that might avoid that New Harvest Mile solution. Is that correct?

Stephen Martz: I need help, or maybe you can rephrase. I guess I don't think of portfolios in and of themselves as avoiding particular projects, and I'm not clear if you're referring to resource portfolios and generation portfolios or transmission portfolios.

Ailen Chong: I'm talking about the resource portfolios.

Stephen Martz: Yes. Again, I think I don't agree with the premise of the question because the point of the transmission study was not to identify the most likely resource portfolios that we expect to come out of a JTS Phase 2 proceeding. These were conceptual portfolios constructed to analyze stresses on the transmission system. So it was never really part of our study scope to try to guess at resource portfolios. So that's a question I can't necessarily answer.

Ailen Chong: Okay. So in those planned resource portfolios, portfolio scenarios that you developed, were there any scenarios that did not include that New Harvest Mile solution?

Stephen Martz: In what we study, that is accurate. However, I do not agree that that represents the range of possible realities of an actual solicitation.

Ailen Chong: Okay, but I'm referring to what you studied. So within what you studied, the New Harvest Mile project is included in every single scenario, and I've already affirmed that.

Stephen Martz: Okay, great.

Ailen Chong: At this time, could we please pull up Hearing Exhibit 105? This is the direct testimony of company witness Svener. And could we please scroll down to page 56, and I'm looking at Table AWS-D9. This is the indicative cost estimates for the JTS transmission study. Mr. Martz, I'm going to focus your attention to 3A and 3B. Are those the two projects that we've been discussing?

Stephen Martz: Yes, they are.

Ailen Chong: Okay. So this project is $1.88 billion or $1.94 billion, depending on whether it connects at Spruce on the 345 kilovolt system. Correct?

Stephen Martz: Yes. 3A is what I've referred to earlier as the base. The cost estimate of that is $1.806 billion, or 1,806 million. And then 3B is the alternative, which I talked about the change being the 345 section, and that cost estimates $1.939 billion.

Ailen Chong: And you testified in rebuttal, and I'll quote you here, that the company recognized that this project is costly, making up the majority of the transmission costs identified in the JTS transmission study. Correct?

Stephen Martz: Subject to check. I agree.

Ailen Chong: And this New Harvest Mile project was included in the calculation of the transmission adders as a variable cost. Correct?

Stephen Martz: Correct.

Ailen Chong: Okay. And can we please move to Hearing Exhibit 2601? Is this Miss O'Neal's answer?

Stephen Martz: It is. Yeah, thank you for verifying.

Ailen Chong: Yeah. And if we can scroll down to page 69, and we're looking at Table E07. And I will represent to you, Mr. Martz, again, this is verifiable information as you stated earlier, that this is a table prepared by staff witness Aaron O'Neal, and is a summary of the company's estimated transmission solutions as seen in company witness Svener's highly confidential JTS transmission cost estimation workpaper. Do you have any reason to dispute this, or can we use this table to direct our questioning?

Stephen Martz: Yes, we can, and it's consistent with the workpapers provided.

Ailen Chong: Okay. And were you listening to Mr. Landram's discussion with staff as it had to do with the total transmission scenario cost estimate?

Stephen Martz: I heard some small parts, but not the totality. You'd have to refresh me or point me to some specific information if there's a line of questioning on that.

Ailen Chong: Sure. And I'm looking at again the first two columns, the Base Case and the Bookend One. And looking at the row at the bottom that says "Total Transmission Scenario Cost Estimate."

Stephen Martz: Oh, sorry. Thank you. My screen went blank for a second.

Ailen Chong: So looking at the first two columns, Base Case and Bookend One, and specifically we're looking at the "Total Transmission Scenario Cost Estimate" row.

Stephen Martz: Yeah, so like the third from the bottom right. Correct? Yep, I'm following.

Ailen Chong: Okay. So would you agree with company witness Landram that despite the fact that the Bookend One portfolio is double the size of the Baseline portfolio, that the modeled transmission costs that we're looking at, the third row from the bottom, stayed pretty much unchanged?

Stephen Martz: I can't speak to that being part of the conversation Mr. Landram or what was discussed as part of his cross-examination in detail like you said, but I will affirm, the Base Case does represent a portfolio, if I recall correctly, approximately 7,900 megawatts. The Bookend One is quite a bit higher due to that being the high renewable case, over 14,000. And they're similar. Similar cost. I don't agree that they're the same number though.

Ailen Chong: Okay, similar cost. I think I would agree with that as well. And if we could scroll up to page 65, and we're looking at that Table ETO3 again. And Mr. Martz, would you agree that the transmission adder that the company calculated was $238 per kilowatt?

Stephen Martz: I would. I believe that's rounded to be precise, but yes, I think that's the number that's generally been thrown around throughout this proceeding.

Ailen Chong: Great. And we're again looking at the first two columns here, the Baseline and the Bookend One. So not asking you to do exact math here, but when you apply the company's transmission adder of $238 per kilowatt to the Baseline capacity of 7,900 megawatts, you get a number that's much smaller than when you apply that transmission adder to the Bookend One of 14,400. Correct?

Stephen Martz: I'm not sure I can agree in totality. I mean, you're kind of dismissing in that high-level calculation the location. I mean, we have not just the transmission adder, but we also have a series of credits which provide differentiation and locational value of resources on the system. So without further breakout of, excuse me, without further breakout of what that would be, I couldn't attest to what the ultimate calculation would produce without that additional information.

Ailen Chong: Okay. And not asking about anything, understand that there's credits and whatnot, but just asking about the transmission adder alone right now, could you agree that, looking at just the adder, the $238 value, that when you multiply that by the total nameplate capacity of the Baseline, which is 7,900, as opposed to the Bookend One, which is 14,400, that you get a number that's much smaller for the Baseline versus the Bookend One?

Stephen Martz: Yeah, so I'm willing to agree to your arithmetic. I don't agree with your application. Without knowing that location of value, I think that would be an imprudent estimation and approach to how you'd think about the application of the adder. So I disagree with that.

Ailen Chong: So for my next question, again, we're just sticking to the adder conversation and the adder application. So despite the modeled transmission costs that we were talking about earlier staying the same between the Bookend One portfolio and the Baseline portfolio, when applying the company's transmission adders, the Bookend One portfolio costs almost two times more than the Baseline portfolio. Correct?

Stephen Martz: Say the last part again, please. You said the Bookend One portfolio costs two times as much, more than the Baseline? Almost two times more when we're applying the $238 adder?

Ailen Chong: I can represent to you from the question earlier, when we apply the $238 adder to the Baseline versus the Bookend One, that the Baseline calculation comes out to be $1.84 billion versus the Bookend One that comes out to be $3.39 billion.

Stephen Martz: Again though, Miss Chong, we've covered this, and that's a misapplication of the transmission adder. The costs of these portfolios have already been represented as part of my testimony, so I disagree with that methodology as a way to surmise or otherwise estimate transmission portfolios. There are a number of things missing in that arithmetic, and so I can't agree to that. I'm willing to concede in the sense of how you perform the math. I think it's a misapplication though.

Ailen Chong: And again, Mr. Martz, I'm only talking about how the adder cost is applied. So, understanding that there are other points that will go into the total cost, but right now we're only focusing on the adder costs. So you stated that you have no reason to dispute the arithmetic that I represented to you.

Stephen Martz: I've already answered that question.

Ailen Chong: Okay. And moving on, the company is proposing to model all transmission upgrade costs as variable based on the total nameplate capacity of the generating portfolio. Correct?

Stephen Martz: Can you point me to the specific reference where we state that?

Ailen Chong: Sure, I can pull up Hearing Exhibit 102, and scrolling down. And this is the direct testimony attachment of Mr. Landram. If we can scroll down to page 44. Thank you for pulling this up. And we're looking at lines 12 through 14, where it states that the company determined the adder value by taking the average cost of all portfolios in the JTS transmission study divided by the average megawatts added excluding the adders.

Miss Chan: I am following you, and I see that. Okay, so to go back to the question, all the transmission upgrade costs that go into the average cost of the four portfolios are treated as variable when creating that $238 adder. Correct?

Mr. Martz: So the part I am not following is you are adding this word 'variable' to your question, and I need you to rephrase that for me to better understand. As I recall, we list our portfolios as well as what the makeup of the generation is as part of the transmission. We have enumerated the projects that would make up each different case that we evaluated, right? And then the associated capital cost, and then what Mr. Landram has represented here is the way the calculation is performed to compute the transmission adder is an average of that cost divided by the capacity. So I am not following the variable part.

Miss Chan: Okay, so just in that, what you were saying, that all the projects are included in this calculation. So there is no one project that is stand-alone that is fixed, but all of those projects are included in the calculation of the adder, is, I guess, what I am asking?

Mr. Martz: I would not say all because the very nature of an average is we are looking at the average of cost across multiple portfolios. And so there are projects that fall in and out of the different transmission portfolios. So I would not say all. As I discussed earlier, we looked at each portfolio individually, the set of projects within that. We looked at the total capital associated with that, and then the $237.97 is an average of those total portfolio costs.

Miss Chan: Okay, so then when you are creating that adder, then that $238 per kilowatt adder is applied in the modeling as a variable cost dependent on the size of the resource portfolio. Correct?

Objection: Objection, asked and answered. I think the witness has already indicated that he is confused by the word 'variable', and we still have not gotten a clear response, nor is that word included anywhere in the cited testimony, which is not, in fact, Mr. Martz's testimony.

Chairman: Do you want to rephrase, Miss Chan?

Miss Chan: Yes, I can rephrase. So after that adder is calculated, similar to the calculation that we did earlier, that $238 adder is multiplied to the size of the portfolio. Correct? To calculate that the adder cost.

Mr. Martz: I think Mr. Landram has covered this because you are really getting into encompass modeling practices and methodologies. I do not believe that it is added as just a, I will call it a binary, just it is on or off. Thus, I do not believe it is variable. It depends on the location of the generation of the bids that we receive. And I apologize for moving away from the word 'variable'. That $238 adder is multiplied by the size of the portfolio. Correct? I would say that it is multiplied by parts of the portfolio. I cannot testify to it just being grossly multiplied by the totality of the portfolio. Again, I believe Mr. Landram has covered this in his testimony. We have different transmission adders for different reasons to reflect locational value. The $238 is meant to reflect the cost of transmission so the Commission has insight into what we think the total cost could be, albeit it is a conceptual cost, but I cannot state that it is just flat out applied in the way that you are representing it in your question.

Miss Chan: Okay, and we can move on from this. Could we please pull up hearing exhibit 105? This is a direct testimony of SBAR, and we are looking at page 56, Table AWS-d9. So directing your attention to the bottom three rows, Mr. Martz, the total base forecast JTS indicative estimate range is between $2 billion to $2.4 billion. Correct?

Mr. Martz: For the base, correct.

Miss Chan: And the total low forecast JTS indicative estimate range is between $1.9 billion and $2.3 billion. Correct?

Mr. Martz: Correct, subject to rounding.

Miss Chan: Okay, so based on the transmission study results that we are looking at, would the company recommend a JTS portfolio of resources that could be supported by less than $1.9 billion in transmission investment? Are we recommending a JTS, are you referring to generation or transmission portfolio in your question?

Mr. Martz: I am talking about transmission or generation.

Miss Chan: So are we recommending a generation portfolio? Sorry, I kind of lost your question there. So maybe rephrase and please stipulate generation.

Mr. Martz: Oh, I am sorry. I meant to say transmission portfolio.

Miss Chan: Okay, so we are talking about transmission portfolios now? Yes.

Mr. Martz: Okay, so do you mind rephrasing? And I appreciate the clarification.

Miss Chan: Yeah, sure. So based on the transmission study results, and the results that, and the estimate range that we are seeing here, would the company recommend a JTS portfolio of resources that could be supported by less than $1.9 billion in transmission investment? We are talking about transmission portfolios. So would we recommend a generation portfolio that could be supported by a transmission portfolio of less than $1.9 billion?

Mr. Martz: I will rephrase. Does the modeling suggest a transmission portfolio that could be developed for less than $1.9 billion? Ah, okay. Thank you, that is very helpful. So I think the table speaks for itself. Again, this was developed in parallel to the JTS Phase 1 generation modeling, and so as we have already talked about in my testimony, there are reasons for that. I think there is an opportunity to think about additional studies, and that is what part of what we have proposed as part of the CCPG Task Force or Working Group, if you want to call it that. But what the transmission study analysis represents is in the table, and so we feel that these are the accurate cost estimates associated with the two forecasts, as well as the different cases that we ran. Again, this is not meant to represent a precise guessing of resource portfolios and associated transmission costs. This was meant to give us a reasonable set of prudent guardrails to think about transmission investment that is associated with the Phase 1 JTS resource modeling.

