Transcript - Day 8

24A-0442E, Public Service Company - 2024 JTS - 06.23.25 - HRA (8 of 9)

I had to split this transcript in to 9 parts. The way A.I. works it doesn't process a bit at a time, it first has to read in the entire document and tokenize it. That is not a great approach for an action this simple, but that's how the general purpose A.I.s work. So at the splits, it tends to think it's now Jack Ihle speaking.

It's the correct transcript based on my checking, but the speaker identification is wrong after a break until a speaker is explicitly identified in the transcript.

Eric Blank: Good morning, everybody. Sorry for the delay. I'm Eric Blank, and this is the public session in the Public Service Company Carers Just Transition proceeding, number 24A-442E. We just concluded a highly confidential session, and for those who have signed the appropriate documents, the transcript will be available for that session. With that, Miss Shields, are there any preliminary matters before we conclude the redirect of Mr. Martz? Any preliminary matters from anybody? Miss Shields, you're up for the public redirect of Mr. Martz.

Miss Shields: Mr. Martz, the first thing I'd like to start with relates to the May Valley Longhorn Extension, or MVLE. Last Friday, Chairman Blank specifically asked you about whether the company would agree to applying the Pathway Project PIM to the company's $34 million cost estimate provided as part of your rebuttal testimony. Do you recall that exchange?

Mr. Martz: Yes, I do.

Miss Shields: Just to make sure we have a clear record, does the company stand by the MVLE cost estimate provided with your rebuttal testimony as being the appropriate basis on which to establish a PIM?

Mr. Martz: Yes, we do. The estimates in my rebuttal testimony are $304 million. If an unconditional CPCN is approved as part of this phase one proceeding, we absolutely stand by that cost estimate attached to my rebuttal testimony. However, if we receive a continuation of the conditional CPCN, we’d need to reserve the ability to update that cost estimate as part of our phase two filing or whenever we request to convert the CPCN into an unconditional CPCN.

Miss Shields: Would you anticipate that the longer the CPCN remains conditional, the more likely costs are to increase?

Mr. Martz: Yes, I would. Given the level of supply chain turmoil impacting all utilities across the United States, we anticipate that would affect our cost estimate for May Valley Longhorn.

Miss Shields: Turning to the PIM structure, could you clarify and elaborate on the PIM structure for the MVLE project that the company is open to or agreeing to be bound by?

Mr. Martz: We’re very committed to establishing a PIM for the May Valley Longhorn project. We contemplate it being very similar to the Pathway PIM. The only element that could warrant modification relates to the timing aspect in the Pathway PIM, which is included for some segments. For May Valley Longhorn, as a single segment, the timeline contemplated wouldn’t be attainable. As I mentioned last week, we’d want to confer with staff to develop tangible documentation of what the PIM would look like. Our intention is to file that into the Pathway proceeding docket, where the Pathway PIM is already in place and being reported on. We’re committed to making this clear and consistent.

Miss Shields: Last question on MVLE. Commissioner Gilman asked about whether there’s any diversity of resources that the MVLE will tap into compared to other resources the Colorado Pathway Project is accessing. Could you elaborate on the potential benefits from the renewable resources MVLE will access?

Mr. Martz: We’re optimistic that constructing the May Valley Longhorn transmission segment as part of the Colorado Power Pathway would help us access some of the best wind resources in the state. In the 2021 electric resource plan or clean energy plan, resources in electric resource zone three were some of the lowest-cost resources bid into our portfolio. Additionally, as we’ve modeled these resources in our updated ELCC and PRM study, represented by Mr. Land, we expect these accreditation values to be higher than other regions of the state. This gives me confidence that constructing this transmission segment would allow us to access the best, lowest-cost, higher-capacity wind resources on behalf of our customers.

Miss Shields: Turning subjects, Commissioner Gilman asked about how the company might keep the commission informed of the company’s JTS transmission stakeholder engagement. Would the company be open to filing the JTS task force study report with the commission, either through this docket or a miscellaneous proceeding?

Mr. Martz: Yes, I recall the discussion. The simple answer is yes. We typically file these kinds of reports as part of our supporting documentation for any CPCNs related to these transmission projects. We can commit to filing that report with this commission as part of those proceedings. Additionally, as part of our 2021 ERP generation and transmission evaluation work, we performed a version of this analysis. I anticipate that as part of our proposed 180-day report, we can provide an update on the stakeholder engagement that has occurred, so the commission can assess the status and understanding of what’s been evaluated.

Miss Shields: Commissioner Gilman also asked about the voting process at CCPG. Do you recall that?

Mr. Martz: Yes, I do.

Miss Shields: Do the CCPG bylaws, by your understanding, establish a voting process?

Mr. Martz: Yes, they do.

Miss Shields: And any stakeholder in the JTS task force will be governed by those bylaws, correct?

Mr. Martz: That’s accurate.

Miss Shields: Commissioner Plant asked about the role of the independent transmission analyst, or ITA. Do you recall that?

Mr. Martz: Yes, I do.

Miss Shields: He inquired about how the ITA may be engaged in the various stakeholder processes the company will engage in. Could you elaborate on that?

Mr. Martz: I apologize if anything I said last week came across as unclear. The commission staff possesses the relationship with the ITA first and foremost, as they are an independent transmission analyst. We view the ITA as an extension of staff. To date, we’ve had a constructive start, and we have a good process working well. They’ve been part of our analysis, and we’ve set up various information-sharing methods on a secure platform, allowing the ITA full access to system models, data sets, and what we’re evaluating. We can discuss that in detail with them and commission staff. As I testified last week, we have no intent to exclude the ITA from any stakeholder process that commission staff participates in, so long as staff views ITA participation as appropriate, depending on the nature of the discussion.

Miss Shields: I’d like to change topics and turn to some dialogue you had with Chairman Blank related to transmission and large loads. Chairman Blank asked several questions about the transmission assumptions in the company’s long-term rate forecast, or LTRF. Within that, he inquired about the extent to which large load customers may contribute to the company’s mid- and long-term transmission cost estimates, which I believe are about $13 to $38 billion, depending on how far out you go. Could you elaborate on the extent to which you see large loads driving future transmission costs, particularly from a capital perspective?

Mr. Martz: For this JTS phase one case, we’ve studied multiple forecasts, both a base and a low, ranging between one gigawatt and two gigawatts of load for these large load customers. Of the nine large load customers in our updated base forecast presented in our rebuttal testimony, we’re confident they do not constitute a major need for transmission upgrades at this point, given that we’ve studied these loads. They’ll absolutely drive new generation, and other forms of load growth might drive additional transmission, but based on our updated base, we don’t see them driving significant projects. Through our existing system impact study and facility studies processes, we have a way of identifying, capturing, and assigning the appropriate transmission costs associated with these large loads, reflected in our base forecast. Until we have a large load tariff in effect, we can direct assign these costs through agreements. We also have tools like upfront capital payments, such as kayak construction or native construction, or we can assess separate service and facilities charges, which are already in our existing tariff. Our primary focus in this phase one proceeding is creating a path for the large loads in our updated base forecast, given their high level of maturity and likelihood of proceeding. In the longer term, we anticipate continued large load interest. Our queue is in excess of six gigawatts of load beyond this base forecast, which we’re actively studying through our data center row cluster study. These loads could drive the need for holistic system upgrades, but it’s too soon to say with precision what those would be. We’re running multiple cluster studies to assess system impact, looking at upgrading or reconductoring parts of our 230 system to 345 or expanding capacity. There’s also a possibility of identifying advantageous projects that increase capacity to service those customers while providing additional capacity across the Denver metro import-export constraint. By studying them as a cluster, we have the opportunity to optimize for those customers. We’re already optimizing off the Smoky Hill Harvest Mile area south of the airport to evaluate network upgrades. In the short term, we need to create a path to bring approximately 950 megawatts of large load to service. The JTS phase one proceeding is a good way to do that. Longer term, as we contemplate more prospective large loads, we’d study those loads and bring that analysis forward as part of a large load tariff filing, where we’d be better positioned to understand the magnitude of system costs for both generation and transmission.

Miss Shields: You mentioned an ongoing system impact cluster study around data center row. Is it your intent that this analysis can help inform a large load tariff filing and rate design structure?

Mr. Martz: Yes. Given how it’s situated on the frontier of our system, on our Denver metro import-export constraint, we can look at it uniquely, different from a customer in a highly networked area. Our intention is to evaluate the economics of what that would look like. We could also appreciate the chairman’s suggestions and look at different transmission system topologies to assess incremental or marginal costs for generation and transmission for large load customers in a few different spots on our system. That would be part of our large load tariff filing.

Miss Shields: The chairman asked about additional modeling the company might be willing to conduct in support of its large load tariff filing. I think you conceptually agreed but had started to identify considerations the company would be interested in modeling. Do you recall that dialogue last Friday with Chairman Blank?

Mr. Martz: Yes, I do.

Miss Shields: Could you spell out the type and scope of study the company would propose to this commission to conduct in conjunction with its large load filing?

Mr. Martz: What we’re talking about is consistent with the chairman’s suggestions. By looking at a couple of different topologies, we could examine the area of interest he suggested, as well as other areas with system challenges. We’re willing to look at it. Data center row is important because customers there have some level of maturity in their siting assessments, choosing those sites for specific reasons. Given where it sits on our system, it’s a good prospect to optimize generation and transmission costs. We’d contemplate this as part of our proposed transmission analysis in multiple parts. First, based on the outcome of this phase one proceeding, we’d update our generation modeling, specifically Encompass, using the updated base forecast presented in rebuttal and updated generic pricing assumptions. We could include several sub-topologies within Encompass to see if there’s a specific benefit to solving for a certain corridor to relieve congestion. I’m skeptical of the efficacy of that, but we could explore it with multiple topologies and sensitivities, inserting a specific load bubble for Encompass to solve for to see the cost delta. Second, we’d import those results from Encompass into our transmission study. Due to the timing challenges of JTS, we didn’t use the exact portfolios, as we wanted to run those analyses in parallel for a more wholesome analysis of transmission system impacts. We’d take the direct outputs from Encompass, use them for the updated generation portfolio and dispatch assumptions, along with the updated load forecast, and run a new power flow analysis to assess the transmission impacts from those customers. For the forecast, we’d contemplate three load scenarios: one with no large load, based on the base forecast; one with the rebuttal large load added, about 950 megawatts to a gigawatt; and a high large load scenario based on our queue, which is six gigawatts and growing, using our data center row cluster study results. We’d seek to do this in early third quarter to maintain progress. Our intention is to file our large load tariff by January 31, 2026. Given the amount of generation and transmission modeling and engineering analysis required, we’d kick off that work as soon as possible, pending the decision from this proceeding. We’d conduct the Encompass modeling, then the transmission modeling, and file that into our large load tariff filing.

Miss Shields: Does this transmission study fit into any broader JTS process refinements that the company is contemplating or proposing in this case?

Mr. Martz: Yes, it does. We’ve iterated on and evolved our multi-party framework. When Mr. Ihle takes the stand later today, he’s prepared to walk you through what that evolution looks like. The updates to the generation modeling, Encompass modeling, transmission modeling, and engineering analysis fit well within that framework and show a necessary evolution of how we’re thinking about this case.

Miss Shields: Thank you very much, Mr. Martz. I have no further redirect questions for you.

Eric Blank: Thank you, Mr. Martz. You can be excused. I think we’re going to bring back Mr. Ihle, hopefully for not too long. Mr. Ihle, do you understand you’re still under oath?

Jack Ihle: I do.

Eric Blank: Commissioner Gilman, did you have some questions for Mr. Ihle?

Megan Gilman: I just have three questions. Good morning again, Mr. Ihle. I wanted to get a policy perspective from the company regarding the company’s role as a bidder and the arguments for conforming bid policy and some of the PPA terms. At a high policy level, is the company open to the commission endeavoring to create corollary treatments for company bids to bind you as a bidder to similar restrictions, especially with regard to future changes in price on your bids, as you’re trying to add for other bidders?

Jack Ihle: Initially, I think that’s primarily a matter for the CPCN proceeding to grapple with. We bring CPCNs for all the generation that comes out of the phase one and phase two process under 3617D, I believe. I don’t know if I have a specific commitment to offer here. Did you have a specific item in mind from the conforming bid?

Megan Gilman: I’m not going to get into each provision, but wouldn’t it be beneficial for the company to understand ahead of time if that was the company’s intention, rather than waiting for the CPCN to introduce that concept?

Jack Ihle: I’m struggling with the generality of the question. Maybe you can help me with that.

Megan Gilman: The company is looking to restrict the ability of IPs to increase prices for things like supply chain risk, changes in law, tariffs, and other things that the company has even looked to increase prices for in previous ERPs. I was wondering if the company would be open to similar restrictions that you’re attempting to put on IPs with regard to future changes in the price of your bids.

Jack Ihle: I don’t know if I can commit to that here. We worked with the IP community in the C delivery filing, and I think we’ve shown an ability to work with them. They’re one of the parties to the three-party framework. I understand the question and the symmetry here. Every time we compare IP and utility-owned generation, there are similarities and differences. I firmly believe the hybrid model of both utility-owned and IP generation has served Colorado’s customers. They both offer unique things, and this is somewhat case-specific.

Megan Gilman: I have a question on the CFFD, very broad, regarding governance. I believe you’re recommending a CFFD advisory board. Given that in the company’s rebuttal, you recommend no budgetary limit to the CFFD, I was wondering if you could tell me anything about how you’re envisioning the governance of that advisory board. Does it operate on a consensus basis, a simple majority rule? How should we view how that advisory board will be set up?

Jack Ihle: That’s a good question. I don’t know if we’ve set up the strict governance. We discussed the members of the advisory board, but I don’t know if we established the governance process or voting rights. We took the budget limit off as we saw this mechanism extending into a second supplemental RFP and having a longer resource acquisition period. I don’t know if we had testimony or a specific position around the governance piece beyond the composition of the board. I’m sorry I’m not more helpful on that right now.

Megan Gilman: Changing subjects to forecast changes with regard to each of the RFPs. Mr. Goodenough and I went through this. He expects to update the forecast prior to the issuance of the base RFP. We’ll start with the base RFP and changes that might take place there. We saw significant changes in the company’s forecast from the direct to rebuttal cases, so it’s feasible there could be significant changes again before the base RFP. What transparency does the company anticipate around how that forecast would be shared with the commission or other parties prior to all the modeling occurring, sticking to the base RFP?

Jack Ihle: Thank you for the clarification. Historically, we’ve provided an update on this forecast as we move from the phase one decision into the actual RFP, typically 60 to 90 days between the phase one decision and the RFP. We’ve usually provided that update in advance. I don’t believe there’s a specific rule provision on it, but we’re willing to commit here to providing that updated load forecast 30 days before the issuance of the RFP to the commission, submitted in this docket.

Megan Gilman: Would that be detailed enough, especially around large loads, which are complicating things with a very different forecast than in the past, so the commission and parties can understand the differences in those components?

Jack Ihle: Yes, that’s the intent. As Mr. Goodenough testified, and I discussed with him, it’s a full refresh of the load forecast, inclusive of refinements on EV and PHEV forecasts. The intent is to provide a good amount of detail on the drivers in that load forecast 30 days before the RFP.

Megan Gilman: Is it your intent that this forecast refresh would segment and separate the forecasts for full battery EVs and PHEVs?

Jack Ihle: Yes. In 2024, our data suggested a 70% EV and 30% plug-in hybrid electric vehicle split, based on registrations. The EV forecasting is looking at new load shapes updated since the 2019-2020 vintage, creating additional granularity to encompass forecasting of both EVs and plug-in hybrid electric vehicles, also looking at the new time-of-use structure and how it affects those electric vehicles.

Megan Gilman: Do you plan to incorporate differentiation in that forecast refresh for the base RFP, with 70% battery EV and 30% plug-in hybrid EV, and provide those with different charging and usage patterns more accurate to their types?

Jack Ihle: Yes. That 70-30 is a historic snapshot from 2024, but they can be independently forecasted going forward, and the energy and demand forecasting on each of those two major classes can be incorporated into that forecast.

Megan Gilman: With their different needs, that would represent a different charging duration for plug-in hybrids versus standard EVs?

Jack Ihle: Yes.

Megan Gilman: Will the company also presume a higher level of flexibility for plug-in hybrid EVs, given that they have an entirely redundant fuel source?

Jack Ihle: I acknowledge they have a different and redundant fuel source. Whether we have enough data or programmatic assumptions to differentiate on flexibility, I don’t know with 100% certainty. They’re on similar types of charging equipment, whether plug-in or pure electric vehicle. I don’t know if the technological capability of the charging equipment and the current maturity of the programs will distinguish between those two. We can take the question back to consider.

Megan Gilman: Same question for the supplemental RFP. What are your expectations around disclosure of the forecast changes in assumptions before the supplemental RFP?

Jack Ihle: There would be a progression of information going into that second RFP. By that time, you should know whether, how many times, and at what megawatts we activated the incremental need pool. That would be new information, fully known to the commission through the ERP annual report process. You’d have full knowledge of any failed bids and replacement bids that triggered the incremental need pool. We’d provide a similar and detailed update on the sales and demand forecast going into the second RFP, at least 30 days in advance.

Megan Gilman: Given the potential we’ve already seen for significant swings, especially in large load customers and potentially in EV forecasting, after the litigation of crucial application filings that could inform EVs, what opportunity do you see, especially if there are major changes in those forecasts, for some intervention or response to those forecasts before they get modeled, acknowledging the very different situation we’re in compared to previous ERPs?

Jack Ihle: Good question. We’d incorporate any evolving knowledge from the market, policy, or regulatory decisions across clean heat, demand-side management, and potentially EVs, depending on the maturity of that information. We’ll have more information on markets, especially the beneficial electrification market, which is still nascent. Our view is that this is structured following the phase one and phase two process. We’ve built a flexible framework with the base RFP and supplemental RFP. With all that additional information, there should be a lot of transparency. We weren’t planning to offer a comment or review process, but there are tools in the regulatory toolbox to address significant concerns. We could offer it slightly earlier, but 30 days feels about right for the updated forecast review. We’re wary of delaying the process through a review process, but I understand the concern about large swings that garner more attention than in the past. We hope the evolution of this phase one and phase two process, effectively two phase twos with adjustments, puts us in a different position.

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

Tom Plant: Hi, Mr. Ihle. Good to see you this morning.

Jack Ihle: Good morning. Good to see you.

Tom Plant: I have a couple of quick follow-up questions around the tri-party process. We spoke about this with Mr. Martz. I’m trying to understand the establishment of the 80% triggered off negotiations for the IIA and ESA, and the 90% is signing the IIA and ESA. But for projects interconnected on the distribution system, there’s more of a construction agreement, not an IIA or ESA. What process does the company contemplate for evaluating the status of projects on the distribution system?

Jack Ihle: It’s similar but parallel. The metric doesn’t work quite as well for those because PG customers are practically the same as strategic economic development customers. They’re local, so a land purchase isn’t necessary—they already have control of the land. The difference between an ESA and a construction agreement is something we could contemplate in the PG tariff, which has some guidelines. Whether there’s a specific contract like an ESA in PG is a bit beyond me commercially. They’re local, regional, and in active discussions with us on developing those loads. We believe they’re real, as Mr. Martz discussed. There are timing adjustments, and we’re in real-time conversations about what’s possible. We’re moving away from the percentage nomenclature, as it lent artificial precision to the probabilities. It’s about the stage of maturity of the commercial project increasing over time, usually to a higher maturity level unless there’s a backout. We’re employing similar processes for regional, local strategic economic development loads, consistent with standard or historic business practices. The creation of these probability levels was driven by larger data centers and the need to assess those with more uncertainty.

Tom Plant: Thanks. I don’t have any further questions.

Eric Blank: Welcome, Mr. Ihle. Mr. Martz outlined a process to study the impacts of large new loads on transmission needs and suggested the company might file it as part of the January 2026 advice letter filing. Given the rate and other issues in that case, could the company look at filing it earlier in a notice and comment process that could later be included in the advice letter filing? I’m not trying to pin you down now, but in your statement of position, could you help us see if we could simplify that advice letter filing? It’s going to be a complicated case. Would you be willing to take a look at that?

Jack Ihle: Absolutely. Mr. Martz, our legal team, and I, with Mr. Martz overseeing his planning team, are trying to assess what’s possible and when through the analytical work. It’s a fair question, and we’re willing to look at it. We’re conservative about offering deadlines to ensure we can hit them. There’s some stakeholder process in front of that large load tariff, so we can discuss directional information with parties, trial staff, the energy office, and others.

Eric Blank: I appreciate that. I have a few questions on the exhibit you filed based on the Public Service Company SEC 10K filing in 2024. Mr. Goodenough acknowledged that the average residential rate in 2024 was 13.82 cents per kilowatt-hour, subject to later check. Would you accept that, or would it be useful to pull up the 10K?

Jack Ihle: I think that’s exactly right, the last time I looked at the 10K.

Eric Blank: Can we pull up hearing exhibit 132 and go to the class allocation sheet, line 113, cell L13? If you could scroll down and take a look. It’s in green. Can you get a little closer so we can all see it? Do you see how in cell L13, the average residential rate in 2031 at the end of the RAP is 20.33 cents per kilowatt-hour? Is that right?

Jack Ihle: May I ask a navigation question? I want to make sure we’re looking at our base forecast, originally in the distribution system plan, brought into the record here in the JTS, with the class cost breakout within DSP.

Eric Blank: Thanks for laying a better foundation. I appreciate that. If we subtract the 2024 rate from that number, 20.33 minus 13.82, the rate increase during the RAP is 6.51 cents per kilowatt-hour, subject to later check. Would you accept that math?

Jack Ihle: Yes, and the 10K was 2024 vintage. I accept that.

Eric Blank: If we divide 6.51 cents per kilowatt-hour by 13.82, the 2024 rate, that results in an average residential rate increase of over 47% during the RAP. Would you accept that math?

Jack Ihle: I’m accepting the math. I’ll add that this relies on all these investments coming in per those years. That’s our current estimate in the sales forecast, but yes, I accept your math.

Eric Blank: This is based on your direct case assumptions. You testified there’s a 74% cost increase in wind, 84% for solar, and over 40% for CTS. If we increase the resource pricing assumptions in this spreadsheet by those percentages, then this average residential rate increase would be higher, assuming all other inputs were the same. Is that fair?

Jack Ihle: It’s fair.

Eric Blank: Can we go down two lines to line 15? This is the average rate for C&I customers at transmission voltage. In cell E15, the average rate is 7.87 cents per kilowatt-hour in 2024. Do you see that?

Jack Ihle: Yes, I do.

Eric Blank: At 7.89 cents per kilowatt-hour, C&I transmission rates are basically flat over the RAP. Would you accept that?

Jack Ihle: I would, and I’d elaborate that the pricing team endeavored to apply current cost allocation policy, as decided by this commission in recent cases, to project the application of those policies going forward by class in a reasonable way. There was no effort to estimate or evolve the policy, which is where the large load tariff proceeding might consider directions going forward. I acknowledge the numbers there.

Eric Blank: The commission is concerned with this large residential rate increase while C&I transmission rates are declining in real terms. This highlights the need for the January filing. Any comments on this trend where residential rates are likely to go up greater than 50% while C&I transmission rates are declining in real terms?

Jack Ihle: We’re following the cost allocation methodologies as decided in tariffs and relevant rate cases. The last electric phase two was the most recent place we did that. These are assigned based on logical cost allocation principles. One thing affecting the residential class that wouldn’t touch the C&I transmission class is the increased investment in the distribution system, which flows proportionally more onto the residential class to provide services benefiting residential customers, like 140,000 electric vehicles and moving the beneficial electrification market forward under clean heat plans. That’s implied in the DSP. I acknowledge the optical concern and offer to work with the commission in communicating what that means and why, as customers may ask these questions more directly.

Eric Blank: As average residential rates go above 20 cents per kilowatt-hour, is it possible that some residential customers will increase investments in efficiency, distributed generation, or decline to pursue beneficial electrification, reducing sales and potentially further increasing residential rates? We’ve seen in California rates have more than doubled or tripled over the last 12 years. Any comments?

Jack Ihle: I don’t agree that energy efficiency is likely to reduce residential sales. I’ve monitored that for over 20 years, and it hasn’t happened, though it has slowed growth. It could increase investment in distributed generation, as theory suggests, but all else is not equal. Federal legislation may shorten the availability of tax credits for customer-sited DG, like solar and batteries. I share your worry about higher rates discouraging electric vehicles and beneficial electrification, which are great for carbon, the economy, and customers. This is a static look, but we have tools like time-of-use rates to help with affordability, expanded assistance programs, and income-qualified programs across efficiency, REST programming, electric vehicles, and beneficial electrification. We’re managing this more than the increase might show. There’s room for consideration of these ratios, and I agree it’s more than optical.

Eric Blank: Last question. If the PUC chose to move toward a conforming model offtake contract, how would we get to a PUC-approved contract on this record, given that we haven’t seen model language from the company’s rebuttal case? Do we need a follow-up notice and comment process? I’m concerned the gap between the company and the IPs is still large, and we don’t have actual language. I’ll struggle to resolve this on this record. Any thoughts on process? I’ll ask Mr. Pierce and Ms. Monson the same question.

Jack Ihle: I hear the question and the concern you're voicing. We'll certainly reflect on that and take it into consideration. We have before us the statement of position process step here. We've had dialogue with CIA, represented in the framework. Notably, not included in the framework, and critical to CIA's alignment, is that we did not resolve the conforming bid piece. We could continue a dialogue there to see what process step may increase your ability to make a decision confidently. I can't commit to that right now. I don't know exactly how that would flow into either PSOP or post-SOP matters, but we're marking the question diligently.

Eric Blank: Appreciate that. Mr. Larson, redirect.

Matt Larson: Thank you, Mr. Chairman. Good morning again, Mr. Ihle.

Jack Ihle: Good morning, Mr. Larson.

Matt Larson: I want to start with the conforming bid conversation you were just having with the Chairman and earlier with Commissioner Gilman. Starting with Commissioner Gilman's questions, a conforming bid requires bidders to bid to the terms of the RFP and the terms of the model PPA. Is that your understanding?

Jack Ihle: It is my understanding, but it's not 100% "here's the document, sign it with no changes." To me, the discussion is about what should be changeable and what shouldn't. With respect to company bids, they do not sign a PPA. Is that your understanding?

Matt Larson: They do not, but company bids still have to bid to the terms of the RFP in submitting their bids, right?

Jack Ihle: Yes.

Matt Larson: There was also a discussion about pricing flexibility or pricing adjustment with Commissioner Gilman. You recall that?

Jack Ihle: Yes.

Matt Larson: During your prior time with us in redirect, we put in hearing exhibit 131, which was the company's response to the staff tariff adjustment proposal. Do you recall that?

Jack Ihle: Yes, at a high level.

Matt Larson: In terms of adjusting for tariff impacts that would apply to both business models, whether IP or company-owned and operated, on top of the conforming bid policy. Is that how you understand it?

Jack Ihle: I do. Our response in my rebuttal was to reflect an openness to having that conversation concerning a tariff-driven adjustment process, consistently between utility-owned and IPs, which is how we've conducted the C delivery process.

Matt Larson: With respect to the discussion with Chairman Blank just now, is the company committed to trying to file a red-lined model PPA, starting from the as-filed version but incorporating the comments Mr. Bornhofen provided in his rebuttal testimony with its statement of position?

Jack Ihle: My understanding is yes. We'll ask COSA and CIA witnesses, as a preview of cross-examination, if they're willing to do the same thing. If they were, the commission would have multiple versions of the contract to select from or review in establishing a conforming bid policy. Does that sound right to you?

Matt Larson: Yes, if those parties are willing to do that, that would be true, and certainly the company’s willing to do that with the SOP.

Matt Larson: One question on carbon-free future development. You had an exchange with Commissioner Gilman this morning about the governance associated with CFFD. Do you recall that?

Jack Ihle: Yes.

Matt Larson: I’ll represent that Mr. Tomjanovich addresses the governance in his rebuttal testimony. It’s a simple majority to approve a proposal to come out of CFFD from the advisory board. Do you have any reason to disagree with that?

Jack Ihle: No.

Matt Larson: Is it your understanding that the commission would have a window to review any proposal advanced by the advisory board prior to the funding actually occurring?

Jack Ihle: Yes, my understanding is the commission would review those.

Matt Larson: Just four other brief areas responsive to discussion this morning. Ms. Federico, could we have a series of demonstratives to work through? Could we call up what I believe has been marked as hearing exhibit 146 in PSCO’s box?

Matt Larson: Mr. Ihle, you have before you what’s been marked as hearing exhibit 146. Four areas from discussion this morning we’re going to talk through. First, we’re going to discuss generation price sensitivity, following your discussion with Chairman Blank. Second, we’re going to discuss the difference between the updated base forecast and the low forecast. Third, we’re going to talk about some of the commitments PSCO has made over the course of this proceeding and how they fit into the framework. Finally, we’re going to talk about an update to the JTS phase 2 framework, responsive to questions and the evolution of the case to this point.

Jack Ihle: Okay, thank you.

Matt Larson: Let’s start on slide one. This builds on the discussion you had with Chairman Blank this morning. Could you describe what’s represented here on the first page of hearing exhibit 146?

Jack Ihle: Yes. What’s new is that after my initial discussion with Chairman Blank concerning the price increases on generators, originally brought forward in Mr. Landrum’s rebuttal testimony, we flowed those through a long-term rate forecast model, which is otherwise identical to the ones I was discussing with Chairman Blank. The left two data columns show I was curious to understand how this would work. This isn’t necessarily addressing the rate change ratios or capital cost pieces Chairman Blank and everyone is looking at, but it does address whether there remains value to having large load customers enter the system under current cost allocation policy. The answer is yes. This shows the difference between the base and the low was about 3.3% on a CAGR basis for five years, about 0.88% on a 20-year basis. With the updated, significantly higher generator costs, holding those in the model over a 20-year time frame, you have fairly similar differences between the CAGR results of these two models. In other words, adding large loads provides value to customers. The left two columns are class averages, the right two columns look at residential customers. The value there is between one and two cents to the residential customer of bringing more large loads in, noting this is the low-load forecast in our original base forecast. Where we are today is that updated base with the potential to add things through the incremental need pool and the supplemental RFP, showing the value on a bill basis to the residential customer. It’s seven or eight dollars, roughly equivalent to what customers are paying in an SNF charge today, reflected in the bottom blue box.

Matt Larson: If we could flip to the second demonstrative on page two of hearing exhibit 146. Mr. Ihle, I’ll represent that this is a public version of hearing exhibit 141 with both a load forecast identification and color-coded bins. Could we start by describing the color coding within the table on the left side of the graphic?

Jack Ihle: Sure. This is consistent with how we’ve testified over the past few days. We see the 944 megawatts of updated base larger loads in three bins. One is the strategic economic development bin, local customers, not data centers. The second is existing loads increasing their load, data centers but existing customers. The third is one customer, a new customer not on our system currently, a data center viewed as highly probable but not having the ESA at this point. It’s demystifying the difference between the low-load forecast and the updated base forecast.

Matt Larson: In the interest of continuing to demystify this, let’s talk about the differences between the low forecast today if the RFP were to start and the updated base forecast today if the RFP were to start.

Jack Ihle: The difference is really the strategic economic development loads, those local existing customers, and the one data center customer G, a newer customer with a strong interest in being served here. Today, based on customer S’s progression, it would make it into the low forecast. Is that your understanding?

Matt Larson: It is my understanding that it is moving that way, yes.

Matt Larson: Is it fair to characterize the difference between the updated base forecast and the low forecast as being one new data center, customer G, and the strategic economic development opportunities, with the exception of customer H, who is also in the low forecast?

Jack Ihle: Yes.

Matt Larson: Ms. Federico, if we could move to the third graphic in this series. Mr. Ihle, the company has made a series of commitments over the course of this proceeding. This graphic attempts to put those commitments into context and into swim lanes, with the base RFP process across the top, the supplemental RFP process through the middle, and the transmission process, which has not changed in any material way, across the bottom. Do you see all of that?

Jack Ihle: Yes.

Matt Larson: The three commitments specifically I want to talk about are: first, the filing of the model IAES that incorporate large load principles, a commitment made by Mr. Bailey. Do you recall that?

Jack Ihle: Yes.

Matt Larson: The second is the generation transmission study that would inform the large load tariff, the one you were discussing with Chairman Blank and also discussed by Mr. Martz. Do you recall those questions and discussion?

Jack Ihle: I do. Mr. Martz discussed the details better than I would be able to. Chairman Blank and I had a conversation about the timing of it.

Matt Larson: The third goes back to when Mr. Landrum was testifying, where he discussed the ability to provide a reoptimized preferred plan or approved plan after the phase 2 decision on the JTS base RFP, reoptimizing around a lower load scenario as a compliance filing. Do you recall that discussion?

