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Good morning. Welcome to the fourteenth biennial transmission workshop. I'm joined with commissioner Marquez Peterson and commissioner Lopez And chair Myers and commissioner Thompson will not be with us today, and they are excused. Let me do a quick sound check with, the commissioners that are remote. If you wanna check-in and say hi and make sure that that you're ready. Yes. Good morning. Hopefully, you can hear me okay. We can hear you. Excellent. And, commissioner Lopez?

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Alright. We'll try we'll we'll try him. Oh, yeah. Alright. Excellent. Good to go. Good. I just wanna make sure before we get started that we've got, got our commissioners online. So, we'll start at the agenda, opening comments. We will start with commissioner Marquez Peterson and then commissioner Lopez. Great. Thank you. I appreciate everyone preparing for today's meeting. I I think the biennial transmission assessment is pretty important to Arizona, and it can assist us in regional coordination of transmission, particularly related to grid reliability during our periods of of high peak,

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which we're having this summer certainly, enable greater access to lower cost power from neighboring states, and increase our resiliency during extreme weather events. There are a lot of benefits to understanding exactly how transmission is occurring and the plans for proposed growth, in the future. Today, I I'd like the presenters to address, please, a coordination among the utilities and their involvement in groups that I heard related to planning, which is Westech, Western Transmission Consortium. And I also many know that I've had an interest in the WEC planned facilities

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map, which is updated once a year. I'd like to also have each of the presenters speak to the WEC map and can tell me how valuable that is, and is it really impacting our regional planning. And I know the the map currently presents tentative and committed projects. So, would like them to each please address those three groups as they present. But thank you again for the opportunity to make an opening comment. Thank you. Commissioner Lopez. Nothing more to add. Just, looking forward to the overall, presentations and, in reviewing the, the new maps that,

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that were provided. I'm kinda really looking into a deep dive. So, I'm looking forward to the meeting. Thank you. Yes. I agree this is crucial for our reliability in the state and looking forward to what everyone has prepared for us. I will turn this over to staff, for any opening comments. And if you'd like, we can have staff go ahead and present the or call up the presenters for each each one. Good morning, vice chair, commissioners, and stakeholders. Adam Beckerman for utilities division staff.

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Welcome to the first workshop for the fourteenth biannual electric transmission assessment. Today, we have presentations of ten year plans from APCO, APS, SRP, and TEP and UNSC. TEP will also present the Southwest Area Transmission ten year Snapshot Study. At the end of the workshop, staff will present a tentative schedule for the rest of the fourteenth ETA process. For those presenting virtually, staff will be controlling the slides. So please let staff know when to move to the next slide. After each presentation, we'll have time for commissioner questions. Thank you all for your participation in today's workshop. And we'll start with APS. Okay. Great. Okay. Good morning,

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vice chair Walden, commissioners, staff. My name is Matthew Robinson. I am the supervisor of transmission planning at APS. My team is responsible for performing the ten year plan, the the analysis behind it, the BTA, and the analysis behind these as well. So looking forward to, presenting our presentation and answering any questions you may have. So an agenda of these slides is going to take a look at the ten year plan for 2026 through 2035 that we've submitted, as well as our distributed generation and energy efficiency study that we performed,

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our extreme contingency study, as well as the reliability must run analysis study that we've also performed. Going on to the next slide, we did perform a technical study as well to inform the ten year plan itself. This slide just details the analyses that were performed as well as the reliability criteria that we evaluate against to ensure that we're meeting all the criteria and to determine whether any proposed projects are needed. So on the right hand side, we can see analyses performed for the BTA.

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We look at what occurs, should the system remain intact, no outages, systems remaining and running as normal. We ensure that the thermal loadings for all elements are within their equipment ratings and all voltages on the system remain within their, applicable normal and emergency limits. We also look at what occurs should an outage happen, an event, a monsoon, a line going down or tripping offline. We also now analyze to ensure that the system remains stable and adequate and reliable

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during those conditions as well. Beyond the BTA analysis, we also look at NERC's TPL, reliability standards. That's an annual study that we perform that looks at beyond just single elements. We look at multiple element outages as well. So what happens if a transmission structure, which has maybe two circuits on it, happens to go down during a storm or gets hit by something? What occurs if those two circuits trip out at the same time? Is our system still stable? So we evaluate a lot of different analyses. During those analyses, we compare the results to the criteria that we have.