Miss Chan: I have no further questions. Thank you, Mr. Martz.

Mr. Martz: Thank you, Miss Chan.

Chairman: Thank you, Miss Chan. I have CIA 20 minutes, and it is 11:36. Greetings, Mr. Martz.

Mr. Martz: Morning, Mr. Dudsky.

Mr. Dudsky: We have not had a chance to meet in person yet, but I am Mark Dudsky for Colorado Independent Energy Association. I want to talk to you today about some of the upgrades needed in the purple box of the framework and a little bit about the adder, and finally a little bit about the surf if we have time. Regarding the, are you familiar with this what has been called the CCP Segment 7 proposal in this case? So you broke up a little bit. The CCP 7 is what I kind of heard.

Mr. Martz: CCP Segment 7. Yes.

Mr. Dudsky: And is that a proposal that would run from May Valley substation to Harvest Miles substation?

Mr. Martz: Very high level, yes, high level.

Mr. Dudsky: And with the potential to high level interconnect the Prong Horn substation in that?

Mr. Martz: I would have to refer to the answer testimony where I think that has been referred to. So I cannot recall the exact routing. I agree to the end points. I just cannot recall if it, if it hits Prong Horn as well or not.

Mr. Dudsky: Miss Frederrico, could we pull up Hearing Exhibit 722, please? Thank you from CIA's box. Do you see this? This is the company's response to CIA Request 9-3, Mr. Martz.

Mr. Martz: I see that it is the request. I would need a minute to review it if you want to ask questions about it.

Mr. Dudsky: I just want to ask if you are the sponsor of this request?

Mr. Martz: Yes, I am.

Chairman: Mr. Chairman, I would like to move for the admission of Hearing Exhibit 722. Any objection? Hearing none, so moved.

Mr. Dudsky: Mr. Martz, I just want to confirm here that you are saying in this response that the company will evaluate KOSA CIA 8U's proposed 345 kilovolt May Valley, Prong Horn, Harvest Mile along with other alternatives. Do you see that?

Mr. Martz: Give me a moment, Mr. Dudsky. It looks like you do want me to answer questions about the substance of the response. All right. If you do not mind, Mr. Dudsky, do you mind reasking your question? I think I have got a simple answer for you but I want to make sure I get it right.

Mr. Dudsky: So this response says that the company will study at the CCPG KOSA CIA AEU's proposed 345 kilovolt May Valley, Prong Horn, Harvest Mile segment. Do you see that?

Mr. Martz: I do see that.

Mr. Dudsky: And you also say you will also study other alternatives. Do you see that?

Mr. Martz: I do. In fact, that is the intention of the CCPG Task Force that I talk about in my rebuttal testimony. So it is, it is really intended to take on that type of work and that type of analysis. I cannot speak to what I think would be the exact study scope at this point in time, but this is certainly the type of project we would entertain as part of that task force.

Mr. Dudsky: But just to be specific, you, this is, you are going to entertain this project as part of the task force. Correct?

Mr. Martz: Yeah. I was, I wanted to provide more information on how we think about the task force. We would look at this one. I think this is a good representative project though in terms of if we are to see, receive feedback or other study ideas, that would be the method, excuse me, that would be the way in which we take those in and contemplate them as part of our scope.

Mr. Dudsky: Okay. You could take this down, girl. Thank you. And do you currently have any other alternatives in mind that you would study as part of that task force?

Mr. Martz: I cannot speak in totality. I think the very nature of the task force is to leverage a diverse and robust set of stakeholders. So I cannot speak to the entire universe of alternatives. We certainly would want to explore alternatives around the 230, some of which I already talked about in my, in my testimony. There could be other alternatives that we look at, but again, I cannot speak to the universe of all.

Mr. Dudsky: Okay, so nothing else right now. Correct?

Mr. Martz: Not currently. We are still in the very early stages of proposing the task force. We have not yet completed the scope, so I could not speak to that in a resolute manner.

Mr. Dudsky: Okay. I want to talk about the need for new transmission during the resource acquisition period, which is generally that has to do with the purple box in the framework. Are you familiar with that concept?

Mr. Martz: I am.

Mr. Dudsky: Okay, so there are two major buckets of new transmission, as I am thinking about it, in the purple box, and one is around Denver metro constraint upgrades. Do you agree?

Mr. Martz: It might be helpful to bring the framework up. I do not recall us binding it to a certain transmission topology or section of our system.

Mr. Dudsky: Well, we can bring that up if I need to, if we need to. I am just talking about how you are conceiving of the upgrades that are needed on this system. Is one that?

Mr. Martz: Go ahead. Sorry, no, no, my mistake, Mr. Dudsky. So as I think about them, and maybe the better place to kind of talk about this is, is I do address this in my, in my testimony, as well as we kind of break out transmission analysis and what we view as two steps. Step one, which is a proactive analysis, and then step two is an implementation phase analysis, if you will. And we would be looking at transmission system upgrades in both parts of those analysis. So just the issue I kind of take with your question, just I cannot say that it is just only Denver Metro. We look at the totality of our system. That is the point of both of those steps. But otherwise, yes, the point of the purple box is for us to look at a proactive set of transmission upgrades as well as implementation upgrades is how I have talked about it in my testimony.

Mr. Dudsky: And imple, by implementation, do you mean reliability?

Mr. Martz: I would say it is a mixture of reliability and deliverability. At that point, we would have the JTS Phase 2 portfolios in totality with specific generation information. And so we would be looking at delivering for those generation resources, as well as, if there were to be reliability issues triggered as a result of that generation fleet, we would look at both parts of that.

Mr. Dudsky: And so what I am trying to distinguish here for the record is we have the interconnection increasing the transfer capacity of the system, right? That is in the CCPG study we just talked about. Correct?

Mr. Martz: Yeah, I think that that is definitely an objective. I do not think it is the sole objective of the CCPG Task Force. Again, I would like to take the opportunity to leverage our stakeholder group to think about other proactive transmission. But that is, it is intended. The way I really think about it is it is intended to really think about the major transmission pieces that we want to move upstream in our process, and that is where we tackle those is through that CCPG Task Force. Specific, specific network issues that arise from specific generators would be addressed through the implementation phase of the transmission analysis.

Mr. Dudsky: And for the implementation reliability, Denver Metro constraint, what I am trying to do is just draw a distinction for the Commission that these are two groups of things that we need to be thinking about for the transmission. And do you agree with that?

Mr. Martz: I do. I do. And I do think that that is actually well represented and how I talk about it in my testimony, is that I would put a little bit differently, Mr. Dudsky, given my role as overseeing planning. I would not say that the solution, the solutions are grouped like that. It is how we perform, how and when we perform the analysis, how are the two different groupings.

Mr. Dudsky: So do you see a path where a public service is acquiring somewhere above, you know, the low load? Let us say they are acquiring somewhere in north of 5 gigawatts, up to like 10 gigawatts of power, and there is, and you do not need any new transmission.

Mr. Martz: Given the confines of that question, I think that that is pretty unlikely. I think that is represented in how we performed our analysis. We intentionally had 24 different cases that we studied to try to understand that relationship as best we could. And, notwithstanding impractical assumptions and things like that, I think that is a reasonable estimation, Mr. Dudsky, is some level of transmission investment is needed to deliver portfolios of a, of a lower magnitude, using your term, 5,000 megawatts. And I would expect there is transmission investment required for higher portfolios. I think you put a big bookmark of 10 gigs on that one.

Mr. Dudsky: Yeah, no, no magic to those numbers. I am just using that within the ranges you have provided.

Mr. Martz: I think that is consistent with how we perform our study is what I am saying.

Mr. Dudsky: Thank you for that. And then, so when we are talking about the MVLE in particular, are you familiar with that proposal?

Mr. Martz: Yes, I am.

Mr. Dudsky: So the MVLE, is it an extension cord to the CPP project? Correct?

Mr. Martz: I mean, I personally always appreciate folksy analogies, and that certainly is one. I would kind of put it as like we are making our extension cord longer. You know, I personally refer to Colorado Power Pathway as I think about it as like a renewable harvesting line. And so we need to make our line a little bit longer because we want to tap into yet another zone of what we think are really great resources for the state of Colorado. So I do not mean to like crush your analogy unnecessarily, it is just how I think about it as a system planner.

Mr. Dudsky: And what I mean as an extension cord is it is radial. It does not add a circuit to this system.

Mr. Martz: Sure, agree.

Mr. Dudsky: And that is important for this discussion because if it is radial coming off May Valley, it essentially takes some of that May Valley transfer capacity. It does not add additional transfer capacity to the CPP. Correct?

Mr. Martz: It is hard to know at this point in time, and I certainly appreciate kind of like the mental model that you are applying to how CPP works. I would anticipate us looking at the 45 system as part of an implementation phase. My hesitancy in offering an exact answer is just it really depends on the generation fleet. You know, we could see offsetting generation working in tandem across the totality of Colorado Power Pathway. So like in simplistic terms, if we just thought about May Valley just in isolation, we said, "Okay, we are going to add, you know, X amount of wind generation down there, and then we perform system analysis and we see, okay, there is now a thermal, a thermal violation somewhere downstream on Colorado Power Pathway." The reality though is that if we saw other generators interconnect a Power Pathway downstream or in that other vicinity, they might actually offset some of those thermal effects or some of those thermal violations. So I just cannot speak to that in such resolute and simplistic terms. It really depends on the overall portfolio we receive.

Mr. Dudsky: Yeah, I appreciate that. I am not asking for a study response. I am only just trying to keep it high level for the Commission's benefit. Did you hear Mr. Landram's testimony last week?

Mr. Martz: I think I am talking about this with Miss Chan. I was only able to capture a little bit of it here and there. I cannot speak to it in totality or in detail.

Mr. Dudsky: Okay. I know Miss Chan did cover this. I did not hear this exactly, but I just wanted you to see if you understand, or your testimony is that these implementation upgrades, they are going to be needed in, as we talked about, an eventuality with as low as 5,000 megawatts added to the system. Correct?

Mr. Martz: Yeah, I do think there is some level of transmission investment. I cannot speak or guess at what the magnitude of those would be, but we, that is the point of the implementation phase, is to study those types of transmission solutions that are needed.

Mr. Dudsky: So my, my question is, if we know those implementation upgrades are coming, and if we have already, you know, taken a stab at their cost, at least as to the Denver Metro in the JTS transmission report, does not it make sense to add those costs as a baseline part of each portfolio versus dividing them up amongst all the generators in a portfolio?

Mr. Martz: No, not necessarily, because one, I do not agree that the set of costs that I present in my testimony as part of the transmission analysis, so there is the base cost which I think we went through with Miss Chan, as well as the low costs. I do not think that that represents the totality or necessarily the exact representation of implementation phase projects that we would expect to see. I talk about the implementation phase as transmission evaluation work that we would do once we know the exact location and specific.

Mr. Dudsky: I want to stop you there because I want to stop you there because the $237 per kilowatt number on the adder, that is not an exact figure, right? You are that is a hypothetical figure you have arrived at. Correct?

Mr. Martz: I am not sure I am following your description as non-exact and hypothetical. I mean, we present every case how we arrived at that calculation, and we have supported it with my, with the transmission study that is in my, in my testimony.

Mr. Dudsky: That is what I mean, is like the transmission costs in your study, they go both into my hypothetical here that those costs get applied to all portfolios, they are also the basis for the $237 per kilowatt number, right?

Mr. Martz: I agree that the transmission costs identified in the study are the basis of the $237. I disagree that it represents the exact projects that would be identified as part of the implementation phase study.

Mr. Dudsky: Oh, I agree with that as well. I am just asking to better understand the transmission costs. Would not it be beneficial for the Commission to see that as representative of, of no matter what portfolio is chosen, as opposed to some projects wearing a $237 per kilowatt number?

Mr. Martz: You might need to rephrase your question. I mean, I think we have talked about the implementation phase study analysis as analysis that we would perform as the result of our Phase 2, as a, as a result of our JS2, excuse me, JTS Phase 2 solicitation. I do not think we have represented as otherwise not presenting those costs.