Jack Ihle: I do, and that is our commitment in that upper right green box. Our hope is that it can address questions of marginal or incremental cost driven by these customers if we can make that contrasting showing. The long-term rate forecast models and how we’ve discussed them also provide some insight to guide those decisions.

Matt Larson: Starting with the JTS base RFP, the blue box says filing of model IAES incorporating large load principles would occur in the near term. Is that right?

Jack Ihle: Yes.

Matt Larson: From there, we would go into the JTS base RFP process phase 2 decision, and then that load differentiation reoptimization we were discussing would occur. That’s the extent of that swim lane. Is that your understanding?

Jack Ihle: Yes.

Matt Larson: When we look toward the red box from the JTS phase 2 framework on the far right, the JTS supplemental RFP, the large load tariff would be filed well in advance of the JTS supplemental RFP. Does that sound right?

Jack Ihle: It does.

Matt Larson: The study is contemplated in the far left box in the second row, which you were discussing with Chairman Blank and Mr. Martz discussed with the commission this morning. Is that right?

Jack Ihle: Yes, it is.

Matt Larson: That constructs that swim lane across the middle?

Jack Ihle: Right. It increases the additional information and insight flowing into that second supplemental RFP, consistent with how I discussed the updated load forecast with Commissioner Gilman. One key thing in the middle swim lane is that the large load tariff would apply to large loads taking service via generation acquired through the JTS supplemental RFP. Is that consistent with your understanding?

Matt Larson: Yes.

Jack Ihle: Certainly, to move through that process with the information Mr. Martz discussed, I agree with Chairman Blank that it’s going to be a wholesome discussion around these issues. The intent is to complete that so we can conduct the second RFP with the large load customers, commission, stakeholders, and the company all having higher confidence in what these large loads mean to the system.

Matt Larson: The JTS two-step transmission process is across the bottom. We have the purple box and the call-out box from Mr. Martz’s rebuttal testimony. There’s no adjustment to that based on the commitments we’ve discussed. Is that right?

Jack Ihle: That’s right. We’ve shown it here for chronological context. There’s a fair amount of complexity, and we’re trying to illustrate how these things will occur over time and inform each other across these three channels leading to major filings and processes.

Matt Larson: If we could go to the fourth graphic in this series of demonstratives. You alluded to this in your discussion with Commissioner Plant this morning, but there have been a couple of adjustments to the tri-party framework over the course of this case. Is that your understanding?

Jack Ihle: Yes.

Matt Larson: The first is changing the probabilities to steps, reflected in the first bullet and shown in the call-out box to the right. Can you briefly describe what’s happening there?

Jack Ihle: Sure. The steps themselves remain the same. It’s really the labeling, moving away from implied probability and identifying it more directly as a level or step of commercial maturity on a particular large load moving through that multi-step process. It represents more accurately what we’re discussing here.

Matt Larson: With respect to the second adjustment, the second bullet puts in place an additional layer of process for incremental need pool projects activated to serve large loads in aggregate over 500 megawatts ramp within the relevant wrap. Can you describe that addition to the framework?

Jack Ihle: Stepping back slightly, the first two boxes of the framework are the same, except the second box didn’t have a top end in terms of megawatts. In further discussions with parties, we added this third piece in case we had a very large load of 500 megawatts or greater. We acknowledge that’s a big thing to accommodate in this process. We want the ability to meet that timing need if we can, through the incremental need pool process. We agreed to add more review to contemplate such a large load through an application process, which we would encourage to move through a 120-day timing. It would have all the steps of an application—discovery, answer, rebuttal, etc. In the event we have a load that large seeking service through the incremental need pool, it would be subject to a full application process.

Matt Larson: Given this adjustment, is it fair to say there are three different processes that could come out of incremental need activation? The first being under 100 megawatts or a bid failure replacement, with a notice and a 14-day comment period?

Jack Ihle: Yes.

Matt Larson: Then 100 megawatts to 499 megawatts would be a notice, 45-day comment period, 10-day reply?

Jack Ihle: Yes.

Matt Larson: Over 500 megawatts would be this application on the 120-day statutory clock?

Jack Ihle: Yes, that describes the universe. The critical piece is the commission gets a vote on each one of these three.

Matt Larson: In terms of activation, it’ll be based on loads in the aggregate for that activation?

Jack Ihle: Yes, loads could be aggregated to trigger those threshold levels.

Matt Larson: Mr. Chairman, I would move the admission of hearing exhibit 146. I have a couple of additional questions for Mr. Ihle. Can you take this exhibit down? Do parties have concerns?

Sam Eisenberg: No concerns.

Eric Blank: So moved.

Matt Larson: Could we call up hearing exhibit 144 out of PSCO’s box? Mr. Ihle, I’ll represent that this is hearing exhibit 144, pre-marked in Public Service’s box. This document, in redline format, adds the change to probabilities to steps and the 500-megawatt-plus process. Have you seen this document before?

Jack Ihle: Yes.

Matt Larson: I’ll ask Mr. Hay this question on cross-examination, but is it your understanding that with these changes, the Colorado Energy Office is prepared to join this framework, making it a quad-party framework as opposed to a tri-party framework?

Jack Ihle: That’s my understanding, and I welcome Mr. Hay’s confirmation if appropriate.

Matt Larson: Mr. Chairman, we have hearing exhibit 144, a redline version, and hearing exhibit 145, a clean version, modified SJD9s, which was hearing exhibit 2606. I would move the admission of both at this time. Any concerns from the parties? Could you take it down so I can see the boxes, Ms. Federico?

Mr. Bunker: One concern is that this is filed at this late date, eight days into a hearing. The second is whether there are changes besides the addition of CEO on the first page in this redline document. Are there changes later in the four-page document?

Matt Larson: I can respond, Mr. Chairman. The only changes are redline changes to effectuate the steps as opposed to probabilities—10% becomes step one, 20% becomes step two—and a brief paragraph to add an application filing if there is an incremental need activation for large loads over 500 megawatts. Those are the only two changes.

Mr. Bunker: I continue my concern that this is brought in on day eight of the hearing. We learned about the original tri-party document the day before the hearing, and now it’s changed to this quad-party document. I’ll continue to voice that concern, in addition to other concerns parties have cross-examined regarding this document.

Chris Leger: Echoing the concerns raised by Mr. Bunker and requesting clarification, as we did with attachment SJD9, that this framework is neither a settlement nor a stipulation.

Matt Larson: It is neither a settlement nor a stipulation. To respond to Mr. Bunker, these changes are relatively minor in the context of the framework. They are a change to a process on the incremental need pool when the activation is associated with very large aggregated loads.

Ellen Kutzer: Mr. Chairman, I’m wondering if it would be possible to walk through these minor changes, especially with staff witness Daly and Mr. Hay coming up. Some of us intend to ask those witnesses questions about this framework, and having an understanding going into cross-examination may save time.

Matt Larson: I’m happy to do that with Mr. Ihle right now, Mr. Chairman, if that’s helpful.

Ms. Federico: Exhibit 144 does not have a header. Is it all right if I put it on after we’re done talking about it?

Matt Larson: Yes, it is. I realized it didn’t have a header and had a moment of anxiety.

Eric Blank: Does the court reporter need a break, or are you good for another 10 minutes?

Court Reporter: Ten minutes, then a break.

Eric Blank: Mr. Larson, if you and Mr. Ihle can put up hearing exhibit 144 and quickly go through it, that’d be great.

Matt Larson: Absolutely. Mr. Ihle, on the screen is hearing exhibit 144, a redline version of attachment SJD9, with no header. On the first page, the changes are to add the Colorado Energy Office to the document in red. Is that the only change on page one?

Jack Ihle: Yes.

Matt Larson: Can we go to page two, Ms. Federico? On page two, in the fifth bullet, there is a textual change to clarify that the updated base forecast for the JTS base RFP includes strategic economic development opportunities. Then there is a reference to the steps in the table below on that same bullet, and it provides the actual table with steps as opposed to probabilities. Is that right?

Jack Ihle: Yes.

Matt Larson: I believe the only other changes on page two are to add CEO to the document. Can we go to page three?

Chris Leger: On the prior page, the step or percentage 8N now also says ESA and IIA, and 9 says IIA or ESA, which I believe confirms what we’ve talked through during the hearing, but that appeared to be a change.

Matt Larson: I can confirm that is a clarification based on the table and testimony in this case to this point. Page three, I believe the only changes are to add CEO. Can we go to page four?

Matt Larson: On page four, in the activation triggers, it changes 80% probability to step eight, 90% probability to step nine, clarifies with the stricken backslash that it’s IIA or ESA. I don’t believe there are other changes on this page. Oh, there is one. Mr. Ihle, do you see that to make clear it’s an aggregated ramp, so if there were multiple large loads, they are considered in the aggregate?

Jack Ihle: I fully agree with that change.

Eric Blank: On page four, the 80/90, the IIA/ESA, following up on what Mr. Leger asked, we have an “or” in the last full line instead of 90%, but up above on the second line, we still have the slash. The party and the commission should take that slash as an “and,” but take the slash out of the fourth line down where we have the word “or.” Is that correct?

Matt Larson: That’s correct.

Matt Larson: On page five, the last set of changes are adding CEO and clarifying a CIA reservation of rights in paragraph 7. Mr. Ihle, do you see the red text in the middle of the page?

Jack Ihle: I do.

Matt Larson: Is that red text designed to implement the 500-megawatt and above process discussed during your examination earlier?

Jack Ihle: It is exactly to do that. One quick elaboration: this simply adds more review to potential activations of the incremental need pool. It does nothing but add more review and more party rights.

Matt Larson: Mr. Chairman, this completes the walkthrough. I re-up my motion to admit hearing exhibits 144 and 145, which is a clean version of this document.

Eric Blank: I’ll admit 144 and 145, subject to the concerns raised by Mr. Bunker and Mr. Leger that it’s late in the hearing and not a stipulation or settlement agreement. Anything else on redirect, Mr. Larson?

Matt Larson: No, that’s the extent of the redirect. Nothing further. Thank you, Mr. Ihle.

Ms. Connelly: I’m assuming you’re taking a break soon. Mr. Hyatt and I have worked out, giving you 35 minutes back. Mr. Hyatt contacted me this morning; he is waiving cross-examination of Commissioner Zack Swearingen, and I’m waiving cross-examination of EJC’s witness Schlissel.

Eric Blank: Swearingen, 10 minutes, and Schlissel. Can I tell Mr. Swearingen he is excused, that there are no commissioner questions?

Megan Gilman: I don’t have questions.

Tom Plant: I have no questions for either.

Eric Blank: Nor do I. Both witnesses can be excused. Thank you, Ms. Connelly. Mr. Hyatt, we’d like you to confirm Ms. Connelly’s representation.

Mr. Hyatt: I can confirm. Thank you, Ms. Connelly.

Eric Blank: Let’s take a break until 10, and we’ll come back with Dr. Daly.

Mr. Bonis: CEO is waiving its cross of Mr. Daly.

Ellen Kutzer: Thank you, Mr. Chairman. COSA and AEU object to submitting new redline contract language as part of the company’s statement of position on due process grounds. We’re concerned we won’t have an opportunity to respond to that new language on the record. Going through that process will require significant additional resources we aren’t able to have at this time. We believe Mr. Detsky is going to chime in on behalf of CIA as well.

Mark Detsky: From a due process perspective, the company chose not to submit new language in rebuttal or any other point in this case. If they want to submit additional redlines, we would ask for additional discovery, testimony, and hearing on those redlines. That could add a lot of delay to a process where we have an RA need now and need to get the RFP on the street as soon as possible. We’re not sure what the company would put in redlines. Much of their rebuttal testimony, Mr. Bornhofen’s, they’ve claimed as rescinded under the condition where the model PPA is not approved. There would be a lot of confusion, needing extra due process. It wouldn’t be appropriate for the company to come out with a redlined 100-110 page model PPA after the record closed.

Eric Blank: Is there a notice and comment process we could do after this hearing that would address this?

Ellen Kutzer: A concern our witness will talk about is that, as a trade association, we’re not representing a single offtaker, so it’d be difficult to land on singular positions in response. I renew my resource concern. I understand wanting to smooth the process, but it’s not only additional resources but significant delay when the industry can’t afford it. I’m gravely concerned about additional process and moving forward with redline changes from the company that we fear will chill the industry.

Mark Detsky: For CIA’s part, our witness is not able to testify on what process, ERP, and regulatory legal process would be appropriate to satisfy industry concerns. Mr. Monson testified in his answer testimony that if the commission wished to explore these issues further, one vehicle could be opening a miscellaneous proceeding, taking comment from parties, and working through PPA provisions in a workshop setting, potentially in place for the next ERP. That’s not a very happy answer.

Matt Larson: In terms of what we set forth with Mr. Ihle, that was a potential process to get enough information in front of the commission to make an up-or-down decision on the conforming bid policy. The model PPA we would file would incorporate the JB2 positional changes. Could we handle that with a responsive SOP that the trades would have an opportunity to respond to solely on that topic? We’re open to any process that gets you the record you need to decide whether to approve a conforming bid policy. My concern with the arguments from COSA and CIA is that they say they’re not the right entity to negotiate a conforming bid policy, and there’s no process in this case that can result in one being approved, which kills the ability to do a conforming bid policy at all. We’re flexible—if it’s notice and comment or a responsive SOP, we’re willing to do either. We want certainty as we head into the RFPs as to whether we’re doing a conforming bid policy. We’ve laid out why we think it’s appropriate.

Mr. Lai: From our witness’s perspective and the testimony we provided, we’re in the same position as Ms. Kutzer and COSA. Any changes in addition to what’s on the record are a significant problem if put forth in an SOP. In terms of Interwest’s ability to redline a 110-page document and put our information that’s already on the record, we don’t have the resources. We’re at the end of the hearing, and what’s on the record is on the record. Unless there’s another process that extends this timeline that the commission is comfortable with, that’s where we’re at.

Matt Larson: All we’re doing is adding the changes from JB2, which have been on the record since we filed our rebuttal testimony. It would be a compliance filing incorporating those changes into the model PPA. Parties are on notice of what positions the company’s willing to take because they’re spelled out in that document.

Mark Detsky: I want to respond to what Mr. Larson said. CIA, COSA, and Interwest have been united in saying we’re not the appropriate parties to negotiate a PPA with the company, which is the primary reason the conforming bid policy should not be accepted. We’re doing our best to amalgamate industry concerns in response to a one-sided, heavy-handed document, as the record has shown, and show the problems to the commission. We haven’t been engaged in contract negotiation because we’re not the contracting parties. In Mr. Bornhofen’s testimony, he talks about the need for a change in law provision, but that’s not in attachment JB2. During the hearing, Mr. Bornhofen said the company withdrew its compensable curtailment PTC provision, which CIA supports, but that changes things. If the PPA is not a take-it-or-leave-it document and they want to file redlines that bidders can comment on, we could live with that. What we can’t live with is a take-it-or-leave-it document that can’t be redlined, with Public Service putting forward after the record is closed what they believe it should say.

Eric Blank: I’ll have some questions for your witnesses that you may or may not be able to answer. More to follow. Mr. Leger, did you have something on a different issue?

Chris Leger: Yes, on witness availability. I wanted to confirm for WRA/SWEEP witness Mr. Iden that the commission can accommodate his availability to appear on the stand today out of order.

Eric Blank: Let’s take him first thing after lunch.

Chris Leger: Perfect. Thank you, Chairman.

Eric Blank: Dr. Dahlke, can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Steven Dahlke: I do.

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

Steven Dahlke: No.

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

Steven Dahlke: I will.

Eric Blank: Mr. Detsky, before we get to Mr. Cox, did you have something?

Mark Detsky: No, I’m getting ready to cross Mr. Cox.

Mark Detsky: Good morning, Dr. Dahlke. Can you please state and spell your name for the record?

Steven Dahlke: Morning, Mr. Cox. My name is Steven Dahlke, last name D-A-H-L-K-E.

Mark Detsky: By whom are you employed, and what is your title?

Steven Dahlke: I’m employed by the Colorado Public Utilities Commission on Trial Staff as an economist.

Mark Detsky: Did you cause to be filed in this proceeding answer testimony marked as hearing exhibit 2600, cross-answer testimony marked as hearing exhibit 2605, and rebuttal testimony marked as hearing exhibit 2606, including attachments?

Steven Dahlke: Yes.

Mark Detsky: If I asked you the questions contained in the pre-filed testimony, would your answers be the same?

Steven Dahlke: Yes.

Mark Detsky: Dr. Dahlke is available for cross-examination. I want to confirm the company has waived cross of Dr. Dahlke. Is that right, Mr. Larson?

Matt Larson: No, we have a few questions for Dr. Dahlke, 20 minutes. We’d like to go last.

Mark Detsky: Good morning, Dr. Dahlke. We’ve met before, but for the record, Mark Detsky on behalf of CIA. I’m going to be asking about the tariffs proposal today, maybe looking at your cross-answer testimony. You agreed with CIA witness Mr. Monson at a high level regarding the challenge that tariffs pose for project developers, correct?

Steven Dahlke: We did agree at a high level as to the challenge.

Mark Detsky: Your testimony concludes that some tariff pass-through mechanism is appropriate for the JTS RFPs. Is that correct?

Steven Dahlke: Subject to the terms and conditions outlined throughout that cross-answer testimony, we agree that a pass-through mechanism is appropriate.

Mark Detsky: Have you had the chance to review Public Service’s responses to your proposal in hearing exhibit 131?

Steven Dahlke: Yes.

Mark Detsky: At a high level, do you agree that although Public Service seeks to modify parts of staff’s proposal on tariff pass-through, there is a high level of agreement between Public Service and staff on that mechanism?

Steven Dahlke: I don’t know if the testimony to date has established that. If you’re asking me to relay at a very high level our thoughts on their response, I think there’s broad agreement, subject to certain clarifications and modifications. I may have a few to add if given the opportunity on the record. At a high level, it supports agreement to the challenge of tariff uncertainty and to some high-level aspects of a potential path forward to adapt the process for that challenge.

Mark Detsky: I do want to hear those responses, but I’m limited in time, so I’ll let that happen elsewhere. This alignment that CIA, Public Service, and staff have at a high level regarding the tariff pass-through mechanism is a pretty notable agreement in this proceeding, wouldn’t you agree?

Steven Dahlke: There was significant disagreement between staff and CIA’s answer testimony regarding some significant aspects of the pass-through proposal. I agree that both of us have proposed different versions of tariff cost pass-throughs in our testimony in this case.

Mark Detsky: Let’s dig into those. Your testimony has a great play-by-play summary of the tariffs this administration has put in place. Is it correct that the tariffs have changed multiple times already this year?

Steven Dahlke: Yes, even since we filed cross-answer testimony.

Mark Detsky: If the United States Constitution is any guide, there should be a new administration as of January 2029. Is that correct?

Steven Dahlke: I’m not a constitutional scholar, but I certainly hope so.

Mark Detsky: I took from your answers to CIA’s discovery that your understanding is that tariffs are generally assessed when goods arrive at a port of entry to the United States. Is that your understanding?

Steven Dahlke: Yes, that’s my understanding.

Mark Detsky: An arrival at a port of entry means the equipment has been shipped and is on its way to a project site. Is that correct?

Steven Dahlke: If equipment for a project in Colorado is assessed tariffs at the port of entry, that means it’s at the port of entry in the United States. It’ll probably go beyond that, but timing and specific strategies of sourcing can vary.

Mark Detsky: Some Public Service witnesses insinuated that a bidder may be stockpiling equipment as opposed to shipping it to a project site. Do you think an IP would generally take the risk of stockpiling equipment at this time versus shipping it to a project site?

Steven Dahlke: I really don’t know, Mr. Detsky. I haven’t worked for an IP in project development, so I can’t give informed speculation. The economic landscape currently and going forward is pretty new, so history may not be the best guide on top of my uncertainty with how IPs may respond in terms of their sourcing strategies.

Mark Detsky: Staff’s proposal of the CKT—you write in your testimony, paraphrasing, that removing tariff risk altogether from IP bids could result in poor decisions. Is that correct?

Steven Dahlke: That was in response to the stated goal of Mr. Monson’s pass-through proposal to remove tariff risk from bids. Our response, largely in opposition, is around how that path forward would not give the commission, staff, company, and other stakeholders useful information regarding the current state of tariffs as it applies to potential projects that may or may not be the case in the future. There was an informational shortfall with CIA’s proposal that was the major concern to staff.

Mark Detsky: The CKT stands for Current Known Tariff estimate, correct?

Steven Dahlke: Correct.

Mark Detsky: I understand that proposal—correct me if I’m wrong—that bidders would submit their bids utilizing the tariff rates effective at the time of bidding for their given project. Is that correct?

Steven Dahlke: That’s correct. They would separate out the portion of those costs from the base project costs in their pricing.

Mark Detsky: As Public Service nuanced in hearing exhibit 131, they argue that should be for major equipment only, as opposed to all aspects of a project. Do you recall that?

Steven Dahlke: I recall the word “major equipment.” If they also used “critical,” you’ll have to clarify. I believe they proposed to limit it to major equipment only.

Mark Detsky: Do you agree with that change?

Steven Dahlke: I think it’s a reasonable sentiment to make this implementable. They’re thinking through that this could be an informational rabbit hole because these projects are complex with many components. I’m sympathetic to that sentiment as long as it’s clear what we’re asking for and every project doesn’t interpret the proposal differently. Given those qualifications, we’re sympathetic to that sentiment.

Mark Detsky: Would you agree that the RFP documents should be revised to state what the CKT is—bid as accurately as possible and separate out your calculation of the impact of tariffs today to major equipment?

Steven Dahlke: If the commission accepts our tariff proposal, I would agree with that.

Mark Detsky: If a bidder had stockpiled equipment, they might not need to do that. They could say tariffs are not applicable at this point?

Steven Dahlke: Yes.

Mark Detsky: Would that be a narrative discussion in a bid, providing the sourcing plan and CKT?

Steven Dahlke: It could be a narrative discussion. It should identify to the best extent possible the sourcing strategy the bidder will take or strategic options, understanding things could change. If a bidder had equipment within the United States already and was committing to use it for this project, they should indicate that, perhaps in narrative form, and I would expect that to be a binding commitment if known with that certainty.

Mark Detsky: You also have a sourcing plan component of your proposal?

Steven Dahlke: Correct.

Mark Detsky: Does that mean whoever is selected for phase two should have the qualifications to evaluate a sourcing plan?

Steven Dahlke: At a high level, yes.

Mark Detsky: You propose in the CKT that selected bidders would have to give an update to Public Service every six months as to the status of their sourcing plan and CKT calculation. Is that correct?

Steven Dahlke: In part. They would only be required to provide updates if the US tariff rates changed. If there was no change and no need to update the tariff estimate component, they wouldn’t need to file an update. The six months was a minimum. If tariff rates change weekly for a period, they could file an update after six months.

Mark Detsky: Did you hear my cross-examination with Mr. Bornhofen the other day?

Steven Dahlke: Yes.

Mark Detsky: Mr. Bornhofen admitted there could be indirect effects from tariffs, like new tariffs on imported steel affecting the price of domestic steel. Do you agree that could be the case?

Steven Dahlke: Yes.

Mark Detsky: Would staff agree that those could be valid components of a CKT?

Steven Dahlke: I’m not sure I’m ready to strongly disagree, Mr. Detsky. I’m tempted to suggest we limit the tariff pricing component to direct effects only because secondary, tertiary effects can be unmanageable and hard to distinguish from broader supply chain and inflation issues. I’m sympathetic that indirect effects can pose challenges. I haven’t fully thought this through, and staff can clarify further in an SOP, but I’m leaning toward ring-fencing this to direct tariff assessments on the major equipment IPs are sourcing directly. Let the other risks be handled in the rest of the project combined with other factors.

Mark Detsky: Just one point of clarification: you said IPs, but it would also apply to company projects, correct?

Steven Dahlke: Thank you, yes, that’s correct.

Mark Detsky: You also propose a 20% cap on the increase of an as-bid price due to tariffs in the CKT. Is that correct?

Steven Dahlke: We did propose that.

Mark Detsky: In discovery, you explained that if a project submits an update on the tariff CKT and crosses the 20% threshold, your proposal is that the project is terminated. Is that correct?

Steven Dahlke: I believe we used that language, yes.

Mark Detsky: If the tariff changes and the IP is required to file an update of CKT, that could still be well before the tariff is actually paid. Could that be?

Steven Dahlke: Could be, yeah.

Mark Detsky: In the instance where a project fails because its tariff update has increased the 20% bid price threshold, do you agree that in the case of an IP that signed a PPA, they should not be forced to lose a portion of their security in the contract for that event?

Steven Dahlke: I’m not prepared to agree or disagree with that at this time, Mr. Detsky. We can give it some thought.

Mark Detsky: That would be a consequence, right? If it faces automatic termination and has to terminate its PPA, those PPAs can have losses of security in the event of an early withdrawal?

Steven Dahlke: Correct.

Mark Detsky: Can I clarify if you’re about to move on or add a few thoughts?

Jack Ihle: Please clarify.

Ellen Kutzer: On this general piece, a couple of thoughts from staff's perspective. One is to acknowledge that a 20% increase in total project cost due to tariffs is a pretty major thing. Whether it's 20% or whatever the commission approves, we understood and appreciated that when picking a number for our proposal, this would be a very significant change to a project cost. I'm not going to elaborate further.

Secondly, in our cross-answer testimony, we explored and included discussion on possible alternatives to contract termination if such a threshold was passed for a particular project because of swings in tariff policy, especially if the project was needed for a critical reliability need. Acknowledging that if a tariff regime changes after a bid is selected, it's likely not just impacting one project but many projects. Our primary sentiment is to have a check if something really significant happens, so we have an automatic check-in and not a mechanistic pass-through without the ability for the commission and other stakeholders to retake a look at what this means for the projects and the portfolio.

Ellen Kutzer: You've gotten to some of those questions on my list, and I'm going to try to get through the last page of my questions here, Mr. Chairman. Because it's possible the tariffs come down, especially after 2028. Isn't that true?

Jack Ihle: That's possible.

Ellen Kutzer: Might it be wise for a project with a 2029 in-service date to wait to take delivery of equipment until after January 2029? Tariffs could come down or go up at any point. I certainly hope they come down. Maybe you're contemplating that they'll go down once there's a change in federal administration. Correct?

Jack Ihle: It's possible. There's a lot of uncertainty here. Even if there's a new president, there's some uncertainty with that too.

Ellen Kutzer: But if there's an automatic termination in the case of a CKT update, wouldn't that foreclose the possibility that tariffs would come down, especially after the current administration? It would foreclose the possibility of that project being saved by reduced tariffs if there was an automatic termination, as we're talking about.

Jack Ihle: If we wanted to refine the language away from automatic termination to an automatic pause and check-in—I don't know the right legal term—we may be open to exploring that with you, Ms. Kutzer.

Ellen Kutzer: That's exactly what I'm getting at. The effects of an automatic termination could be hard to undo. For example, if there had been a CKT update in April of this year when there was a 140% tariff on goods from China, and there was a slew of automatic terminations from battery projects, then the tariff rate was reduced to 30% the following month, you could have had a slew of battery terminations in April that would have been rescued, so to speak, in May. Correct?

Jack Ihle: Possible, yeah.

Ellen Kutzer: So, I want to take you up on your offer and maybe end this cross earlier than needed. Would staff be open to a check-in with some flexibility as opposed to an automatic cut-off if that tariff rises during the CKT check-in?

Jack Ihle: As long as—I don't know if check-in is the right word—we'd be open to the concept, Ms. Kutzer, assuming it addresses our concern that we're not automatically letting this project get delivered with pass-through costs to Colorado customers without further review and consideration. Frankly, project termination should be one of the possibilities among others that should be seriously considered in such a check-in if costs go to that level.

Ellen Kutzer: Thank you for that. My final questions: you mentioned earlier this system reliability carve-out. Does that ring a bell? I think you said the project should be terminated with a few qualifications, like unless it's critical for reliability or something like that. My question is defining that critical reliability a bit. Is that talking about a resource capacity need, meaning any project that is significant in size to affect the resource adequacy need? Is that the kind of project you're talking about?

Jack Ihle: That's most likely what we're talking about in the context of this solicitation with large generation projects, yep, resource adequacy, if you will.

Ellen Kutzer: What about from an emissions perspective? For example, if a large project termination would affect the emissions profile of the portfolio, would that also fall under your exception?

Jack Ihle: I don't think we proposed that in cross-answer, Ms. Kutzer. It could certainly be part of the consideration if there's a check-in, for lack of a better term.

Ellen Kutzer: Given that, as you said, if one project is facing these tariff considerations in the CKT, it's likely that other projects, for example, in the INP, are facing similar constraints or challenges. Correct?

Jack Ihle: It's possible. Different technologies and projects could have varying levels of exposure.

Ellen Kutzer: There's a compelling incentive to keep projects around as well as to perhaps get rid of projects that made bad choices in sourcing and should be terminated. Correct? There's a balance there.

Jack Ihle: I agree with that, yeah.

Ellen Kutzer: Great. Thank you, Dr. Ihle. That's all the questions I have, Mr. Chairman.

Eric Blank (Chairman): Thank you, Ms. Kutzer. I have 15 minutes for Kosia, and it's 10:36, Ms. Kutzer.

Ellen Kutzer: Thank you, Mr. Chair. I expect I'll be able to give quite a bit of that back as Mr. Ihle covered a lot of the terrain I intended. Good morning, Dr. Ihle. How are you?

Jack Ihle: Good morning, Ms. Kutzer. I'm well, thank you very much. It's nice to see you.

Ellen Kutzer: Could we please pull up hearing exhibit 131? You were just going over this with Mr. Detsky, correct?

Jack Ihle: Yes.

Ellen Kutzer: While we're waiting for that to get pulled up, I'm curious as to staff's position in general on the company comments to your recommendations. Have you agreed to those? Are you still reviewing them and potentially addressing them in your post-hearing statements of position? Where is staff at on these?

Jack Ihle: We've reviewed them. We're certainly going to reserve the right to respond in more detail in SOP. We're at a point where we can respond at a very high level to what's on this two-page document if asked, subject to the qualification that we can clarify those as needed in our written SOP.

Ellen Kutzer: Great, thanks for that clarification. Ms. Federico, would you mind blowing it up just a little? Dr. Ihle, I'm going to ask you about one of these terms, number four. You have a recommendation that, as part of the CKT proposal, bidders should be supplying any executed contracts or letters of intent from suppliers that substantiate the components' sourcing and pricing. Correct?

Jack Ihle: Yep.

Ellen Kutzer: Here, on the right column, the company says they'd support that recommendation with a further modification. A few of the things they recommend is that bidders need to establish commitments from their EPCs and suppliers and provide documentation, including master service agreements, memorandums of understanding, capacity reservation agreements, term sheets, supply contracts, letters of intent, etc. Do you see that?

Jack Ihle: Yes.

Ellen Kutzer: I want to dig into this a bit. Do you agree that the company and independent power producers are competitors when it comes to owning renewable energy projects? Let me rephrase. Would you say that the company and IPs are competing for the same resource pool to serve that capacity that's needed?

Jack Ihle: At one level, yes. Perhaps at another level, there's possibilities of collaborations on bids that then could compete with other bids. So, a couple of levels to that, but yes, fair enough.

Ellen Kutzer: Providing your competitor with the prices of the supplies and the prices you're paying for those supplies could give the company an advantage over IPs in some situations. Would you agree?

Jack Ihle: There are laws and rules that I'm not super privy to around establishing firewalls between the company's bidding team and the evaluation team. To some extent, I understand the sentiment behind your question, and I'm not disagreeing with it. I think there are safeguards in place to try and mitigate those concerns to the extent possible.

Ellen Kutzer: Let me restate another way. If we're asking here in this modified term from the company to provide materials such as master supply agreements or other documents that contain pricing, do you see a need to affirm that those guardrails are in place so there is not an anti-competitive concern about providing those materials?

Jack Ihle: I would agree that those guardrails should be robust. More broadly, Ms. Kutzer, some of these types of documents can help provide useful information with respect to tariff costs. The primary pieces of information are sourcing strategies and which countries are available to provide major equipment, and then which tariffs potentially could apply to goods and services that come from those countries. Those are the primary pieces of information that would be helpful to a bid. The language here on the right is from the company, not specifically from staff, but to the extent that documentation like this could support and provide confidence in a project's sourcing strategy and potential tariffs that could apply, that's helpful. It might not require disclosing a lot of other detailed confidential information beyond the location and the type of equipment.

Ellen Kutzer: Would staff be open to narrowing the information that is provided to the company to just that information that's necessary to provide sourcing information and any associated tariffs associated with that sourcing?

Jack Ihle: At a high level, that's our intent. The company has taken the initiative to propose more detailed examples of what that could be and also appears to propose a minimum documentation. I haven't had a chance to think through to what extent staff agrees with that. A strongly supported tariff estimate can help provide us confidence that we fully understand the risks of going forward with that project. That's a long way of agreeing with the high-level principle behind your statement.