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And should any, concerns or any reliability thresholds not be met, that's when we would develop a transmission project in order to maintain a reliable system. Down at the bottom there, per the decision that occurred back in October of twenty third of last year, APS utilities, a APS in Arizona utilities, APS in general, took a look at providing confident additional confidential reporting metrics, load pockets inside of our area, where we're seeing that future load occur, as well as where we're seeing the need for some of these transmission projects as

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a way to to show visually a a better way to justify why these projects are being proposed. Excuse me. So, based on that technical report that we filed, we merged those maps together to show areas in our system where we're seeing those types of load growth. On the left is the state of Arizona where we're showing three specific areas, the Yuma load pocket, the Pinal County load pocket, and then the metro area and Valley load pocket. On the right hand side is a more zoomed in map of the valley.

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Down at the bottom above the legend, it might be tough to see, is Baseline Road. On the eastern side, we have State Route 101 going north south and looping up through Scottsdale. And right in the middle of the biggest circle on the left is State Route 303. So we can see that's those are the primary areas inside of the valley where we're seeing large, large growth. The next few slides detail our plans, for transmission projects throughout the state and those particular areas, focusing on the outer division.

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Here is all of the projects and, that we're planning to complete for various reasons. From the last BTA to this BTA, here were some of the completed projects. We had one up in Rabbit Canyon up north in the state. There was a Sitgreaves project and a project down by the Saguaro generating facility called Serrano Solar. So all of these projects happen to be related to large generators that were connecting to the system and APS needed to connect new substations or, transmission facilities in order to interconnect those those generators.

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This next slide details the newer projects that we proposed as part of this BTA that were not included in the last BTAs over the past two years. You can see there's a significant amount of projects in there. Some of them won't be to be determined. We've seen a need in future studies where should certain conditions occur, this would be the solution to, mitigate any concerns or to interconnect new facilities. However, that date hasn't quite been determined yet due to those triggers not occurring. Again, changes from the last BTA, some of the projects that we've had have had their dates shifted.

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Some of them have been pushed out while others have been pulled in. Based on the needs, we can we continuously reevaluate the need for these projects. There's also other concerns such as supply chain delays or, maybe the needs may have been pushed out further. So we've gotten a little bit of time to to more adequately, space those projects out. Switching to not just the state itself, but the the valley and the metro area load pocket. We can see some of the projects there. This is the same map that was previously shown. A majority of our projects are on the West Side Of the valley,

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West Southwest Side. Some of the completed projects that we've had since the last BTA, again, are listed on here. Some two thirty kilobytes lines that were connecting new substations for new customers. We had some reliability upgrades that were that occurred. The country club to Lincoln Street was an underground cable that we had to, that's been in service for the past thirty or forty years, and it was time to, increase the ratings of that, so we've replaced that cabling. New projects, from the past BTA to this one, are a new two thirty kV line going from Agua Fria to Contrail that we're

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hoping to have installed by 2030, along with Morgan to what used to be called TS 21, but it's now called Wafer Substation up in the north part of the valley up near, our Avery Substation. We've had a significant amount of date changes. Again, we're continuously reevaluating based on loads that are coming in, loads that maybe are ramping a little bit slower, various different conditions that we evaluate every year leading to some of these date changes. Some of them have been pushed out due to either timing differences or supply chain

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issues, such as, like, the contrail lines going from 25 to 26 in the near term. We've also seen some get pulled in, like the Raptor TS thirty four substation or the lines connecting to that. It was to to be determined. However, the trigger was met in the past couple of years, so that's being pulled into this year. And then finally, looking at the Yuma area, there's a lot less activity going on down there, but still also very important part of the system. One of the completed projects we had since the past BTA was the interconnection of the Ironwood Solar and Storage Facility connecting to the Hudu Wash Substation.