Mr. Dudsky: Yeah, and we could, we could move on. I am not arguing that you do not present them. I am just talking about the manner in which you present them. You could present them as part of a portfolio underlying base cost estimate or as part of an evaluation transmission adder estimate. Correct? The differences in how they are, whether they are applied to the portfolio or to a generator, each generator. Correct?

Mr. Martz: Yeah, I would have to think through all of the options. I would agree with you, Mr. Dudsky. I think what is important for this Commission is we want to understand, we want to, we want to represent that cost, right? That was a challenge in the 2021 C and ERP, and certainly acknowledge that was a frustration admittedly of the Commission. That is why we took steps to evolve our planning construct. And so I think it is important to represent that cost in some way. I think Mr. Landrum has already talked about why we feel that the transmission adder is the best, is the best vehicle by which to apply and represent that cost.

Mr. Dudsky: Okay, with the last line questioning here about the Surf, changing topics. I want to try and clear up the record on this proposal regarding transformers and breakers. And so my understanding of the proposal is that the company is going to get position in line as soon as possible to reserve transmission, sorry, transformers and breakers to roughly match the expected size of the JTS procurement, at least for the first RFP. Is that your understanding?

Mr. Martz: At a high level, I would note I am not the witness that is carrying that as an issue within this case. So I would need to see the exact exhibit that you are referring to to confirm your representation.

Mr. Dudsky: I am reserving. I am responding to many exhibits. And if you are not familiar with the Surf, that is a little troublesome, but we can move on.

Mr. Martz: I am happy to talk about it, Mr. Dudsky. I am just saying, if you want to ask detailed questions, I just do not have that as part of my testimony. I am happy to review it.

Mr. Dudsky: Yeah, no detailed questions, just a high level what it is.

Mr. Martz: Sure. I think you captured the essence of it.

Mr. Dudsky: Okay, thank you. And my questions are, so in the normal course of events, in the company's large generator interconnection procedures, are you familiar with those?

Mr. Martz: Yes, I am.

Mr. Dudsky: Okay, so in the normal course of events for the LGIP, the company might procure transformers and breakers anyway. Correct?

Mr. Martz: So I want to make sure I answer your question. In the normal course of events, we would procure transformers as part of the LGIP, as part of the LGIP study process for any given generator. I think that is a possibility. I do not know if I could say that that is the normal course.

Mr. Dudsky: Okay, well, just to break it down a little bit further then. An LGIP study will identify, here is the transformer you need and here is the breaker you need to interconnect. Correct?

Mr. Martz: Correct. I would say it, it also identifies electrical connectivity as well as system impacts. So yes, it, that is just not the only thing it identifies.

Chairman: Hey, Mr. Dudsky, you are at time. So if you could wrap up, that would be great.

Mr. Dudsky: I will wrap up with five more questions if I can, Mr. Chair. Mr. Martz, so I am not trying to pin you down here. I am just trying to get this straight on the record that in the, when you are, when that happens in a, and then there is an agreement signed, in general, high level, a generator would order or finance the ordering of that equipment, but ultimately, if it is on the high side of the transformer, the utility is going to own that equipment. Is that correct?

Mr. Martz: I actually do not know specificity. I would have to, I would have to check on that.

Mr. Dudsky: Well, assuming for a moment that that is true, subject to your check, is the real difference of the Surf the early ordering of that equipment by the utility before it goes through the complete study and finance process that would happen throughout the company's oat? So, so in your hypothetical, Mr. Dudsky, if it is the case that a high, I think you said a high-side transformer is required, you are asking the only difference is the application of the Surf?

Mr. Martz: Yeah.

Mr. Dudsky: Is the, is the difference between the normal course of events under the LGIP and the Surf is that the Surf is kind of getting out in front of everything and ordering that equipment well before it would be ordered in the normal LGIP process?

Mr. Martz: I think that is a possible scenario. I do not think it is the only scenario.

Mr. Dudsky: Okay. Thank you, Mr. Chairman. That is all I have.

Mr. Martz: Thank you, Mr. Dudsky.

Chairman: Thanks. Mr. Dudsky, in a west, I have 10 minutes. Thank you. Good morning, Mr. Martz.

Mr. Martz: With one minute left, good morning.

Mr. Le: My, for the record, my name is. We are, we are going to go to one or later. No, no, no, understood. I just could not decide between good morning or good afternoon.

Mr. Martz: Oh, I see. I have heard good day is appropriate for right about now.

Mr. Le: That I will do that next time. Thank you. For the record, my name is Chris Le with the Inner West Energy Alliance, and I only have some short questions for you about your rebuttal testimony. I do not believe we will need to bring it up, but if we do, we can. In your rebuttal testimony, you discuss your continued objection to providing injection capacity information. Is that correct?

Mr. Martz: That is accurate.

Mr. Le: And this is based upon the dynamic nature of the PSCO system. Is that correct?

Mr. Martz: Yes, that is part of our rationale amongst other things for why we feel that that is challenging to provide and potentially misleading.

Mr. Le: And you disagree with the injection capacity calculated by other witnesses in this docket. Is that correct?

Mr. Martz: That is accurate.

Mr. Le: Really, my final question is, is there any point that you foresee in the future where the PSCO system becomes less dynamic?

Mr. Martz: That is a very interesting question, Mr. Le. And less dynamic is certainly a vague term, which I am okay with. There is no tone behind that comment. I have a hard time seeing it become less dynamic. The future is highly uncertain. This is a complex proceeding where we are talking about resources to be acquired within the resource acquisition period through 2031, but also tail modeling through 2050. We are talking about resource portfolios which could contemplate high levels of VPPs or aggregated DERs, high renewables, etcetera. So I would agree with the characterization. I have a hard time seeing it as less dynamic.

Mr. Le: Great. Thank you so much. Appreciate it.

Chairman: Good day, Ms. Good. I think I have 30 minutes, but I am not sure where did you.

Miss Cutzer: That is what I have, Mr. Chair. I will endeavor to be under that.

Chairman: All right, 30 minutes. Thank you so much.

Miss Cutzer: Good afternoon now, Mr. Martz. How are you?

Mr. Martz: We cannot stay with good day. I like good day.

Miss Cutzer: Good afternoon. That is right. I spent time in Australia, so we will stick with good day. Good day. I will not do the accent. I am well. How are you?

Mr. Martz: I am doing well.

Miss Cutzer: Well, for the record, my name is Ellen Howard Cutzer. I am an attorney for KOSA, also representing CIA and AEU in this case. Miss Crane, I believe you are driving. For efficiency, I am going to be working with Hearing Exhibit 121, Hearing Exhibit 121 Attachment SM3 and Hearing Exhibit 2606 Attachment SDJ9 with Mr. Martz. Thank you so much. All right, Mr. Martz, I am going to start off talking a little bit about the transmission studies that are coming up. When we get to the rebuttal testimony, I would like to turn to page 39. And this is the section of testimony where you respond to intervener recommendations on transmission studies, including KOSA AEU's witness Ken Wilson, as well as Mr. Monson from CIA. Do you want to take a minute to refresh on this section?

Mr. Martz: I am familiar with the section, so if there are specific questions or lines, I assume we can go to those.

Miss Cutzer: Yeah, so I am just going to level set for everyone's sake. In this section between here and page 41, you explain that Mr. Wilson, our witness, generally recommended the company file a CPCN application within 100 days of the Commission decision, a, the Commission decision in Phase 1 for all transmission that is necessary and sufficient to meet the resource needs in this JTS. And you similarly respond to CIA's witness. But I just want to clarify here in the rebuttal, you are not agreeing with either of these recommendations. And one of the reasons you state for not agreeing with those recommendations is that there is not enough time to conduct the necessary transmission planning processes on the timeline that Mr. Wilson has put forward. Do you agree with that?

Mr. Martz: Can you direct me to the line that you are referring to, Miss Cutzer?

Miss Cutzer: Yeah, I did this to be fast, but I believe it is on page 41 if we can like scroll down into your ultimate recommendation.

Mr. Martz: Yeah, I certainly remember the dialogue. So not trying to be opaque, we just like to refer to the right line. We are talking about multiple interveners here.

Miss Cutzer: Yeah, take a look at page, at line eight there on page 41.

Mr. Martz: Thank you very much.

Miss Cutzer: Okay, would you mind asking your question again? Yeah, so really just restating your recommendation here, the reason, one of the reasons you reject the intervener recommendations is you said there is not enough time to conduct the necessary transmission planning studies. Correct?

Mr. Martz: Yeah, so if I recall in like kind of the preamble getting to this question, I recall this being discussed in light of what we have proposed in response to answer testimony around the desire to contemplate this as part of the CCPG Task Force. And what I address in my rebuttal testimony is just in our experience, as well as the timelines that we have seen with CCPG, we just, we think that it kind of puts in tension the ability to conduct that analysis and receive outcomes in contrast to what we think are more realistic time frames. So it is not that, you know, we think that there is anything inherently challenging with how the interveners have proposed this. We are just simply saying more realistic approach and timelines laid out based on that CCPG Task Force timeline that I present.

Miss Cutzer: Mr. Martz, you anticipated where I am going with this. I am actually not going to dispute you on the timeline. I just want to clarify kind of what that timeline is. So in response to these recommendations, you prepared Attachment SM3. If we could go ahead and pull that up, I would appreciate it. And this is where you explain the timing that you think is necessary to conduct these studies. Correct?

Mr. Martz: Correct. And I think as we are, I think we can answer these without pulling it up if there is a struggle. So this is the Gantt chart that you prepared. We will look at it in a bit.

Miss Cutzer: Yeah, I recall. Thank you. And so it is fair to say that the company disagrees with Mr. Wilson's recommendation on timing, but agrees with Mr. Wilson's underlying position that the company is short on transmission to meet the needs of the JTS per portfolio. Correct?

Mr. Martz: Well, we kind of went through a similar line of question, I think with Mr. Dudsky. And ultimately, my, my caveat as the planner is it is going to be, it is going to depend on what we ultimately receive as part of a phase, Phase 2 solicitation. But I do think it is reasonable to say that we are anticipating the need for transmission investment.

Miss Cutzer: Okay, fair enough. And company correspondingly needs to conduct additional transmission planning studies to investigate this need for a new transmission. Correct?

Mr. Martz: Correct, that is what we are proposing. And again, I talk about that in my rebuttal and break it out into the two steps.

Miss Cutzer: Great. That is where I am headed now. So let us talk a little bit about what has changed or maybe is consistent with your rebuttal case and where we are at now. Could we please pull up the Triparty Framework, which is Hearing Exhibit 2606, Attachment SDJ9. So, Mr. Martz, you are generally familiar with this document.

Mr. Martz: Yes, I am.

Miss Cutzer: Okay, great. Let us walk through this as it relates to transmission and other things that drive transmission. So here on page one, we are looking at Figure JWI-R1. This is the framework that the company staff and CIA have committed to as a part of this triparty agreement. Correct?

Mr. Martz: Correct. I would not say commit. I would say it is what is currently contemplated.

Miss Cutzer: Currently contemplated. Fair enough. So as part of this contemplation, the company is committing to a second Phase 2 supplemental RFP. Correct?

Mr. Martz: Again, there are caveats to that. I would say we are committing to this framework. We like this framework for reasons that we have espoused. Again, I just I think it is the necessary caveat to say it somewhat depends on what we see from the base. But I think the framework speaks for itself in terms of how we see the process working together.

Miss Cutzer: So just fair enough. Could we scroll down to the beginning of Phase 2? And just to clarify here for the record, I think it is bullet two, if we get there. The company and staff and CIA are committing to use the two-step approach described in your rebuttal testimony. Correct?

Mr. Martz: So you are sorry, Miss, second bullet there at the top of page two. Right.

Miss Cutzer: Okay, not your question. I am just saying we are agreeing to the two-step approach you put forward in your rebuttal testimony. Do you agree?

Mr. Martz: I do.

Miss Cutzer: Okay, great. And the way that these two things work together is that the company is going to be studying additional transmission under your two-step approach in between the first solicitation and the second solicitation. Correct?

Mr. Martz: That is accurate.

Miss Cutzer: Okay, great. And the purpose of this is to have additional transmission studies completed prior to the second supplemental RFP being conducted. Correct?