Ellen Kutzer: Let's move on to one last line of questions. In your surrebuttal testimony, you briefly address the CFFD proposal. Do you recall that?

Jack Ihle: Yes.

Ellen Kutzer: One thing you state is that you don't support the removal of the $100 million cap on the CFFD proposal. Correct?

Jack Ihle: Correct.

Ellen Kutzer: What's staff's position on the CFFD after this hearing? Do you support that proposal? Have you refined your thinking? Any clarity you can provide to your surrebuttal testimony?

Jack Ihle: It's a big question, Ms. Kutzer. There are a lot of components of our position on the CFFD that are spelled out in my answer testimony. We further clarified in my surrebuttal that we would support implementing a budget, opposed the company's proposal in rebuttal testimony to remove the budget, and want that reinstated, perhaps at the $100 million level.

Ellen Kutzer: Fair enough. That's all the questions I have. Thank you very much.

Jack Ihle: Thank you.

Eric Blank (Chairman): Thank you, Ms. Kutzer. Mr. Larson, I have 20 minutes, and it's 10:44.

Matt Larson: Thank you, Mr. Chair. Good morning, Dr. Ihle.

Jack Ihle: Morning, Mr. Larson.

Matt Larson: You and I have met before, but for the record, I'm Matt Larson. I represent Public Service. I want to start with what was entered into the record this morning as hearing exhibit 144. If we could call that up. Dr. Ihle, do you see this on the screen, which is hearing exhibit 144, a redline version of your attachment SJD9, hearing exhibit 2606?

Jack Ihle: I see it.

Matt Larson: Have you reviewed the changes that are in this document?

Jack Ihle: Yes.

Matt Larson: Do you agree to the changes that are in this document?

Jack Ihle: I do.

Matt Larson: Do you support CEO joining the tri-party framework?

Jack Ihle: I do. It might not be the tri-party framework anymore, but I welcome CEO joining the framework.

Matt Larson: Would you object to calling it the quad-party framework?

Jack Ihle: No.

Matt Larson: Thank you. We can take that down. I want to go back to hearing exhibit 131, which you've already taken a series of questions on this morning, but I want to step through it more systematically in the interest of understanding where there's still space between Public Service and staff.

Jack Ihle: Okay.

Matt Larson: First, the company at the top of this document has a couple of general statements. Would you agree that any kind of tariff pass-through approach should be simple and transparent?

Jack Ihle: I agree that's one of a few key objectives we should look for.

Matt Larson: Would you agree that simplicity and transparency benefit bidders in submission and the company and the independent evaluator in evaluating the materials provided?

Jack Ihle: If we're getting the information we need, the simpler, the better.

Matt Larson: The way this document is structured is your recommendation on the left, PSCO's position in the middle, and then comments on the side. You see that?

Jack Ihle: I do.

Matt Larson: With respect to the first line, the company supports your proposal with clarification. Do you have any objection to the company's clarifications there?

Jack Ihle: I would probably offer a clarification on top of the company's clarification in this box, Mr. Larson. Specifically, in response to the second sentence in that cell, "the size of the CKT portion compared to the overall bid cost must be reasonable," from our perspective, perhaps desired clarification around the word "reasonable." If I were allowed to redline this document, I would propose crossing out "reasonable" and replacing it with "accurate" based on current known rates. If a tariff rate is really high, to the extent some might call unreasonable, and a project comes in exposed to that tariff based on everything we know today, I'd want to know that. I wouldn't want that to be behind the scenes, especially if we're going to allow full pass-through of those costs. That's the one clarification I would propose from staff's perspective.

Matt Larson: Essentially, what you're saying is that it needs to be accurate with respect to the CKT component of the bid that comes in, with the CKT component being discreet from the bid component. Is that correct?

Jack Ihle: Correct.

Matt Larson: Moving to the second line, the company supports that. Any concerns with the company's comment in the far-right box?

Jack Ihle: No. We want to be supportive and not further delay the evaluation process, so I understand the company's sentiment on this and others along this line.

Matt Larson: In the third box, that's a recommendation, a subset of the piece in the second line. Do you see that?

Jack Ihle: Yes.

Matt Larson: The company supports this piece with clarification. Do you have any concerns with the company's major equipment clarification provided in a comment?

Jack Ihle: No major concerns. I'm wondering if there's a definition that can be established of major equipment. I don't know how easy that is, but we don't have major concerns with that response, Mr. Larson.

Matt Larson: From an implementation perspective, that definition could be loaded into the RFP that's ultimately provided ahead of the phase 2 JTS base phase 2 competitive solicitation. Correct?

Jack Ihle: It could, yeah.

Matt Larson: With respect to number two, which relates to countries of origin, the fourth line down in hearing exhibit 131, the company supports this piece with modification. Have you had an opportunity to review that modification?

Jack Ihle: Yes.

Matt Larson: Do you have concerns with limiting the number of countries for a country of origin for components if it aligns with the major equipment definition?

Jack Ihle: If it aligns with the major equipment definition, I wouldn't have major concerns with that limit.

Matt Larson: You would agree that the comment does draw a line between the number of countries and major equipment. Correct?

Jack Ihle: Can you repeat or clarify what you mean by a line between?

Matt Larson: I apologize. In the company's comment with respect to item two, fourth line down, it discusses both the number of countries and limits it to only major equipment. Correct?

Jack Ihle: Correct, it says that, yeah.

Matt Larson: The fifth line down is a support, so I want to move to the sixth line down, which relates to executed contracts or letters of intent. Do you see that, and have you had an opportunity to review the company's modification provided in the far-right column?

Jack Ihle: Yes.

Matt Larson: Do you have concerns with that modification? I believe you discussed this a bit with Ms. Kutzer as well as Mr. Detsky, but for clarity of the record.

Jack Ihle: I see this as a bit of a new sub-proposal from the company, building on what we proposed. I understand the IP concern about disclosing commercially sensitive data that may not be needed to substantiate a known tariff estimate on the project. I would be supportive of crafting a solution that respects that to the extent possible without diving too deep into the weeds at this time.

Matt Larson: Looking at strategies for tariff mitigation, line seven of the table, the company supports that with clarification. Do you have a concern with the clarification provided by the company on the far-right column?

Jack Ihle: I don't have a major concern with that clarification.

Matt Larson: The last line in the table on this page of hearing exhibit 131, the company opposes. Do you see that?

Jack Ihle: I see that.

Matt Larson: Your statement is that the independent evaluator and Public Service need to flag any questionable or incomplete CKTE and sourcing plans in initial screening. Do you see that?

Jack Ihle: I see it.

Matt Larson: The company proposes that it be a completeness review only and to have an outside consultant conduct that work, which circles back to some of the questions you received from both Kosia and CIA. Do you see that?

Jack Ihle: I see the company comments on that.

Matt Larson: Does staff have an objection to utilizing an outside consultant for this purpose?

Jack Ihle: We don't oppose the concept. I may be interested to learn more about whether it's just a completeness review, whether it's additional staffing or expertise behind needing a consultant, and how that motivates the search and selection of such a consultant. If some of the other things the company clarified above make a completeness review more robust—for example, proposing minimum requirements that staff didn't propose—then I could see how those work together to give us more confidence in the things we really want. Subject to those open questions, we could look at this being the right path forward on this proposal.

Matt Larson: To this point, you would agree that this could potentially chill the information that bidders provide out of concern that the company is going to see more detailed information about their bids than they might otherwise see. Would you agree?

Jack Ihle: I see where you're going, and I didn't connect those dots yet, but that could help alleviate competitiveness concerns. I agree.

Matt Larson: If we could go down to the next page, Ms. Federico. On both the top line and the bottom line of this page, the company supports your recommendations on both items. You see that?

Jack Ihle: Yeah, the first and the third on this page, correct.

Matt Larson: On the second item on this page, the company supports with modification. Do you see that, and do you have concerns or objections with the company's proposed modification?

Jack Ihle: I don't have major concerns. It's a slightly different approach, but if we're getting to the same need that staff had in proposing ours, I wouldn't have major concerns with a tweak like this. Maybe I'm interested in learning more about why the company thinks a modification like this is preferable to what we propose. I'm open-minded to it, but I'm not going to agree or disagree at this time.

Matt Larson: The company and staff are relatively close on this proposal. Would you agree with that characterization?

Jack Ihle: Yes.

Matt Larson: Ms. Federico, we can take this down. I want to move to two other items, one quickly and one in a bit more detail. They both relate to your surrebuttal testimony, hearing exhibit 2606. I don't think we need to pull it up, but let me know if we do.

Jack Ihle: Sure.

Matt Larson: In attachment SJD10 of hearing exhibit 2606, you provide new solution set scenarios for phase 2 portfolio development. Correct?

Jack Ihle: Yes.

Matt Larson: Ms. O'Neal is the correct staff witness to question on that particular attachment. Is that right?

Jack Ihle: Yes.

Matt Larson: With respect to CFFD, have you had an opportunity to review Mr. Tomjonovic's rebuttal testimony, hearing exhibit 119?

Jack Ihle: Yes.

Matt Larson: Would you agree that PSCO has essentially adopted staff's rolling approach to the CFFD in Mr. Tomjonovic's rebuttal testimony, with the exception of the removal of the budget?

Jack Ihle: Yes.

Matt Larson: Your position is that you want to retain the $100 million budget cap that was initially proposed when CFFD was a one-shot deal. Correct?

Jack Ihle: That's correct.

Matt Larson: Have you had an opportunity to review the review process that Mr. Tomjonovic lays out in hearing exhibit 119?

Jack Ihle: Yes.

Matt Larson: I'll represent to you that the first step is that the advisory board would file a project selection report coming out of each semiannual meeting with projects selected for funding along with the duration of that funding. Any reason to disagree with that?

Jack Ihle: Could you quickly repeat that? I don't want to slow you down too much.

Matt Larson: The advisory board is convened as part of the CFFD under the proposal. It would meet on a semiannual basis, and after each meeting, the advisory board would provide a project selection report that would show the projects selected for funding and the duration of that funding. Correct?

Jack Ihle: Yeah, this is all Tomjonovic's rebuttal proposal, correct.

Matt Larson: At that point, the commission would have 30 days to review the report and weigh in if it doesn't support funding one of the projects. Correct?

Jack Ihle: Correct.

Matt Larson: If the commission does not affirmatively act on project recommendations, the proposals would move forward and be funded. Correct?

Jack Ihle: Correct.

Matt Larson: The modified version of CFFD in response to your answer testimony has quite a bit more process than the original approach. Would you agree?

Jack Ihle: Certainly, the process is spelled out further. I don't know if his direct case proposal foreclosed this additional process, but it's definitely described in more detail in the rebuttal case.

Matt Larson: There's more opportunities and disclosure of CFFD projects under the rolling approach than under a one-time approach. Correct?

Jack Ihle: I would agree with that.

Matt Larson: A rolling approach is different than a one-time approach, right?

Jack Ihle: It is.

Matt Larson: Isn't it true that a budget built for a one-time approach might not be appropriate for one that's on a rolling basis over a series of years?

Jack Ihle: One of the primary concerns we had with the initial proposal was that all of this would have to be done in one shot by the phase 2 deadline, in parallel to a lot of other important things, perhaps straining staffing resources among the company, state, and other stakeholders. In response to the original case, we felt that stretching that out would be potentially prudent, which was behind some of our rolling approach and also a rolling approach that has a budget cap, as we countered in our surrebuttal. It doesn't foreclose the possibility of spending it all in one go if there's enough projects that the advisory group thinks should be funded right away and proposed to the commission. This is just another check-in guardrail that, once the initial budget is exhausted, regardless of how many meetings and proposals it takes, it requires another request to the commission to extend it if the company and others feel like doing so would be beneficial.

Matt Larson: Under the rolling approach, even in the absence of a budget cap, the commission has the opportunity after every semiannual report to step in and not fund a project if they start getting concerned about the overall level of spending in CFFD. Isn't that true?

Jack Ihle: I believe in your proposal, they would have 30 days to respond, and if they didn't, it would be effectuated. That's the opportunity you're referring to.

Matt Larson: One final question. Talking about hearing exhibit 144, the modified SJD9 showing the quad-party framework, given the interrelationship with that framework to your answer testimony, why does staff support the quad-party framework?

Jack Ihle: We think this is an important evolution in the resource procurement planning process here in Colorado. It gives us more flexibility, more checkpoints as we move forward in response to the difficult macroeconomic environment around us. It's not a silver bullet, but it changes things under our control to put us in a position to be better adaptable to things that are changing fast in a very uncertain manner on both the load and resources side. At its highest level, that's why we support it. I could go into details on each part if you wanted, but I'll stop there.

Matt Larson: I'm almost out of time, Dr. Ihle. I appreciate your time. Thank you, nothing further.

Jack Ihle: Thanks, Mr. Larson.

Eric Blank (Chairman): Thanks, Mr. Larson. Commissioner Gilman, questions for Dr. Ihle?

Megan Gilman: Good morning, Dr. Ihle.

Jack Ihle: Morning, Commissioner Gilman.

Megan Gilman: I just have a couple for you. Picking up on the CFFD that you were talking about with Mr. Larson, I understand from your surrebuttal comments that you still recommend having a budget cap. If that program is instituted and goes to a rolling idea, do you foresee $100 million as still being the appropriate budget cap, and if so, how would that be applied? Like the max committed at any one time, the max actually expended? How do you apply a budget cap to the rolling concept?

Jack Ihle: The way I understand the money-moving mechanics, Commissioner Gilman, is the budget cap would apply to stop once that cap has been cumulatively spent over time. In the first six months, if you fund $10 million or whatever, each time you spend the money, it's a cumulative accounting that would stop or require another request once the cap has been reached. It applies as the projects are funded after the commission approves each portfolio under the proposal.

Megan Gilman: Is there a possibility that one project gets a few tranches of funding, or do you see it as a one-time per project?

Jack Ihle: It could be worth having the company clarify how they think about that. My understanding is that it didn't contemplate projects coming back for more under this proposal. The concepts around the applications were described as getting a milestone payment schedule towards commercial development, getting them to the point where they could competitively bid in a future RFP. My understanding is that milestone schedule is proposed upfront. If there are multiple milestones, committing funding to a project commits the aggregate of the funds requested for each of those milestones, but the payments would go out once each milestone is achieved. It's a bit complex, and that would all apply under the budget cap. That's how I envisioned it working, but I acknowledge that perhaps some of those details weren't fully spelled out in the record.

Megan Gilman: That helps me understand. You would see it as the committed funds, even if you haven't hit those milestones and paid out the money. Whatever money is committed would go toward the budget cap you proposed. That's your assumption?

Jack Ihle: Assumptions can be dangerous, but that's how I was envisioning this working. I acknowledge that perhaps that wasn't fully spelled out in the record.

Megan Gilman: Just a couple of questions on the tariff pass-through concepts that you went over with a few of the different councils. To my understanding, this general concept is to provide better transparency and process about the very real possibility that dramatic tariff changes could impact the pricing need for projects, but to have better transparency about that upfront so that if that comes to pass, we'll have better information to act upon than perhaps we did in the delivery motion or things like that. Is that a fair understanding of the basis of what led to this?

Jack Ihle: It's one of maybe two key motivations behind it, but yeah, I would agree with that.

Megan Gilman: Would you expect the company, as a bidder, to be providing the same sort of disclosures in their bids as the IPs?

Jack Ihle: Yes.

Megan Gilman: My last question: since it seems like the main utility of the information would be if this comes to pass and we're getting requests for changes in price due to changes in tariffs or whatever—either the tariff changed or we had to switch country of product—I'm trying to figure out, given some of the competitive concerns from the IPs and disclosure of some of this information, is it possible that this information just goes to the IE or the IE and staff in the interim unless or until it's needed to be acted upon? Do you get my question, trying to address some of the IPs' concerns with maybe limiting this unless something needs to be done with the information?

Jack Ihle: I understand the question. One possible problem is that a lot of this information is something we want to have in pocket when we select projects. It's not just knowing it if costs change later; it's understanding, to the best extent we can, the uncertain risk profile with respect to tariffs for the suite of proposed projects that we have before us and making informed selection decisions based on that information. The information is valuable when the portfolios are selected, not just later when a change in project costs occurs if tariffs change.

Megan Gilman: To take that further, let's say we have two IP bids that look similar. It would be in someone's discretion, like the company's, to say we believe this one, based on this information, has a higher tariff risk and therefore would downgrade it in putting the portfolios together. I'm a little worried about the transparency of how this information will be used if it's used before any actual request to increase price because of what's going on. How can we better understand, in a transparent way, how it would be used, even qualitatively?

Jack Ihle: There's certainly a lot of qualitative aspects to sourcing risk. Under what we've proposed in this tariff bidding structure, in concert with my colleague, staff witness Aaron O'Neal's proposed scenarios, we would take the tariff component of bid costs in the scenarios and offer an additional scenario that explores a change in the tariff regime to get some quantitative insight into what that risk profile looks like. Under the framework, you get the cost attributed to tariffs, likely a dollar per megawatt-hour number. Our phase 2 scenarios proposal allows the ability to explore a scenario where tariff rates go down if we feel these tariffs are still pretty high when we get the bids. We can see how that impacts project selections. If there are projects with lower tariff costs that show up in both scenarios, we know that's pretty robust. If there are projects that look good if tariffs go away but aren't so good with current tariffs, that's when we take a closer look. The motivation behind our proposal is to think about those trade-offs and do the best we can in this tough environment. That's some detail around how the cost components attributed to tariffs can be useful in the selection phase, not just later if tariffs change and projects need to update their costs.

Megan Gilman: That's helpful. I'll try to fill in some of the color with Ms. O'Neal regarding how that portfolio might be structured and what assumptions would have to be made. I'll save some of that detail for her. In keeping with what goes on in the bidding, do you anticipate the company doing anything to qualitatively rank or discount certain bids based on this information? I'm a little confused if that might happen and, if so, how do we have transparency around what happens there?

Jack Ihle: Some of the company's comments on exhibit 131 could be viewed as helpful to that extent because they move certain aspects of our proposal, which were qualitative and perhaps undefined, towards minimum pieces of information to designate a bid as complete from a tariff-checking perspective. Subjecting that completeness review to a third party gives me a little more confidence, as long as this minimum set of requirements gets us what we need and isn't overly burdensome or unlevels the playing field in a way we're not anticipating.

Megan Gilman: Thanks, those are my only questions, Dr. Ihle.

Jack Ihle: Thank you.

Eric Blank (Chairman): Thanks, Commissioner Gilman. Commissioner Plant?

Tom Plant: Thank you. Good morning, Dr. Ihle.

Jack Ihle: Good morning.

Tom Plant: I just had one quick question related to the SRRF. The company's position was committing a certain amount of money, hundreds of millions of dollars, to the acquisition of various resources in anticipation of development. Staff's position was more about basing it on a certain amount of capacity rather than money. We've also heard from some intervenors and public comments that those expenses should fall with the investors as they're preparing plans for development, making certain investments before those resources are useful, and then becoming part of the rate base. I wanted to get your perspective on those three different approaches.

Jack Ihle: Thanks, Commissioner Plant, for the question and opportunity to respond. At a high level, staff is in a similar place to where we were in our answer testimony on the SRRF proposal, which can be described as having significant concerns, not sure exactly what the need is in a defined, specific way, sympathetic to the challenges around sourcing key equipment and lead times, but the record that has developed since then hasn't fundamentally changed that.

To unpack that a bit, the flexibility the company wants with that budget cap gives them a lot of leeway to do anything they deem needed, like manufacturing slot reservations or paying cash for a whole turbine. We also heard one of the company witnesses mention they recently scooped up a few reservation slots that GE contacted them about and they took. Those things raise questions regarding the need. Do those new slots cover the need we have in Colorado for this JTS? Who are those slots for, and where are they? What would be nice to evaluate the need behind this proposal is the company's estimate of capacity need, which we have in this case, some thoughts around what equipment may or may not be needed to meet that need, and the timing of getting that related to the slots they have now. Perhaps, as part of its normal course of business, the company reserves slots at a corporate level. I don't know the answer to all these, but significant pieces haven't been tied together or provided to give me confidence that this is helpful versus adding money to things they already will be doing in response to projects they expect to be needed.

Those are our major concerns. I want to qualify that it's a tough environment to get equipment, and I'm sympathetic to that. That's the driving need that started this conversation. I just don't think we're at a point with this proposal that gives me confidence it helps relative to what we otherwise did. There are tools under the PUC rules to bring projects out of cycle or start developing projects out of cycle if the company believes there's a discrete need that can't be met in time for the phase two we have in front of us, like a standalone CPCN amendment to the prior ERP. There's a lot of questions from staff, and not a great answer, which is why we're still opposed to the proposal as it stands.

Tom Plant: I understand. Thank you, I appreciate that clarification. That's all the questions I had.

Eric Blank (Chairman): Thanks, Commissioner Plant. Dr. Ihle, several parties have raised concerns that current rates may not result in outcomes in the public interest in terms of calculating and fairly allocating the costs and benefits of integrating large new loads into the system. Given that the company has agreed to submit an advice letter filing by January 2026, would you have any advice or guidance about what model runs or other analysis should occur between now and that advice letter filing to ensure there's an adequate record to address those concerns?

Jack Ihle: I've listened to various conversations throughout the hearing. What I've heard is discussion around doing additional generic modeling, Encompass modeling runs that explore resource needs under the existing Encompass model design with and without various new loads to get a sense of the incremental cost of those load additions. Correct me if you're talking about other things, but that was the most specific.

The Encompass model, these are generics, not real projects, but it can give insights. It's designed decently to give good insight into incremental generation costs. It's not, as currently constructed, a great tool on its own to give a sense of incremental transmission costs. There was discussion around linking different types of tools together, which could help, but it's still clunky. Encompass alone can give good insight into incremental generation costs, but those scenarios can be limited for other incremental costs from transmission or other needs for large loads.

Eric Blank (Chairman): To the extent current tariffs may not fairly allocate costs and benefits of large new loads, are you concerned about the company signing 15-year contracts with no PUC review that may lock in existing customer class structures prior to the resolution of the January 1, 2026, advice letter filing?

Jack Ihle: I do have concerns with that. The principles we've discussed hopefully provide protections in those contracts, but there's commercial flexibility around their implementation, so it's not a full-stop thing. I agree with you at a high level and would encourage you to punt some of that discussion to my colleague, Ms. O'Neal, who has done a lot of work over the years and knows more than I about rate allocation.

Eric Blank (Chairman): Just one follow-up on the transmission question. Mr. Riley testified that transmission investment in the original direct testimony base case was $13.5 billion through 2031, while the load case transmission spending was $12.8 billion, suggesting that almost 95% of the transmission capital spending was independent of large new load growth. At the same time, a series of Public Service Company witnesses acknowledged there was no detailed line-by-line capital spending plan outlining the basis for the size of these transmission investments in either the base or low-case scenarios. Given the lack of detail, do you understand the basis for the company's assertion that one might expect the load case without 1895 megawatts of large new load to require basically the same transmission as the base case? Any thoughts or comments on that concern that transmission spending seems largely independent of these large new loads, even though there's really no detail on a decent part of what that spending is?

Jack Ihle: I understand the lack of detail. I would observe that that outcome is roughly consistent with what we've seen in a microcosm related to the near-term potential transmission needs outlined in the JTS transmission portfolio submitted in this case. Mr. Marge testified in those transmission studies looking at a wide range of bookends, and the output is very similar levels of transmission needs and costs across all different portfolios. That one has some specific projects, but I can't fully understand why that's the case beyond comments attributing this more to generation. There's potentially a need and opportunity to dig further into those studies and understand what's driving them, perhaps related to load. Ms. O'Neal is our witness on the transmission study and related recommendations, so she can provide more details than me.

Eric Blank (Chairman): Just one last question on tariff language in the C Delivery Plan. This commission declined to permit project-specific contract modifications and decided to adjust price across all projects on a technology-specific basis to avoid delay, ensure fairness, and simplify the process. Do you recall that? I forgot when you came back, but you might be familiar with that at a very high level.

Jack Ihle: I wasn't around or involved in that case in detail, but I understand the outcome as you described it.

Eric Blank (Chairman): My question to you is, should we do something similar with these contracts? More specifically, what would you think about general model contract language that allowed an LD adjustment or price increase for tariff, supply chain, change of law, or tax credit issues that impacted all projects, subject to a cap and PUC approval, like we did with stage two of the C Delivery Plan? This would allow for PUC-approved price and LD waiver flexibility across all projects, maybe by technology, but not project by project, in response to certain events outside of all developers' control, both UOG and IP. What do you think about that approach? It would avoid delay, ensure fairness, and simplify the process. Any thoughts on that approach?

Jack Ihle: It's certainly useful to think about this stuff ahead of time so we're not caught flat-footed if and when things happen. We've proposed a more detailed mechanism as it applies to tariffs. We submitted our cross-answer testimony when tariffs on things from China were 135%, with the possibility in mind that these things are highly uncertain and very impactful. We don't want to roll the dice, but we want to be able to adapt if and when they come down, and frankly, hope they don't increase further. The targeted pass-through mechanism we've proposed on tariffs allows those benefits to flow through. It removes that risk from the base costs of the project, so it lowers the project costs, not considering tariffs, lower than they otherwise would be. If tariffs go down, we have a mechanism to pass those savings on to customers. That was an important component. Tax credits were starting to get on our radar when we finalized cross-answer, and now it's more in a real way. At a high level, I hear the benefits, and the delay risk you're articulating is important. I'm also concerned about deciding this in a way that allows bidders to take that into account when they provide their bids. To the extent you can minimize the gaming of the bids, that's a concern. If they know right now they're going to get a blanket possible increase, some of that is built in, but doing that at a large scale will increase the problem that we're getting bids that know they can activate this relief later. They might be less upfront in the hopes they can get selected and then use that relief later to get what they need. Isn't that a lot more likely in a project-specific approach?

Eric Blank (Chairman): What I'm suggesting is that we put contract language into a form contract, and the only way there's a price increase is if the commission approves it for all bidders going forward. It seems like that risk of gaming is a lot more likely if you allow project-by-project adjustments based on whatever country somebody sourced the equipment from. It seems to me we should be treating pretty much everybody the same. Just curious about your thoughts on that thinking.

Jack Ihle: If we, in a credible way, articulate now before the RFP that projects can get relief up to 10% from a variety of things—this is just a hypothetical number, maybe you said a number, I forgot if you did—

Eric Blank (Chairman): I did.

Jack Ihle: Okay, so let's say it's a number. Whether that's applied to specific technologies or blanket across all the bids, it wouldn't surprise me if that gets baked into the bid. Maybe there's a bit of risk-sharing depending on the appetites, but I would expect all the bids to come in, maybe not all the way to 10%, but some of them certainly could, knowing they can get that later by coming up with some reason from the list you described. But it would only apply to all bids, and it would have to have PUC approval. I wouldn't be surprised if all the bids applied that coming in. That's still my concern. You may see a way out that I'm not seeing, Chairman, but I also want our process to accept and reflect the fact that different technologies, projects, and sourcing strategies have different levels of risk exposure to these possibilities and reward those that, all else equal, are hedged better. Your proposal doesn't obviate that, but if it's too blanket and too general—and I'm not saying what you said is too blanket—but if you go to that end, then I might be sad if it didn't contemplate that some projects might be better bets in this current risk environment than others based on where they come from and what the equipment is.

Eric Blank (Chairman): That's all I have, Mr. Cox. Redirect?

Mr. Cox: Thank you, Chairman. Just a few questions for you, Dr. Ihle. We spent a lot of time on Hearing Exhibit 131 and discussion of the PAR proposal, and we were just discussing here as well. Back to Hearing Exhibit 131, did you participate in the preparation of that document?

Jack Ihle: No.

Mr. Cox: Did the company confer with you about that document before submitting it in the hearing?

Jack Ihle: No.

Mr. Cox: Miss Kutzer asked you about your response to the company's response to your tariff proposal. You mentioned the need for further clarification or modification. Do you recall that?

Jack Ihle: Yeah, I think there were a few categories of things in that vein, yeah.

Mr. Cox: You went through the document with Mr. Larson, but are there any additional clarifications or modifications regarding Hearing Exhibit 131 that you'd like to share?

Jack Ihle: I think maybe just take the opportunity to rearticulate two key things that I see at this point that staff probably would want further clarification on before accepting. All of this is subject to further clarification when we write up our SOP. Leaning on the point you made, Mr. Cox, this is still a pretty new document that we didn't co-develop. I do want to stress the importance of, when the company proposes that the bid cost must be reasonable, reasonable in our mind doesn't mean low, it means accurate. If a battery project, for example, is subject to 135% tariffs when it's bid in under current known rates, if it were delivered under the plans provided, we would want to know that. I think we don't have those tariffs right now, as far as I understand, but many people could reasonably say that a 135% tariff on a piece of equipment is unreasonable. But that's not in our control, so we want to know what we're signing up for. If reasonable means accurate, we're on board. If reasonable means inaccurately low, then we oppose. The other one is, I think we just want to think a little bit more about what the minimum documentation could and should be, in line with competitive concerns. I do want to extract the key pieces of information related to sourcing and applicable tariffs that can be verified in that documentation to the extent possible, while acknowledging that some projects may be at different stages of development and firmness of their sourcing agreements. That doesn't necessarily in the past automatically disqualify a project, but we can take that into consideration. Those are the two key categories of things that we may want to clarify and reflect further on before writing them up in our statement of position.

Mr. Cox: You talked with Commissioner Gilman about her concerns about what the company would do with the tariff-related information upfront in potentially selecting projects or, she used the word, discount projects. Do you recall that?

Jack Ihle: Yes.

Mr. Cox: You discussed the modeling scenarios, but are there multiple factors that would go into the determination of the portfolio that the commission would eventually choose?

Jack Ihle: There definitely are. They may consider other things: emissions reductions, geographic diversity, risk profile, etc., all of that through the modeling in phase two and related selection decisions.

Mr. Cox: Is it your view that the tariff proposal here, including the modeling scenarios, would be one additional factor for the commission to consider?

Jack Ihle: That's right.

Mr. Cox: Moving to the CFFD proposal, there was some discussion regarding the $100 million budget cap. Do you recall that?

Jack Ihle: Yes.

Mr. Cox: Could you expand a little more, provide clarification about why you believe the budget cap is still needed?

Jack Ihle: Thanks, Mr. Cox. In addition to the motives and reasons I gave in response to other questions, we thought through and had a concern related to the makeup of the advisory group. We're not opposed to the proposal of the advisory group, and we're not recommending specific changes, but as currently proposed, I believe there are eight members: staff, UCA, CEO, an environmental perspective, two community perspectives—one from Pueblo and Hayden, I believe, subject to check—the Office of Just Transition, and the company. That leaves eight. There are some coalitions of simple majorities within that that could occur on projects that aren't necessarily bad but would motivate me to have a cap in addition to the other checks. Just so you know, it doesn't hurt, I don't think it'll slow down or take away the value of the program. But looking at it from a simple customer perspective, there are majorities within that advisory group that aren't solely focused on representing electricity consumers. I'm not suggesting it'll go one way or another; given the makeup, we thought a cap would be a prudent additional guardrail.

Mr. Cox: Thank you, Dr. Ihle. That's all the questions I have for you.

Eric Blank (Chairman): Thank you, Dr. Ihle. Thanks for joining us. You can be excused.

Matt Larson: Apologies, coming in out of order, Mr. Chairman. The company is prepared to waive Mr. Iden, who's going to come on after lunch. I believe we're the only cross-examination for him, so sorry to step in. We reviewed our notes and don't have any questions for him.

Mr. Baraso: Oh, well, hold on, let me check. Miss Concia?

Eric Blank (Chairman): Well, let me finish this. Commissioner Gilman, do you have any questions for Mr. Iden?

Megan Gilman: I may. I'll let you know after lunch, but I'm not prepared to let him go just yet.

Eric Blank (Chairman): So we will not excuse Mr. Iden quite yet. Miss Concia, your honor, I was wondering if you could share with us whom you think will be called this afternoon. I'm hoping it's not Jeff Shaw because he's got some business commitments. He is available tomorrow morning.

Eric Blank (Chairman): We will not call Mr. Shaw until tomorrow morning and work around his schedule.

Miss Concia: Thank you.

Eric Blank (Chairman): Miss O'Neal, are you out there? This is Harriet. Given that we started at 7:30, do you think we could take an early lunch? It's 11:54, we're pretty close, and it's been a long four and a half hours for all of us.

Miss Wisenthal: I bet, yeah. Let's take a 45-minute break till 12:30. Thanks, all.

Mr. Baraso: Just confirming, will we be coming back with Mr. Iden at 12:30, or are we taking Miss O'Neal first?

Eric Blank (Chairman): Let's do Miss O'Neal first, finish the staff case, and then we'll go to Mr. Iden next. By then, Commissioner Gilman will let us know if she has any questions for Mr. Iden. Commissioner Plant?

Tom Plant: I do not—

Eric Blank (Chairman): Sorry, were you saying you would have Mr. Iden on the stand after Miss O'Neal, or we would just answer the question on if he's off the hook?