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We have a CEC for the two lines going from North HeLa down to our Orchard Substation. The first line went in service a couple of years ago, and the second line was a to be determined date. However, due to other factors in the area, I think this one was primarily driven by generation connecting in there. We're seeing the need to pull that project in and actually give it a date. This may be difficult to see. It's kind of small, but these are a summary of all the changes, the new projects, completed projects, in service date changes as well as canceled or removed projects that have occurred since

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the previous BTA, As well as other additions and facilities, not specifically transmission lines or substations, but transformers, shunt capacitors, series capacitors, or reactors. This is another summary page showing which, what are the which ones were completed or how many were completed, how many are new, and the the date changes. So I think the biggest takeaway from this is that we're continuously building the system to remain as reliable as we possibly can. So that concludes the, our APS' presentation on the ten year plan. I'm not sure if anybody has any questions on that or just continue on.

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Yeah. We can we can pause for for questions. Commissioner Marcus Peterson, do you have any questions? Yeah. Thank you. I do. First off, on the second map, mister Robinson, you had, the identified projected projects, and I guess I wanted to understand the difference between kind of load growth and congestion. Is that identified on that map? Thank you for the question, commissioner. Was this the map you were talking about? Let's see. I'm online, so I can't see that map. Oh, there we go. Is that the second slide? It's one that had the yellow right there. Oops. Go back. This one. Right there.

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Okay. The one on the left identified kind of key areas you were focusing on. And I guess I'm just I'm I wanna ensure that the data center load growth we're seeing in other types of industries in the state, I'm sure that's in these highlighted areas, but also kind of the differentiation between load growth and congestion. Yeah. So these maps are identifying the areas where we're seeing the largest load growth, not necessarily particular customers or a particular type of customer. This is just looking out over the next few years, next ten years, the amount of load that we're expecting. These are the areas where those are planning to come in.

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The the projects that are listed in the background there that are in red, they're probably easier to be seen on this map without the yellow circles. We don't specify in this report which are for specific customers and which are for congestion. Some projects are strictly to connect a customer directly to the the transmission system. Others are to, reinforce the system if that customer were to come on. So in this map, we don't specifically call out which projects are for which reasons.

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However, in the ten year plan on the project pages in the back, we do put a purpose and need for each of the projects to to show why we need this project. Okay. Thank you. And I'm also just curious about, I guess, the difference between, growth that was identified in your last IRP that you acknowledged and this transmission planning process. I saw one of your slides showed a summary of the different projects, but what's what's primarily what's the difference? I mean, are we seeing dramatic difference because you have a number of projects listed there that we haven't seen before in the last ETA?

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Were those included in the last IRP, or are these entirely new to the commission? Thank you for the question. Based on the timing and, my my, the director of resource planning here at APS, Mike Eugenas, he might be able to speak further to the assumptions in the IRP. However, based on the timing of when the previous IRP was done and when this BTA was completed, there is a two year roughly gap there. So I I'll let Mike speak to that. Good morning, vice chair Walden and commissioner, Marcus Peterson. My name is Mikey Genas. I'm the director of resource planning at APS.

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The projects that were in the 2023 IRP, were aligned to the previous BTAs that have been in front of the commission. So we we heavily leveraged, projects that were identified as part of the, 2022 BTA as well as the the most up to date, information from transmission planning as of the 2023 time frame when we created those cases. Since then, the load has continued to evolve and we've started to see additional customer growth on the system. And both the resource planning team and the transmission planning team have been working together

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to understand the impacts of those loads, as well as, plan the system upgrades necessary to support those. So that's why you see, such a large number of upgrades that are have been identified as part of this BTA that you didn't see in prior BTAs. And those upgrades, will be included in the the upcoming, 2026 integrated resource plan. Okay. Thank you. And, Mike, this might be a question for you, but, with the incredible load growth we're seeing and the queues and so on that we're hearing a lot about, when does that load become firm? When is it prospective?