Mr. Martz: In part, I do not think it is the exclusive purpose of it. It is primarily meant to study what we receive out of the first RFP. And in the framework, it may include analysis of what we would contemplate supporting the second RFP. But I think that remains to be seen. This is a framework we have not yet used. And so you know, we, we endeavor to make the best use of that transmission analysis. I just do not think that that is its sole outcome or, excuse me, its sole purpose.

Miss Cutzer: Would you agree with me that one benefit of this approach is that bidders in that second RFP will have a better sense of the location of new potential transmission line prior to submitting their bids in that second RFP?

Mr. Martz: Well, I actually think we are doing quite a bit to provide bidders information on how we think about transmission. And I do not think that it is just limited to the second step, which we would refer to as the implementation step. I think also benefit from the proactive transmission study identified as part of what I call step one in my rebuttal. So I think, I think the information developed spans multiple transmission studies and is accretive to bidder information for understanding transmission.

Miss Cutzer: And Mr. Martz, just to be clear, I am not disputing that with you. I am just trying to see clarity that this could be a potential benefit to bidders and the community as a whole to understand the location of new potential transmission lines. Correct?

Mr. Martz: Again, it is a possibility. It is going to be highly driven by what we see from the first RFP and then the necessary transmission that is identified as part of the implementation phase. I mean, there are multiple aspects and attributes to how we would contemplate performing that study.

Miss Cutzer: Fair enough. Because I have limited time with you, I am going to move forward and talk to you about what this two-step approach is. Could we please pull back up Mr. Martz's rebuttal testimony on page 42? And here, if I am getting this right, as we are getting it up, lines 4 to 7, you explain the first phase. The first phase is direct, dedicated to proactive transmission planning where the company will work to establish a CCPG Task Force to engage interested parties in the development of new transmission and deliverability needs to promote interconnection of JTS resources. Did I read that correctly?

Mr. Martz: Yes, you did.

Miss Cutzer: This is that phase, that step one of your two-step approach. Correct?

Mr. Martz: It is.

Miss Cutzer: And to confirm, the CCPG held a meeting during the first week of this hearing to discuss this concept. Correct?

Mr. Martz: That is my understanding.

Miss Cutzer: And it is my understanding CCPG agreed to convene a new task force for the Just Transition Solicitation transmission studies. Is that your understanding as well?

Mr. Martz: Yes, it is.

Miss Cutzer: And just for our benefit, can you explain to me very briefly what CCPG is?

Mr. Martz: Sure. So very high level, CCPG is a collaborative group of transmission owners and operators in the state of Colorado that coordinate on planning issues within the state.

Miss Cutzer: So the company participates in CCPG but it does not have complete control over CCPG's timing and ability to conduct studies. Is that correct?

Mr. Martz: Agree. We do not have complete control. That is the point of a collaborative and coordinated Task Force and planning group like that.

Miss Cutzer: Okay, great. Can we please pull up the Gantt chart, which is that Attachment SM3? Thank you so much. And so we are dealing with more purple boxes here, Mr. Martz. Do you and I agree that the proactive transmission planning deadlines in this Gantt chart that are at the top reflect this Step 1 process that you and I have been discussing?

Mr. Martz: They do. I would just note that this is an illustrative, and that is how we have represented it as such. I would say final deadlines are subject to our working with CCPG on specific dates. So I view this as an illustrative. We certainly want to work on this as fast as we can, but we wanted to present a realistic picture of what we think the timeline would be.

Miss Cutzer: So you have anticipated my question. You have deadlines here, including deadlines earmarked as September of this year until the end of March of next year to conduct the transmission studies at the CCPG. But as we sit here today, you cannot guarantee that we are going to meet those deadlines. Correct?

Mr. Martz: I would agree with that. We, we, the way it works with CCPG is, is part of what is contemplated in, excuse me, contemplated in proposing a task force. We would certainly have a, we would have a, I will call it like a convening role in that task force. We would be responsible for proposing deadlines. So I think that we have the ability to influence and impact. I agree with your earlier representation. We do not have complete control per se. There could be other exogenous factors that would go into timeline limitations. And so, we would endeavor to do our best to propose to the task force what we thought is a reasonable timeline to execute.

Miss Cutzer: Who takes the lead in terms of conducting the transmission planning studies at CCPG? Is that typically utility staff?

Mr. Martz: That is correct. It would be utility staff of the proposing or maybe a better word here is hosting, like the hosting utility who is endeavoring to perform the task force. It would be their staff that would conduct the analysis.

Miss Cutzer: So in this case, that would be public services staff who are primarily conducting those transmission studies for?

Mr. Martz: That is accurate. And I would further clarify, it would be public service staff or consultants, you know, hired at our direction.

Miss Cutzer: And I am glad you mentioned consultants because my next question was, in your opinion, does the company currently have adequate transmission planning staff to meet the deadlines that you have put forward on the Gantt chart?

Mr. Martz: Again, subject to the caveat that we talked about is we view this as an illustrative. And again, we would endeavor to propose what we thought was a reasonable deadline. I do feel confident that we have the appropriate resourcing. Again, we, we have internal staff. We also have the ability to pull resources across different jurisdictions. Some of our planners are focused only on PSCO. However, we do have other planners that work across our jurisdictions. We also have professional services contracts with multiple vendors who are capable of performing this analysis and have actually performed analysis on our system.

Miss Cutzer: So you are committing to having those resources available to hopefully meet the timelines you have put forward on this Gantt chart?

Mr. Martz: Again, I would say, Miss Cutzer, this is an illustration. The final timeline that we ultimately propose to CCPG would be supported by our resources and thus we would be identifying and making available the resources necessary to support the timeline that we proposed in CCPG. I do admit that this may not be the exact timeline that we propose. We might learn things through the development of the task force which could cause changes to this, but the underlying staff that we use to support this analysis we would, we would have to furnish that as part of the task force.

Miss Cutzer: Okay, that is fair enough, Mr. Martz. Let us move forward and talk a little bit about Step 2. Without flipping back to your testimony, can you and I agree that Step 2 is represented by this implementation phase transmission planning? I think I read that, and my glasses may not be strong enough. Do you agree that is Step 2 here, the brown and green boxes?

Mr. Martz: I do. And you are reading it just fine, Miss.

Miss Cutzer: Okay, great. Phew, my eyesight is all right. So when I look here at these deadlines, I see similar deliverables, CPCN preparation and proceeding, but I do not see a line item for CCPG. Can you explain to me why this Step 2 process is not running through CCPG?

Mr. Martz: Sure. So the point of the Step 1 is to look at more macro transmission aspects of the system. Again, in a proactive way so we can understand what those projects and potential alternatives could be and what they could look like. And we would anticipate that those would generally be larger project types, of a nature that, you know, would be more material and larger in size either in scope, so think like mileage of transmission line and potentially cost. Although not committing that, but that is the point of the proactive transmission planning. We also are intentionally taking it through a CCPG, excuse me, CCPG Task Force, like I said an earlier line of questioning, to best leverage our set of stakeholders. The implementation phase differs in that it is looking at the specific transmission necessary to deliver the received Phase 2 portfolio that comes out of the solicitation process. And so it would be, it is a more detailed analysis based on those specific resource types, and it is consistent with our past practice and previous ERPs to evaluate those resources. And so it is looking at more specific issues driven by specific generators.

Miss Cutzer: So my, the purpose of this line of questions is to ask you that the stakeholder process that is available for this second step, is it correct to understand that stakeholders will not be able to be involved in this Step 2 process until after the CPCN proceeding commences?

Mr. Martz: I do not believe that that is accurate. As an example, I believe that we did review, as, as an example, our 2021 transmission portfolio with members of the CCPG. I cannot remember the exact rules and and stakeholdering process by which that was governed. But I disagree with the characterization that there is zero collaboration prior to CPCN. And I do not want to put words in your mouth.

Miss Cutzer: I do not want same to me. I did not say there would be zero collaboration. I am just looking for the window in which we could get involved in that Step 2 process. And it sounds like there may be an opportunity to do so if the company chose to present those plans to the CCPG. Is that what I just heard?

Mr. Martz: Correct. I think, you know, that is something I think we would be willing to better refine. And, you know, we could work with parties to, you know, better enumerate when we think that right window would be.

Miss Cutzer: Okay, great. I want to move on to a last line of questions about something else that is in the settlement. We can take the Gantt chart down. Could we please turn back to Hearing Exhibit 2606, Attachment STJ9, that triparty framework? And let us see, Item 4, paragraph two, if you could go down to Item 4. I believe so, they are numbered. It is just a little bit further.

Unidentified Speaker: Yeah, thanks, Miss Cutzer.

Mr. Martz: I was going to say, I do not see number four yet.

Miss Cutzer: So you see the second paragraph that starts with the word 'beginning'?

Mr. Martz: Yes, I do.

Miss Cutzer: Beginning summer 2025, the company will commence a small group stakeholder process with staff, UCA and CEO as described in the answer testimony of Aaron O'Neal. I will talk with her as well, but I want to understand the difference between this small stakeholder group and the processes that are happening at the CCPG. So just to be clear, at the CCPG, anyone is allowed to come to the meetings and participate. Correct?

Mr. Martz: I am not sure if I am not sure what you mean by 'anyone'. I would say it is generally an open and public process.

Miss Cutzer: Okay, fair enough. But in, when we are talking about this small stakeholder group, this is restricted to the government interveners in this case and the company. Correct?

Mr. Martz: I would like to second, Miss, to review exactly what is written here.

Miss Cutzer: Okay. Do you mind re-asking your question, Miss Cutzer? I reviewed the second paragraph.

Mr. Martz: Yeah, my question was, in this group described in this paragraph, the stakeholders are limited to the government interveners and the company. Correct?

Mr. Martz: I am not sure I can say that it is limited. This might be a better question for Mr. Eiley. I do not see that we are representing this as limited, and I could not personally speak to how that would, how that would apply per se. I agree that the way this is written, it reflects staff, UCA, CEO, and the company as part of who would participate in the small group.

Miss Cutzer: Would the company be open to including other stakeholders, including our witness Ken Wilson in that small stakeholder group?

Mr. Martz: Again, I think that is a better question for Mr. Eiley, who is been the primary sponsor of the, of the framework.

Miss Cutzer: Fair enough. So, are you aware of the difference, of, difference in focus of these two groups? The way that I read this is it seems to be in application to how we think about Phase 2 modeling. I take that to mean generation modeling, but I think that would be good to clarify with Mr. Eiley. And earlier in this case, I heard Mr. Eiley explain that this small group would also discuss, discuss the transmission adders that the companies proposes as part of that Phase 2 modeling. Is that correct? Is that going to be a focus?

Mr. Martz: I did not hear that part of Mr. Eiley's cross-examination. You would have to verify that with him.

Miss Cutzer: Okay. Is that your understanding based on your role at the company being involved in transmission planning?

Objection: Objection, asked and answered. He has already indicated, I think, at least three times that he is not the appropriate witness for this line of questioning.

Miss Cutzer: Might I respond, Mr. Chair?

Chairman: Yes.

Miss Cutzer: So while Mr. Martz has said this is something Mr. Eiley discussed, I just asked him, as in his role as a lead of transmission planning, if he has the understanding that this is what the group is going to discuss. If he does not know or does not have that understanding, he can answer. But I do not think he has asked and answered that specific question overall. Keep going.

Mr. Martz: I could not provide that verification.

Miss Cutzer: Okay. But as this sits right now, there is no current plan for IP representatives to be included in this group. Is that correct?

Mr. Martz: Again, I cannot speak to that in totality. Again, I am willing to agree to the representation of how this is written. Again, the expansion or inclusion of other participants would be better addressed with Mr. Eiley and Miss O'Neal.

Miss Cutzer: Great. No further questions. Thank you, Mr. Chair.

Chairman: Thank you. I have Mr. Bonis, CEO, or Miss Vitali, CEO. I have 15 minutes. Thank you.

Miss Vitali: Good afternoon, Mr. Martz. How are you?

Mr. Martz: Good. How are you, Miss?

Miss Vitali: I am doing pretty well, thanks. I do not believe we have met, so for the record, my name is Cynthia Vitali representing the Colorado Energy Office. And I would like to start with a question that I asked of your colleague, Mr. Eiley, on Wednesday, and he referred us to you. So that question is, would all loads that connect at the distribution level require an interconnection agreement?

Mr. Martz: Well, the distribution interconnected projects follow a different line extension policy. And so IAs, excuse me. I should say, interconnect agreements traditionally are part of our transmission line extension policy. Distribution, we would have what are called construction agreements.