Mr. Baraso: We'd ask, answer the question if he's off the hook first. We'll go through Miss O'Neal, and then we'll go to Mr. Iden if that works for you.

Eric Blank (Chairman): Yeah, I didn't understand he was going out of order. Is that the plan?

Mr. Baraso: Yeah, he's only available today, so we talked about taking him first thing after lunch. The company has now waived their cross of him, so we're trying to decide if we can excuse him or not.

Eric Blank (Chairman): Thank you. Sorry, Commissioner Plant. See everybody at 12:30. Maybe I'll swear you in, Miss O'Neal, while we're waiting for your counsel.

Erin O'Neal: Sure.

Eric Blank (Chairman): Can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Erin O'Neal: I do.

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

Erin O'Neal: No.

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

Erin O'Neal: I will.

Eric Blank (Chairman): Back to you, Mr. Cox.

Mr. Cox: Thank you, Chairman. Good afternoon, Miss O'Neal.

Erin O'Neal: Good afternoon.

Mr. Cox: Could you please state and spell your name for the record?

Erin O'Neal: My name is Erin O'Neal. First name is Erin, E-R-I-N. Last name O'Neal, O-apostrophe-N-E-I-L.

Mr. Cox: By whom are you employed, and what is your title?

Erin O'Neal: I am employed by the Colorado Public Utilities Commission as a deputy director of fixed utilities.

Mr. Cox: Did you cause to be filed in this proceeding answer testimony, including attachments marked as Hearing Exhibit 2601?

Erin O'Neal: Yes.

Mr. Cox: If I asked you the questions contained in your answer testimony, would your answers be the same?

Erin O'Neal: Yes, with one minor edit.

Mr. Cox: Miss Federico, if we could pull up what's been marked as Hearing Exhibit 2601 Rev One, staff box. Miss O'Neal, is this your answer testimony?

Erin O'Neal: It is.

Mr. Cox: We can go down to page 71. Can you briefly summarize the changes proposed here in the red lines?

Erin O'Neal: In reviewing my testimony, I realized that for both tables ETO9 and ETO10, the label indicated that it was total accredited capacity in that third row, and that's inaccurate. Those are actually reflecting the total nameplate capacity. It's a similar edit to table ETO10, which I believe is on page 74. Those are the only two changes to my testimony.

Mr. Cox: Staff would move to admit the public and highly confidential versions of Hearing Exhibit 2601 Rev 1. Any objections?

Unknown Speaker: No objection.

Eric Blank (Chairman): Hearing none, so moved. We can take that exhibit down. Thank you. Miss O'Neal is available for cross-examination. I forget, is the company going first, or is Kosa going first?

Mr. Cox: I believe Kosa is going to go first, Mr. Chairman. Are you going last on all witnesses or just staff witnesses?

Unknown Speaker: Yes, sir, that would be our preference to go last on all witnesses.

Eric Blank (Chairman): All right, Miss Good, five minutes.

Ellen Kutzer: Thank you, Mr. Chairman. This will be relatively quick and painless, Miss O'Neal. It's nice to see you.

Erin O'Neal: Nice to see you too, Miss Kutzer.

Ellen Kutzer: I have a few questions regarding the now Quad Party settlement. If we could maybe have that available, I think the most recent version is now Hearing Exhibit 145. Miss O'Neal, were you present when company witness Mr. Martz was being cross-examined?

Erin O'Neal: For most of it, yes.

Ellen Kutzer: Great. I have a few clarifying questions as to staff's position on the new settlement agreement on Hearing Exhibit 145, term seven, where we're conducting a small stakeholder group on transmission cost assumptions. Do you generally remember that provision in the framework?

Erin O'Neal: I do.

Ellen Kutzer: Do you need it to be pulled up, or are you okay answering some quick questions without it being on the screen?

Erin O'Neal: I think I'm okay answering questions without it being pulled up.

Ellen Kutzer: Great. It was unclear to me after cross of Mr. Martz as to what that small subcommittee is planning to focus on, more specifically, if that small group is making adjustments to the company's transmission adder as well as its transmission credit. I just love your perspective on what you expect to come out of that stakeholder process.

Erin O'Neal: Part of why it's vague is that the exact scope of that stakeholder process is what we agreed to. Exactly all of the things that will be covered in there is still somewhat open to discussion. On the transmission adders, it's staff's position that we haven't changed our recommendation from our answer testimony, which is that we think it would be appropriate to treat the approximately $1.9 billion line, the new Harvest Mile double circuit line, as a fixed cost and have a much smaller variable cost. I believe it is still the company's position that the entirety of those transmission costs be treated as a variable cost. Staff did have a backup position that if the commission wanted, it could try to have the stakeholder group address that, but that is not staff's primary recommendation. Our primary recommendation is to have that transmission adder decided here as part of the phase 2 process. On the transmission credits, it's slightly more nuanced. Staff's position is that the analytical support for the calculation of the transmission credit was not robust enough. We're supportive of the process of comparing transmission portfolios to try to understand the benefits of distributed resources located in the Denver metro area, but the actual analytics performed by the company were insufficient. The commission should adopt the basic methodology of comparing transmission outcomes, but the company should do additional transmission modeling to fix some of the deficiencies that staff identified in our answer testimony. So slightly different perspectives on adders versus credits. The rest of the scope of that stakeholder group, I think, is fairly well agreed upon that the intent is to move toward identification and hopefully having CPCN applications come out of that process that would support the portfolios in this proceeding. Staff is also interested in some additional modeling of transmission drivers and insights, similar to what the chairman was asking Dr. Ihle about earlier, a lack of understanding of some of the longer-term drivers for transmission costs. That could be a potential venue to explore some of those ideas.

Ellen Kutzer: One last question. To the extent that that small group comes up with any recommendations as to adjustments to the transmission adder or the transmission credit, how do you envision that to be introduced into the record, and do you expect there would be an opportunity for written feedback on those findings?

Erin O'Neal: That's a great question. I think what we had envisioned is those updates occurring similar to the way the company updates its load forecasts or updated its generic resource pricing. There are certain things that get updated right before the RFPs go out or as part of phase two. The intent was to do something similar here, to provide a notification of the final methodology or decisions, and there would be some ability for folks to comment if they had concerns with those updates.

Ellen Kutzer: Thank you, Miss O'Neal. All the questions I have for you. Thank you, Mr. Chairman.

Eric Blank (Chairman): Thank you, Miss Kutzer. Mr. Larson, 20 minutes.

Matt Larson: Thank you, Mr. Chairman. Good afternoon, Miss O'Neal.

Erin O'Neal: Good afternoon, Mr. Larson.

Matt Larson: For the record, Matt Larson on behalf of Public Service. I just have two areas I wanted to discuss with you today. First is the transmission adder, very briefly, and then I want to talk about attachment SJD10. Dr. Ihle said you're the appropriate witness to discuss the portfolio presentation. If we can start and maybe it's helpful to pull up the document, if we go to Hearing Exhibit 2601 Rev One and go to page 72. I'm focused here on lines one through eight of your answer here at the top of page 72. My question based on that is this: all else being equal, a higher transmission adder is going to produce a smaller portfolio, isn't that true?

Erin O'Neal: A higher transmission adder will increase the costs, and therefore the model will be less likely to—sorry, I'm making that more complicated than it needs to be. All else equal, a higher transmission adder will likely result in a smaller portfolio by nameplate capacity.

Matt Larson: Part of what a higher transmission adder could do is deter the model from selecting higher amounts of energy-only resources that are not needed to meet capacity needs, isn't that true?

Erin O'Neal: I think you're imputing a lot of information to the transmission adder. The transmission adder will tend to favor portfolios that have higher nameplate capacity, higher ELCC projects, but in staff's view, it is not an accurate reflection of the actual transmission costs associated with such resources.

Matt Larson: I understand we have a disagreement about the value of that adder. I'm just talking about the functionality of that adder. My question is that it could deter the model from loading and stacking on energy-only resources, as we've seen in the past, isn't that true?

Erin O'Neal: The flip side of that, Mr. Larson, is that it could encourage the model to pick high ELCC gas and storage resources in order to avoid a fictitious variable cost. Yes, it could do what you're saying it would do, and the flip side is the opposite: it will pick high ELCC gas resources based on faulty economics.

Matt Larson: Part of it could be managing the size of the number of energy-only resources that are put within a portfolio, correct?

Erin O'Neal: There's a distinction between what the modeling will report and what actually occurs in terms of costs. Having a higher variable cost associated with the transmission adder will tend to have the model select smaller portfolios and portfolios that are heavier on high ELCC resources, but that's different from actually saying that you will have avoided transmission costs when you do that.

Matt Larson: If we could flip to attachment SJD10, Hearing Exhibit 2606. Miss O'Neal, can you see that okay?

Erin O'Neal: I can.

Matt Larson: Just a few questions. I'm focused on the far right here. As I understand it, as part of the staff rebuttal case, staff has now proposed 14 different portfolio presentations and then the four alternatives at the very bottom, is that right?

Erin O'Neal: That's correct.

Matt Larson: Two of those are checkpoint cases, reflected number one and number two, right?

Erin O'Neal: Staff doesn't love the term checkpoint, but yes, I think we are aligned on what those cases are structurally, maybe not as aligned on exactly what they're for.

Matt Larson: Nomenclature notwithstanding, they have no constraints within them for purposes of modeling from an emissions perspective, correct?

Erin O'Neal: Correct.

Matt Larson: Then you have two informational LCPs, which are three and four, correct?

Erin O'Neal: Correct.

Matt Larson: Then four ownership cases, which are five through eight, right?

Erin O'Neal: Correct.

Matt Larson: These eight generally match PSCO's proposal, correct?

Erin O'Neal: With one minor difference, which is a long-term emission reduction assumption. We reverted a little bit back to what you had proposed in direct testimony in terms of having an assumption of a linear decline in emissions until you get to 2050, as opposed to having no constraint after 2030. Otherwise, those scenarios are essentially constructed the same way the company had proposed for their solution set.

Matt Larson: I saw that. That's actually one of the questions I had. For portfolios five and six, which are the ownership 80% by 2030, 100% by 2050, why are both of those linear, but then the 90 cases are not linear? We were curious about the logic behind that if you could provide any additional information.

Erin O'Neal: Happy to. Our logic there is that it is difficult for us to imagine a world where, for 20 years between 2030 and 2050, Colorado makes no incremental commitments on further reductions in CO2 emissions. Nobody knows what new statutes or requirements will be put in place, but it seemed unrealistic to assume there would be nothing after 2030. That was our preference for the 80 by 30 cases to have a continued linear reduction after that. For the other two cases, there is an incremental reduction, which is the 90 by 2033. That seemed like an acknowledgment that there is an expectation of additional emission reduction requirements for the state after the imminent 2030 goal. That satisfied the condition that there is something that happens after 2030, either the linear reduction or the 2033 requirement.

Matt Larson: With respect to portfolios 9 and 10, if I understand these correctly, these are variations on the accelerated emissions reduction cases, and they have an 86% target in 2030, is that right?

Erin O'Neal: That's correct.

Matt Larson: The social cost of carbon would be utilized in both of those cases, is that right?

Erin O'Neal: Yes.

Matt Larson: Why?

Erin O'Neal: Those cases in our minds were intended to provide a bookend of a more aggressive pressure being put on CO2 emissions. If that's the intent of those cases, to understand how much we might be able to do and what the cost of that would be, those cases are constructed to put maximum downward pressure on CO2 emissions. It seemed appropriate that both would include the social cost of carbon as part of the decision-making in those cases. They're intended to be bookends, applying as much downward pressure on CO2 emissions as we can and understanding the costs of those pathways.

Matt Larson: The 86% comes from the value of the approved clean energy plan, correct?

Erin O'Neal: Correct.

Matt Larson: I'll represent to you that Public Service would agree to that 86% in select cases like this one. Given that, across portfolios one through 10, staff and the company are relatively close in terms of the content of these portfolios, correct?

Erin O'Neal: Good to hear, Mr. Larson. I think the intent was to have a great deal of alignment between portfolios that you had recommended and ones that we think have value. We're also recommending the same number of portfolios.

Matt Larson: I want to talk about 11 to 14 in a moment, but we have 14 portfolios on the PSCO side, staff has 14 portfolios on the staff side, isn't that true?

Erin O'Neal: That is true.

Matt Larson: On 11 to 14, there's this notion of match PP, which I assume means match preferred plan. We looked at the note associated with this, but can you describe the process you're envisioning for match preferred plan but then testing these four futures?

Erin O'Neal: It's our assumption and understanding that the portfolio the company will ultimately identify as its preferred portfolio will be one of the company ownership cases, but we do not know which one—whether that would be numbers five, six, seven, or eight under staff's listing. It's unclear at this point which one of those four would ultimately be brought forward by the company as its preferred plan. In the interest of trying to get more insight and understanding of that preferred plan, but also to be careful not to overuse analytical support, the idea behind portfolios 11 to 14 would be that they would be based on whatever the company actually brings forward as the preferred plan. Say the company's preferred plan is number eight, assuming modeling with social cost of carbon and an emissions constraint of 90 by 2033. That would form the basis, the base plan, and scenarios 11 to 14 would be variants of that. There would be a test of having slightly less company ownership constraint around that specific portfolio, having a lower gas requirement or constraint around that portfolio, so we're testing the company's preferred plan to get more insight into that specific plan and how much different variants change the cost and dispatch of that system or portfolio. But also not to create solution sets which are four times everything. We're trying to be circumspect with our analytical time and energy.

Matt Larson: Let's take low company ownership as an example. Let's say we're in portfolio number eight as Public Service's preferred plan. I want to see if I got these steps right. We would lower the ownership constraint, but then it would be a full reoptimization based on all the bids that are eligible for computer-based modeling, not some subset of the bids. Is that the correct way to think about it from your perspective?

Erin O'Neal: That's correct, but again, that scenario is constructed the same way as the preferred plan, so with the social cost of carbon on a 90 by 2033 emissions path, just one variant off of that. It wouldn't trigger four variants off, just reoptimize that constructed case with lower company ownership constraint instead of the 50%.

Matt Larson: Can you briefly describe how the no tariff cost or the alternative tariff case would be run? Let's use the same example where portfolio number eight is the company's preferred plan.

Erin O'Neal: The intent is that, assuming staff's recommendation is adopted where bidders are identifying the tariff costs included in their bids as specific separate costs, a no-tariff case would be intended to understand how much a portfolio cost would change and what bids might change if you reoptimized assuming there were no tariff costs. Rerun the bids, take out the tariff costs that were included as a separate line item, and reoptimize that portfolio to understand how much costs are being associated with the tariffs and whether different resources would be selected if those tariff costs were to go away. The second tariff alternative, number 14, is intended to be a similar test but a little dependent on the starting point. It's a little unclear sitting here today if we're going to be in a high tariff or low tariff regime when you come to actually doing the phase 2 modeling. We've seen tariffs range pretty widely in the last couple of months. The intent was to have some discretion that says if the background tariff rate is relatively low, 10% level, then maybe you run a case that doubles that to understand the risk of an increase in the tariff cost after the time of bidding. Take whatever was identified as tariff costs, double those costs, reoptimize, see what difference that makes. Vice versa, if you're in a high tariff regime and want to understand what the impact of having a somewhat lower regime would look like, you would halve those tariff costs and rerun it. It was an attempt to quantify and understand how much difference it makes to the resources selected and the overall cost of the portfolios.

Matt Larson: In terms of implementation of this, in the no-tariff cost run, is it your view that we would simply take the CKT component of each bid, pull that off, and then reoptimize without that CKT component in there? Is that how this interrelates with Dr. Ihle's staff pass or the tariff pass-through?

Erin O'Neal: Yes, that's correct.

Matt Larson: Same thing for the alternative—either take the CKT value, cut it in half or 2x the CKT, reoptimize again?

Erin O'Neal: Correct.

Matt Larson: Thank you. That's all the questions we have. Appreciate your time.

Erin O'Neal: Thank you.

Eric Blank (Chairman): Commissioner Gilman.

Megan Gilman: Good afternoon, Miss O'Neal.

Erin O'Neal: Good afternoon.

Megan Gilman: I have a few questions, hopefully in some order that makes sense, but it's all good. Some questions about portfolios. We might as well look at that exhibit we just had up, attachment 10. You talked with Dr. Ihle about staff's recommendation to use the tariff information to run a portfolio, which I think here is like 13 and 14 in some variation. Is that fair?

Erin O'Neal: That's fair.

Megan Gilman: Help me understand what I'm looking at. The no-tariff costs—there are already some tariffs probably going to be baked into the bids, right? There are tariffs today, presumably, but who knows?

Erin O'Neal: That would be the execution, right. The intent was to be no tariffs. Putting this in context with all of staff's recommendations, we're recommending that bidders provide information specifically about what tariff costs are included in their bids. This would be to take those costs out and reoptimize and say there's uncertainty around the tariff costs, whether they go up or down, and also just trying to get a better understanding of how much of the costs of the portfolios is being driven by those tariffs. Take all those costs out entirely. It's not just a no-new-tariff assumption, as you said. That would be the base—the tariffs will be whatever they are when those portfolios are being run. This would be to take all those costs out and reoptimize.

Megan Gilman: As opposed to all the prior portfolios listed in staff's rebuttal, which would include whatever tariffs were disclosed as part of the total pricing at the time they were bid, right?

Erin O'Neal: Correct.

Megan Gilman: Then 14 would somehow alter the tariffs to test a case where tariffs change?

Erin O'Neal: That's right. A few months ago, when we had 140% tariffs on China, I would have argued we should look at a case that's maybe half the tariffs case. As we sit here today, those Chinese tariffs have come down a fair amount, so maybe there's more value in rerunning a high-tariff case where we're doubling the existing tariff costs. The point is to understand how much difference it makes, whether there are projects that show up in all of those cases, which ones get traded out for which other ones. It provides information to the company and to parties such as staff to look at that and say, is there some project here that looks to be less or more sensitive to tariffs that would be included or excluded from portfolios across the range of tariff looks? So we have some sense of which ones of these projects have more inherent cost risk associated with them. Looking at this holistically with all of staff's case, we're arguing there should be some process for price relief associated with tariffs as something beyond the control of bidders. If there are projects that are less sensitive to those tariff costs and represent less risk to ratepayers, it would be nice to understand that. That's part of what we're trying to do here, given this moment in time, tariffs are a potentially big price driver and big determinant of these portfolios. It would be helpful to have some analytics to understand the order of magnitude and relative risk across projects from those tariffs.

Megan Gilman: Is it your understanding that these variations that go into portfolios 13 and 14 are more or less the universe of what the company is doing with that information, or are they doing some other undefined ranking, exclusion, promotion that we don't have information about?

Erin O'Neal: It is not my expectation that they would be doing that. The analytics—this is the point of phase one, to establish these analytics. It's why they report on things like generic pricing and their load so we can all understand in as robust a way as possible the underpinnings to the quantitative analysis. Would it be helpful, similar to a BBEM metric, to have information that ranks the proportion of a bid that is a result of tariff costs? I think that would be helpful information for the commission and interveners to have. In terms of the analytical process of modeling and Encompass, it is not my expectation that that information is being used elsewhere. That's the point of these cases, to have that analytical look at it. But just like the reputation of a bidder, parties, including the commission, have discretion to look at these things holistically and try not just to do least-cost planning but to take into other nonquantitative factors as well. The company should model quantitatively, and this is the point of phase one, to set out all that quantitative analysis. The commission and other parties and the company have some discretion to argue that certain things make sense based on qualitative factors if they can carry their burden to demonstrate why that's better in the public interest.

Megan Gilman: Thank you for that. I hope this is my last question on tariffs. Since tariffs are set potentially on a per-country basis, presumably goods are coming from a number of countries. There may be predominant suppliers, but how do you go about testing the assumption on, like, maybe it doubles, maybe it halves, whatever that ends up being, when really the exposure could be very different depending on what country? The details matter, and so just testing every portfolio by the same multiplier might be a very rough way to do this.

Erin O'Neal: I agree with that. There's still information content in doing it that way to understand which one seems to be most sensitive to it. I'm just trying to think if there's another way to do that, if there's some way to have bidders identify where things are coming from, but that also gets to be very complicated. The intent here was to have something relatively straightforward from an analytics standpoint so the company knew exactly what it was supposed to do and there was no discretion or bias sneaking into that process. I agree with the concern, and frankly, it's a little of the concern I have with the chairman's question of Dr. Ihle about a process for giving across-the-board tariff relief. There could be a lot of variation across projects depending on where they're sourcing equipment and whether they have equipment on hand in warehouses or whatever. I'm not a developer; I don't know what all their options are. Different projects would face different risks. We still felt it was valuable information to get an understanding of how much risk the ratepayers might be facing looking at tariff cases, but I agree, it is not perfect.

Megan Gilman: Has staff dropped its request to have different forecasts modeled in phase two?

Erin O'Neal: Largely, we felt the Quad Party settlement framework addressed staff's concerns about load uncertainty. The point of having the incremental knee pool and second RFP was to do some of what staff was hoping to in those different load forecast requests—planning for the load we're pretty darn sure is going to show up and having a flexible process to address other load as it becomes more firm. That alleviated the need for a lot of analytics around a base and high load forecast in the phase two scenario modeling.

Megan Gilman: You proposed two accelerated emissions cases, numbers 9 and 10, right?

Erin O'Neal: Correct.

Megan Gilman: Although, accelerated in this sense would hit 86% carbon reduction by 2030, which essentially was the result of the 2021 ERP, right? That was the projection from the last ERP?

Erin O'Neal: Correct.

Megan Gilman: Both of those cases, 9 and 10, as I understand it, would also be bound by the 90% by 2033 additional requirement, and then they would move differently from there. I was wondering why, and if that's an appropriate additional requirement. If we just want to test what happens if we stay on the same track we were supposed to be on before, do we need to saddle both of those test runs with an additional emissions requirement?

Erin O'Neal: That's a good question. We definitely wanted to have one case in there that was the bookend, throwing everything at the emissions reductions that you could—social cost of carbon, 86% by 2030, 90% by 2033, linear reduction after that—just to understand what that cost looks like. Then it felt like this was an important enough issue in terms of what we're doing here from a planning perspective to have a second case that was an accelerated emissions case. I can see the logic of what you're suggesting, of having a somewhat different intermediate accelerated emission case. These cases are clearly intending to understand the full range of outcomes. I'm not sure staff would have a preference between what we suggested and your recommendation of doing something similar but backing off the 2033 goal. I can see that as an intermediate but still accelerated case that also makes sense.

Megan Gilman: With regard to the use of the linear increase in emissions reduction moving forward, a similar concern is that it’s an unnecessarily stringent boundary to put on since resource acquisition is in no way linear. Would that potentially lead to more costs or lumpier acquisitions than would be natural and give a bizarre or skewed outcome as a potential?

Erin O'Neal: Let me talk about this in terms of the non-accelerated emission reduction cases first, and then the other one. I think the answer is no. Most of those cases that have an 80 by 30 reduction—the company's phase one modeling projected an 84% reduction as their current expectation for 2030. We expect to start in a position of still being somewhat over-complying with the current statute, so you have some wiggle room there. The linear reduction is from the 80 by 30, so it's what does the model need to do to make sure it stays ahead of a linear constraint going forward, one that it's going to start by being a little bit over-complying with. I don’t think a linear programming model like Encompass would have a problem instituting that constraint. It's just another constraint as you go through the end of the planning period in 2050—what do you need to do to add resources to make sure you stay ahead of that constraint? In the accelerated cases, where you're starting with 86 by 30, it's going to be harder, pushing for more additions sooner, but it's still just a constraint that the model sees and knows it needs to add resources to stay ahead of over that period. I don’t see that as being particularly problematic for the model.

Megan Gilman: In your testimony, you note that Public Service needs a phase 2 portfolio that identifies incremental clean energy plan activities for the purpose of the C rider. In rebuttal, the company introduced these, I understand not your favorite language, checkpoint portfolios that would have basically no emissions reduction requirements. Do you think those portfolios provide that lens of the contrary situation upon which to calculate a C rider, or do you see something else as being necessary to serve that purpose?

Erin O'Neal: I think that is the purpose of those, to determine whether there is any incremental C resource that needs to be added to the C rider and to identify what that resource is. I'm not saying it's a great use of analytical firepower, but I do think it's required to have that understanding of whether there are incremental C resources.

Megan Gilman: There were two of those checkpoint portfolios. Is there one in particular you see as the baseline? In the 2021, we called it the baseline ERP; here we're calling them checkpoints. Is there one in particular you see as the appropriate one for that use?

Erin O'Neal: We're a little unsure about that, which is why we left them both in. I could probably make an argument either way. The statutory requirement around this says the baseline portfolio is supposed to be modeled with the social cost of carbon. Logically, the unconstrained case is the baseline for the calculation of the C rider, which is why we left both of them in there to make sure we're checking the statutory requirements to model the baseline case with and without social cost of carbon. Staff would argue that it's probably the without social cost of carbon that is the better basis to determine the C rider.

Megan Gilman: You also listed at the bottom of your portfolio table alternative other cases. Are those like if we elect to run more portfolios, if we have time, in what circumstance do those come in?

Erin O'Neal: That was our intent to say, here’s some things we think if we were commissioners, we might be interested in. I do think you heard the company say there was a little bit of wiggle room on the 14 portfolios, not a lot. Staff would support that we don’t want to be in as delayed a situation as we were in the last ERP, so it’s important to keep those to a constrained number. There are other things that could be helpful to the commission to understand—modeling of the just transition credits, for example. The last time we did an ERP, we modeled a high project labor agreement portfolio. Our scenarios were a reflection of what staff thought were the highest priorities, but also recognizing that you might not agree with us. If there’s a scenario or two of our suggestions that you don’t feel has a lot of value added, maybe there’s another case like a high project labor agreement or something that you think would be more interesting. This was our attempt to suggest things you could replace as things of interest. If you’ll permit me, through the course of the hearing, I might add one to that list of things you could be interested in, which would be a no-PTC extension portfolio, understanding what this would look like if the production tax credits and investment tax credits were not continued or there was a change in federal law around the PTCs and ITCs. That might be a scenario the commission could be interested in understanding.

Megan Gilman: A question on portfolio 16, one of your alternative cases titled just transition credits. I wanted to understand the basis of that. Is that akin to just transition adders? Do your other portfolios not have just transition adders, and this would just be one portfolio that has those? Help me understand the variation there on the treatment of just transition adders across your portfolios.

Jack Ihle: Thank you for the question. It’s helpful to clarify. Generally speaking, the staff did not take issue with the recommendations of the company to model all of the portfolios, including the just transition credits. It’s our assumption that the other scenarios would include those just transition credits. A number of parties in this proceeding have recommended running a case without them so that the commission can understand the cost and changes in portfolios if those just transition credits were not included. That was the intent: to assume that the base set of scenarios would be as the company had recommended, including the just transition credits, but if the commission were interested, run a case where there were no just transition credits.

Eric Blank (Chairman): Understood. Cool. A question about gas price sensitivities. I know staff recommends not including gas price sensitivity, given the significant demand we’re seeing around gas export of LNG, as well as projections across other proceedings on decreases in retail sales, which potentially could impact cost allocation, especially for these firm customers. I wanted to understand if you didn’t think that would meaningfully change any of the models or why we wouldn’t want to understand a variation under higher gas prices.

Jack Ihle: I think it’s our expectation that the impact of a change in gas prices is going to be pretty minimal. The gas CTs are driven by the need for dispatchable resources and don’t run very much. Our expectation was that they will be a smaller portion of the portfolio as we go forward, as we get to deeper levels of renewable penetration, and they will run less. The need for the CTs is driven by the capacity need to have them on the system to be able to call them. A change in the gas price or slightly more efficient heat rate isn’t going to be the driver of the need for those resources. In trying to be circumspect about what makes sense to poke at from an analytical perspective, the gas price sensitivity didn’t seem like the most important thing to test. The need for those resources and the cost of the portfolios isn’t really about the fuel price; it’s about having the dispatchable capacity that runs as little as possible.

Eric Blank (Chairman): Thanks. Another question about portfolios. I know staff doesn’t have an ISO or RTO portfolio, at least doesn’t show that as a variation recommended to be modeled. I’m curious, with the statutory requirement that the company join an organized wholesale market within the RAP, you know far more than I do because I know you participated in the study at the commission as to potential savings associated with full RTO participation. Just curious about your perspective on that and what, if anything, you think would change as far as model characteristics and why we wouldn’t be including that if that’s a statutory requirement.

Jack Ihle: I haven’t thought too much about this one, but I’ll say a couple of things and might need to clean it up later. The level of detail that the model can get to in terms of intra-hour treatment of curtailments is limited. It’s a model; it’s doing a decent job, and hopefully, we get to do better over time, but a lot of the benefits of the imbalance market and even the day-ahead market are about very detailed dispatching of the system and intra-hour dynamics and curtailments. I’m not sure that the planning model is going to be the best model to try to capture that, especially for full RTO. In terms of full RTO, I think you heard the company say they are still going to have a resource adequacy requirement. They need to show up to an RTO able to meet their own resource adequacy requirements. It’s unclear how I would back off or change the planning reserve margin as a result of the RTO. I don’t think we know that today, and I don’t think it’s going to change the company’s resource adequacy requirements. Once you’re in a full RTO and doing joint long-term transmission modeling, hopefully, we see some benefits to that and economies of scope in doing a better job with regional transmission planning, but that’s not primarily what this model is intended to capture. Within the error bars of the modeling, it doesn’t feel like you’re going to get enough robust analytical information from trying to create an RTO scenario here that you could rely on or use for decision-making. It did not meet the list of scenarios we felt were worth the analytical effort.

Eric Blank (Chairman): I asked you because you wrote about PIMs to some degree, maybe not these PIMs. Given the company’s suggestions on conforming bid policy and PPA terms, many of which would significantly restrict future price adjustments, I was curious if you thought PIMs were a mechanism, or if we had some other more appropriate mechanism by which the company, as potentially the single largest bidder, would also live by the same means as the other bidders.

Jack Ihle: In terms of the details of the bid policy pieces, I’m not sure. We do have an approved PIM structure for the resources that came out of the last ERP. Staff’s current position, as I talked about in testimony, is that we want to continue with those PIM structures that we just approved with the projects that come out of this ERP. We are interested in having the company do some reporting on what a PIM that looked more like a PPA structure would do. The company is opposed to that, but to get a more wholesome understanding of how PPAs versus company-owned projects differ, it could be helpful to have that reporting around those kinds of PPA versus company-owned PIM structures. In terms of actual PIMs’ operational cost to construct coming out of this proceeding, I think we believe it makes sense to keep on the path we’re going, implementing the same kinds of structures that were just approved for the projects in the last ERP.

Eric Blank (Chairman): Would it make sense to align the potential cost to construct price modifications from bid to CPCN with whatever the same kind of bid modification pricing allowances are contained within a PPA?

Jack Ihle: Yes, I think that would make sense.

Eric Blank (Chairman): One other question on forecasting. Given the significant swings we’ve seen already in forecasting within this proceeding, are you concerned? Do you think we need a different process than in the past, more heads up if we see any major deviation in forecasting, especially if the commission orders any modifications that then need to be followed up on? Do you have any concerns for both the base RFP and supplemental RFP on what process would occur to vet or review that forecast before we go straight into bidding?

Jack Ihle: I agree with you. This is one of the central questions in this ERP: what is the load forecast, what are we doing, and how are we reacting as it changes over time? Having a process where the commission is made aware of significant changes is important. There’s a balance because you don’t want to be informed every time something changes, but periodic reasonable updates make sense. Mr. Eye said this morning that the company could commit to providing information 30 days before the RFP went out. That seemed like a reasonable process, and having some ability for parties to comment on that could also make sense without creating more process that we can’t keep up with.

Eric Blank (Chairman): Those are all the questions. Thank you. Before we go to Commissioner Plant, Commissioner Gilman, did you have questions for Mr. Ihle, the witness? I forgot to ask you after the break.

Megan Gilman: I do, yes, sorry.

Eric Blank (Chairman): Commissioner Plant.

Tom Plant: Thank you. Good afternoon, Mr. Ihle.

Jack Ihle: Good afternoon, Commissioner.

Tom Plant: I don’t have much to add to what Commissioner Gilman asked, except I did want to come back to one of the points as it relates to the various models. I had a similar conversation with Mr. Landrum, but in your view, what is the value of the checkpoint cases?

Jack Ihle: The statutory structure of the clean energy planning creates a rate mechanism, the clean energy plan rider, the CEPR, which is up to a 1% adder for recovering the costs of incremental resources needed to comply with the clean energy plan but that would not have otherwise been needed but for that planning. There has to be some mechanism to identify what those incremental resources are. Unfortunately, to do that, you need to understand what the base is, like what we would have approved as resources in the absence of the clean energy plan. The last ERP was most of that clean energy planning, but this resource acquisition period does cover those last two years, 2029 and 2030, of that clean energy planning time frame. The commission already has a CEPR in place that approves what we identified as incremental resources from the last resource plan, but it’s possible that there are resources showing up in 2029 and 2030 that are also incremental clean energy resources. The only way to identify them is to have a comparison case. As part of that CEPR ratemaking process, we need to have a comparison case to identify those resources. I’m not saying it’s the best use of our collective analytical time; it’s just the structure of the ratemaking that was put in place to recover the incremental costs for the CEPR.