Miss Vitali: Okay. So is it fair to say that not all loads, large loads connecting at the distribution level would sign specifically an interconnection agreement?

Mr. Martz: Not, not to my knowledge. Again, we, we use construction agreements to govern interconnection with distribution facilities.

Miss Vitali: Okay, that is helpful. Thank you. And can you point to anywhere in your testimony or elsewhere in the record that clarifies that you are using a different type of agreement at this stage in the process?

Mr. Martz: Not off the top of my head. I do not have that committed to memory.

Miss Vitali: Okay. Do you happen to know if there is anything elsewhere, maybe in PSC rules or public services tariff that would touch on this point of the different type of agreement?

Mr. Martz: Yeah, I think that is easily referencable and all of our interconnection information that is available on our public website that includes the full totality of our, excuse me, of our tariff books as well as our line extension policies. Interconnecting parties could easily reference those materials to understand that.

Miss Vitali: Okay, great. Thank you. And then I would also like to ask you a bit about transmission planning today. And I have done my best to cut questions that are redundant with ones you just answered with Miss Cutzer. So in your rebuttal testimony, you propose a two-step transmission planning process. Is that right?

Mr. Martz: That is accurate.

Miss Vitali: Okay. And could we pull up Hearing's Exhibit 121 and go to page 12? Thank you. And could we scroll down a little bit more to kind of the very bottom of page 12, top of page 13? That is perfect. Thank you. Okay, so here starting on line 16, you describe Step 1 as, quote, "Step 1 is a proactive study where the company will engage stakeholders in a Colorado Coordinated Planning Group CCPG JTS Task Force to identify and develop the company's next proactive transmission project similar to the framework used to develop the Colorado Pathway Project, the CPP." Correct?

Mr. Martz: Yeah, I am following you.

Miss Vitali: Okay, thanks. And then if we could, we scroll to page 42, line 4, Miss Vitali, this is still my rebuttal. Correct? Same exhibit. Yes. Thank you. Yeah, Hearing Exhibit 121. Okay. And here starting at the very end of line 4, you say, quote, "The company will work to establish a CCPG Task Force to engage the interested parties." Did I get that right?

Mr. Martz: That is accurate. As we covered with Miss Cutzer, I actually would say it is almost a little bit out of date. That has effectively already happened. We have, we have talked about that with CCPG and already proposed it.

Miss Vitali: Great. Well, I just have a couple questions now about kind of what this task force looks like and how it functions. So can you point us to where the company specified the entities that are going to make up this task force?

Mr. Martz: We have not specified that in my rebuttal testimony.

Miss Vitali: Okay. Have you, have you specified it anywhere else?

Mr. Martz: Not yet. We have talked about it in, I just, I will say it like this, we have talked about how we would think this would work at a high level. In my rebuttal, this is the primary place that we, we pick this issue up and talk about this. Again, this was driven by feedback that we have accepted from parties of the case that we have heard on answer. And so we have not yet specified that in totality, so I would say that that is pending.

Miss Vitali: Okay. Have you specified anywhere how the company would select the entities that make up the task force?

Mr. Martz: No, I have not. I am not sure I agree with the premise of like selection per se. The point of this is not to be otherwise, you know, exclusionary or discriminative in any way, shape or form. I mean, we are, we are choosing to take this path of using the CCPG Task Force, so I cannot say that there is like a selection per se. I mean, that kind of has the connotation of performing a draft. I kind of think it is as simple as, you know, we, we would gauge who is interested in participating in the task force and and proceed with the task force with interested parties.

Miss Vitali: Okay. So if any party that expresses interest is going to be allowed to be part of it?

Mr. Martz: Subject to the bylaws of CCPG, which I cannot speak to in detail off the top of my head. I certainly do not have those committed to memory. Again, I would say it is not the point of what we are endeavoring to do. I personally view as, as someone who oversees planning, is the point of the task force is to engage in this topic in a transparent manner. So I just, all I am saying is I cannot, if there would be a bylaw or otherwise, you know, some limitation that CCPG would impose as a product of their rules, that would be something we consider and how we constitute the task force. Otherwise, our, our, our desire is inclusion.

Miss Vitali: Okay, that is helpful. Thank you. And has the company identified what the voting structure and process would look like for the task force?

Mr. Martz: I do not believe so.

Miss Vitali: Okay. And we have just recently proposed that, and I believe we have talked about the process steps in, in my rebuttal. We could talk about those in detail if that is of interest.

Mr. Martz: I think that comes at a later part in the process.

Miss Vitali: Okay. Do you have a sense of exactly when you think that level of detail will be made available?

Mr. Martz: I think in the coming weeks and months, as we work with CCPG on developing that. Again, we are kind of like the hosting member, if you will, that would, that would bring a lot of that to bear. And so we would make that available as part of CCPG as, as we work to scope the task force timelines and and participants in the task force.

Miss Vitali: Okay. And in terms of, you know, it sounds like you have described this as the vision is for this to be pretty inclusive process. And so I want to ask a little more about kind of what is going to happen if someone, if an entity who is part of the task force proposes a specific transmission line. Does that mean that any, any idea proposed by a member of the task force will necessarily be presented to the Commission?

Mr. Martz: So if I am understanding your question correctly, are you, you are asking, are all projects proposed as part of the task force presented in totality to this Commission?

Miss Vitali: Yes. I am just trying to get a better sense of how what the internal process is going to be like and if there is going to be some sort of filtering or cutting down of discussed proposals.

Mr. Martz: I mean, I do think it is a fair question. And we do have some precedent to rely on in the sense of how we saw the CCP, excuse me, the Colorado Power Pathway Task Force working. I would envision something very similar. I am doubtful that we would otherwise, you know, fail to discuss alternatives as part of the final study report. There is a report that is issued as part of the task force. I cannot yet speak to how I think we would talk about every single alternative and the process by which we, you know, would otherwise promote certain projects over others and then the way in which we would think about benefits of various projects. I think that is too early to tell. And again, those are things that we constitute as part of how we stand up the task force as CCPG.

Miss Vitali: Okay. So when you establish the task force, there will be some process for establishing exactly how proposals are identified and moved forward?

Mr. Martz: That is something we would work with the task force on as well as the participants to determine what we think is the right, the right way to assess that.

Miss Vitali: Okay. And do you have any sense of timing of when that will be completed?

Mr. Martz: Yeah, I mean, I think I, I would categorize that into the space of what we talked about previously, Miss Vitali, which is, you know, that is part of what we as hosting, hosting utility sponsoring the task force will be engaging with CCPG on over the next weeks and months as we seek to stand this task force up.

Miss Vitali: Okay, that is all very helpful. I am just taking quick look at my notes. I think that is all I have for you this afternoon, Mr. Martz. Thank you.

Mr. Martz: Thank you.

Chairman: Thank you, Miss Vitali. I think UCA, I have 30 minutes for you, Mr. Bunker, but let me just do a quick check with my colleagues before you start. Commissioner Gilman, it sounds like you want to talk to Mr. Martz in confidential session. Is that correct?

Commissioner Gilman: I do. And I think technically it is highly confidential.

Chairman: Highly confidential, right? And just, do you have like a rough sense of how much public and highly confidential you got for Mr. Martz?

Commissioner Gilman: About 10 minutes public. I think 10. And then probably 15 highly confidential.

Commissioner Tom Plant: I don't have any highly confidential, and probably have maybe five minutes to be public.

Chairman Eric Blank: And can you guys go to two? Or would you? I mean, are we going to be hungry and grumpy? Any preferences about, do you want to just start up early Monday morning? Finish with Mr. Bunker now and then start it with Mr. Martz?

Mr. Bunker: Mr. Chairman, if I can help with the scheduling issues here. Our questions were basically asked and answered. I'm going to wave our remaining 30 minutes with Mr. Martz. So we could utilize that time to go into your questions and the highly confidential session now, if that works for you.

Chairman Eric Blank: All right. Well, Commissioner Gman, let's see if we can get through the public commissioner questions. Why don't we start Monday morning at 7:30 with a highly confidential, and then we can take the public session starting at 8:00. Would that work for you, Miss Shields?

Miss Shields: Yes, Mr. Chairman. And so, to clarify, it sounds like we plan to go until approximately 1:00 today. And then we will reconvene at 7:30 with just the highly confidential and not the restricted highly confidential.

Chairman Eric Blank: Yeah, and just, it's probably going to go beyond 1:00 because I probably have 10 or 15 minutes of questioning for Mr. Martz too. So, the time is short. We are, I believe we're all happy to accommodate as I look around me. Okay. So, Commissioner Gman, Commissioner Plant, we'll go to maybe 1:15, 1:20 this afternoon. We'll commence Commissioner Gilman with a highly confidential session 7:30 on Monday, and then we'll do the public session and redirect at like 8:00. Commissioner Gman, you're up. Hold on.

Miss Jensen: I don't know if Miss Jensen. Yeah, I can only see from your... Sorry, yeah, I can see your mouth. Just on the topic of scheduling, on behalf of my colleague, Miss Keen, representing Onward Energy, she requested that Mr. Spurgeon be available for questioning first thing on Monday morning. So I wanted to confirm if that would be available before the highly confidential session or after the highly confidential session with Mr. Martz.

Chairman Eric Blank: I think I was the only one who had questions for Mr. Spurgeon. And given where we're at in this hearing, I'm going to forgo my questions. So I think Mr. Spurgeon is excused.

Miss Jensen: Great, thank you very much for the clarification.

Chairman Eric Blank: Yes, thank you. Commissioner Gman, you're up.

Commissioner Megan Gilman: Okay, thanks. Good afternoon, Mr. Martz.

Mr. Martz: Good afternoon, Commissioner Gman. Good day.

Commissioner Megan Gilman: Good day. Yes. So, a question that was referred to you from your colleagues. The company has already or looks to plan to bring on upwards of maybe 100 megawatts of new load, new large load, in 2025, despite some dramatically negative resource positions according to the loads and resources table. And I was just kind of curious, how is the company able to commit to serving the loads that they've already committed to serving prior to acquiring new resources, given the resource adequacy shortfalls?

Mr. Martz: Sure. I mean, I think this is something we've covered from Mr. Landram, who's really the expert witness on resource adequacy and generation planning. As I generally understand the matter, this is a challenge of timing. This is also a result of resources identified as coming out of the 2021 resource plan. And so, the outgrowth of large load is a relatively new phenomena. So, we're using this proceeding, as well as other tools, to work through developing what we think is a better planning basis to service those loads.

Mr. Martz: So, what I kind of see as having happened is the updated ELCC PRM study that Mr. Landram sponsors has given us additional technical and statistical clarity into what we think our true resource position is, in addition to the 2021 ERP portfolio. And then these large loads emerging in a relatively short timeframe has definitely put pressure on RA, resource adequacy. And so again, we're using this proceeding to identify resources that would help us service that load.

Commissioner Megan Gilman: Okay, but they won't service the load in 2025 or 2026, and potentially not in 2027, right?

Mr. Martz: Yeah, 2027, I think, is somewhat opaque at this current moment, and we're evaluating the necessary generation resources to service the large loads that we're contemplating. So again, questions that I think Mr. Landram addressed.

Commissioner Megan Gilman: Okay. A question regarding the HCSC transmission project and kind of the scenarios that are being run in investigation of that project, like zero solar, zero battery overnight, and with CTS performing what looks like well under their spec. And I was just curious if that's really a practical look, and if the company would really anticipate there would be no way they'd be having their thermal generation running at a higher percent of its ability or utilizing the thermal in situations that look to really stress the grid pretty considerably?

Mr. Martz: Sure, so if I'm following the question correctly, I think you're just essentially asking, how practical do we think are the sensitivities that we've developed, so the day, twilight, and overnight, and then the generation dispatches that we've identified? Is that the heart of it?

Commissioner Megan Gilman: Yeah, I mean, it looks to kind of intentionally hobble storage and thermal resources when it looks to be a time where they would be the most valuable to the system. And so I was wondering if that's really practical, and does that impact the determined needs from that transmission study?

Mr. Martz: Sure. So I actually think that we did recognize in part the need to evolve our thinking and assumptions around DEARs. That's actually reflected in the comparison of the low forecast versus the base. And if you notice, we move beyond a no-DEAR case for twilight and overnight. In simple terms, we're kind of thinking, look, most of most DEARs, as of now, are mostly solar. And so, we saw a pretty depressed scenario in that case. We took a different course when looking at the base specifically to recognize that issue.