Tom Plant: If we were to apply the transmission adder in the way the company proposed, do you feel the same?

Jack Ihle: The transmission adder and the checkpoint cases are very distinct issues. The checkpoint cases, or unconstrained cases, are about the CEPR rider. The transmission adder is used in the modeling and applied to all the resources. It’s going to emphasize the high-capacity, high-ELCC resources, so we’re overemphasizing the savings in the high-emissions, high-gas portfolio and underestimating the savings in the portfolio we’re ultimately going to select. Is it giving us anything truly useful to calculate the rider? The transmission adder piece is not giving you anything useful to calculate the rider. The CEPR specifically only recovers incremental generating assets. We expect those transmission costs to be constant across portfolios, which isn’t to say that we agree with the list of portfolio upgrades identified by the company. There’s still a lot more work to do to understand what transmission we really need and get into the details of those specific projects, but as indicative pricing goes, the company’s modeling suggests that’s pretty static. That supports staff’s recommendation to treat most of those transmission costs not as a variable adder that varies with the nameplate capacity but as a fixed cost to support the entire portfolio approved by the commission. It’s going to need a fair amount of transmission to support delivering that energy, regardless of exactly which portfolio we end up with.

Tom Plant: Mr. Landrum had a couple of different scenarios: one without any emissions objectives that was around 7,900 megawatts and another that was 14,000 megawatts. If we’re attaching a per-megawatt cost to these two portfolios, there’s going to be a significant difference. I don’t know if that gives us an accurate representation of what that gap is for the CEPR that you’re trying to achieve through the checkpoint cases.

Jack Ihle: Those cases weren’t checkpoint cases. The difference in 7,000 megawatts versus 14,000 megawatts were both clean energy plan portfolios, just different potential portfolios that could get you to the same accredited capacity. They checked the box on the loads and resources planning and were sufficient to meet the 80 by 30 clean energy planning goals. They weren’t unconstrained cases. The CEPR cases are literally unconstrained; we don’t even have to get to 80 by 30, we just add the resources from the last ERP and let the rest go. Our point on the transmission adder is that, given that potential range of size of portfolio that are still clean energy plan portfolios, applying a dollar-per-megawatt adder burdens those portfolios with very different transmission costs. You’ll end up with twice as much transmission costs in the high-renewable portfolio and half the transmission costs in the 7-gigawatt one. That’s not an accurate representation of the actual transmission cost, and the result potentially is a bias towards gas-heavy portfolios and away from renewable portfolios. That’s the potential consequence and why it mattered to staff. It’s a modeling construct, and I understand the company’s stance is they’re just trying to get close from a modeling perspective, but there’s the potential to create a bias when you treat the adder as if all the transmission costs were variable when they’re not.

Tom Plant: If we’re creating a bias and not accurately representing cost, and in those two plans the transmission costs were about the same in the actual table but would be very different in the model, we’re using a model that’s creating a bias, misrepresenting the cost, and then using it as a basis for what the gap is in the rider. I’m trying to find the usefulness of these checkpoint cases, and I can’t come up with it.

Jack Ihle: The rider and the checkpoint cases are not about the difference in transmission cost. It’s the cost of an incremental generating asset. Those are comparing a literally unconstrained emissions case versus a clean energy plan case. The transmission adder is applied to all the cases, so that’s not going to get you a delta at all; it’s all going to come out in the wash. The transmission costs aren’t the costs that get captured in the CEPR. It’s an incremental generating unit, say I need one more wind plant to get me to 2030 goals. I won’t know that if I haven’t run an unconstrained case, and it would be that wind plant that goes to the CEPR. I don’t know the transmission costs for those checkpoint cases because the company didn’t run those as part of their transmission modeling. I’ll think about that more, Commissioner, to consider what might have come out, but it’s hard to know if we don’t have any analytical modeling suggesting what those transmission costs or portfolio might look like for those checkpoint cases.

Tom Plant: If we were to not do those two cases and run a couple of alternative cases that might give us a little more information, I heard you say an RTO case would be hard to identify the inputs for, and you’re questioning whether it would change anything in our portfolio or cost because you don’t capture the intra-hour benefits.

Jack Ihle: To the extent that the point of the ERP is to select the portfolio of generating assets that the commission wants to approve based on the phase 2 RFP process, that’s about generating assets, not about avoided transmission in the future or dispatch. It’s about picking specific assets to make sure we are meeting our loads and resources reliability, have enough capacity on the system, and that there’s enough energy to meet the emissions goals. The system needs enough flexibility to operate reliably. Those questions aren’t really RTO questions. An RTO, as opposed to the imbalance service, is more about integrated transmission planning and better coordination on dispatching with neighbors. The company is still going to need to meet its resource adequacy constraints, so we’d go in with a 0.1 LOL either way.

Tom Plant: I heard you had your runs from 15 to 18 that are your wish list, and an additional one of taking out all PTC and ITC benefits and seeing what happens in that case. I hope that doesn’t happen, but it may be helpful to have that view.

Jack Ihle: I appreciate that. Thanks.

Tom Plant: That’s all the questions I had. Thank you, Commissioner.

Eric Blank (Chairman): Thank you, Commissioner Plant. Ms. O’Neal, several parties have raised concerns that current rates may not result in outcomes that are in the public interest in terms of calculating and fairly allocating the costs and benefits of integrating these large new loads into the system. To the extent that’s true, are you concerned about the company signing 15-year contracts with these large new load customers that may lock in existing customer class approaches prior to the resolution of the January 31, 2026, advice letter filing, especially since no party or this commission is going to be reviewing those contracts prior to execution? Thoughts, concerns?

Ellen Kutzer (Ms. O’Neal): I’ll start with the caveat that I am not a lawyer. I don’t think there’s ever a guarantee that our tariffs don’t change. There’s nothing in them that says this is a fixed price tariff that will be the same forever. My expectation would be that customers understand when they take service under a tariff that that tariff may change in the future.

Eric Blank (Chairman): I’m asking a different question. To the extent we create a new category or a new large load customer class, if they sign a 15-year contract prior to this commission doing that, presumably they wouldn’t have to go in that class if the company signed a 15-year contract.

Ellen Kutzer (Ms. O’Neal): I’m not sure that’s true. I don’t think there’s a guarantee that a rate class would never be disaggregated into two different rate classes. Our tariffs don’t say if you qualify for one tariff and we reconfigure rate classes in the future that you automatically get grandfathered onto an existing one. I share your concern. That’s a risk for any customer. If the company is signing long-term 10- or 15-year contracts with its customers, the company and the customer should understand that tariffs may change over time. The structure of tariffs may change, and the terms and conditions under which people take service change. If the company is signing 10-year contracts, depending on the terms and conditions, they may be taking on some risk. Those are not contracts the commission is approving, so the company has risk. They are different from the economic development rate customer, which had statutory requirements. These are normal regulated tariff customers. I share your concern, and it will be a very interesting advice letter proceeding where we argue about these things. It would be good to clarify with the company where the risk sits and what the expectations are.

Eric Blank (Chairman): On transmission, Mr. Riley testified that the transmission investment in the original direct testimony base case was 13.5 billion through 2031, while the low-case transmission spending was 12.8 billion, suggesting that almost 95% of the transmission capital spending was independent of large new load growth. At the same time, a series of public service company witnesses acknowledged that there was no detailed line-by-line capital spending plan that formed the basis for much of this transmission investment in either the base or low-case scenarios. Given the lack of detail, are you curious if you understand the basis for the company’s finding that the low case, without 1,895 megawatts of large new load, requires the same new transmission as the base case?

Ellen Kutzer (Ms. O’Neal): I would say a couple of things. There is a lack of analytical support for general insights on what’s driving transmission. That’s one of the reasons we recommended a stakeholder process. The hope is to get to actual transmission CPCNs to support these portfolios, but part of the intent was to have this discussion: what is driving the need for both the deliverability projects bringing load into the Denver metro area and the proactive, CPP-type loop projects? We want a better handle on what those drivers are and how we potentially avoid costs. I don’t think there’s been a robust analytical structure to address some of those insights around transmission planning. That’s aspirational; I can’t guarantee that stakeholder group will address all those questions, but that’s part of staff’s intent. The company has been consistent for a couple of years in saying there is a substantial amount of transmission upgrades needed to move power into the Denver metro area. Exactly which projects and how much that cost is still an open question, but they have been consistent in saying there are substantial fixed costs around transmission deliverability that will be needed as we retire things within the Denver metro and build outside of it.

Eric Blank (Chairman): Mr. Riley argued that the base case was somewhat better for residential customers compared to the low case, but that finding assumes that 95% of the transmission investment is still needed even in the absence of a large new customer load. If you make different assumptions about the percentage of new transmission needed, that finding reverses itself, and the low case is better for residential customers. Any thoughts about how we deal with it in this case?

Ellen Kutzer (Ms. O’Neal): This case is about creating an analytical structure to evaluate bids in phase two, laying the analytical foundations for future transmission CPCNs, figuring out the load forecast, and being responsive to it. The biggest innovation and most important thing is that framework process of trying to keep the investments in step with the load and making sure we are not getting ahead of where our commitments need to be. I realize there’s been a lot of questions about that process, but I want to make sure that’s clear because it somehow gets lost in the weeds. That is the point: to pull back as much as possible to keep those things in lockstep and not get ahead of ourselves.

Eric Blank (Chairman): If you allocate a larger portion of the transmission investment to the new load, the low-load case looks better than the base case. Any comments on that?

Ellen Kutzer (Ms. O’Neal): It’s a balance of making sure we are attracting new large loads. I don’t have any reason to disagree with the company that having new large loads show up and contribute something has the potential to be a benefit to the rest of the system. The way it is done matters. Your question is how do we make sure we are creating a structure to capture that potential. It’s not going to happen by magic; we have to think clearly about what structure we create to ensure those benefits flow to the whole system, not just to one rate class.

Eric Blank (Chairman): As we struggle with these transmission issues, one path forward may be to encourage, through tax policy or electric rates, large new loads to locate outside the Denver metro area, perhaps on the 345 kV system. That approach could significantly reduce congestion into and within the metro area, use our existing transmission system more efficiently, lower transmission-related curtailment, and maybe put economic development where the state may prefer. Any thoughts or advice on how to better understand this prior to the advice letter filing?

Ellen Kutzer (Ms. O’Neal): I expect that to be part of the advice letter: understanding if there are zones for these new loads, if the tariff changes depending on where the load is physically located, or if it’s picked up in the interconnection costs, which are customer-specific. How we’re best doing that is a good question for the advice letter. To your point, how do we set ourselves up with the analytical framework to answer those questions before we’re in the middle of the advice letter filing? That’s a directive to the company to make it clear that you’re interested in understanding that from an analytical perspective. It was my hope that the transmission stakeholder group would discuss what is possible to do to get that analytical framework and understanding.

Eric Blank (Chairman): In the clean energy delivery plan, component one, stage two, the commission approved contract language that allowed for up to a 15% increase in the event of supply chain and other events that occurred after contract signing. Do you recall that?

Ellen Kutzer (Ms. O’Neal): I do.

Eric Blank (Chairman): Could we pull up what has been marked as hearing exhibit 2909? Let me represent that this is the contract language the commission approved in that clean energy delivery plan. Go down to 8.2, 20.3. Any thoughts about, in the event the commission chose to adopt a conforming contract approach, putting similar language as this in the model contract, like we did in component one, stage two of the clean energy delivery plan? It would address change of law risk, tariff risks, and tax credit risk.

Ellen Kutzer (Ms. O’Neal): I would have to review this language to remember it in detail. A couple of thoughts: similar to what I talked to Commissioner Gilman about, we continue to feel that all projects are not situated the same. Where they’re sitting with respect to tariff changes or even PTC/ITC changes isn’t the same. Setting up a process where, across the board on a particular resource type, you’re treating everybody the same may not accurately reflect the actual cost to individual projects. As we’ve seen tariffs roll out that vary substantially country to country, the expectation is that different projects will be situated differently. At the time we did the clean energy delivery plan, the expectation had been that tariffs would be more uniform across the board, but that has not turned out to be the case. Do you have a concern about treating everybody the same? It feels like that ends up being a ratchet; everybody is going to ask for the same cost increase, and the whole portfolio is going to get ratcheted up by whatever the potential is. It’s hard for me to see where the downward pressure comes in. I’m not sure I love the across-the-board representation here. When we did the clean energy delivery plan, there were other potential processes floated to address some of these changes, and we didn’t have time or a process in place to do that review through an independent auditor. Sitting here today, we have more time. Whether it’s revising some of this language to be more project-specific or creating a different process, there is time to do a more detailed look at how this could be accomplished in the most cost-effective way. I would encourage folks to think about whether there’s a different process and a little more review to make sure we are doing it in a way that is most protective of ratepayers.

Eric Blank (Chairman): Do you think we could do it in a notice and comment process, or start that way, and if we need a hearing, we can schedule a half-day thing or something?

Ellen Kutzer (Ms. O’Neal): Potentially, I agree, Chairman. Giving folks time to review this and think about whether there’s a way to avoid my ratchet concern would be well worth creating a little process around that.

Eric Blank (Chairman): Thank you, Ms. O’Neal. That’s all I had.

Chris Leger (Mr. Cox): Mr. Cox redirect, and then go to Ms. O’Neal. First, I’d like to start talking about the scenarios. We covered that with just about everyone. If we could pull up hearing exhibit 2606, attachment SG JD 10. On staff scenarios seven and eight, you talked through that with Mr. Larson, particularly around why there wasn’t a linear constraint. Do you recall that?

Ellen Kutzer (Ms. O’Neal): I do.

Chris Leger (Mr. Cox): Was that also how the company proposed those scenarios in its direct case?

Ellen Kutzer (Ms. O’Neal): Yes, that’s correct. Scenarios seven and eight are essentially identical to what the company proposed in both its direct and rebuttal. It’s only scenarios five and six that were similar to their direct proposal, slightly different from their rebuttal proposal.

Chris Leger (Mr. Cox): You talked with Commissioner Gilman about the accelerated emissions and the use of the 86 by 30 and 90 by 33. How do these emissions constraints compare to the accelerated emissions proposals from other parties, including the company?

Ellen Kutzer (Ms. O’Neal): They’re a little more robust in terms of providing detail about exactly how these would be constructed, with the intent to create that bookend look at what accelerated emissions would look like and maybe one or two steps back from that. Saying we’re going to meet the 2033 objective but then not having the constraint after that is one step back. The intent is to say what’s the most accelerated we could get and, similar to the variance on the preferred plan, what’s the marginal impact of that? How much difference would it make to try to get more understanding into how much cost and difference in portfolio results from a marginal reduction in the accelerated nature of that scenario?

Chris Leger (Mr. Cox): You talked a little with Commissioners Gilman and Plant about a potential PTC scenario option. Can you clarify whether staff sees a PTC scenario as needed if the PTCs are removed under federal law prior to modeling?

Ellen Kutzer (Ms. O’Neal): If we know that the PTCs have been removed prior to bids being received, then I don’t think we need that scenario. We would have certainty, and I would expect all the bidders to incorporate that into their bids. It would only be needed if it is still unclear as to what the federal guidance or statutes would be. As we sit here today, it’s unclear where that’s going to land. If there continues to be uncertainty, it could be a helpful scenario to model a variant of removing the production and investment tax credits.

Chris Leger (Mr. Cox): Is there anything else you’d like to add about staff’s proposal on the portfolio scenarios?

Ellen Kutzer (Ms. O’Neal): One overarching comment: staff was quite aligned with the company in terms of the principles of what the scenarios were intended to do, which is to be circumspect and not use so much analytics that we can’t get to the 120-day report in a reasonable amount of time and to create reasonably different views of the world that provide information to the commission. Where we differed was in the concept of the solution sets. Staff did not see unique, interesting, different results from all of the solution sets that the company proposed. We have one solution set around the company ownership that we agreed on, and the rest we felt we could be more efficient with our analytical capability if we moved away from that solution set concept and addressed more individual scenarios. The scenarios we had were not intended to be advocacy positions. We’re not advocating for lower company ownership or lower new gas. We’re trying to make sure the commission has the information it needs to understand the trade-offs: what is the cost of the company ownership constraint, how much more would it cost if there was a lower gas constraint? It’s not that we’re advocating for any one of those scenarios, just trying to create a complete analytical picture of the options in front of the commission.

Chris Leger (Mr. Cox): Moving on to the transmission adder, you talked about this with Mr. Larson, particularly the impacts of a higher adder amount. Do you recall that?

Ellen Kutzer (Ms. O’Neal): I do.

Chris Leger (Mr. Cox): Why, in your view, is the adder amount important?

Ellen Kutzer (Ms. O’Neal): Staff sees it as important because we’re concerned that it creates a bias within the modeling towards resources that are higher ELCC resources without actually reflecting a real economic dynamic. By treating the transmission costs as varying with nameplate capacity, the portfolios that are higher in firm ELCC resources—dispatchable gas and storage—will be burdened with much lower transmission costs than the portfolios that are more renewable-based. Commissioner Blank mentioned the 7,000-megawatt portfolio versus the 14,000-megawatt portfolio. The 7,000-megawatt one has more gas and less wind and solar and would be burdened with half of the transmission costs that the 14,000-megawatt high-renewable case would, when the company’s own modeling suggests almost exactly the same transmission cost. Staff is concerned that in the modeling, this will create a bias for the model to select more gas and storage resources as opposed to wind and solar when that’s not actually reflecting a cost that can be avoided. That’s a bias in the model we want to avoid if possible.

Chris Leger (Mr. Cox): In staff’s proposal, would you say the bias is removed?

Ellen Kutzer (Ms. O’Neal): I think the bias is removed in staff’s proposal. None of these proposals are perfect. Ultimately, staff would agree with UCA that it would be nice to have much more detailed transmission modeling that connects specific projects with actual transmission lines and upgrade costs. Sitting here today, we don’t have the analytics to do that, so staff was trying to propose something that was a compromise and more reflective of the actual costs that the portfolios would be burdened with. Recognizing that it’s not perfect, we believe it creates less bias in the modeling than the company’s proposal does.

Chris Leger (Mr. Cox): If we could pull up what’s been marked as hearing exhibit 2610. Ms. O’Neal, are you familiar with this document?

Ellen Kutzer (Ms. O’Neal): I am.

Chris Leger (Mr. Cox): Can you describe what we’re looking at here?

Ellen Kutzer (Ms. O’Neal): The company did a total of eight transmission scenarios. These are in their transmission modeling, not EnCompass modeling. As we talked through with Mr. Martz, the company created four different portfolios, all meeting the loads and resources need, for the base load and the low load, making a total of eight transmission scenarios. They evaluated what transmission upgrades would be needed to support each of those portfolios, shown in the second column. Those numbers vary between 1.9 and 2.2 billion dollars, a pretty tight range of transmission costs, even when the capacity ranges from 3.6 gigawatts up to 14. The table on the right shows that if the commission were to approve the company’s transmission adder, it would burden those high base-load capacity resources with transmission costs up to 3.4 billion dollars for that second case and burden the small portfolios with much smaller transmission costs. The low-load case, labeled as row seven, had 0.8 billion of transmission costs associated with it. Staff is concerned that that’s not an accurate reflection of what the company’s own modeling suggested. The last column in that table is what staff’s proposal would do, which is to treat a good fraction of those transmission costs as fixed and only a small portion as variable. Those transmission costs are much closer to the costs modeled by the company in its transmission modeling.

Chris Leger (Mr. Cox): We could move to page two. This may help illustrate that comparison a little better. Can you talk us through this graph?

Ellen Kutzer (Ms. O’Neal): This graph is graphing the size of the portfolio by nameplate capacity across the x-axis, and the y-axis is the transmission costs. The big blue dots are plotting Public Service’s transmission modeling, showing, based on the size of the portfolio, what the predicted transmission costs were. The orange line is plotting what Public Service’s transmission adder would do. It’s linear with a pretty big slope, so small portfolios have relatively low transmission costs, and high portfolios have relatively high transmission costs. The green line is plotting staff’s proposal, which is to treat most of those transmission costs as fixed and a small amount as variable. You can see that matches the company’s transmission modeling—those big blue dots—a lot closer than the company’s model. Staff is concerned that the company’s transmission adder proposal is analytically not supported and does not match its own modeling. The reason we care is because we’re concerned that it creates a bias in the model towards smaller portfolios by nameplate capacity, which ultimately means more gas, more storage, less wind, and solar. That’s a problem if it’s not accurately reflecting the actual cost of the transmission.

Chris Leger (Mr. Cox): Staff would move to admit hearing exhibit 2610.

Eric Blank (Chairman): Any objection?

Unidentified Speaker: No objection.

Eric Blank (Chairman): So moved. That is all the questions I have for you, Ms. O’Neal. Thank you.

Ellen Kutzer (Ms. O’Neal): Thank you.

Eric Blank (Chairman): Thank you, Ms. O’Neal. You may be excused. Is Mr. Iden out there? Can you hold up your right hand, sir? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Andy Iden: I do.

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

Andy Iden: No. My child is upstairs, so you might hear some noise in the background. I’ll try to limit that.

Eric Blank (Chairman): We have cats and dogs running around in the background, so if that changes, will you let us know?

Andy Iden: Yes.

Eric Blank (Chairman): Back to you, Mr. Fersa.

Unidentified Speaker (Mr. Fersa): Thank you. Good afternoon, Mr. Iden.

Andy Iden: Good afternoon.

Unidentified Speaker (Mr. Fersa): Could you please state and spell your name for the record?

Andy Iden: Andy Iden, A-N-D-Y, last name E-I-D-N.

Unidentified Speaker (Mr. Fersa): Did you cause to be filed answer testimony in this proceeding on behalf of W Sweep, which was pre-marked as hearing exhibit 1301 and attachments?

Andy Iden: Yes.

Unidentified Speaker (Mr. Fersa): Thank you. With that, Mr. Iden is available for commissioner questions.

Megan Gilman: Thanks. I’ll try to make it snappy. You recommend in your answer testimony that the commission direct the company to file a clean transition tariff that would allow large customers to procure and/or sponsor clean energy projects. Do you recall that?

Andy Iden: Yes.

Megan Gilman: Would you see the potential for that to be part of the large load tariff filing that has been much discussed and anticipated in January 2026, or would that necessarily have to be a different effort?

Andy Iden: No, I think it could be rolled into that. I also see some acknowledgement, on what seems like a voluntary basis, for the commercial principles that Mr. Bailey put forth and the company put forth. I think under the last stipulation, there’s a recommendation for renewable and other flexible load interconnection agreements. Possibly, it could be under the interim. There’s much discussion about whether the 15-year lock-in applies before the tariff is proposed, but I think the clean transition tariff could certainly be discussed during that January advice filing and related hearings.

Megan Gilman: You also discussed requiring the company to fast-track a flexible connection and complementary tariff options. I was curious if you have a reason to believe or a sense as to how many of the large loads that would be applicable for, as they’re largely being described as wanting power 24/7, that being a key priority for them. What gives you confidence that that would be an offering that is at least somewhat acceptable to the market?

Andy Iden: In my discussions with people watching the market for large load, it’s true that when you ask an individual large load customer if they prefer that or would be amenable to that, the answer is largely going to be probably not or no, not at this time, because they prefer a firm connection when possible. That’s why my recommendation puts it toward the commission to establish fair and consistent rules for all large loads seeking to interconnect. That would allow a level playing field, in which case those large load customers who have capability that they’ve potentially been exploring through R&D and other means could actually push it towards the market. It’s trying to draw that out, if that makes sense.

Megan Gilman: You expressed concerns about the company’s transmission line extension policy and distribution line extension policy with regard to whether large loads are paying their fair share of the costs needed to serve them. Does that sound accurate?

Andy Iden: Yes.

Megan Gilman: I was curious if you saw both of those as potentially being properly handled in a large load tariff filing that we’ve already discussed, or if those are separate efforts?

Andy Iden: I think that could also be included, subject to potentially making that a large endeavor. I would note that the request by the company for a permanent CPCN exemption for when customers are paying 100% of those interconnection costs or facility upgrades is about the definition. Where does the line extension end, and network upgrades begin? The previous discussion highlights uncertainties and questions around the transmission cost allocation that the company and other utilities often do in their cost of service studies and how that is attributable to a certain customer class or not. If you’re investigating a tariff or the creation of a new customer class or tariff that encompasses large loads over 100 megawatts, you could and possibly should include the line extension updates.

Megan Gilman: Is it your stance in your testimony or now that large loads should be responsible for paying their full marginal cost that they cause to the system, or some other varying level?

Jack Ihle: I agree. In my testimony, I attempted to show that going back and forth between the reference or the base case forecast and the low forecast, that presentation by the company that the base case has lower impacts on rates. My point was to highlight that that’s assuming in a given scenario that the load does materialize. There’s risk of building to that specification and then the load not materializing, which my testimony shows, I think, a 7 to 24% rate increase in that scenario. Generally, I agree with the principles they’ve put forth that having more skin in the game from the large loads is beneficial. As to what that exact amount is, I agree that if load does materialize, it can reduce average per unit costs, so you want to balance that.

Paying 100% of the marginal costs is more akin to a behind-the-meter situation, like large clean firm resources, whether nuclear or geothermal, behind the meter. In that case, is there any benefit to other customers? I don’t want to insinuate there’s no potential benefit, but the risks need to be properly mitigated. I think the 75% is a good starting point for discussion, but in the company’s testimony, they point to Indiana, which has an 80%, and Ohio, which has an 85%. I’m aware of other states looking at 80 and 90% potential minimum demand charges. Some cost sharing there, I think, has flexibility but should be accompanied by a rigorous analysis of actual network expansion costs, considering the greenhouse gas goals of the state. Does it make achieving that mission more costly?

Megan Gilman: Shifting gears quickly, your testimony indicates that the company assumed all-electric heat pump installations would be paired with supplemental electric resistance heating strips of 10 kilowatts or more, whereas in the clean heat plan proceeding, we had testimony from SWEEP that air-source heat pump systems are likely to require between 3 and 8 kilowatts of supplemental heat. We’ve heard from a heat pump implementer that two-thirds of their installations in the Front Range are going without electric resistance backup. Given these conflicting visions of the future and what these installations will look like, especially in peaking conditions, what accurate data is available to understand actual installation of systems, what is the most predominant, and what granular load information do we have to understand which scenario is more accurate and in what proportion?

Jack Ihle: A couple of sources I’m aware of: a recent PNNL study publishing field validation from the cold climate heat pump challenge, between northern U.S. states and Canadian installations of about 22 heat pumps meeting that specification, looking at the run times of the auxiliary heat functions. It showed that even in the coldest hours, down to -10 Fahrenheit, 25% of the time in those coldest hours was auxiliary heat called upon. More data will be coming. I’m aware of other heat pump-specific end-use load metering studies, but not from the same climate zone as Colorado. The Northwest has examples with Bonneville Power and the Northwest Energy Efficiency Alliance that could be instructive to the diversity of load profile.

My concern is that I’m not certain, because it was difficult to track how the company built up the load profiles, both in the DSP and the JTS, about that assumption. My hunch is that it’s taking a static assumption and applying it to all heat pumps, the 7-kilowatt impact from their modeling in the DSP at -2 degrees. The company’s own meter data, filed with the DSP docket, showed 114 homes with all-electric heat pumps, where they got rid of gas backup. That showed no more than 7 kilowatts at a whole-home meter level for a cold snap in 2024. That corroborates, to me, when I look at Elephant Energy, cited in my testimony under the clean heat plan, where they said two-thirds of homes are going without backup heat, and those with it maintained the setpoint down to -22 degrees in the 2022 winter. Those are some sources I’m aware of.

There’s a need to tie field-validated data points to the energy modeling that the company and others are doing. The company points out in their rebuttal testimony that they’re using an engineering model that looks at various factors, and it’s sufficient. Going forward, finding ways to pair a modeling approach with field-validated experience is important.

Megan Gilman: Thanks. Now a question on demand response. You talk in your testimony about other forms of demand response that the company could be modeling, especially from prior studies, and its treatment in the model as a resource rather than a load modifier. Is that fair?

Jack Ihle: Yes.

Megan Gilman: Help me understand why, in your view, it’s more appropriate to model it as a load modifier rather than a resource, which is applied in ELCC, especially given the company’s arguments about it being an energy-limited resource influencing their ELCC decisions?

Jack Ihle: My recommendation was based on the ELCCs of the current DR suite, which is reflective of mostly summer, limited-duration dispatch resources, like typical AC programs or thermostat setbacks, 1 to 4 hours with limited calls per year, not wanting to disturb customer comfort. Looking at something like water heating or other flexible loads that can be dispatched around the clock, their use of the 100-hour approximation for new megawatts, compared to a water heating demand program that could operate every day, was one reason. In winter, the approach right now does not accurately reflect possible combinations of resources that could improve overall ELCC, such as under their VPP program rollout.

Megan Gilman: Those are my only questions. Thanks so much.

Jack Ihle: Thank you.

Tom Plant: Thanks a lot. Good afternoon, Mr. Ihle.

Jack Ihle: Good afternoon.

Tom Plant: A couple of questions to follow up on what you discussed with Commissioner Gilman. In your answer testimony, you criticized the way PSCO is modeling their managed charging. Do you agree that they’re currently at a 10% managed charging level, or do you think they’re measuring their existing managed charging capability incorrectly?

Jack Ihle: I haven’t had a chance to corroborate that with other filings. I’d be inclined to accept what the company said if I looked at the wrong start year for their percentage of current enrollments. Recognizing that there are utilities with rates of managed charging, like Xcel in Minnesota, that are much higher, what I’m suggesting in my different modeling is more of an S-curve, a higher adoption. What we’ve seen in Xcel is not very high adoption if we’re only at 10% at this point.

Tom Plant: What can the company do to accelerate that level of adoption and increase managed charging on the ground to reflect the modeling you’re proposing?

Jack Ihle: Before I get to active managed charging, there was discussion around how much of that potential was from a programmatic approach versus a time-of-use approach. Looking at jurisdictions like California and Arizona, who have multiple EV time options, sometimes a default time-of-use opt-out approach, could scale that program more quickly. Having a super off-peak rate that speaks to different customers’ needs versus a one-size-fits-all EV time-of-use rate would be beneficial to encourage enrollment.

For the managed charging approach, there’s research about customer experience, like point-of-sale offerings, working with dealerships to offer incentives for home charging that’s pre-enrolled or pre-discounted with conditions for a managed charging program. Other approaches include financial incentives for level-two charger purchases with smart charging capability, different financing options, including on-bill tariff options to pay that back. When I think of those, I try to think of an all-electric customer and how they’ll optimize performance. Looking at technologies independently doesn’t reduce delivery costs, but bundling marketing of a program with a solar installation, for example, to look at future electrification needs is a missed opportunity in the industry, not particular to Xcel in Colorado.

Tom Plant: That’s great. One thing that came to mind is other types of locational management based on distribution-level dispatch, which the company has indicated they’re moving toward. Stacking the distribution value, companies and aggregators offer that service to avoid service panel upgrades behind the meter or impacts on local service transformers. Making that proposition, recognizing the company’s role and how they can work with behind-the-meter providers to minimize costs for the end-to-end customer experience, is a good step.

Jack Ihle: Perfect segue.

Tom Plant: You also had criticisms about the ELCC approach and the values attributed to solar and ADERs in their model. For ADERs, is there a good model for attributing a more appropriate ELCC? The integrated resource planning best practices report talked about the approach you’re proposing, which is basic load reduction and an ELCC approach. Is there a good mechanism for applying ELCC to ADERs, based on specific technologies or a programmatic approach?

Jack Ihle: I recommended, and the company had rebuttal testimony indicating that, of the energy-limited resources, a 4-hour battery, the current ADER approximation, is the most generous, so they don’t think it’s needed. They recognize that over time they can evolve toward better approximations. My intention was not to switch to a different energy-limited resource like water heating or solar individually but to look at them as a bundle. The company seems to do this for utility-scale wind, solar, and battery, looking at the diversity benefit, but doesn’t carry that forward to ADER or distribution-connected resources.

The minimum I’d recommend is moving toward the solar-plus-storage hybrid model, which could add ELCC benefit compared to standalone for those resources. Including energy efficiency, managed charging, and other behind-the-meter resources in the ADER would be ideal in the long run. For programmatic versus technological, I’d base it on the technologies and commensurate dispatch rules. If they’re not known yet, that’s a question mark, but at minimum, get a proxy of similar supply-side resources with a hybrid profile in the ELCC modeling, then work toward reflecting actual VPP resources through procurement.

Tom Plant: Are there states that have applied this approach well in their resource planning?

Jack Ihle: I’m not familiar with how California is doing it, but I know they’ve looked at ELCC updates for VPP resources. ComEd in Chicago is pushing through a VPP tariff, going back and forth on solar-plus-storage or allowing other DERs. It’s jurisdiction by jurisdiction. Progress toward more flexible dispatch and allowing more resources to be parameterized within a model provides the most flexibility. As a proxy modeling exercise, you model actual resources as bids come in. I encourage moving toward the near-term hybrid resource approximation and advancing toward a discrete characterization of the VPP buildup. For example, Brattle has done production cost runs looking at water heaters, thermostats, and EV charging compared to gas plant buildout, finding significant cost savings. RMI has also done a Colorado-specific modeling exercise looking at VPP characterization to offset system need.

Tom Plant: PSCO argued in their rebuttal that these issues are more appropriately hashed out in the DSP proceeding. Are there aspects of this decision we should be cognizant of to not put ourselves in a box for incorporating inputs from that proceeding?

Jack Ihle: On the transmission side, evidence suggests the company didn’t look at distribution deferral when citing up to 1500 megawatts of ADER in transmission buildout scenarios. There might be a gap where potential distribution offset, like capital expenditures through strategic deployment, was missing from the JTS perspective. On the distribution side, a similar story plays out where there are investment needs, but in the future, there’ll be a VPP tariff and procurements. In winter, 2 to 3 gigawatts of solar receiving a zero ELCC shapes the distribution grid where it’s located. How that solar could be bundled into actively managed VPP aggregations is an area to explore. There’s room to model that within the JTS to reflect in the RFP phase one. Co-optimizing across distribution and transmission investment horizons could yield significant cost savings opportunities, given the size of investments in this round.

Tom Plant: Thank you very much. That’s all I have.

Eric Blank: Mr. Ihle, do you recall having a discussion with Commissioner Gilman on the 2026 large load tariff?

Jack Ihle: Yes.

Eric Blank: Based on your professional experience, is there anything more you’d like to say regarding risks associated with large loads that might be subject to that tariff?

Jack Ihle: Paying attention to the terms of the minimum demand charge, not just accepting a proposal but understanding how it relates to cost risk under different scenarios, like those contemplated with witness O’Neal’s portfolios. Understanding how planning assumptions carry over to the rate case and cost allocation mechanisms is important because they don’t always align, especially when historical mechanisms relate to capacity and energy. With increasing renewable penetration, there’s more value on fast-ramping capability. Large loads can impact ramping needs. There’s a NERC incident review in PJM where lightning caused a 1500-megawatt load to trip offline and stay offline, causing concern in markets integrating large loads. Understanding all cost drivers to accommodate those loads upfront versus waiting for a rate case is important, as it can be time-consuming to get into that detail.

There’s also an opportunity for large load customers with climate reduction goals to partner creatively, like the clean transition tariff with Google and Fervo Energy in the Nevada Energy case. Observers looking at the 2040 horizon say it’s costly to get to 100% decarbonized, so taking advantage of this case to infuse near-term investments in those resources would help the market evolve. Tracking mechanisms are important for collecting initial load requests, how data center types are evolving, especially collocated versus hyperscalers, and keeping an eye on emerging AI data centers for differences in load patterns.

Eric Blank: Last question, switching gears. You discussed the base forecast and assumptions on backup heating. Is there more you’d like to share regarding your recommendation to assume a 3-kilowatt electric resistance strip as backup heating?

Jack Ihle: It’s important to account for actual customer behavior, not only with the operation of the heat pump in the field but also whether customers undergo whole-home upgrades, like installing more insulation or upgrading windows, which would impact heat gain, retention, and the sizing and operation of heat pumps. When discussing the ELCCs of batteries and solar or the lack of modeling of winter-based demand response, those whole-home flexible load approaches to an all-electric future are critical to keep in mind, not just the worst-case scenario of a single device or technology extrapolated to all customers.

Eric Blank: Thank you very much, Mr. Ihle. You may be excused.

Unidentified Speaker: Let’s take a break till 2:50. Mr. Lucas, you had some questions. Commissioner Gilman, a few?

Megan Gilman: I can keep it very brief.

Eric Blank: If you could, that’d be great. Then Mr. Pierce and Monson. Ms. Kutzer, just popping on camera in case you need me for any of these. Commissioner Plant had questions for Mr. Turner.

Tom Plant: I had Lucas and Turner.

Eric Blank: We’ll come back and do Lucas and Turner. Mr. Dentman, I mentioned yesterday we have availability issues for Mr. Mendicino. Could we take him after the next set of witnesses, maybe tomorrow?

Unidentified Speaker: We’ll do Lucas, Turner, then Mr. Mendicino first after the break. PBLO had 10 minutes for him.

Eric Blank: Let’s come back at 2:50 and put on Mr. Mendicino. I’m going to swear you in while we’re waiting for Commissioner Gilman. Mr. Mendicino, can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Matthew Mendicino: I do.

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

Matthew Mendicino: No.

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

Matthew Mendicino: Yes.

Eric Blank: Mr. Dentman, thank you so much. Good afternoon, Mr. Mendicino. Can you please state your name and spell it for the record?

Matthew Mendicino: My name is Matthew Mendicino. First name is spelled M-A-T-T-H-E-W, last name is M-E-N-D-I-C-I-N-O.

Eric Blank: By whom are you employed, and what is your title?

Matthew Mendicino: I’m employed by the Town of Hayden. I am the town manager.

Eric Blank: Did you cause to be filed in this proceeding answer testimony, which is labeled Hearing Exhibit 1801, and its attachments?

Matthew Mendicino: Yes.

Eric Blank: If I asked you on the stand today those same questions, would you give those same answers?

Matthew Mendicino: Yes.

Eric Blank: Thank you, Mr. Mendicino. Ms. P is now available for cross-examination. Ms. Consilia, I think I got 10 minutes, correct?

Frances Consilia: Thank you, Mr. Chairman. Mr. Mendicino, my name is Frances Consilia. We’ve not met before, is that right?

Matthew Mendicino: Correct.

Frances Consilia: I represent the City of Pueblo, Pueblo County, and Pueblo Economic Development Corporation. I have questions in a few areas. First, I’m going to ask about some of your calculations, which I don’t understand. Then I’m going to inquire about some of the just transition payments you’re asking for and, if you’re successful, whether you’d support Pueblo getting similar payments. Third, I’m going to challenge that the Town of Hayden is in worse shape than the City of Pueblo and the County of Pueblo, as we all have different concerns, but I understand why you made some statements.

As I understand it, the community you live in has a commitment to clean energy. Do you have a 100% renewable energy goal?

Matthew Mendicino: The Town of Hayden specifically does not have any renewable energy goals in a policy. We are part of the Routt County Climate Action Collaborative, a combination of all Routt County governments through an IGA, and we do have some clean energy goals associated with the Routt County Climate Action Plan.

Frances Consilia: Thank you. It’s my understanding that, on that basis, you would object to having a new natural gas plant in your community?

Matthew Mendicino: You’re right. The Town of Hayden did not list any objections. However, we did advocate for a geothermal plant as opposed to natural gas or any other fossil fuel usage.

Frances Consilia: That would be something that could be bid into this resource plan, correct?

Matthew Mendicino: I assume so. I don’t work for Xcel, but I would assume so.

Frances Consilia: Your testimony seems to indicate surprise that the Clean Energy Plan of 2019 was going to require the closure of Comanche, Hayden 1 and 2, and Craig. Is that a fair assessment of your testimony?

Matthew Mendicino: The accelerated closure, yes.

Frances Consilia: Dylan Roberts was your representative in 2019. He’s now your state senator. He was one of the primary sponsors of Senate Bill 236, which we call the Clean Energy Bill. Have you discussed with Senator Dylan Roberts your displeasure with having to close the coal plants as early as Senate Bill 236 requires?

Matthew Mendicino: Once that bill was introduced, we had discussions about its introduction. We discussed that the accelerated closure was going to require new adjustments to economic plans, and hopefully, in the future, he would account for those in bills and other things to help just transition communities.

Frances Consilia: Hayden was not a participant in the 2021 Clean Energy Plan. Have you had an opportunity to go back and look at any of the testimony filed in that case?

Matthew Mendicino: I have not reviewed the testimonies.

Frances Consilia: Since that time, Holly Velasquez testified on behalf of this company and indicated she’d had conversations with representatives of Hayden and Routt County. Did she have any conversations with you about this early closure?

Matthew Mendicino: If you read my testimony, prior to the 2021 Energy Resource Plan, Xcel Energy reached out six months prior to the announcement of the accelerated closure. They had conversations not just with us but other community members as well and proposed different things that could happen at Hayden Station. I discussed that in my testimony.

Frances Consilia: Ms. Velasquez, as well as Keith Haye from the Energy Office, stated in their testimony in the 2021 case that only Pueblo had voter-approved projects relying on revenue from the coal facilities that would be entitled to the benefit under the statute. From your testimony, do you believe that the Town of Hayden or Routt County had voter-approved projects?

Matthew Mendicino: I’m not sure I understand the question. The statute says the utility is supposed to have a plan to pay community assistance to a local government or school district, the voters of which have approved projects, the costs of which are expected to be paid from property taxes. Mr. Haye and Ms. Velasquez said Hayden did not have such voter-approved projects. That is wrong. The Hayden School District passed a bond issue in 2018, I believe, presented in 2017 but authorized in 2018. That’s part of my testimony, based on Xcel Energy Hayden Station property taxes.

Frances Consilia: Was there anything the voters were aware of that indicated that school bond issue was going to be paid for with revenues from Hayden?

Matthew Mendicino: The property taxes currently being paid were based on that. That’s what the financial schedule of the payback of that bond issue, which was over $20 million, was based on.

Frances Consilia: I don’t understand how you calculate the payments you think you’re entitled to from Hayden 1 and 2. The company indicates they think it’s about $1.246 million for Hayden 1 and $1.474 million for Hayden 2. You have a number that’s almost double that. Let’s set aside whether we’re talking about six or ten years; let’s talk on an annual basis. What’s the number, and can you explain how you calculated it?

Matthew Mendicino: Our calculations are based on the Routt County assessor’s reporting of what Xcel Energy, Public Service Company, Hayden Station specifically, pays in property taxes per year. Those are payments that come to Routt County, received or anticipated based on assessed value. That’s where those calculations come from.

Frances Consilia: What’s your understanding of how the assessor calculates, or do you think your county assessor calculates the taxes due from Public Service for Hayden 1 and 2?

Matthew Mendicino: I believe that would be the treasurer of the county. That information is public information from the county, and my numbers were based on that.

Frances Consilia: I noticed in none of your testimony did you attach an actual tax bill to Public Service. Is there a reason for that?

Matthew Mendicino: Not specifically. The numbers that went into our economist report came from the county directly. It wasn’t intentional. I’d be happy to submit the report we got from the county. I believe it was attached to our economic development report done by our economic development specialist.

Frances Consilia: I couldn’t find a tax bill; that’s why I was asking. On page 32 of your report, figure MM1, your economic development projects that you’re requesting the commission order Public Service to make payments for. The $22.7 million for debt relief, what is that for? What will it pay off?

Matthew Mendicino: That would pay off several things, existing debt on the books, not just for the school district, which is the large majority of that $22 million. Their bond issue was in the 20s when passed in 2018. It would also cover our fire district, which has lease payments for equipment, and position the town to pay off voter-approved debt to grow at the level we’d need to transition.

Frances Consilia: If the commission were to order Public Service to pay this $22.7 million, do you think it would be fair that Pueblo would get a similar amount to pay off its debt?

Matthew Mendicino: Anything the commission would order based on the community’s interests or what they’ve put forward, I believe, would be fair.

Frances Consilia: Let’s look at the larger items. You’re asking for $50 million for water and wastewater treatment expansion. Is that related to the coal plants, or is it something you believe you need for economic development?

Matthew Mendicino: They’re both connected. Hayden’s 2,100 people, and the only place we’ll make up assessed value for growth is in the Town of Hayden, where Hayden Station is, not in Steamboat or other places in Routt County. To grow at that size, we’ll have to expand both our water and wastewater treatment plants to offset the assessed value lost from Hayden Station. Our plants won’t handle the capacity needed for that growth. That’s why we made that request.

Frances Consilia: Most of these items on your figure MM1, since they are city-owned, would not generate tax revenue to the city, correct?

Matthew Mendicino: The RCEDP is not city-owned. The RTA would be for a future regional transportation authority. But the water and wastewater treatment plant and the county solar project, you’d be correct; they’d be jointly owned by us and Routt County and would not generate property taxes.

Frances Consilia: Pueblo adopted a half-cent sales tax to set up an economic development fund. Does Hayden have anything like that?

Matthew Mendicino: We do not.

Frances Consilia: Let’s look at exhibit 12:15. This sounds crass, Mr. Mendicino, but who suffered most, Pueblo or Hayden, or are we all in this together? Are you familiar with the Bureau of Economic Analysis, an economic profile for Pueblo and Hayden, used by the Department of Commerce?

Matthew Mendicino: I have not looked at it.

Frances Consilia: It says in 2023, Pueblo had a per capita personal income of $48,891. For Routt County, it’s $131,057. That’s three times what Pueblo’s got, right?

Matthew Mendicino: I haven’t done the math, but it is higher.

Frances Consilia: Pueblo’s got a high amount of transfer taxes, another indication of poverty level. You make the claim in your testimony that you’re entitled to as much as Pueblo and want 10 years of payments plus more. Is that correct?

Matthew Mendicino: We requested to be treated the same. Ten years seems fair.

Frances Consilia: Do you understand that Pueblo expected Comanche 3 to exist until 2070 and was going to get about $625 million from Comanche 3?

Matthew Mendicino: I didn’t know that exact timeline.

Frances Consilia: What’s your position on how the commission should treat the three coal communities—Craig, Hayden, and Pueblo—on a similar basis?

Matthew Mendicino: The commission should look at each community, the issues they’ll face, and make decisions on what that community deems appropriate, uniquely, because not every community faces the same challenges. For example, our fire district, without Xcel Energy’s property taxes, that’s 54% of their budget. They’ll have to shut down. I think the commission should prioritize communities’ specific requests and treat us all fairly, not better or worse.

Frances Consilia: Thank you. I have no further questions.

Eric Blank: Commissioner, I don’t have any questions. Commissioner Gilman, questions for Mr. Mendicino?

Megan Gilman: I don’t have any questions.

Tom Plant: No, I don’t.

Eric Blank: Mr. Dentman, redirect?

Unidentified Speaker: Thank you, Your Honor. Just a few quick questions. Mr. Mendicino, Ms. Consilia was speaking with you about figure MM1 in your testimony. If we could pull that up, it’s Hearing Exhibit 1801 on page 32. The projects reflected in this chart—is Hayden or Routt County requesting money specifically for these purposes, or was there another purpose for showing these projects?

Matthew Mendicino: The purpose of showing these projects is because they align with our economic development plans on what will have to be executed. They were prioritized based on the revised economic plan from our master plan and the county’s master plan, respectively. The airport is listed because it’s within our municipal boundary. RCEDP stands for Routt County Economic Development Partnership for continued economic development. We don’t have a dedicated fund for that; we’re all paying into it. Regional transportation authority, we don’t have regional transportation. There’s a small bus service paid by Steamboat directly. These are action items called out in our master plan.

Unidentified Speaker: To be clear, you’re not asking Xcel Energy to fund airport expansion in your testimony?

Matthew Mendicino: No. This specific amount of money could help. The airport is the single biggest economic driver for the Town of Hayden because it’s within our boundary. It’s part of the master plan. It could be used for water and wastewater expansion to the airport, for example, because we provide all the water, sewer, police, and fire to that airport.

Unidentified Speaker: Is this $89 million figure in your testimony the overall level of economic expansion necessary, or is it something else?

Matthew Mendicino: It’s vastly short of what would be needed to grow three times the size of the Town of Hayden. My testimony talks about needing 891,000 square feet of commercial space to make up for the difference. This is a drop in the bucket compared to what that would entail to grow in six years’ time; it’s almost impossible. When we pulled this list together, we were saying, based on what Routt County agreed to with Tri-State and other things, what would be fair to get us started. The 10 years was an equitable thing. We don’t want to be treated differently.

Unidentified Speaker: Thank you, Your Honor. No further questions.

Eric Blank: Thank you, Mr. Mendicino. You may be excused.

Eric Blank: Let’s go to Mr. Lucas. There you are. Can you put up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Unidentified Speaker (likely Mr. Lucas): Yes, I do.

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

Unidentified Speaker (likely Mr. Lucas): No.

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

Unidentified Speaker (likely Mr. Lucas): Yes.

Megan Gilman: Good afternoon, Mr. Lucas.

Unidentified Speaker (likely Mr. Lucas): Good afternoon.

Megan Gilman: My first question is regarding just transition payments and adders. In your answer testimony, you argue that we should treat just transition payments as largely a sunk cost and remove the proposed adders. Does that sound familiar?

Unidentified Speaker (likely Mr. Lucas): Generally, yes.

Megan Gilman: You argue that the commission should not approve a process that could ultimately increase the total cost that ratepayers must bear. By encouraging development in just transition communities where we’ve committed to replacement tax payments, we could replace those with actual tax payments and ideally result in lower costs to all ratepayers. Help me understand the scenario you’re concerned about where we could see increased total cost for ratepayers given the situation.

Unidentified Speaker (likely Mr. Lucas): Thank you for that question. The easiest place to piece together where I close this argument is on page 19 of my answer testimony, Exhibit 2200. I went through an analysis saying the settlement agreement has agreed to provide a certain amount of money to the counties in replacement for the tax payments they would have gotten from these facilities. I looked at if you allow some of the adders to be put in place and they select bids that are more expensive than bids that wouldn’t have been selected without those adders, what would happen over the life of those projects. There’s a difference between modeling the cost of the project and the actual cost.

The tax payments are a real cost recovered from customers. My analysis on page 19 compares the potential incremental cost of a bid selected through the modeling mechanism with the actual payments customers will pay over a 25-year lifetime for different project sizes. There’s a mismatch between the value the model ascribes to these additional projects and the limits on the tax payment the universal settlement obligates customers to pay.

This table shows the payments you’d get from a property tax perspective. I used a hypothetical example of a project that’s $1.99 more expensive per megawatt hour but qualifies for a $2 per megawatt hour credit. In a simplified way, if you had two identical projects, one qualifying for this modeling credit and one that did not, Encompass would select the one that appears slightly less expensive. The model would select that project in the modeling run, advancing it to the portfolio and potentially the RFP. But that credit isn’t a real credit affecting the cost of the contract. If you had a project $1.99 per megawatt hour more expensive selected because of these credits, over the 25-year lifespan, customers would pay more. My calculation determined that on a per-megawatt basis, the added costs could result in higher payments from the rate base.

My argument was that, yes, it’s a good idea to spur investment in these communities to offset tax payments with actual property taxes, but one must be cautious not to commit the rate base to paying more than what was agreed in the settlement. This shows the types of extra expenses that could result from allowing these credits to be unlimited and not constrained to the actual tax offset they’d produce.

Megan Gilman: What would be the best way to remedy this, providing some benefit but addressing this potential issue?

Unidentified Speaker (likely Mr. Lucas): My recommendation is to limit the effective per-megawatt-hour credit of a project to what it would actually offset in property taxes. That’s specific to the project size because the tax amount is nonlinear and specific to the location, as different locations have different tax payment obligations. Those are known numbers. One could go through the process, lay out what the offset benefit would be on a per-megawatt-hour basis for different project sizes in different locations, and limit the credit in the model to a calculated number. It’s variable depending on the size and location, but those are knowable numbers or good estimates based on future tax property assessments.

Megan Gilman: Got it. We can take this down for now. Thank you for pulling it up. I have a couple of questions on the RA study and reliability rubric. Did you listen to my conversation with Mr. Landrum last week regarding the application of the company’s reliability rubric after the development of the portfolios based on the RA study?

Unidentified Speaker (likely Mr. Lucas): I was on for part of the discussion with Mr. Ming. I was driving from here to Philly, watching my son play in a soccer tournament, so I was multitasking. I heard some elements of it and similar discussions with other witnesses.

Megan Gilman: From your answer testimony, you expressed concern that we could be adding capacity at a cost for a vanishingly small amount of unserved energy with the company’s plan, potentially going well beyond the 0.1 LOLE planning standard. I want to understand any impressions you had or if your position changed based on explanations from Mr. Ming and Mr. Landrum regarding the use of the reliability rubric and its potential to add significant costs.

Jack Ihle: Thanks for the question. It’s a fascinating and challenging issue for the company and for you as commissioners. You’re trying to ensure the company puts together a portfolio that appropriately balances the risk of unserved energy with the cost. I liken it to an insurance policy: you can spend more on insurance for lower risk of unexpected bills, but it’s more expensive daily. I’m sympathetic to Mr. Landrum’s position that you don’t want a portfolio unable to serve load under normal weather circumstances. That’s the first step in their process. Encompass uses weather-normalized, standard expected grid situations, and you should meet all load in those scenarios.

Where we differ is what happens next. In the reliability rubric, they substitute typical meteorological weather and load patterns with extreme load and weather conditions, resulting in very low renewables during high load times. They test the portfolio against that. Mr. Landrum mentioned that, because it’s a central analysis using normal weather, you don’t want unserved load at the tail end. But when you load extreme forecasts and weather conditions, you’re no longer modeling normal conditions. The question of whether chasing every megawatt hour of uncertain load makes sense implicates how reliable a system you’re planning and how much insurance you’re purchasing to serve those last few megawatt hours.

I calculated an example where you might need an entire combustion turbine to serve 55 megawatts for half an hour. I don’t think that’s a reasonable final step, especially with other alternatives. Yes, Encompass in its native form should serve all native load, but the reliability rubric risks pushing costs much higher. My recommendation is that the company provide the commission with more information around these parameters to dig into these trade-offs. It’s unclear how historically likely or unlikely a recent event was—say, a one-in-10-year event stressing the system. More information is needed for the commission to make a reasonable, informed choice.

Additionally, having just gone through a three-hour outage on Friday due to a thunderstorm, the vast majority of customer outages come from the distribution system—trees blowing into lines, failures, people hitting poles, or animals crossing wires. Well north of 99% of customer outage minutes result from distribution grid issues. A bulk power system serving 100% of load 100% of the time doesn’t mean customers experience no outages. Most outages are driven by distribution system issues, which require different procedures and protocols to minimize. We want a reliable system meeting one-in-10-year rubrics, but that won’t guarantee zero customer outages, especially from distribution issues.

Megan Gilman: One final question. Your criticisms focus on the lack of cost-effectiveness or cost-benefit analysis, especially in extremely marginal situations, and no attention to how widespread or long outages or unserved energy might be. You recommend more transparency in the reliability rubric. Does that provide enough basis for actionable commission decisions on cost, duration, and extent issues, or is additional process or information needed?

Jack Ihle: That’s a good question. Mr. Landrum or Mr. Ming said the industry doesn’t typically consider economics in these calculations, and that’s generally correct. However, I’ve seen cases where a more economically focused planning reserve margin balances the value of lost load against the cost of additional capacity, providing an economic optimum. I referenced this in my testimony. The utility industry has evolved. Decades ago, every utility used a 15% planning margin because that was standard. Then, utilities got more sophisticated. With renewables, capacity accreditation was based on summer afternoon performance, but it was static. Now, we see ELCCs used, initially for one technology at a time, and recently for interactions between wind, solar, and batteries.

The industry is evolving to consider not just the one-in-10-year standard but the depth and duration of outages. Dropping 2 gigawatts for five hours versus 50 megawatts for half an hour is materially different, even if both are technically one-in-10-year events. Additional analyses comparing the tail end of incremental model outputs with economic numbers would help. If building the last combustion turbine costs $300–$500 per kilowatt-hour, smart people at Public Service could find lower-cost solutions. The commission would benefit from economic analyses. Applying the reliability rubric to generic portfolios earlier, as I recommended, would clarify if all portfolios handle challenging conditions or require expensive additions. This information is critical, especially since there’s no economic balancing for that last unit of energy.

Tom Plant: Thank you, Mr. Ihle. Good afternoon, Mr. Ihle.

Jack Ihle: Good afternoon.

Tom Plant: I’ll pick up where Commissioner Gilman left off on the value of lost load and how we might incorporate it into the process. In your testimony, you showed a planning reserve margin (PRM) producing power at one level, a higher PRM at another, and finding an optimal point in between that minimizes unserved energy at a higher PRM than the start but lower than the extreme. Is that something you suggest should be done after the LOLE Encompass model creates the PRM, then applying incremental PRM increases to find that optimal point? How would that process work?

Jack Ihle: That’s a good question. It’s challenging because these are different approaches. I’m unsure if Encompass produces this exact result. The consulting group uses a different tool. I complimented the company for moving related analyses to the same model with consistent data and assumptions, which is positive. I’d hesitate to break that apart and require completely different models. As an overlay, like the reliability rubric, an economic threshold analysis is a good second check. You run the baseline Encompass scenario, then an extreme situation, incrementing through the recap model to ensure everything checks. As part of that second step, calculate the cost of the last unit of capacity needed to eliminate unserved load and compare it to the value of lost load. If the model chases a resource costing five, 10, or 20 times the value, it raises questions about whether building that unit is worth it.

I’m sensitive to the company’s position—they don’t want a portfolio with a high risk of losing load. But they also have an incentive to build assets for returns. The challenge is finding the right balance. The value of lost load, though imperfect and wide-ranging, provides direction. If the marginal resource to close out the last 50 megawatts costs $500,000 per megawatt-hour, while studies show values of $25,000–$50,000 per megawatt-hour, that’s a useful data point for the commission to evaluate trade-offs. Right now, that data isn’t in the docket. Additional runs supplementing this information would help present trade-offs and edge cases for decision-making.

Tom Plant: How do you arrive at the value of lost load? It depends on who’s losing it, right?

Jack Ihle: It does. On page 79 of my testimony, I discuss several recent reports on this issue. It depends on the customer and even the individual. For someone with medically necessary equipment, the value is effectively infinite—they need that equipment running. Fortunately, technologies like home backup systems can address this without building a combustion turbine. Estimates range from $5,000 to $60,000 per megawatt-hour. That’s a wide range, and I’m not saying one number is exactly right. But even $5,000–$60,000 is far below $300,000–$500,000. That’s useful information.

Tom Plant: Are you suggesting running the Encompass and RA models alongside an economic analysis to determine the price of that last bit of energy? Would you increase from a 0.1 LOLE to something else, or find more economic mechanisms to achieve 0.1 LOLE?

Jack Ihle: It’s likely the latter. The 0.1 LOLE has been traditional, but utilities increasingly supplement it with analyses of unserved energy, depth, and duration of outages. If a 0.12 LOLE yields acceptable unserved energy and economic trade-offs, that’s the goal. There’s no hard rule mandating 0.1 LOLE regardless of cost. Cost is critical. Chasing high values may find customers willing to pay more or modify load. The ISO tariff for interruptible load is much lower, asking customers to interrupt for 40–80 hours a year. The company has established a supply curve for curtailments at a lower value than what we’re discussing. Economic opportunities exist for additional programs or tariffs.

In California, during a crisis before batteries were widespread, they sent a general text via the emergency alert system asking people to reduce energy use. The response was dramatic. I’m not saying that’s the right planning exercise or reliable long-term, but on rare occasions, outside-the-box thinking—small changes aggregating to 50–150 megawatts—can be more cost-effective than building an entire generating system for a small amount of lost load.

Ellen Kutzer: Just one redirect, Mr. Ihle. You discussed with Commissioners Gilman and Plant studies on the value of lost load. Is one of those the Astra study for the ERCOT service territory?

Jack Ihle: Yes, I believe I referenced that in my testimony.

Ellen Kutzer: And we provided a link to that study in your testimony, correct?

Jack Ihle: That’s correct. There are a couple, including one for Alberta, on pages 79 and 80 of my testimony.

Ellen Kutzer: No further questions. Thank you.

Eric Blank: Thank you, Mr. Ihle. You may be excused. Have a good afternoon.

Jack Ihle: You too.

Eric Blank: Mr. Turner, are you out there?

Brian Turner: I am. Good afternoon.

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

Brian Turner: I do.

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

Brian Turner: No.

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

Brian Turner: I will.

Eric Blank: Back to you, Ms. Kutzer.

Ellen Kutzer: Good afternoon, Mr. Turner. How are you?

Brian Turner: Good afternoon. Doing well, thanks.

Ellen Kutzer: Could you please state and spell your name for the record?

Brian Turner: Brian Turner, B-R-I-A-N T-U-R-N-E-R.

Ellen Kutzer: By whom are you employed and in what capacity?

Brian Turner: Advanced Energy United. I am the director of regulatory policy in the Western States.

Ellen Kutzer: Did you cause to be filed what’s been pre-marked as Hearing Exhibit 2201, your answer testimony, and Hearing Exhibit 2205, your cross-answer testimony in this proceeding?

Brian Turner: Yes.

Ellen Kutzer: If I asked you the same questions in these pre-filed testimonies today, would you have the same answers?

Brian Turner: Yes.

Ellen Kutzer: The witness is available for commission questions.

Megan Gilman: I don’t have any questions.

Tom Plant: Good afternoon, Mr. Turner. I have a quick question. You heard me talking to Mr. Riding about valuing distributed resources and how the upcoming DPP proceeding feeds into this one, particularly regarding ELCCs attributed to DERs. I’d like clarity on a couple of things. How should we think about those ELCCs? Are there good examples of applying ELCCs in aggregate, by program, or by technology in an IRP like this? The company suggested this is better addressed in the DSP-VPP proceeding later this year. How should we think about that proceeding as we draft the order in this one and approach these issues in that proceeding?

Brian Turner: I’ll take them in a different order. Most issues relevant to the VPP specifically belong in the VPP-DSP case. I distinguish between the aggregated DERs as VPP versus front-of-the-meter dispatchable distributed generation, which isn’t what I was addressing. The VPP is best explored in the DSP proceeding, where you can assess the benefits and costs. My testimony noted that the company’s representation of costs and benefits in this proceeding was flawed, underestimating benefits and possibly overestimating costs, not giving a good indication of how those resources should be valued in a portfolio.

Regarding ELCC, in your exchange with Mr. Iden, you asked if the proxy method is appropriate or if program details should determine ELCC quantification. My testimony leans toward program details. You can specify what an aggregation of resources can perform, impacting resource adequacy calculations in the ELCC.

Tom Plant: Are there characteristics of an aggregation we should identify ahead of time to inform the ELCC?

Brian Turner: I’m not prepared to provide technical details, but I’d say the energy limitation, how it’s represented in modeling, dispatch duration, and structure of dispatch. In my original answer testimony, I referenced a report by the Energy Systems Integration Group. It discussed how the dispatch structure of a VPP—whether the full amount is dispatched for two hours, spread over four hours, or used to cut shoulders at the beginning and end of expected unserved load—affects unserved load expectations and total hours, impacting resource adequacy metrics.

Tom Plant: I appreciate it. Thank you. Sorry to keep you for this short session, but I wanted your input.

Brian Turner: No problem. I appreciate the opportunity.

Ellen Kutzer: Hopefully not much redirect. Just one cleanup question. You discussed with Commissioner Plant using the VPP docket to derive values of VPP-specific resources, including ELCCs. Do you remember that exchange?

Brian Turner: Yes.

Ellen Kutzer: Some parties suggested the company made corrections to avoided cost calculations, including avoided distribution value and transmission adders, in this case. Is it your opinion that this is the right proceeding to make those corrections if there are errors?

Brian Turner: I distinguish between dispatchable distributed generation and VPP. The value of avoided generation, transmission, and distribution for the VPP should be decided in that case.

Brian Turner: One clarification. Regarding ELCC value and whether it should be determined in the DSP case, I would not support that. It needs to go with broader reliability modeling in the ERP or JTS in this case.

Ellen Kutzer: Thank you, Mr. Turner. No further questions.

Eric Blank: Thank you, Mr. Turner. You may be excused. Thanks for joining us. I think there were no questions for Mr. Wilson, is that correct, Ms. Kutzer?

Ellen Kutzer: I think we have questions from the Energy Office on my list, and we also have Mr. Pierce next before Mr. Wilson.

Eric Blank: I thought Mr. Bonis waived cross for Mr. Wilson.

Ellen Kutzer: That’s correct, Chair. Thanks. I missed that. Apologies.

Eric Blank: I think none of the commissioners had questions for Mr. Wilson, so he’s excused, correct, Commissioners Gilman and Plant?

Megan Gilman and Tom Plant: [No response, assumed agreement.]

Eric Blank: If we can bring up Mr. Pierce.

John Pierce: I’m trying to get on. Hold on a moment. There we go.

Eric Blank: 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?

John Pierce: I do.

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

John Pierce: No.

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

John Pierce: I will.

Eric Blank: Back to you, Ms. Kutzer.

Ellen Kutzer: Good afternoon, Mr. Pierce.