Mr. Martz: Commissioner Gilman, we recognize it's definitely driven by solar. However, we want to create a reasonable opportunity to understand the benefits that distributed battery storage could provide. And so that's why we updated that assumption for the base modeling that we did. And so beyond that, I think there's a healthy representation of solar, battery, and other DEAR types in the three tranches of DEARs that are in the base transmission results. So I think that's well represented there and that change is well represented.

Mr. Martz: And then you asked about the thermal generation. The point of that was to identify what we thought would be a stressful dispatch scenario for our thermals, essentially looking at compounding effects of low DEARs and reduced generation. So, it's not really trying to say that's how we plan to operate the system. Again, I go back to, in endeavoring to respond to commission feedback from the 2021 ERP, we wanted to find kind of the corners of the stress of the system.

Mr. Martz: I would respectfully say that the way we ran those cases is not a statement by the company on how we think about those resource types. It's more of, we're system planners, engineers; we want to figure out how do we find a way to break it, if you will. And so we look at those stress types to come up with conceptual analysis to understand again, the guardrails of the system. I don't think that it represents necessarily a majority of how we'd anticipate the system to run, but it's certainly a possibility, and so it's a scenario we wanted to look at.

Commissioner Megan Gilman: Okay, thanks. You talked about the great resource off the MVLE in prior testimony. Do you recall that?

Mr. Martz: I do. You broke up for just a second for me, Commissioner Gman, and you used an adjective before MVLE, and I didn't catch that.

Commissioner Megan Gilman: Yeah, sorry. Oddly enough, I think we had a little power flicker here. I hate to blame it on that, but I think that's what went on. So you had talked about the great resource, I think were your words, off of the MVLE line. Do you recall that?

Mr. Martz: I do. And thank you for reclarifying. I really just didn't hear you.

Commissioner Megan Gilman: So, yeah, no worries. I was hoping I would ride straight through that, but it could have impacted the router downstairs. So, curious, in that great resource off the MVLE, is that kind of diversified in any way in terms of resource from what you would get on other places on the CPP? Like, is the wind resource diversified in any meaningful way?

Mr. Martz: Do you mind clarifying what you mean by diverse? Like, economically diverse, or locationally diverse? There's a few different...

Commissioner Megan Gilman: Really, I think locationally and weather pattern diverse. And that would, I do expect that the weather resource there produces kind of different diversified energy off say wind than on other areas of the CPP.

Mr. Martz: Sure. So, good questions for Mr. Landram, if they weren't already asked. Again, I didn't see the totality of his cross-examination. I have a high-level understanding of the evaluation of the renewable zones. I do appreciate that between the different renewable zones there is that diversity that I think that you're getting at. I personally can't speak to diversity within the renewable zone if we expect a stronger wind pattern at the north end of that renewable zone versus the southern end. Those would be details Mr. Landram would have. But I mean, I think at a macro level, the point that I'm making in my testimony as I think about major impacts to the transmission system and where we think the most likely set of resources are to be, specifically around renewables, we generally are saying that we think that the set of resources that we can tap into in that renewable resource zone, which, using I think it's Mr. Deadki, extending our extension cord into that area, is going to be very beneficial for our customers because we expect that those resources are going to have good capacity factors and are likely to be economically efficient renewable resources.

Commissioner Megan Gilman: Okay, yeah. And I just, I didn't see a lot of what looked like wind data had been studied in the RA study in that particular area. So, also just trying to understand if there's any diversification if that represents kind of an improvement to ELCC, particularly for resources coming from that area. But that might be beyond what you're aware of.

Mr. Martz: Yeah, I would agree with that. I generally understand that part of how the renewable zones are constituted is based on weather patterns. Mr. Landram could speak to their impact within the ELCC PRM study that he sponsored.

Commissioner Megan Gilman: Okay. So, you clarified with Miss Vitali that large customers who would connect straight to the distribution system would not sign an IIA but would rather sign what you call the construction agreement, is that right?

Mr. Martz: Yeah, I was just simply trying to clarify for Miss Fatali that there's essentially two tracks as I think about it within our tariff. There's a distribution track, there's a transmission track. If a customer is going through the distribution track, which would be 20 megawatts or less, that's a different process. And so that agreement is called a construction agreement.

Commissioner Megan Gilman: Okay, got it. And then, would they sign an ESA, or that wouldn't apply to that size or type of customer?

Mr. Martz: For a distribution customer, an ESA would not apply.

Commissioner Megan Gilman: Okay, got it. Is the, and I'm sorry, I don't have this on the top of my mind, but the company's commercial principles, are you familiar at a high level? I know that Mr. Bailey discusses that in his rebuttal and has had conversations on that. And I can't recall offhand if there's a certain size of customer the company is communicating that those only should apply to. But to the extent that it would include these large customers connecting straight at the distribution level, does the company have any opposition to including kind of similar to the commercial principles within the construction agreements the large customers connecting at the distribution level would sign?

Mr. Martz: It'd be hard to commit to that in the moment. It's something we could certainly take back and think through and clarify in an SOP. I believe, subject to verification, Mr. Bailey talked about the large load principles as primarily applying to loads of 100 megawatts or more. And then, obviously, you and I are dialoguing about distribution-interconnected customers. I'd need to go back and revisit the distribution extension line language in order to commit to that, because it is different than transmission language, and some of that code could not already be included. So just for clarity's sake, I think it'd be best for us to discuss internally and clarify that for you in terms of how we think that could apply.

Commissioner Megan Gilman: Okay, got it. And apologies if there is, there probably is a size designation, I just off the top of my head couldn't remember. STA is actively working to put resources in place to finance kind of high priority transmission projects as I understand them, that have been identified in its statewide needs study. Does that sound familiar to you?

Mr. Martz: It does.

Commissioner Megan Gilman: Okay. And I'm just curious, has the company had any discussions with CEDA regarding the possibility or perhaps any reason why lines identified as necessary here could or shouldn't be financed by CEDA through that mechanism?

Mr. Martz: It's something that we're certainly willing to contemplate. My understanding of CEDA and where they're at in that bonding process, and I address the tail end of my rebuttal, is it's still pretty nascent. I don't think there's much that's been fully documented, so I can't just give you a blanket answer. I think we're definitely willing to work with CEDA once we see that mature and we see a greater understanding of how that bonding and financing could work. We're willing to look at that, absolutely.

Commissioner Megan Gilman: Okay. And I think you had referred to some frustration that people had from 21A-141E, the prior ERP, with what some parties called the $2 billion surprise in the 120-day report, which was the $2 billion of needed transmission that was first identified in the 120-day report. And I just wanted to understand what might guard against those sort of additional surprise costs on transmission in this proceeding. So, help me understand how you would attempt to continue to refine those costs and make either the commission aware or try to avoid the circumstance that we had essentially in the last ERP where that came up and changed pretty dramatically without any notice until we saw the 120-day report.

Mr. Martz: Sure. And I certainly understand your commentary. I think "surprise" was offered in quotation marks. It's certainly burned into my brain as someone who is leading that group. And I acknowledge the need to improve, and I think that's what we've done a lot of work to do and overhaul our transmission planning group just in a very short amount of time between the ERPs. And again, I know there's been a lot of testing and questioning around, "Well, why these portfolios, Mr. Martz?" And I again, I feel like I sound like a broken record on this, but I'll just keep reiterating, the transmission study was not our endeavor to guess at the most likely portfolios. I actually think that's an improvement practice. I have to balance planning across resource planning and transmission planning. And again, we intentionally identified those study cases. For example, you correctly honed in on a lower thermal dispatch assumption just so we could see the full set of stresses of what we could think could happen on our transmission system. So, the way that we've thought about this and the way that we've designed this, I think Mr. Ihle will talk about a revised framework, because I think there's actually a lot of opportunity for transparency into how we're thinking about transmission. There are multiple steps now at this point that we're adding into the resource planning process that didn't exist before. In simple terms, I think it was pretty simple before: we held a resource plan, we got our bids in, we evaluated our transmission, and then we determined what the projects were. And that was kind of the basis of how the 2021 ERP occurred, and that's what constituted the surprise.

Mr. Martz: We're bringing a lot more of that work upstream in this process, hence the first step and then the second step. And so those are all things that we would confer with commission staff about; that's explicitly enumerated in our framework. And so I think through those vehicles we could make the commission itself aware of material developments and how we're thinking about transmission investment, both the proactive but also the implementation.

Commissioner Megan Gilman: And making the commission aware, that's what, like during the pendency of phase two as you're modeling things, or what does that mean? What would be the mechanism there?

Mr. Martz: Yeah, we'd have to give that some thought and confer with other parties that are part of our tripartite framework. And I also, I'm not a lawyer, so I couldn't speak to if there are certain rules that would limit that kind of communication. But I think the way we would think about it is, as we saw progress in the CCPG task force, if we were to see specific issues, that's something that we could highlight as an area of concern and say, "Look, we looked at this kind of alternative. We're thinking about it like this, based on stakeholder input. We think that this can impact the implementation phase, or it could impact, or sorry, it could drive this type of transmission investment that wasn't previously contemplated." That's how I would think about how that information would come to light.

Commissioner Megan Gilman: Okay. And just one more question that was kind of kicked to you from a prior witness. So, in addition to the Colorado Power Pathways and the Denver Metro Transmission Project, the company still projects billions more dollars in transmission expenses that will be needed to effectively bring the generation and serve the loads identified in the company's base scenario. And I just wanted to understand, costs aside, which are a lot, but costs aside, has the company done any internal studies or tabletop exercises to kind of game out the actual ability of the company to bring those transmission projects online at the time needed to bring the generation in when you show it's needed, serve the new loads, especially large loads at the time you're expecting to commit to them? It's a massive undertaking, not just in money, but in actual physical labor and getting it done. And I'm just trying to understand to what extent the company has really studied the feasibility of doing that in due time to kind of comport with your projections for generation and load.

Mr. Martz: Sure. So I talk a little bit about this at a high level in my testimony. I apologize, I can't remember if I addressed this in my APD adopted direct or later on in rebuttal, but it is something that we talk about. And I'd say, we use what we call a gated execution process, and we refer to that as the PEP or PP process, Project Planning and Execution Process. And that's a way for us to stack together what is in our capital budgets, whether it's generation and/or transmission, or we do this for distribution and gas as well. But we look at that, and part of what that gating process does is it basically requires that our engineers and project managers look at project execution and delivery, work through risk analysis, siting analysis, engineering analysis, and essentially mature those throughout the process. And one of those steps is looking at deliverability, specifically the construction planning, when that applies, whether that's generation or transmission. So yes, in short, to your question, we use that process to look at and exercise how we would actually physically execute the projects. And I'll just lastly note that's a process that we're also in the process of evolving in light of, as you correctly know, the sizable capital expenditures. There's a scaling effect here, and so we're working to ensure we can deliver at the scale that we're talking about as well, and that is a specific topic we're discussing.

Commissioner Megan Gilman: Okay, thanks. Those are my only public questions. Thanks, Jeremy.

Chairman Eric Blank: Commissioner Plant?

Commissioner Tom Plant: Thanks. Good afternoon, Mr. Martz.

Mr. Martz: Good afternoon, Commissioner Plant.

Commissioner Tom Plant: I just had a couple of quick questions. So, at what point, you talked about the two-step planning process with transmission, and at what point does the proposed plan go to the Independent Transmission Analyst Evaluator? I'm not sure exactly what we're calling, yeah, the ITA.

Mr. Martz: So, in this case, it's OldTech, who commission staff have retained. I think that's a fair question, and I don't believe that I refer or specify how that would work. I think that's a question that staff could possibly expound on. I don't, it's their relationship. I think that's something we could talk about with commission staff and further enumerate for you. So I'd say it's more that we didn't enumerate it. It's not our intention to exclude the ITA from those conversations.

Commissioner Tom Plant: Okay. And you touched on this with Commissioner Gilman, but at any point, is there any kind of a formal role that involves the Clean Energy, Clean Electricity Transmission Authority, CEDA, to see how these proposed projects intersect with the statewide transmission priorities projects?

Mr. Martz: Sure. So CEDA, and just to clarify, Commissioner Plant, you're just talking about the CEDA study, correct, not the bonding process?

Commissioner Tom Plant: Right, yeah. Not, I think you talked about the financial stuff with Commissioner Gilman. I'm just thinking in terms of planning.