John Pierce: Good afternoon.

Ellen Kutzer: Could you please state and spell your name for the record?

John Pierce: John Pierce, J-O-H-N P-I-E-R-C-E.

Ellen Kutzer: By whom are you employed and in what capacity?

John Pierce: Kilpatrick Townsend and Stockton, a law firm, as a partner.

Ellen Kutzer: Have you caused to be pre-filed in this proceeding what’s been marked as Hearing Exhibit 2202, your answer testimony, and Hearing Exhibit 2207, your surrebuttal testimony?

John Pierce: I have.

Ellen Kutzer: If I asked you the same questions in those pre-filed testimonies today, would your answers be the same?

John Pierce: They would be.

Ellen Kutzer: Thank you, Mr. Pierce. The witness stands available for cross-examination.

Sam Eisenberg: I have 15 minutes. Good afternoon, Mr. Pierce.

John Pierce: Hi, good afternoon.

Sam Eisenberg: For the record, Sam Eisenberg. I represent Public Service in this matter. Mr. Pierce, you were not involved in the negotiations for any of the IP projects selected in the Public Service 2021 ERP and CEP, is that right?

John Pierce: I was not.

Sam Eisenberg: Could we pull up your answer testimony, Hearing Exhibit 2202, page 12? It should show up on the screen. There’s a list of several documents you reviewed in preparing your answer testimony. Did you see that?

John Pierce: I would have seen that, yes.

Sam Eisenberg: That list doesn’t include the company’s highly confidential filings in support of the Clean Energy Plan delivery plan. Did you review any of those filings?

John Pierce: I don’t believe I did, no.

Sam Eisenberg: It doesn’t list the company’s highly confidential PPA status updates filed in the same docket for the 2021 ERP and CEP. Did you review any of those?

John Pierce: I did not.

Sam Eisenberg: Did you review any actual PSCO PPAs signed from the 2021 ERP and CEP?

John Pierce: No.

Sam Eisenberg: Did you review any redline edits for those PPAs during their negotiations, either by IPs or Public Service?

John Pierce: I did not.

Sam Eisenberg: Let’s talk about your testimony regarding the conforming bid policy. I want to clarify COSA’s position in this proceeding. Is it COSA’s position that bidders should be able to submit redlines to the model PPAs?

John Pierce: That’s not my understanding. The idea is that there’s confusion. As I recall, Public Service wants conforming terms. Any comments on those aren’t redlines. Expecting bidders to forgo marking up documents in favor of agreeing to them, however qualified, and then redlining later seems confusing and outside the process I’m used to.

Sam Eisenberg: I’m trying to clarify COSA’s position, not the company’s. Is it COSA’s position that bidders should be allowed to submit redlines with their bids?

John Pierce: We’re dealing with specific issues within the documents, not specific redlines. We don’t represent any one seller or IP; it’s a consortium.

Sam Eisenberg: I understand, Mr. Pierce. I’m just asking, yes or no, is it COSA’s position that when a bidder submits a bid in the upcoming RFP, should they be allowed to submit redlines to the model PPA?

John Pierce: That wasn’t a question before me, stated as such.

Sam Eisenberg: Is COSA okay with a conforming bid policy where there are no redlines to the contract, so long as the terms listed in your testimony or attachment to your surrebuttal testimony are included?

John Pierce: Those are advisory, meant to reflect the association, not any one party participating in the RFP.

Sam Eisenberg: I’m asking about COSA’s position, not any potential bidder. COSA is opposed to the conforming bid policy, correct?

John Pierce: That’s correct.

Sam Eisenberg: The company would then model each bid based on the redlines submitted if there’s no conforming bid policy, right?

John Pierce: That’d be correct.

Sam Eisenberg: Is it COSA’s position that the company would have no ability to reject bids prior to computer modeling based on the redlines?

John Pierce: That’s not a question addressed to me previously.

Sam Eisenberg: Do you know COSA’s position on that?

John Pierce: I do not. I’d defer to their counsel.

Sam Eisenberg: Unfortunately, I can’t ask questions of counsel, only witnesses COSA puts forward. After selection, the company and the IP would negotiate the entire contract under COSA’s position, correct?

John Pierce: Correct.

Sam Eisenberg: Let’s talk about specific terms. Did you listen to COSA’s counsel’s cross-examination of Mr. Bornhofen?

John Pierce: I did, to substantial portions of it, yes.

Sam Eisenberg: You may recall counsel pointed out that in your answer testimony, Hearing Exhibit 2202, page 14, lines 13–16, you’re not endorsing sections of the contract just because you didn’t discuss them. Do you recall that?

John Pierce: That’s correct.

Sam Eisenberg: Does that include terms relating to rates for capacity and energy in the contract?

John Pierce: Those are subject to change from RFP issuance to PPA negotiation.

Sam Eisenberg: So, COSA’s position is that terms relating to rates for capacity and energy would be open for redlines and negotiation?

John Pierce: I would think so.

Sam Eisenberg: Same with performance requirement terms other than those described in your testimony?

John Pierce: Yes, for negotiation.

Sam Eisenberg: Same with terms relating to tax benefit qualification?

John Pierce: Yes, because it’s a movable target at the moment.

Sam Eisenberg: So, basically, everything’s up for negotiation or redline under COSA’s position?

John Pierce: Yes. These agreements are highly bespoke and negotiated. Successful ones are like that. Imposed terms typically don’t reflect the best aspects of a deal and result in issues.

Sam Eisenberg: It’s clear the company and IP trade organizations are somewhat far apart on this. Let’s discuss a path forward. If Public Service puts forward redline language in the model PPA, reflecting Mr. Bornhofen’s Exhibit JLB2 with its SOP, could COSA commit to putting forward its own redlines to model PPAs?

John Pierce: COSA doesn’t represent any one entity. Getting three dozen-plus entities to agree on a single redline would be outside the scope and very difficult. It wouldn’t reflect any one member’s perspective.

Sam Eisenberg: It would be possible for COSA to come up with redlines, but you couldn’t approve them as an entity due to COSA’s governance structure?

John Pierce: It’s the membership structure, governance, and resources available.

Sam Eisenberg: If PSCO filed redlines, could COSA respond within two weeks in a response SOP?

John Pierce: That’d be very difficult. Getting all members to respond timely would probably be challenging and wouldn’t reflect the association’s general views.

Sam Eisenberg: You put together a table in your surrebuttal testimony responding to Mr. Bornhofen’s table, critiquing his positions on various terms. Do those represent COSA’s position?

John Pierce: I believe so.

Sam Eisenberg: There were a few items where you couldn’t get full member input due to a confidentiality dispute, now resolved?

John Pierce: I did not. There were intervals where things were confidential that I didn’t have sight of. But now that the document is public, COSA could seek member input for a more defined position as part of the SOP, reflected in Exhibit 2205 and my rebuttals.

Sam Eisenberg: Thanks very much for your time, Mr. Pierce.

Megan Gilman: I don’t have any questions.

Tom Plant: I don’t have any questions either, Mr. Pierce. Given we’re looking to acquire thousands of megawatts from dozens, maybe many dozens, of projects, and assuming the commission shares the company’s concerns about giving individual developers the ability to propose specific contract terms, which could delay and complicate negotiations—since it took two years to sign contracts from the prior process—wouldn’t it be fairer, quicker, and simpler to have every project bid to the same model PPA structure?

John Pierce: That’s a matter of perspective. You’d likely end up with fewer bids. The industry is economically stratified between class-A developers and those with less economic ability to perform or get financing. Conforming terms make it harder for many entities to find financing or negotiate terms important to their economic success and willingness to bid.

Tom Plant: Isn’t the goal to get the cheapest and best resources online as quickly and fairly as possible, not to maximize the number of bids?

John Pierce: More bids increase the likelihood of successful projects. IPs have self-defined parameters and financing needs, differing from large to small entities. Conforming terms may lead to fewer bids, less to work with, and higher prices. Those with balance sheets will bid around market economics, possibly higher, not yielding the pricing you want with a conforming bid approach.

Tom Plant: Any advice on a process to get a fair contract? If the company proposes detailed contract language in the coming weeks, what would the follow-on process look like?

John Pierce: I don’t have a good answer. It depends on the process. Efforts at conforming bid documents have largely failed or been unsuccessful. Processes that work involve a first cut based on parameters, continually narrowing to a number of qualified bidders, then negotiating contracts to final form. I’ve not seen a conforming bid process yield adequate results.

Tom Plant: Doesn’t that process give the company a ton of discretion?

John Pierce: Yes, but they’re exercising discretion early in the conforming process. You have to give counterparties discretion to respond in a way they can support and perform, and this may not do that.

Ellen Kutzer: Thank you, Mr. Pierce. Just a few brief redirect questions. When Mr. Eisenberg asked about documents you reviewed, were you retained by COSA in the previous electric resource plan case?

John Pierce: I was not.

Ellen Kutzer: So, you did not execute a highly confidential non-disclosure agreement in that proceeding?

John Pierce: No.

Ellen Kutzer: Because of that, you do not have access to highly confidential documents filed in that prior proceeding?

John Pierce: Correct.

Ellen Kutzer: You touched on this with both counsel for Public Service and Chair Plant. Could you elaborate on why you did not submit a redline contract on behalf of COSA as part of your answer testimony?

John Pierce: Representing the association and its members, no single actor or member’s perspective would be reflected in a redline. It wouldn’t reflect the broader views of the membership or my views of the documents. When reviewing a contract, you review the whole, not specific terms. No single term dominates; they must be read as a whole to understand performance and execution.

Ellen Kutzer: On your surrebuttal response, is it fair to say the liquidated damages provision in section 12 of the model contract is still extremely problematic?

John Pierce: Yes. The emphasis on early damages, as opposed to reporting, recovery, and dealing with those early on, is damaging. Typically, you see larger liquidated damages later, where they impact the buyer, seller, and contract performance.

Ellen Kutzer: You’re speaking of early construction milestone liquidated damages?

John Pierce: That’s correct.

Ellen Kutzer: Would you say the lack of adequate change-in-law language is another major issue?

John Pierce: Yes. Change in law is a big issue for both sides. The risk must be negotiated, not planted on one side. Usually, there’s a process allowing both sides to understand impacts and negotiate equitable solutions, not just one side bearing the risk.

Ellen Kutzer: As you contemplate the company’s model contract, even as modified by Mr. Bornhofen’s rebuttal, does it reflect a typical contract available across the industry?

John Pierce: No. We’re working on large solar and battery projects in other jurisdictions that are very different, highly negotiated without required terms. Every aspect is up for negotiation, except perhaps scale, size, and certain technical matters.

Ellen Kutzer: Have you represented both IP and utility parties in contract negotiations?

John Pierce: I have.

Ellen Kutzer: No further questions.

Eric Blank: Thank you, Mr. Pierce. You may be excused.

John Pierce: Thank you.

Eric Blank: I think that’s it for COSA. Mr. Monson, can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Chris Monson: I do.

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

Chris Monson: No, they are not.

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

Chris Monson: I will.

Eric Blank: I have 20 minutes for Public Service Company, Mr. Larson.

Matt Larson: Thank you, Mr. Chair. Good afternoon, Mr. Monson.

Chris Monson: Good afternoon.

Matt Larson: For the record, I’m Matt Larson. I represent Public Service. You’re familiar with what was the triparty framework, now called the quad-party framework, correct?

Chris Monson: Yes, I am.

Matt Larson: I’d like to pull up the modified SJD9, marked as Hearing Exhibit 144. Mr. Monson, can you see that?

Chris Monson: Yes. If you could make it a little bigger, that would be helpful.

Matt Larson: Great, thanks. Have you had an opportunity to review this document?

Chris Monson: Yes, I have.

Matt Larson: Have you reviewed the changes to SJD9 reflected in Hearing Exhibit 144?

Chris Monson: If the changes are those discussed this morning, going from the triparty to the quad-party agreement, I’ve had a chance to look at those.

Matt Larson: Does CIEA support those changes and the quad-party framework?

Chris Monson: Yes, CIEA does.

Matt Larson: Thank you. We can take that down. I want to change gears. We agree on quite a bit in this proceeding between Public Service and CIEA, but one open issue is the conforming bid policy, which you addressed in your testimony, correct?

Chris Monson: Yes.

Matt Larson: CIEA opposes the conforming bid policy?

Chris Monson: It does.

Matt Larson: You also offered testimony on compensation for foregone PTCs, correct?

Chris Monson: Yes, I did.

Matt Larson: Are you aware that Public Service has taken the position that it’ll compensate for foregone PTCs if a conforming bid policy is approved?

Chris Monson: My understanding is the company agreed to provide compensation for foregone PTCs, but there’s potential confusion regarding the level of compensation with regard to tax gross-ups.

Matt Larson: Does that change CIEA’s position on a conforming bid policy?

Chris Monson: CIEA submitted two policy-related changes to the model PPA as part of the conforming bid policy. One related to compensation for PTCs under curtailment, the other to change in law.

Matt Larson: Are those the only two issues CIEA has with the conforming bid policy? If resolved, would CIEA agree to a conforming bid policy?

Chris Monson: No, not at all.

Matt Larson: Let’s pose a hypothetical. Assume a 500-megawatt wind generator, two identical projects bid differently. One is required to post security and forfeit it if the project doesn’t achieve commercial operation, while the other gets a free walk-away. You follow me so far?

Chris Monson: I think I’m following your hypothetical.

Jack Ihle: The projects are exactly the same, and that’s the only difference: one has a free walk away, and one has to post security and forfeit it if it’s not delivered. You’d agree with me these projects might be priced differently, wouldn’t you?

Mr. Monson: I thought the assumption was that they would be priced the same, that the only difference was the ability to walk away.

Jack Ihle: Let’s assume you’d agree with me that there’s less risk to the developer where there’s a free walk away than where you have to post security and forfeit that security, would you not?

Mr. Monson: The project that has the ability to walk away without paying a penalty or losing security would have less risk to the developer, that’s true. But it would potentially have more risk to customers depending on that project, isn’t that true?

Jack Ihle: There’s more risk to those customers depending on that project to be delivered, isn’t that true?

Mr. Monson: Assuming there’s a deep bid pool and the commission adopts CIA’s proposed shortlist process, there would likely be other projects that could step in and provide basically the same benefits as the project that steps away. But if there was no project that could step in when the other project walks away, then there’s more risk to customers, isn’t that true?

Jack Ihle: Yes, but it’s my understanding that solicitations are oversubscribed by between five and ten times the requested demand, so that would be a surprising result. What if the project went away very close to the commercial operation date that the company and customers were depending on? Don’t you think that increases the risk to customers and Public Service that the project with the free walk away won’t be delivered?

Mr. Monson: I believe it would be Public Service’s responsibility to negotiate a project that’s in the best interests of its customers. To the degree it couldn’t do that with a project that has the ability to walk away, it always has the opportunity to find another project early in the process.

Jack Ihle: So your testimony is essentially that we should allow any redlines to any contract, and if they can’t deliver, it becomes Public Service’s problem to solve, isn’t that right?

Mr. Monson: No, that’s not what I said at all. I believe my testimony is clear that specific, limited redlines should be allowed to the model PPA, but there are certain terms that should not be changeable through a redline process.

Jack Ihle: So CIA is willing to agree to some kind of limited conforming bid policy, is that your testimony?

Mr. Monson: I believe my testimony is that CIA would be comfortable with having certain terms and conditions not changeable, such as price, online date, point of interconnection, and term of the agreement. But bidders could provide specific redlines to the model PPA, not something like “to be determined during discussion,” and those would be provided as part of the bid. Public Service would be able to review those during the initial evaluation of bids at the end of phase one or beginning of phase two.

Jack Ihle: If Public Service didn’t agree to one of the redlines, should they be able to reject or disqualify that bid, or should they be forced to take and model the bid?

Mr. Monson: I believe Public Service would model the bid in the bid evaluation, consistent with the proposal the bidder made.

Jack Ihle: Coming back to the example of the 500-megawatt wind project with two commercially different terms and maybe different pricing based on the commercial terms and redlines provided, should Public Service just model both projects and let them compete against one another? Is that your testimony?

Mr. Monson: I don’t think I understand your question. Could you repeat it?

Jack Ihle: I’ll rephrase to make it clearer. Bidders should be able to provide any redline they want, and Public Service should model them through EnCompass and pick the portfolio selected by EnCompass on specific projects, regardless of whether the commercial terms deviate from one another. Is that right?

Mr. Monson: I already indicated that a certain limited amount of redlines should be associated with the bids that project developers make, but there would be certain terms that would not be changeable.

Jack Ihle: With respect to the terms that would be changeable, you’d agree with me that it could create issues with the comparability of those bids. You can’t compare them apples to apples, isn’t that true?

Mr. Monson: The evaluation of the bids would be based on the proposals the bidders make, so that’s what should be evaluated.

Jack Ihle: If you had a $25 per megawatt-hour wind project with a free walk away and a $30 per megawatt-hour wind project that has to post security, do you think those bids are comparable from a risk perspective to customers?

Mr. Monson: I don’t know.

Jack Ihle: Are you familiar with Rule 3616A in the commission’s ERP rules?

Unidentified Speaker: Objection, calling for a legal answer.

Jack Ihle: I’m not asking for a legal answer. I asked if he knew or has seen the rule. Can we call up the commission’s rules and go to Rule 3616A? I think it’s 412. I’m 85% confident in that number.

Unidentified Speaker: Yes, that’s it.

Jack Ihle: Can we go to 3616 on page 136? Mr. Monson, can you see that rule there?

Mr. Monson: Could you make it slightly larger, please? I think I can see it now.

Jack Ihle: I’ll give you a moment to read that and let me know when you’re done. This rule says that one of the reasons we provide model contracts as part of the ERP is to enhance bid comparability, isn’t that true?

Mr. Monson: I was still reading, but I’ll take your word for that.

Jack Ihle: Last couple of questions. Were you listening when Mr. Pierce testified on behalf of COSA?

Mr. Monson: I was.

Jack Ihle: If I want to talk about the same path forward that Mr. Eisenberg talked about with Mr. Pierce, if Public Service puts forward a redline reflecting the changes from Mr. Bornhofen’s attachment JLB2 and its SOP, can CIA commit to putting forward its own redline language as part of its statement of position?

Mr. Monson: I don’t think CIA would be able to do that for basically the same reason Mr. Pierce indicated. CIA represents a trade association, not a specific bidder or counterparty to that contract.

Jack Ihle: Thank you, Mr. Monson. I don’t have anything further.

Megan Gilman: Hi, Mr. Monson.

Mr. Monson: Hello.

Megan Gilman: I have one question regarding compensable curtailments and the differentiation in the tax gross-up, the way Public Service has proposed doing it, essentially giving an average gross-up based on the average tax rate across the board and not changing the curtailment order based on the actual value of the tax. Does that ring a bell for you?

Mr. Monson: I wasn’t listening to the hearing. I’ve heard this secondhand, but that’s about all I’ve heard.

Megan Gilman: It’s my understanding the current practice is that they rank in the dispatch stack by the actual cost or gale, which includes the tax gross-up based on the actual tax rate as described by the owner of the unit. Their proposal would use an average tax rate and no longer curtail in that specific order, providing everyone a generic tax gross-up for both federal and state tax. I’m assuming everyone has the same federal marginal tax rate, so that makes sense to me. I wanted to understand if you had any thoughts or feedback on that change. They described it as somewhat unfair wear and tear for those first in the order getting curtailed more. Are there arguments for one method versus the other?

Mr. Monson: It’s a tricky issue. Having a bunch of different generators with slightly different costs of curtailment because, although they probably have similar federal tax rates, they might have slightly different state tax rates, results in different places in the dispatch stack. The challenge is if you’re a bidder with a significantly higher marginal tax rate and you’re in this average price curtailment or compensation group, you’d have to reflect that potential loss of revenue in your bid. This is better than getting no compensation, but a bidder would need to figure out how much they think they’ll be curtailed and reflect that potential loss of revenue in their bid without a great sense of what that level of curtailment would be. It’s a small effect, but it’s probably real. Those are the trade-offs as I see it. Does that answer your question?

Megan Gilman: Yes, I’m just trying to understand what’s going on and the pros and cons. That’s my only question. Thanks.

Mr. Monson: Happy to help.

Tom Plant: I don’t have any questions. Thanks.

Eric Blank: Mr. Monson, I’m going to ask the same question I asked Mr. Pierce. Given that we’re looking to acquire thousands of megawatts in this process, likely requiring hundreds of bids, if this commission shares many of the company’s concerns about giving individual developers the ability to propose their own project-specific contract terms regarding security, credit support, liquidated damages, notice and cure, default, termination, force majeure, etc., wouldn’t it be fairer, quicker, and simpler to have every project bid to the same model PPA terms on these issues?

Mr. Monson: It’s a tricky issue, as discussed with Mr. Pierce. In the last ERP proceeding, things went remarkably slowly, and they’re still ongoing. CIA recognizes that and made proposals in my testimony to speed up the process, recognizing you don’t want to be in the same situation two years from now. That said, I’m not 100% sure the types of redlines proposed will be the real cause of potential delay. From what I understand, in the last solicitation, Public Service encouraged a lot of redlining in its solicitation documents, and there were slow turns on contract revisions. A number of issues came up, including bidders saying, “We’ll discuss this TBD provision,” which we recognize is a bad idea. By tightening up what bidders can put in as a redline, making them specific and clear, that would speed the process up.

Eric Blank: I don’t even get how the company models two bids with different prices and different force majeure, liquidated damages, notice and cure, default. How do they trade off between price and terms without an apples-to-apples comparison? How do you compare prices?

Mr. Monson: I haven’t been involved in that type of bid evaluation, so I couldn’t really respond to that.

Eric Blank: If this commission wanted a conforming model contract regarding all these terms, can you give me any advice about how we could get to a fair and balanced contract on these terms?

Mr. Monson: I suggested in my testimony that if you go down that road, there should be a separate phase or discussion associated with that, separate from this proceeding. You’ve got a timeline and a lot of potential resource needs to be met. If you’re trying to hammer out something parties can agree to, including bidders in those discussions, it would need to be separate from this proceeding where trade associations can’t represent individual bidders.

Eric Blank: Say the company filed something in a couple of weeks, and the IPPs had three weeks to respond with comments to help us get to market with a notice and comment process in the next month or two. Any thoughts on that?

Mr. Monson: That would be very difficult. You’d have to bring in a whole set of entities that haven’t been following closely and get comments from them. Two to three weeks seems tough to wrangle that large group together. CIA can’t make those recommendations, as Mr. Pierce indicated.

Eric Blank: What’s the alternative? The company files its model contract, the commission takes this record and tries to find the middle ground, puts that out for comment by all parties, and takes it from there? How do we move forward when what we did last time didn’t work?

Mr. Monson: I understand, and that’s why we’ve been trying to narrow down what bidders can offer in response. For example, we said limit the number of projects under a specific bid fee. It’s a hard question. Mr. Pierce has been more involved in the weeds on these model PPAs than I have, but I’d be concerned that strong bidders might decide to find opportunities elsewhere, which probably isn’t to the benefit of ratepayers.

Eric Blank: It’s a lousy answer, I know.

Mr. Monson: I’m not happy.

Mr. Detsky: Redirect. Mr. Monson, you were asked questions by Mr. Larson about comparability and apples-to-apples comparison with redlines. Do you recall that?

Mr. Monson: Yes.

Mr. Detsky: Is it hard to do an apples-to-apples comparison for utility ownership bids versus power purchase agreement bids?

Mr. Monson: If it’s just a single utility making those proposals, I think I’m not understanding your question.

Mr. Detsky: When a utility makes a bid for its own project versus a PPA project, are there significant differences in how those projects can be compared apples to apples?

Mr. Monson: Yes, absolutely.

Mr. Detsky: When you were asked about the conforming bid policy and explaining the nuances of CIA’s position, can you explain the difference between CIA saying you have to bid to the RFP but can redline the model PPA?

Mr. Monson: There’s been confusion about what the so-called conforming bid policy is. The model PPA is one part of the RFP, but there are other parts bidders have to respond to. CIA has been clear in my testimony and papers that bidders must respond to the RFP as written. If they don’t, Public Service can rule them nonconforming or try to get them to change. The place we’re concerned about is one portion of the RFP, the model PPA, since different companies have different views of what’s acceptable or unacceptable. As a trade organization, we couldn’t come up with changes to the model PPA.

Mr. Detsky: There was a discussion with Mr. Larson about whether Public Service could reject a bid. Did you testify that Public Service could reject a bid that seeks to make changes to RFP terms like pricing?

Mr. Monson: I indicated that if a bidder bids pricing, online date, and point of interconnection and then tries to change during contract negotiations, Public Service could move on to another bidder. Under CIA’s proposal to have a shortlist of projects, they would have other projects readily available to move to quickly.

Mr. Detsky: The chairman asked about the delay in the C and how long it took to resolve things. Did you testify regarding the major delay in PPA negotiations being the need for the delivery plan and repricing in the C?

Mr. Monson: That was a very big issue. We were in a high inflationary period, and coupling that with the long period between when bids were submitted and when negotiations were happening was a big issue.

Mr. Detsky: Is that one reason CIA proposed its shortlist and best and final offer process to bring more certainty to that part of the process?

Mr. Monson: Unfortunately, in the quad-party framework, the shortlist and best and final offer were not part of that. But we think it’s an important point. If it’s a year between when a bidder submits its bid and when they’re ordering equipment, a lot can happen. If a project is unviable because things have changed beyond their control, that doesn’t help anybody. That’s why we proposed this best and final offer process for bidders, not just in the preferred portfolio but for everyone on the shortlist, to create competitive tension.

Mr. Detsky: Did we also suggest that the shortlist time is a place where the company could make choices based on different redlines?

Mr. Monson: Exactly. In the last solicitation, there was a lot of discussion prior to portfolio selection regarding redlines. We think that’s a bad idea. Public Service can review those redlines, and once the commission adopts the preferred portfolio with the shortlist, they can look at which projects have more or less onerous redlines and pick the projects they believe they should negotiate with first.

Mr. Detsky: Last two questions. Are you an expert in PPA redline negotiation?

Mr. Monson: That’s not something I’ve spent any time on.

Mr. Detsky: Did CIA have an expert in PPA redlining in this case?

Mr. Monson: No, we didn’t.

Mr. Detsky: Thank you, Mr. Monson. That’s all I have. Mr. Chairman, I have one extra matter to discuss.

Eric Blank: Should I excuse Mr. Monson?

Mr. Detsky: Yes.

Eric Blank: Mr. Monson, you may be excused. Thank you for joining us, sir.

Mr. Monson: Thank you.

Mr. Detsky: Mr. Chair, when one of his first questions, Mr. Larson said something to the effect that the company’s withdrawal of the compensable curtailment position was conditioned upon acceptance of the conforming bid policy. That was not my understanding of Mr. Bornhofen’s testimony. They withdrew the claim without conditions, except for their claim about the federal marginal tax rate averaging. I think my request is that Mr. Larson’s references to that be stricken from the record as not reflective of the company’s testimony and position.

Eric Blank: I don’t think a motion to strike is appropriate, but it would be helpful to the record if the company would clarify its position. I agree with Mr. Detsky’s characterization of Mr. Bornhofen’s testimony, but I didn’t hear you reverse that in your boss. Mr. Larson, can the company clarify its position?

Matt Larson: My intention in posing the question to Mr. Monson was not to change the company’s position. The company is going to withdraw its proposal to not compensate for foregone PTCs, so long as the commission approves that change.

Eric Blank: That’s helpful. Thank you. Mr. Chair, while I’m on, we’re going to waive Mr. Sanger for Interwest, and we may be the only cross-examination there.

Unidentified Speaker: Just let me check. Commissioner Plant, Commissioner Gilman, are you all right going till 6 or 6:30 tonight? We still have about seven hours of cross left, and I don’t think we have anybody to go beyond tomorrow. Are you willing to keep going?

Tom Plant: I am, and I don’t have anything for Sanger if you’re okay.

Megan Gilman: I don’t either. I’m just going to ask the same question.

Eric Blank: Miss Whitman, thank you. Given that it’s about 5:00, I’m curious whether you believe we’ll get to Wade Buchanan this evening, given that we’ve got about an hour or so of testimony left. If not, I’m going to cut him loose.

Unidentified Speaker: You can cut him loose. We’ll plan to have him available tomorrow morning.

Eric Blank: Thank you very much. My day is ending. I’m sorry, guys, but I’ve got 700 pages to do next week. We’ll do the rest of it from the tape. Thanks, Miss Wisenthaw.

Unidentified Speaker: My hands are fine.

Eric Blank: Mr. Sanger, can you hold up your hand and come off mute? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Irene Sanger: Yes, I do.

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

Irene Sanger: Not other than yourself, sir.

Eric Blank: If that changes, let us know.

Chris Leger: If you can do this quick, thank you. Could you please state and spell your name for the record?

Irene Sanger: Irene Sanger, I-R-I-O-N S-A-N-G-E-R.

Chris Leger: Did you cause to be filed what has been entered into the record as exhibits 500 and 502 as your answer and cross-answer testimonies?

Irene Sanger: Yes.

Chris Leger: Mr. Sanger is available for questions. Just one question, the same one I asked the other IPP witnesses regarding security, credit support, liquidated damages, notice and cure, default, termination, force majeure. Do you think we can get to a conforming model contract, and would you be willing to live with that? Any concerns, thoughts?

Irene Sanger: There’s an assumption that you need a pure apples-to-apples comparison with a pro forma conforming contract, and there’s a view that that might provide difficulty in analyzing results. What I see being recommended by independent power producer organizations is what’s generally done in RFPs throughout the western United States. Somebody submits a bid with a price attached based on the contract terms they obligate themselves to. Utilities are skilled at evaluating bids with different force majeure provisions and security requirements. The process being proposed in opposition to the conforming bid policy is fairly standard. Requiring everyone to submit a bid tied to a specific PPA form is unusual and unnecessary for the utility to evaluate different terms and conditions.

Chris Leger: Are there form PPAs in this record that document that view of the world?

Irene Sanger: We have the RFPs we cite to. They’re based on that form of analysis. I don’t know if the RFPs themselves are in the record, but we can provide that information.

Chris Leger: That would be helpful. What’s the downside to making common terms on all those issues so you get an apples-to-apples bid? It’s easier to replicate, you don’t spend two years sorting through this, and it takes a lot of discretion from the company. Here’s the terms we all agree are market. There may be concerns where the utility is at now. Why shouldn’t we just do that?

Irene Sanger: What you’re addressing is a legitimate concern when you don’t have fixed contract terms. It can make a process longer. In my experience, that’s always what’s done. Having a locked-in conforming bid policy is very unusual. The risk is that you get one apple at the end, and the utility might want something that provides a different type of value. One place a commission can go is to identify what provisions can be modified and what can’t. If you do not adopt a conforming bid policy, bidders should take away that this is the contract form desired by Public Service, and they should make adjustments that aren’t wholesale redlining. In other RFPs, the utility has its preferred contract, there’s some litigation over terms, and regulatory commissions decide what’s okay, but bidders start with that contract form. They’re not bringing in completely different PPAs. We’re talking about adjustments, like delivering at an 80% availability guarantee rather than 90%, with adjustments elsewhere in the contract.

Chris Leger: Any advice about how to get to a more market set of terms, assuming we move strongly in the direction of a conforming bid policy?

Irene Sanger: If you move strongly in that direction, I’d adopt all the proposals by the independent power producer organizations to get rid of the low-hanging fruit. In contract negotiations, there’s give and take. One bidder might like a force majeure provision similar to what the company wants, another may not, but they might have something else they don’t like. It’s difficult for a wide group with different business models to come up with one form. What you’re hearing is that these are the most problematic provisions. If you adopt a conforming bid approach, for each item raised as a concern, adopt the Independent Power Producer Association’s position or say it’s a negotiable term.

Chris Leger: I have no redirect. Thank you, Mr. Sanger. Appreciate you.

Eric Blank: Where are we? The next witness is Miss Miller, right? Miss Miller, can you hold up your right hand? Do you swear to tell the truth, the whole truth, and nothing but the truth?

Miss Miller: I do.

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

Miss Miller: No.

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

Miss Miller: Yes.

Mr. Ghart: Miss Miller’s testimony is already in the record, so she is available for cross-examination.

Frances Consilia: Thank you, Mr. Chair. Miss Miller, I don’t think we’ve met before. My name is Frances Consilia, and I represent the City of Pueblo, the County of Pueblo, and Pueblo Economic Development Corporation in this proceeding. Good evening, and thank you for your flexibility in waiting.

Miss Miller: Thank you.

Frances Consilia: You filed only cross-answer testimony in this case, correct?

Miss Miller: Yes.

Frances Consilia: You essentially have three positions. Your first position is that the settlement agreement entered into in the 2021 C proceeding prohibits the addition of modeling credits or the CCFD approach, the carbon fuel futures, correct?

Miss Miller: I wouldn’t say the settlement agreement prohibited those things, but rather they seek to reopen issues that were resolved in the settlement.