Mr. Martz: Sure. So that, excuse me, that, the CEDA process is still underway. They have published the projects that they're contemplating. That is absolutely something that we can contemplate as part of our CCPG task force. The acronym is a mouthful, a lot of C's. The CCPG task force, we could look at a way to converge the two and see if there are projects that have come out of the CEDA study that are worth studying. There's not a lot of detail yet from CEDA on the cost-benefit justification for the projects that they've selected as part of that study. So we need to seek out a deeper level of project information on those and then contemplate inclusion through our CCPG task force and participants. Okay, so we're not opposed. That's how I'd see the process working.

Commissioner Tom Plant: And is there any, when you're looking at these various different projects, and I know that this maybe is too prescriptive, but is there any consideration of how this might intersect with future larger regional transmission network system?

Mr. Martz: Do you mind if I specify, Commissioner Plant, regional or interregional?

Commissioner Tom Plant: I'm not sure what the difference is. We're not in a regional market, just a larger market.

Mr. Martz: Okay, sure. So maybe I'll, I'm actually happy to provide answers on both parts. And I think it's an important clarification. I think of regional as projects that would occur within a common balancing authority or multiple balancing authorities within the same interconnect, meaning the same frequency, if you will. I look at interregional as major projects that would otherwise interconnect major RTOs or could potentially cross interconnect boundaries, so like an East to West project or a project that would interconnect like with MYSO South or something like that.

Mr. Martz: So, in terms of regional projects, there are regional entities that we already engage with. There's the WestConnect entity, which consists of several transmission operators within WECC. And then within WestConnect, there's specifically WEST, which is a regional planning task force that's looking at regional transmission amongst multiple parties throughout WECC. And they've been working on that process for a couple years now and have recently identified projects, I'd say an initial and indicative set of projects coming out of their first forecast and resource plan update. So I'd say they're reasonably far along in their process, but they're not yet at the point of conclusion. And again, similar to CEDA, I would see that working similarly, wherein we could bring in or essentially evaluate projects from that study to see if those are worthwhile to bring into the CCPG task force. I would just note that that WestConnect task force does not exclusively look at PSCO. There are other projects, like for example, interconnection between other WECC entities that don't touch our system. And so those are very likely projects that we would not propose as part of CCPG; they would otherwise not impact our system and our customers.

Commissioner Tom Plant: Okay, great. Yeah, I wasn't talking about the sort of DC/AC intertwine. So, you mentioned this, I think with Miss Vitali, about the process for large loads interconnecting into the distribution system. And I was wondering, is there a possibility that if there were large loads that were being cited in the Denver Metro system, that they could exacerbate the constraints that we're currently dealing with on that system?

Mr. Martz: Well, I think you have to identify a baseline or a reference point by which to think through that question. And so the way I think about that, Commissioner Plant, is we looked at a number of large loads as part of our transmission study. And I'm assuming you're talking about transmission primarily in your question, correct?

Commissioner Tom Plant: Yes. Yeah.

Mr. Martz: So we looked at two different load forecasts, if you will, and within those load forecasts, the base and the low, there's a decent amount of large load identified in there. I think approximately 2 gigawatts of large load within the base. And then, subject to check, I think several hundred megawatts in the low; sorry, the numbers escaping me at the moment. We do not see large load as a significant driver of transmission network upgrades coming out of that study. We see it far more on the generation side. And so generation and generation deliverability and associated reliability are driving that. So I think within the confines of how we've studied transmission and specifically large load already, I feel relatively certain that we wouldn't see additional major transmission needed. We've looked at some pretty significant tranches of large load irrespective of rate class. The rate class doesn't really impact how we think about studying that load, because for a transmission system, it's rolled up to a distribution substation anyway. So we're either assigning that load nominally at a distribution substation on the transmission system, or it's being aggregated at its distribution anyway. So there's not a lot of differentiation there. And again, we don't see much, we don't see really any transmission driven, based on the large loads that have been studied in that transmission report.

Commissioner Tom Plant: That's interesting. I mean, I think we have this transmission adder that kind of tries to capture some of those costs, or I guess it would be the credit for things that aren't going through the Denver Metro area. But you're saying that the actual loads that might drive some of that generation being required to be delivered through those systems don't actually, you don't see them as driving those transmission upgrades that might be necessary?

Mr. Martz: That's accurate. And as we've evaluated large loads, again, irrespective of rate class, we have processes in place through our line extension policies by which we identify the necessary costs and cost allocation processes. I would actually like to revise something I said. I don't want to give you the sense that there's zero cost, right? There's obviously interconnection cost, and so there's the physical infrastructure that's necessary to electrically interconnect the customer with our system. So there are costs associated with that. I was speaking generally around network upgrades, which I understood is the intent of your question. We have not really seen significant network upgrades. We have studied our cluster study that I think we've referred to in the case as "data center row" or the "cluster study" as a colloquialism. We do see some network upgrades driven through that clustering, but we're able to see cost efficiencies associated with that. And then again, as part of our cluster study and our transmission line extension policy, our practice is to perform that cost allocation and assignment through that system impact study and associated agreements from there.

Commissioner Tom Plant: So I'm, I'm sorry, I'm trying to understand this. So if you're looking at large loads being cited in one of two places, one place would basically be within that Denver Metro constraint area, and another place would be outside of that area. You're saying that you don't see the choice of where you would put that load as driving different requirements as it relates to the costs of delivering generation to those loads?

Mr. Martz: Not quite what I'm saying, because I'm not trying to represent that we've done iterative locational analysis as a function of that load. What I'm saying, Commissioner Plant, is that as we've received large load requests from customers, whether distribution or transmission, we have not seen our study results indicate significant network upgrades of a magnitude not previously discussed.

Commissioner Tom Plant: Is there any process when you're evaluating load locations that would quantify the costs associated with increasing the load within that sort of area of the system versus another area? Is there anything that would drive loads to areas where there is less congestion?

Mr. Martz: Not currently. However, it's certainly a topic that we've talked a lot about internally. I think it's an area that we're not conceptually opposed to. I think we've heard that in a couple different lines of commission questioning. And so we'd be willing to think about what that could look like and what a process could look like to perform that kind of assessment and develop a reasonable price signal.

Commissioner Tom Plant: Great. Let me double check, yes, that's all the questions I had. Thank you, Mr. Chair.

Chairman Eric Blank: Thank you, Commissioner Plant. I think you set up exactly the conversation I want to have with Mr. Martz. Can we pull up what's been marked as Hearing Exhibit 2907? And let me represent to you, Mr. Martz, that this is the exact same map that Mr. Senaler presented at page 42 of his direct testimony. In that testimony, provided a web link, and this is just a larger and clearer version from that web link. Would you accept that or would you like to pull up his direct testimony?

Mr. Martz: I appreciate the explanation, Chairman Blank. I accept that, and I appreciate the additional clarification.

Chairman Eric Blank: All right. And do you see the large green arrow coming into the Smoky Hills that's labeled "Total Generation 4955"?

Mr. Martz: Yes, I do. You broke up a little bit for me. I think you said the green arrow, correct?

Chairman Eric Blank: Yes, coming into the Smoky Hill substation labeled "Total Generation just under 5,000 megawatts."

Mr. Martz: I do.

Chairman Eric Blank: And is it fair to say that over time as load grows in the Denver Metro area, that that substation may represent a constraint or bottleneck in getting generation into Denver during certain hours? Would you agree with that, or would you say that differently?

Mr. Martz: So you're asking, does that interconnection point represent a constraint as load grows?

Chairman Eric Blank: Yeah, I think it's already an existing constraint.

Mr. Martz: Yeah, I agree on both regards. It's an existing constraint, and again, it features prominently in how we think about transmission investment to improve the import capacity. And I would anticipate, as a generality, with load growth that would be exacerbated. I think you'd have to think about a pretty extraordinary load growth construct where you see no growth in Denver and growth someplace else for that to not be true.

Chairman Eric Blank: Yeah. And it's complicated. It depends on the wind, when the wind blows, the sun shines, the state of charge of batteries, customer behavior, the exact location of timing loads in the Denver Metro area. Is that fair, or would you say that differently?

Mr. Martz: When you say "it depends," I'm not sure what you're referring to. Are you talking about the import capacity constraint?

Chairman Eric Blank: Yeah, on an hourly basis.

Mr. Martz: Yeah, on an hourly basis. I think I'd say transmission's job is to balance load and generation, so I don't think it's exclusive to generation. Load profiles in and out of Denver can drive that as well, so it's the balance of both. But I would agree with, there's certainly variety and disparity, if you will, or variety, I should say, in our generation dispatch as a result of resources. Similarly, load changes and fluctuations would drive that constraint as well.

Chairman Eric Blank: Okay. And focusing on all the green arrows and black boxes within the Denver Metro area and forecasting them over time may present a whole other range of downstream bottlenecks and constraints that will also vary hour by hour and over time depending on the location of loads, customer investments, how the system evolves. Do you agree with that or would you say that differently? So you're asking, do the green arrows, yeah, the little green arrows, it's a whole other set of constraints and investments that are needed as load grows, and it's a complicated hourly calculation about where the load is, how customers behave, how generation is.

Mr. Martz: Yeah. I think as a generality, maybe. I think generalities actually are more dangerous the lower into the system you get, if you will. Additionally, I think generation's impact changes a bit as you get to lower levels in terms of system planning. As an example, if you're doing feeder analysis, like feeder power flow analysis, you'd find that generation dispatch on the very far end of like Colorado Power Pathway would matter less and less. And so it's certainly an element of it, but the way that analysis is performed and the attributes, if you will, they do change as you kind of get further down within the system.

Chairman Eric Blank: And is it fair to say that addressing constraints within the Denver Metro area by upgrading substations or building new transmission lines could be expensive to do in a dense urban area? Is that fair?

Mr. Martz: I mean, "expensive" is a relative term, so it's hard to say if I agree with that or not without some other reference case.

Chairman Eric Blank: Okay. Mr. Ihle and Mr. Landram both testified that over the WRA, the company expects to spend roughly $13 billion on transmission. I think that's more than current existing rate base. Mr. Landram testified that over the next 20 years, the company could spend as much as $38 billion, but both made it clear that the company did not have firm transmission plans supporting the totality of these investments and that the spending could be significantly more or maybe less. Would you say that any different? And does that give you context for costly?

Mr. Martz: I was thinking through that, Chairman, again. I mean, I'll apologize, I kind of took "expensive" in the sense of relativism, like unit cost of a substation and location A versus B, appreciating your comments on the long, I think you're essentially getting to the long-term rate forecast. I don't have reason to disagree with how Mr. Ihle and Mr. Landram have talked about that.

Chairman Eric Blank: Okay. And I guess what I really, where this is all going is I want to talk to you about an alternative approach. Instead of trying to place thousands of megawatts of additional load into the heavily constrained Denver Metro area, and then spending tens of billions of dollars on new transmission and substations, I'm wondering what would happen if Colorado as a state quickly catalyzed say 2 to 3,000 megawatts of new load on the 345 kV system outside the Denver Metro area, on the high side of the Smoky Hills and Daniels Park substations. Are you following me? Do you see those purple lines going into both Smoky Hill and Daniels? I think on this map that's 345 KV, right?

Mr. Martz: It is.

Chairman Eric Blank: Okay, so what I'm asking, instead of putting the large new loads in the Denver Metro area and then having to deal with all these choke points in ways that create double rate base and then maybe triple or quadruple rate base, why don't we just put the large new loads on the high voltage side of the transformer? And I'm just asking, would that reduce congestion at these two substations, at least as compared to putting the new load on the low voltage side?

Mr. Martz: Sure. So I think there are many parts to that question, but I certainly appreciate where your head is at. I heard similar questioning with Mr. Ihle and Mr. Landram. I think it's a little bit more complex than that though. There's more than large load driving our load growth. There's what I'll refer to in a few different tranches. Mr. Goodenough is certainly an expert on that, so I don't mean to otherwise confuse if I use improper terminology in reference to Mr. Goodenough's testimony, but I think you can generally follow me as, you know, there's organic load growth through development, expansion of residential homes, electrification of home heating, purchasing of electric vehicles, and things like that. So, I disagree with the premise that large loads are the sole driver of load growth. There's more load growth as part of that, and that is primarily in the Denver Metro area as it represents the predominant population center of the state and our customer base as well.