Frances Consilia: Your position is that the settlement did not include those two items, and therefore it’s improper to consider them in this just transition solicitation, correct?

Miss Miller: Those two items seek to address issues that were addressed in the settlement agreement, so this would be introducing new ways of resolving issues.

Frances Consilia: Your third argument is that my cross-examination of a Vote Solar witness waived the ability of my current clients to ask to have bonus credits considered or the CCFD, correct?

Miss Miller: I wouldn’t characterize my testimony like that. I stated there were inconsistencies between parties who were on the settlement agreement and what is currently being proposed in this proceeding that was a result of the settlement agreement.

Frances Consilia: You specifically referenced a cross-examination that I did of a Vote Solar witness as being an implied waiver of rights.

Unidentified Speaker: Your honor, I’m going to object that misstates the witness’s testimony. The witness’s testimony never uses the word “waiver” and never claims there was a waiver of rights.

Frances Consilia: Miss Miller, what is your position with respect to the cross-examination that I did and how it bound my clients to a position?

Miss Miller: I don’t believe my testimony was seeking to bind any parties. We entered into the same settlement agreement, and that is what we collectively are bound to, the terms we agreed to. I was using the record to demonstrate what the conversation had been about around key issues, including how we would incentivize resources to be located in communities and how resources would compete against each other, using the transcript and other pieces of the record to illustrate that those issues were resolved. Now some parties and the company are seeking to relitigate certain pieces of the settlement agreement.

Frances Consilia: Were you involved in the C proceeding?

Miss Miller: Yes.

Frances Consilia: How much time did you spend putting together your cross-answer testimony and the exhibits?

Miss Miller: I don’t have an estimate offhand. A week, maybe.

Frances Consilia: Were you acting on behalf of NRDC, the Sierra Club, or the two entities together when you put together your cross-answer testimony?

Miss Miller: We are intervening together as the Conservation Coalition, and that is the testimony.

Frances Consilia: Is there a process whereby the Sierra Club and NRDC vet your testimony and approve it?

Miss Miller: I certainly have review between different staff members, yes.

Frances Consilia: You testified that had these terms, meaning the coal community bonus credits and the CCFD, been included in the settlement, the Conservation Coalition would not have signed on to the non-unanimous settlement, correct?

Miss Miller: Correct.

Frances Consilia: How did you arrive at that conclusion? Did you talk to supervisors or board members at NRDC or Sierra Club?

Miss Miller: As the bonus credits and CCFD are being proposed, we are opposed to them. It’s a bit of a hypothetical, but with our current opposition, we would have likely been opposed in the settlement.

Frances Consilia: The purpose of the payment in lieu of taxes, netted out for any investments in the 2021 settlement, was to drive investments into the coal communities, correct?

Miss Miller: Yes.

Frances Consilia: Your position is that by not including a bonus credit component in that settlement agreement, it cannot now be added into this modeling proposal?

Miss Miller: My position is that the settlement agreement offered a very specific mechanism by which we would incentivize resources to be located in coal communities, that is, the offset of property taxes and community assistance payments. That’s a specific mechanism. Bonus credits were never contemplated, discussed, or proposed in the settlement conversations, agreement, or what was approved by the PUC. It’s an entirely different mechanism to incentivize resources in coal communities, reopening an issue we believe was resolved in the settlement and approved by the PUC.

Frances Consilia: Were you involved in the settlement negotiations or the case with Tri-State recently, their clean energy plan?

Miss Miller: We are intervening in that proceeding as well, yes.

Frances Consilia: Were you personally involved in that proceeding?

Miss Miller: Yes, I have been.

Frances Consilia: The Conservation Coalition had no objection to bonus credits in that settlement agreement, correct?

Unidentified Speaker: Objection, the question assumes facts not in evidence. The Tri-State settlement doesn’t include bonus credits like the credits here, so it’s assuming facts that don’t exist.

Frances Consilia: Are there any provisions for bonus credits in the settlement agreement with Tri-State?

Miss Miller: Not that I’m recalling right now, but I would need to review that.

Frances Consilia: Is the Conservation Coalition objecting to bonus credits for coal communities as a position of principle or policy?

Miss Miller: There’s the principle about the settlement agreement; it wasn’t in the settlement, and that’s reopening that. As I state in my testimony, I think it’s unfair to reopen certain provisions that some parties want to see now and not others. Primarily, we have three reasons for opposing the bonus credits. One, there’s no evidence they’re needed to achieve the stated outcomes, and what we agreed to in the settlement is insufficient. Second, they’re completely arbitrary numbers; there’s been no quantitative study on the amounts or why they were selected. The company testified they were done with scratch work, and we haven’t seen that analysis. Third, there’s no analysis on the impact, so the costs could be high, but we don’t know because there hasn’t been modeling in phase one, and the company said they won’t do it in phase two. It’s pushing the model to select more expensive resources that will come at a cost to customers, and we don’t have evidence that it’s necessary or what it will result in.

Frances Consilia: You state in your testimony that in proceeding 21A-0141E, did Pueblo County’s attorney imply that PSCO’s ratepayers should not have to pay more money for just transition than what was included in the settlement agreement? Do you recall that?

Miss Miller: Yes.

Frances Consilia: The implication you claim is based on your interpretation of cross-examination in that proceeding, correct?

Miss Miller: Yes.

Frances Consilia: Have you ever heard of anyone taking a position that a lawyer’s cross-examination can imply a limitation on a settlement term?

Miss Miller: As we discussed at the beginning, it was not my intent, nor do I think I said in my testimony, that it would limit Pueblo’s position. I was illustrating what the conversation had been around how we arrived at the tax offset, citing company testimony and other places as well, drawing from the record to illustrate the decisions made at the time that created this proceeding.

Frances Consilia: You quote from my cross-examination for about two pages, and you use the word “imply,” correct?

Miss Miller: Yes.

Frances Consilia: In the 2021 proceeding, I was representing only Pueblo County, correct?

Miss Miller: I’ll take your word for that.

Frances Consilia: In this proceeding, I’m representing the City, the County, and Pueblo Economic Development Corporation, correct?

Miss Miller: I understand.

Frances Consilia: Is it your position that when I was the lawyer for the County, I could, in cross-examination, imply that certain elements were going to be excluded from the settlement agreement?

Miss Miller: Could you restate or repeat that last part?

Frances Consilia: Is it your testimony that I, as the attorney for Pueblo County, could imply that these bonus credits could not be included in this solicitation?

Miss Miller: Are you a lawyer, Miss Miller?

Frances Consilia: I know.

Miss Miller: Are you a lawyer?

Frances Consilia: I don’t need a lecture on cross-examination. Let me ask you again if your testimony—

Unidentified Speaker: I’m going to object that that’s really not appropriate editorializing. If Miss Consilia has questions, she can ask questions, but those statements are not appropriate.

Frances Consilia: I will move on. Your statement was clear. How could I, as the lawyer for Pueblo County, impliedly limit what the City could ask for, whom I was not representing?

Unidentified Speaker: I’m going to object once again that Miss Consilia is repeatedly mischaracterizing the witness’s testimony, which never claimed Pueblo had waived legal rights. Instead, the witness pointed out inconsistencies between positions taken in the last case and this case. Miss Consilia is welcome to ask about her actual testimony but not things she didn’t testify to.

Frances Consilia: Let’s pull up hearing exhibit 802, page 15. The question there in your testimony is, in proceeding number 21A-0141E, did Pueblo County’s attorney imply that PSCO’s ratepayers should not have to pay more money for just transition than what was included in the settlement agreement? Your answer is yes, and then you quote from the transcript, correct?

Miss Miller: Yes.

Frances Consilia: Did that implication of ratepayers not having to pay more money than what was in the settlement agreement also bind the City, whom I was not representing at the time?

Miss Miller: I’m struggling with the word “bind.” That’s not what I put forward. I was looking at the record between what Pueblo County agreed to in the settlement agreement and conversations around specific mechanisms for a just transition and interpreted that as a disagreement with a witness asking for more provisions on just transition. Others might interpret that differently, but the record speaks for itself. I’m happy to walk through what I cited, but I believe you’re presenting Pueblo County’s opposition to Vote Solar’s ask for additional provisions on just transition.

Frances Consilia: One of the things Vote Solar asked for, and Miss Krisco had never been to Pueblo, to my recollection, but one thing they recommended was an economic development fund, and Pueblo already had one. Do you recall reading that in the transcript?

Miss Miller: Yes.

Frances Consilia: Did you listen to the testimony of Mr. Miscoco from Hayden earlier this afternoon?

Miss Miller: I caught some of it.

Frances Consilia: Did you catch the part about how desperate that community is, concerned about the loss of coal jobs and how they cannot develop other commercial businesses to replace the tax base of the jobs?

Miss Miller: I understand the general concerns from the community.

Frances Consilia: If the lack of bonus credits reduces the chances of these projects being built in coal communities, would you still oppose them as they have been proposed?

Miss Miller: We urge the commission to reject them. We haven’t seen evidence they’re needed. I’d like to see that analysis. It would be interesting and important to know whether the mechanism we agreed to in the settlement for offsetting tax payments is sufficient. I don’t have reason to believe it’s not, and I haven’t seen anything from the company. These numbers are completely arbitrary.

Frances Consilia: Can you pull up exhibit 1223 and hearing exhibit 1224? Miss Miller, are you aware that Public Service laid out to a large group of stakeholders the concept of these just transition bonus credits? Were you aware whether Public Service laid out last year the possibility of these bonus credits being included in this just transition solicitation?

Miss Miller: I don’t recall the stakeholdering that went into it.

Frances Consilia: What’s in front of you is hearing exhibit 1223. If you can scroll down, this is an email from Mr. Piscuchi to several people, including Mr. Ghart. Do you see that?

Miss Miller: I see the email.

Frances Consilia: If we can pull up exhibit 1224, page one is just transition benefits modeling at $3 a megawatt hour, correct?

Miss Miller: Yes.

Frances Consilia: Can we go to page two, which is the workforce commitment, page three? Assuming I’m correct that Mr. Ghart and the Conservation Coalition got a copy of this exhibit and did not object to this potential bid credit, can we say that—

Unidentified Speaker: Objection, the question assumes facts not in evidence. She’s asking the witness about whether I received a copy and whether I objected. For one, I can tell you we opposed this when Public Service alerted us to it, but it’s not appropriate to ask the witness about whether I, as an attorney, received this document and my position on it.

Frances Consilia: She believes you impliedly had no objection to this. Go ahead, Miss Miller.

Miss Miller: I don’t know what the conversations were around that. I’d point out that I don’t think that’s how you change a settlement agreement through email conversations. Various other parties have opposed these issues. There were recommended changes. I don’t know the full count of who was on the settlement agreement, but we were on the settlement, and we don’t support the bonus credits.

Frances Consilia: I have no further questions.

Megan Gilman: Commissioner Gilman, questions for Miss Miller?

Matt Larson: Mr. Chair, I believe we had moved some time around in the final cross. I think we only have five or ten minutes. My apologies.

Eric Blank: It’ll be brief.

Matt Larson: Good evening, Miss Miller.

Miss Miller: Hello.

Matt Larson: Nice to see you again. I’m Matt Larson on behalf of Public Service. I want to talk about the bonus credits and then the carbon-free future development. In your cross-answer testimony, hearing exhibit 802, you call the just transition bonus credits “an entirely different mechanism for incentivizing resources in certain communities” than approaches in the updated settlement agreement, correct?

Miss Miller: Yes.

Matt Larson: The updated settlement agreement, which the Conservation Coalition supported, includes payments in lieu of property taxes for just transition communities, isn’t that true?

Miss Miller: Yes.

Matt Larson: You all support that approach, isn’t that true?

Miss Miller: Yes.

Matt Larson: When you say “entirely different,” you’re not insinuating that the bonus credits take the place of the payments, are you?

Miss Miller: No, my understanding is that there would still be payments.

Matt Larson: Any replacement generation in the community can offset those community assistance payments under the settlement, isn’t that true?

Miss Miller: Yes.

Matt Larson: If just transition bonus credits drive a resource into a community, that same offset would apply, isn’t that true?

Miss Miller: Yes, the offset would still apply.

Matt Larson: The offset applies regardless of whether the bonus credit is the dispositive factor in driving the resource into the community or not, isn’t that true?

Miss Miller: Yes.

Matt Larson: So the bonus credits are additive to the terms of the settlement agreement, isn’t that true?

Miss Miller: Yes, they are an additional mechanism to drive investment in a community, but they don’t obviate the other mechanism in the settlement agreement in any way, that’s my understanding.

Matt Larson: Flipping over to carbon-free future development, in your cross-answer, you take the position that the carbon-free future development approach, or CFFD, conflicts with the requirement that the JTS be an all-source competitive solicitation, isn’t that true?

Miss Miller: Yes.

Eric Blank (Chairman): Have you been watching all of this hearing? It's been lengthy, but are you familiar with the JTS Phase 2 framework that the company has worked on with staff, CIA, and now Colorado Energy Office, conceptually, not in all the details?

Miss Miller: Conceptually, not in all the details.

Eric Blank (Chairman): The JTS base RFP is an all-source solicitation. Isn't that true?

Miss Miller: Yes.

Eric Blank (Chairman): The JTS supplemental RFP is an all-source solicitation. Isn't that true?

Miss Miller: Yes.

Eric Blank (Chairman): So, there are two all-source solicitations in this JTS. Isn't that true?

Miss Miller: Yes.

Eric Blank (Chairman): The CFFD rolling approach that the company has proposed operates completely outside of those all-source solicitations. Isn't that true?

Miss Miller: Yes.

Eric Blank (Chairman): Thank you, Mr. Chair. Thank you, Miss Miller. Nothing further.

Matt Larson: Thank you, Mr. Larson. Commissioner Gilman?

Megan Gilman: I don't have any questions. Thanks.

Matt Larson: Commissioner Plant?

Tom Plant: Sorry, I don't have any questions either. Thanks.

Eric Blank (Chairman): Nor do I. Mr. Ghart, redirect?

Mr. Ghart: Sure, just a few questions. On the CFFD, you were asked a few questions about that by Mr. Larson. Do you recall that?

Miss Miller: Yes.

Mr. Ghart: Can you explain your concern about how you think the CFFD is inconsistent with the language in the settlement about all-source solicitations?

Miss Miller: My understanding of the proposed fund is that it would fund certain types of technologies and not others. So, other resources wouldn't be able to compete against the specified technologies. It is not all-source; it's for a limited set of technologies, which are also speculative, pretty risky at this point, and pretty expensive. I think it's a big risk to customers.

Mr. Ghart: Mr. Larson asked you questions about the JTS bonus credits being proposed in this case, whether they are additive and separate from the modeling property tax offset approach in the last ERP settlement. Do you recall those questions?

Miss Miller: Yes.

Mr. Ghart: Is part of your concern the fact that they are additive and separate, that there's been no showing made by the company that the property tax offset approach in the settlement is insufficient?

Miss Miller: Precisely, yes.

Mr. Ghart: So, if there were a portfolio that didn't include the new JTS bonus credits, it would still include the mechanism from the prior settlement to incentivize resources in coal communities?

Miss Miller: Yes, it would still allow for the property tax offset to reduce the total cost for the company to incentivize the resource to locate in those communities.

Mr. Ghart: One last question, Miss Miller. What are you recommending the commission decide with respect to the JTS bonus credits proposed here?

Miss Miller: Our primary recommendation is to reject them. As we've discussed, there's no evidence that they're needed. The money amounts dedicated for them are arbitrary, and we haven't had any analysis on what impact they will have for cost or resources. At a minimum, we'd like to see them modeled against portfolios without them so that we can know some of those impacts to rates, resources, and cost.

Mr. Ghart: Thank you. I have no further questions, Mr. Chair.

Eric Blank (Chairman): Miss Miller, thanks for joining us. You may be excused. I think we'll do one more witness, Mr. Jameson Valdez, and then we'll call it a night. Mr. Leger?

Chris Leger: Apologies, I hope this doesn't take more than a minute. Going over my notes, in your discussion with our witness, Irene Sanger, would you like us to put into the record all of the RFPs cited in her answer testimony to guide your decision on this? They are likely very voluminous, so I don't know if they're really that useful to you, but they are already all linked within exhibit 500. We'd be happy to do whatever way you'd like us to.

Eric Blank (Chairman): I think the links are enough. Thank you.

Chris Leger: Thank you.

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

Jameson Valdez: I do.

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

Jameson Valdez: No, sir.

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

Jameson Valdez: I will, yes.

Eric Blank (Chairman): Back to counsel.

Unidentified Speaker: Thank you, Mr. Chair. Good evening, Mr. Valdez. Can you please state and spell your name for the record?

Jameson Valdez: My name is Jameson Valdez, J-A-M-I-S-O-N V-A-L-D-E-Z.

Unidentified Speaker: Are you testifying on behalf of the Environmental Justice Coalition?

Jameson Valdez: Yes, I am.

Unidentified Speaker: Who are you employed by, and in what capacity?

Jameson Valdez: I'm employed by Roots to Resilience as the executive director.

Unidentified Speaker: Is Roots to Resilience one of the nonprofit organizations in the Environmental Justice Coalition?

Jameson Valdez: Yes, it is.

Unidentified Speaker: Great. Mr. Valdez's pre-filed testimony has already been admitted into evidence, and he's available for cross-examination. Miss Concia?

Miss Concia/Consilia: It's 5:38, and you've got 20 minutes. Hopefully, I'll make it shorter than that because I know everybody's anxious to leave. It's been a very long day. Hello, Mr. Valdez, how are you doing today? We haven't seen each other for a while.

Jameson Valdez: I'm good, thanks. How are you doing?

Miss Concia/Consilia: We are all tired. We've been doing this since 7:30 this morning. Mr. Valdez, I hope you haven't been waiting for us that long.

Jameson Valdez: I definitely have been checking in very often.

Miss Concia/Consilia: I want to discuss with you, Mr. Valdez, your very passionate objection to a new natural gas plant in Pueblo or even the possibility of discussing advanced nuclear. That's what we're going to talk about a little. You've attached the Pueblo Innovative Energy Solutions Advisory Committee report to your testimony, and I'd also attached it to Mr. Shaw's testimony. I'm assuming you have read it.

Jameson Valdez: I have, yes.

Miss Concia/Consilia: Did you read any of the presentations that Public Service posted on their website about the things that were considered?

Jameson Valdez: I don't think so, no.

Miss Concia/Consilia: You object to the approach that was taken in the PISAC report. Is that correct?

Jameson Valdez: Yes.

Miss Concia/Consilia: Let's talk about first who was involved in the PISAC report. To make sure my memory is correct, Mr. Jeff Shaw, who proffered this as part of his testimony, was involved. Did you think Mr. Shaw was not an adequate representative for the community being involved?

Jameson Valdez: I point out in my testimony that the PISAC committee represented mostly business interests in Pueblo. I include Mr. Shaw as a business interest since he represents Pueblo Economic Development Corporation.

Miss Concia/Consilia: Corine Kohler was a co-chair. Do you regard her as a business representative?

Jameson Valdez: I'm not familiar with her.

Miss Concia/Consilia: You're not aware that she was on city council and has been active in historic preservation?

Jameson Valdez: I was not.

Miss Concia/Consilia: Jerry Bella, from the regional manager for the International Electrical Association, was a representative on the committee. Did you object to Mr. Bella's involvement?

Jameson Valdez: I don't believe I objected to anyone's involvement. What I objected to was the lack of involvement from certain voices, voices of the community.

Miss Concia/Consilia: You believe, though, that the committee was primarily business interests. Correct?

Jameson Valdez: I would say, yeah, that's pretty accurate.

Miss Concia/Consilia: Mr. Bella, as a member in leadership of the IBEW, that's not representative of a business interest, do you think?

Jameson Valdez: I would say yes. The IBEW represents workers, and oftentimes the workers represent the corporation for which they work as well as the union.

Miss Concia/Consilia: Do you believe that Sarah Blackhurst, who's head of Action Colorado, is a representative of the business interests?

Jameson Valdez: Yes.

Miss Concia/Consilia: Why is that?

Jameson Valdez: I don't know her very well, but what I do know of her has all been as a CEO of various organizations or corporations.

Miss Concia/Consilia: Russell Dalvo, who's head of Pueblo Plex, do you regard him as being a business interest to some degree?

Jameson Valdez: Definitely not. Environmental justice voice community.

Miss Concia/Consilia: Patty Herj Vic, who was until recently head of Pueblo Community College, do you regard her as also being a business interest?

Jameson Valdez: Yes, insofar as education is a type of business.

Miss Concia/Consilia: Dennis Mays, the former district court judge from Pueblo who now serves on the District 60 school board, do you regard Judge Mays as being a representative of the business interests?

Jameson Valdez: Not necessarily. Again, I said mostly.

Miss Concia/Consilia: What about Dr. Mate, who at that time was president of CSU Pueblo? Is he a representative of the business interests?

Jameson Valdez: I'm not familiar with him, but again, I said mostly.

Miss Concia/Consilia: Dwayne Nava, who is head of the Pueblo Chamber of Commerce, do you regard Dwayne as a representative of business interests?

Jameson Valdez: As head of the Chamber of Commerce, absolutely.

Miss Concia/Consilia: What about Chris Weissman, who's a former county commissioner?

Jameson Valdez: My understanding is that Chris, former Commissioner Weissman, was also a businessman prior to being county commissioner.

Miss Concia/Consilia: He was executive director of the state fair. Is that a business interest?

Jameson Valdez: I would say yes, definitely focused on commerce.

Miss Concia/Consilia: One of the things that the PISAC committee did was community outreach. There were meetings at churches, there were focus groups. Did you attend any of those?

Jack Ihle: Mr. Chair, this question assumes facts not in evidence. You can restate.

Miss Concia/Consilia: Are you aware of whether or not the PISAC committee had outreach to various community members?

Jameson Valdez: Yes.

Miss Concia/Consilia: What is your understanding of what that outreach was?

Jameson Valdez: There was at least one focus group, and from what I read in the PISAC report, there were a couple of open house events. I know from the PISAC report that there were also some other types of outreaches, but I don't remember what they were right now. All I'm aware of is the focus group I participated in and the two open houses I attended.

Miss Concia/Consilia: Do you object, Mr. Valdez, to the report or the lack of involvement of somebody from what you call the environmental justice community?

Jameson Valdez: Do you object to both of those things, or—I'm sorry, can you repeat the question?

Miss Concia/Consilia: Sure, it was a confusing question, and I asked it in multiple parts. I apologize. Did you object to any of the substance in the report?

Jameson Valdez: I did, yes.

Miss Concia/Consilia: What was that?

Jameson Valdez: The analysis of what energy generation resources would be best for our community.

Miss Concia/Consilia: Back in 2021, Pueblo County had a nuclear town hall. Do you remember that?

Jameson Valdez: I do.

Miss Concia/Consilia: Did you attend that?

Jameson Valdez: No. To my understanding, it was invitation-only.

Miss Concia/Consilia: How did you hear about it?

Jameson Valdez: I heard about it after the fact by a friend of mine who attended it by invitation.

Miss Concia/Consilia: Shortly after that, in fact, in January of 2022, Chris Weissman put together an energy committee to discuss the kinds of energy that would be replacing Comanche. You recall that?

Jameson Valdez: I do.

Miss Concia/Consilia: You were asked to be a member of that committee. Correct?

Jameson Valdez: Correct.

Miss Concia/Consilia: That committee only had two meetings. Is that correct?

Jameson Valdez: To the best of my recollection, yes.

Miss Concia/Consilia: Chris Weissman hired a professional facilitator to run the meeting. Do you recall that?

Jameson Valdez: I think so, yes.

Miss Concia/Consilia: There was no agreement on format or purpose, and so the committee was disbanded after two meetings. Is that correct?

Jameson Valdez: Yes, that's what I remember.

Miss Concia/Consilia: Isn't one of the reasons it was disbanded, Mr. Valdez, because you refused to even discuss the possibility of having advanced nuclear or a new natural gas plant in the community?

Jameson Valdez: No.

Miss Concia/Consilia: What is your understanding about why it was disbanded?

Jameson Valdez: Just like you said, there was no agreement on the agenda, the purpose, the direction of the committee.

Miss Concia/Consilia: Even though former Commissioner Weissman was hoping to dedicate the following year, the committee disbanded after two meetings. Correct?

Jack Ihle: Objection, Mr. Chair. This question assumes facts not in evidence about Mr. Weissman's intention. You could rephrase, Miss Consilia.

Miss Concia/Consilia: Let me actually get an exhibit up. If we can go to my exhibit box and pull up exhibit 1222. This is an article from the Chieftain that's dated November 5th, 2021. It says, "Pueblo County Commissioner to evaluate Comanche plant replacements through energy board." Did you read this article about the time in November?

Jameson Valdez: I don't remember this article.

Miss Concia/Consilia: Mr. Weissman says here, "We're going to be looking at every energy source possible from what we're doing here in Pueblo County on solar." And he lays out some other things. Is that your understanding of what he was trying to do with his energy committee?

Jack Ihle: Mr. Chair, Miss Consilia has not laid a proper foundation for this exhibit. Mr. Valdez has not reviewed it, she's not moved it into evidence. I think it's improper to be asking substantive questions at this point about this exhibit.

Eric Blank (Chairman): I overrule. I think she's in the process of trying to lay a foundation, and if she moves to admit it, we'll see where we're at. So keep going.

Miss Concia/Consilia: Thank you. If you can scroll down a bit, it says, "We're going to be looking at every energy source possible." And then he mentions green hydrogen. Was that your understanding of what the committee was to look at when it commenced its meetings the following year?

Jameson Valdez: Yes, in basic terms, yes.

Miss Concia/Consilia: If we go down a little further, Mr. Weissman, then commissioner, said he absolutely plans on involving those who oppose nuclear energy as well as those who consider it a viable option on the energy board. So, you were asked to participate because Mr. Weissman knew you opposed nuclear energy. Correct?

Jameson Valdez: I'm not sure exactly why he asked me. He never gave a reason.

Miss Concia/Consilia: At any time in those committee meetings, did you accuse former workers or current workers of Public Service of being murderers?

Jameson Valdez: No.

Miss Concia/Consilia: Did you accuse Public Service workers, including me, people who worked at the plant, of being colonialists?

Jameson Valdez: No.

Miss Concia/Consilia: What is your understanding of why the committee shut down after only two meetings?

Jameson Valdez: I think I answered that already. Because there was a lack of agreement on the direction of the committee, the agenda of the committee, the purpose, etc.

Miss Concia/Consilia: So, other than there was no member from the environmental justice community on that committee, what are the other things that you object to in the PISAC report?

Jameson Valdez: First of all, as far as the composition of the committee, it wasn't just environmental justice groups that I testified were absent from the community. It was also experts on public health and, oddly enough, energy. I think that's exactly how I put it.

Miss Concia/Consilia: Looking through the PISAC report, you think that there was no expertise on energy in there, and by that, I mean energy generation, transmission, process. So, did you use the website and look at any of the presentations that were made?

Jameson Valdez: I did look at the website. I don't know, I don't remember if I looked at any presentations.

Miss Concia/Consilia: If we could now look at hearing exhibit 1214. Mr. Valdez, I will represent to you that what I've done here is taken all of the presentations off of the Public Service website and put them into one PDF. I wanted to go through a few things with you. Do you remember looking at the first presentation that was done?

Jameson Valdez: I don't remember which presentations I did or didn't look at at this point. It's been a long time.

Miss Concia/Consilia: Let's look at page 52. There was a discussion of introduction to effective load-carrying capability. Do you see that? Would you agree with me that this is a sort of first step in understanding energy generation?

Jameson Valdez: I'm not really sure. I don't know what I'm looking at, to be honest. I don't know what any of this is.

Miss Concia/Consilia: Let's look at page 66. There was a presentation about energy generation and energy storage. If we look at the next few pages, scroll down please, there were definitions provided to the group. Then, if we scroll down again, initial technology screening. Isn't this the sort of thing that provides people with a background on energy generation?

Jack Ihle: I'm going to object, Mr. Chair. Similar to my prior objection for this exhibit, Miss Consilia has not laid a proper foundation. It's a 326-page exhibit, apparently, which Mr. Valdez has said he's not sure if he's seen these presentations. By asking substantive questions without actually laying a foundation, asking for admission of the exhibit, I think it's an improper use of an exhibit.

Eric Blank (Chairman): The objection is overruled. It sounds like this is being offered as evidence of a presentation, not for the accuracy of the substance of the presentation. So, you can keep going.

Miss Concia/Consilia: Let's look at page 72. You can go through all these different pages. What I'll say is I've had a lot of presentations on different various types of energy too. I wouldn't say that makes me an expert on the matter.

Jameson Valdez: I do, but they were not members of the committee. My objection was that there were no members of the committee who are experts in energy or public health or environmental justice.

Miss Concia/Consilia: Can we agree that the community has been changing in terms of its support for 100% renewable energy?

Jameson Valdez: I don't know that I would agree with that, no.

Miss Concia/Consilia: When you were with the Sierra Club, how long were you with the Colorado chapter of the Sierra Club?

Jameson Valdez: Altogether, about five years.

Miss Concia/Consilia: During what period of time was that?

Jameson Valdez: 2015 through roughly late 2019.

Miss Concia/Consilia: Was that a paid position, or were you a volunteer?

Jameson Valdez: Strictly a volunteer.

Miss Concia/Consilia: In about 2017, you, Mr. Valdez, were instrumental, along with Terry Hart, in getting both the city and the county to pass a resolution of 100% renewable energy. Correct?

Jameson Valdez: I don't remember if Terry Hart was a part of that effort, but I was.

Miss Concia/Consilia: If you want to take credit for it, that's fine. Since that time, the county has repealed that resolution and adopted an all clean energy vision. Correct?

Jack Ihle: Objection, Mr. Chair. Miss Consilia is testifying, assuming facts not in evidence. There's nothing in this record about the local government action she's referring to.

Miss Concia/Consilia: I'm just asking if he knows, Your Honor.

Eric Blank (Chairman): Overruled, but we are getting close to the 20 minutes.

Jameson Valdez: The county adopted the same resolution that the city adopted in 2017, but the county did it in 2018. In 2021, yes, the county did go back and change the renewable energy resolution to a clean energy resolution. Last year, the city repealed its 100% renewable energy resolution completely. I think that was earlier this year, but yeah, I agree that they repealed it.

Miss Concia/Consilia: One of the reasons that the mayor led that effort was because she concluded it was just too expensive.

Jameson Valdez: That was her opinion, but yes.

Miss Concia/Consilia: Are you aware that part of what the PISAC committee did was a poll conducted to determine support in the community for different kinds of energy resources?

Jameson Valdez: I am, yes.

Miss Concia/Consilia: It was the Keing company that did that poll. Correct?

Jameson Valdez: Yes.

Miss Concia/Consilia: It's referenced actually in the PISAC report, and it indicated that 65% of the community, once they understood jobs and tax base, were supportive of advanced nuclear. Correct?

Jameson Valdez: Right.

Miss Concia/Consilia: Did you look at the presentations that were done to the PISAC committee from the Keing report? Did you actually look at that detail?

Jameson Valdez: I may have. I don't remember the details of it.

Miss Concia/Consilia: Mr. Chairman, what I would like to do is to move the introduction of this exhibit, and I would have no further questions of Mr. Valdez.

Jack Ihle: I will renew the objection I made earlier. Mr. Valdez explained that he wasn't aware if he saw this presentation. He hasn't seen the entire 326-page exhibit. I don't know actually what's in that exhibit. I just think there's no foundation to move that into evidence.

Miss Concia/Consilia: Mr. Valdez has indicated that he did look at some of the presentations on the website. They've been publicly available. This is the data and information that the PISAC committee used to issue its final report, and I think it's relevant to give the commissioners a sense of the in-depth analysis and the work that was done by this committee.

Eric Blank (Chairman): Mr. Ihle, I take your point about the lack of a foundation, but I think the commissioners and the parties can attach the weight it deserves, especially given how it was brought before us. So, I'll overrule and allow this to be admitted into evidence.

Megan Gilman: No, I don't have any questions. Thanks.

Tom Plant: I don't have any questions either.

Eric Blank (Chairman): Nor do I. Mr. Ihle, redirect?

Jack Ihle: I'm going to save us time. I have no redirect for Mr. Valdez.

Eric Blank (Chairman): Mr. Valdez, you may be excused. Thank you. Let's call it a night. Any final matters? Mr. Larson, I just want to confirm, is a 7:30 start time tomorrow, Mr. Chair?

Eric Blank (Chairman): That seems a little too early. How about eight?

Matt Larson: We can do eight. Commissioner Gilman and Commissioner Plant, would you be willing to do eight?

Megan Gilman: Sure.

Tom Plant: I agree. It's an improvement over 7:30.

Eric Blank (Chairman): Anything else before we break for the night? We'll start with Mr. Buchanan, Miss Bard, and keep going from there. So, see everybody at 8 a.m. tomorrow. Thanks, and have a good night.