Mr. Martz: The other issue I don't agree with is you kind of phrase it like, "Why don't we put the load there?" And I would note that it kind of infers that we have selection authority over where our customers want to site their businesses, homes, etc. What I can tell you is that the requests that we have received reflect where our customers would like to conduct their business. And I have not seen any major preponderance of large load within the Denver Metro area that's driving a specific problem. In fact, I talked about that with Commissioner Plant, that we haven't seen major network upgrades being driven as a result of the customers. It's really more on the generation and generation deliverability side.

Mr. Martz: So, I'd say we are kind of mirroring your concept in some sense, not necessarily Daniels Park to Smoky Hill, but really Smoky Hill up through SP Spruce, and I don't see Palhattan and the other substations on here, but like High Point, which is south of the airport, and Sky Ranch, which you can kind of see in the upper right there. That is where we are already seeing a clustering of large load, and it has the benefit of sitting on the fringe of the Denver Metro area. I think it's impacting both sides of the constraint but primarily hitting the export or the outside of it. And so really what that then becomes about is identifying the right transmission investments to deliver the generation to get to that load. So, I would argue that we're already starting to see some cost efficiencies with a natural clustering of those resources in that area. Again, I appreciate it's not exactly what you proposed, Mr. Chairman, but I think it's very similar in terms of how it's situated. And then, at a higher level concept, pulling that back, like I talked about with Commissioner Plant, identifying those types of corridors is something that we're not necessarily conceptually opposed to. I just don't think that that should be the exclusive vehicle by which we drive economic development in the state. I think that'd be inconsistent with what I've heard as, inconsistent with what I read in Governor Polis's letter. I do think it's a potential tool, and it's something that we're open to exploring with the commission and commission staff.

Chairman Eric Blank: Well, I appreciate that there's a lot of pieces to pick apart. But I mean, it all, for me it all comes, I mean, it seems like it comes down to that $13 billion that doubles rate base and the $38 billion that you... Well, let me ask it this way: assume that the company could generally control where the large new loads would be sited. I understand that you may not agree with that, where the state established strong tax incentives for them to locate in areas that don't create that whatever $13 billion or $38 billion set of transmission costs. If you had control of where the load was sited, is it possible that that might simplify the transmission planning process? Set another way, the company developed the Colorado Pathway on a "build it and they will come" strategy. Is it possible for the company to do a similar thing here with these large new loads and take control over the siting of the loads and the building of the new transmission and substations? So any thoughts on that?

Mr. Martz: Again, Mr. Chairman, I think we're open to identifying reasonable pathways to develop appropriate price signals. I couldn't personally speak to what I think would be the recipe we'd have to develop to otherwise create a reality where the company's in control of the siting of load. That's far beyond our purview. And there's a significant customer element to that that I can't speak to in terms of how they want to think about siting their facilities. And I'm not sure that I can agree that tax implications are the sole way that our customers think about their siting. I mean, they think about the balancing of resources. That could be access to rail lines, access to arterial highways, access to labor markets. I'm sure that taxes come into play. I don't think that if you were to establish a simple tax incentive that it would be enough to otherwise put the utility in the control of where load would be. So it's hard for me to speculate on how I think that that would work.

Chairman Eric Blank: But you understand that you're asking all of their customers to potentially pay $13 billion for new transmission over the next seven years and maybe as much as $38 billion over the next 20 years. So somebody's got to pay for that.

Mr. Martz: Respectfully though, Chairman, I guess I don't think about it exclusively in the sense of cost alone. There are benefits that flow as a result of our capital packages. And as I understand it, Mr. Ihle would be the appropriate witness to ask detailed questions about. We've intentionally constructed two different long-term rate forecasts and have thought through those, and what we generally see is large load as beneficial to rates overall. And I've further clarified in the record here through this line of questioning that I've not seen major network upgrades resulting from large load. So I appreciate the concern over cost. I think the LTRF analysis kind of shows how we think the rate of load growth pairs with capital expenditure.

Chairman Eric Blank: Okay, well, I'll take that up with Mr. Ihle. But what do you think is causing the $38 billion in new transmission if not load growth?

Mr. Martz: Well, I mean, the $38 billion is speculative. We've taken our long-term rate forecast all the way out through 2050. We talk about what goes into those numbers. I'd say it's in part load growth, but not overall. What we contemplated as part of the assumption set is maybe a little bit different from what you were thinking. And so what the LTRF represents in the low and then in the high case, it essentially represents the JTS transmission investments that we identified in our base study for essentially now and the WRA. In effect though, that's 2029 through 2031. When you get further out beyond the WRA, and you look at investments in the mid to late 2030s, then into the 2040s, we're identifying more concept-level transmission. And so, in the low case, that would be another arterial line from Longhorn to Wenberg to Sandstone, and then into Daniels Park, not dissimilar from the proposal of interconnecting like Harvest Mile and Longhorn. So the idea is just another artery for additional renewable resources. I'd argue that there are benefits that flow with that, as our existing customers benefit from access to those low-cost resources as well. So I just don't agree with the linearity in which you're presenting that. I think there's a benefits discussion to go along with how we think about those investments.

Mr. Martz: And then that's the low end. To round out the $38 billion which you've referenced a couple times, what we're saying and part of our assumption set is we think that in those outer years we'd need to contemplate some major regional transmission or possibly interregional transmission investments to further access generation if needed. And we've taken it upon ourselves to put that type of cost in there so we can have a picture into what that would look like. I don't think that what the rate forecast implies is that we would spend that absent the load growth.

Chairman Eric Blank: Okay. Over the coming month, just a couple more questions. Over the coming months, prior to the filing of a large new load tariff, would the company be willing to analyze the transmission and other potential benefits and costs of three actions: siting large new loads on the high voltage side of these constrained substations; putting as much battery energy storage as reasonably possible within the Denver Metro area transmission and distribution constrained areas; and assuming that customer load, especially EV charging, could be much more effectively managed, potentially through new rate approaches? Would you be willing to take a look at those things over the coming months?

Mr. Martz: Yeah, I think those are all concepts we're interested in, and as just a generality, I think they're concepts we're actively exploring in other dockets. I mean, I think there are multiple ways that we're exploring DEARs overall with the commission, with the state, whether that's the virtual power plant docket or AD. But there's also the distributed dispatchable generation filing. So there are a number of avenues by which I think we're already exploring that.

Chairman Eric Blank: All right. So it sounds like, at least on the spur of the moment, no obvious concerns. And I'm talking about utility-scale transmission-interconnected storage, not distribution-interconnected storage.

Mr. Martz: I appreciate the clarification. I think it's something we could do some additional thinking on and think about how we could explore that. Again, that could be something we identify as a case that we could study. I would say that there is already a very healthy amount of DEARs that we've studied as part of this portfolio, and we don't see major differentiations in terms of cost outlay. And that delta is upwards of 10x. So we've looked at 1500 megawatt portfolios of DEARs, of which those don't exist today, that's a speculative number. And we've looked at the low end as low as 150 megawatts, and don't see major changes in transmission investment as a result. So I think it's worth exploring further, but there is already some existing work that we've produced that show that delta. And then I think I'll further expand that the way that we treat DEARs is very favorable within transmission, our transmission studies. We essentially assume that the DEARs are there, and there's some reasonable ability of them to serve that type of generation deliverability subject to their effective load carrying capacity. So there are no additional constraints that are imposed. We look at DEARs favorably as part of our transmission studies.

Chairman Eric Blank: Yeah. I think the main thing I'm asking you to study is the locating the load on the high side of those two transformers, the of those two substations. But yeah, and maybe most of the work on the battery storage in the Denver Metro area is done. Any comments on studying the putting the load on the high side of those two substations?

Mr. Martz: Again, I think we've kind of conceptually done that already with what we've looked at with our data center cluster study and what we've seen in terms of large load analysis on the transmission system. I couldn't speak off the cuff to those two precise substations, but I think actually if we broaden that and looked at the high side of the Denver Metro ring, that's something we're willing to evaluate.

Chairman Eric Blank: Yeah, mainly the 345. That's what I got from Mr. Landram. I think that's the piece that could be transformative. And that's...

Mr. Martz: And Mr. Chairman, that's currently how we're thinking about that load coming online, is connecting to either the 230 or the 345. So some of that load we're already studying as part of that 345 system.

Chairman Eric Blank: Yeah, so I guess the request is to get it on the high side, on the 345, not the 230. Just two more questions. On the May Valley Longhorn Extension, would the company agree to the same PIM that was approved in the Colorado Power Pathway based on the rebuttal testimony cost assumptions?

Mr. Martz: I'm not an expert on the Colorado Power Pathway PIM. The way I kind of think about that working is, one, as we've requested through my rebuttal, we're asking for the unconditional approval of the Colorado Power Pathway. We do stand by the estimate that we've presented in my rebuttal. And the way that I've thought about this, and again, I'm not a lawyer, so subject to ensuring the right procedural steps, I could see us kind of conferring with staff on the right way to bring that type of PIM structure forward and could file with the commission.

Chairman Eric Blank: Okay, so standing by the assumptions, are you saying you are not in a position to see if you would agree to something like the CPP PIM, or that you are asking for a CPCN approval before there is any PIM? I guess what I'm asking is, if we were to grant the CPCN, would you agree to a PIM as part of that approval? That clarifies what it meant to stand behind those estimates.

Mr. Martz: Sure. Yeah, happy to further clarify. So, I was simply denoting, Mr. Chairman, I just can't speak off the cuff to all the attributes of how the PIM was constructed for the Colorado Power Pathway because I understand there's some differentiation in the PIMs for certain segments of that. What I'm proposing we do is, we're not opposed to a PIM framework as part of this. So, we would confer with staff on memorializing May Valley Longhorn PIM and then make a filing into the Power Pathway docket with how we propose that PIM would work.

Chairman Eric Blank: All right. I think that's all I had. So, Miss Shields, do you have a bunch of redirect or do you want to wait till Monday to do the redirect?

Miss Shields: Yes, I will have some redirect. I understand we have the highly confidential session. I would prefer, excuse me, prefer to wait until Monday, but we'll certainly make best efforts to streamline that as much as possible to keep everything moving along.

Chairman Eric Blank: Okay. And then we'll do Mr. Ihle after Mr. Martz? Is that where we're at?

Miss Shields: Yes. And I guess it would be my intent to just limit it to keep our questioning very narrow, just to the commissioner follow-up that we had, and not try and open it up to the parties. I'm committed to keep mine very narrow. Would that work for you, Commissioner Gilman?

Commissioner Megan Gilman: Sorry, can you say that one more time?

Miss Shields: Yeah, I'm just trying to see if we can keep the commissioner questioning of Mr. Ihle narrow and just focused on the follow-ups. Does that work for you?

Commissioner Megan Gilman: Yeah, I don't intend to have much.

Miss Shields: Okay.

Commissioner Tom Plant: Me either.

Chairman Eric Blank: Commissioner Plant, would that work for you? All right. Anything else before we break for the day, Miss Chartran?

Miss Chartran: Yes, Chairman Blank. I wanted just to update you on the availability of Moffat County and City of Craig's witnesses for Monday and Tuesday.

Chairman Eric Blank: Okay.

Miss Chartran: And the first is Moffat County Commissioner Ard. She originally stated she was not available on Monday, but she's available all day now.

Chairman Eric Blank: Okay. On the 24th she's available starting at 10:30 a.m. You say after 10:30.

Miss Chartran: Okay. And then the City of Craig Mayor, Chris Nichols, on Monday is available in the morning from 7:30 a.m. to noon. And on Tuesday he's available any time until 5:30 p.m.

Chairman Eric Blank: Okay. Thank you.

Mr. Hyatt: Good afternoon, Mr. Chairman. While you have your matrix in front of you, just want to let you know that the EJC will waive its cross and UCA witness Chris Neil, I think we had 10 minutes.

Chairman Eric Blank: Okay. Thank you, sir.

Mr. Rollo: Thank you, Chair. I just wanted to clarify, when Mr. Ihle is recalled on Monday, that will be limited to commissioner questions, correct?

Chairman Eric Blank: Thank you.

Mr. Cox: Yes, we'll add to the waivers. Staff will waive on sweep witness Valentine.

Chairman Eric Blank: Okay. Thank you. Any other final matters before we break for the evening, Miss Shields?

Miss Shields: Nothing for the company.

Chairman Eric Blank: All right, Mr. Martz, we'll see you in highly confidential session first thing Monday at 7:30. And then we'll jump into the public session. Good weekend, everybody. Thanks.