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We hear about large customers like data center shopping multiple states. So at what point are you putting it in the DTA? The thank you for the question. We only allow load that, we can reliably serve to be counted as firm load into the system. So that means that we need to be able to, procure enough, generation resources to support that load, as well as inter connect it to the system and maintain the transmission system reliability associated with it. And so those those triggers, can take a considerable amount of time depending on the specific location that that load

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is is being cited as well as the the size and the, the attributes of the load shape itself. And so we don't have a a specific time period that, we usually quote for when prospective load becomes firm load, other than the fact that we continue to, aggressively pursue infrastructure upgrades on our system. Like I said, both on the resource side as well as the transmission side in order to accommodate as much, growth that we can reliably do so. Okay. Thank you. And and in my opening comment, I spoke about the wet prospective map.

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I think it's called plan facility map, and they identify tentative and proposed projects. So are many of these on the BTA, that you've just identified, are those tentative then? Because these these aren't large loads that have put hard money down or any kind of contractual relationship with APS then. Is that correct? So the the planned projects that are listed here have multiple different reasons. Some of the substations that are listed here are some of the TS numbers that you'll see that haven't been named yet for transmission substations. Some of those are for, new coming customers that have been considered firm and that we've we've been able that

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we're able to serve. So some of those are real there, and those are coming, especially ones with the dates. Other TS's that you see that are TBD, those are ones that could be coming should a trigger occur. So should that load materialize or should that load become more firm, then we would trigger that new substation, as well. So this map shows, all of them. It's it's hard to differentiate which ones are for perspective and which ones are not. I would say that, in general, if it's a TBD project,

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then there is a we've seen a possible need for it should the triggers occur, and that trigger could be, higher load growth than we've expected or or various other scenarios. A new generator that has yet to sign any type of interconnection agreement, but we know that it should they, we'll need to start the planning process on getting these substations or lines upgraded. We've noted them in here as a TBD. Okay. Thank you. And what type of regional coordination is APS participating in related to transmission?

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So APS, we participate with, excuse me, with the West Connect. That's our regional transmission planning forum that we use primarily. We also use SWOT, the Southwest Area Transmission Forum, which is as, mister Kitterman will probably be talking to later about the, tenth year snapshot case that's part of the BTA. So we coordinate with them as well. Other parts of APS' organization work with, Westech, as you've mentioned. We are involved, very closely with WEC itself, helping them to you know, working with them, and putting input into some of the new standards that they're looking to create and

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regional criteria that they're creating for the for the Western interconnection. So we're we're very involved with the regional entities, and and our planning associated with that. K. Thank you. And I guess last question is supply chain. We hear about so many concerns. So can you talk about your projections and how supply chain challenges will play into that? And also, are you back ordering certain key items that you're you know, you're gonna need in the future? Or when does that decision making occur? That's a great question. That is some of the drivers for the date changes have been those types of

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of supply chain delays. We're seeing a a significant supply chain lead time for large equipment like transformers and two thirty, three forty five, and 500 kV breakers. Those are bordering on three years to four years. It can be more, it can be less depending on which manufacturer you go with. The the specifics of those devices as well can kind of play a role into it. We're seeing a lot of supply not a lot of, but we're seeing supply chain extensions for a lot of facilities.

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In those cases, what we're seeing, we're not going to meet any of our projected in service dates here. APS is constantly looking on the back end. Are there short term mitigations we can use, operational mitigations that we can do in order to maintain the reliable system there? I'm sorry. There was a second part to that question I forgot. I don't recall either, but they did think I did think of another question while you were speaking. And is there some coordination, some entity, or some regional effort to track key supply issues or key vendors that you can tap into to understand the time frame?

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Because you know it. It sounded like three to four years I wrote down on breakers and so on. How is that coordinated in the industry? I don't personally have that information. Our APS's apparatus team and and other engineering teams that we have work a lot with those OEMs, those original, equipment manufacturers, and have those agreements and those contracts with them. I I just I'm not the person to really answer that. And do I do remember the second question was, are we procuring equipment, just in case? And yes, we are. That is one of the initiatives that, my leadership has taken,

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well, leadership above me, not my leadership, has taken in the preview in the future. In the most recent years has been to evaluate where, what our spare strategy is, and should we be procuring, extra transformers or extra breakers to have should some of these projects and these TBD projects come to fruition. We'll need to procure those quicker. So we have been procuring, equipment, and to a moderate degree extra, in addition to our spares for these. That also is it's just prudent so that if we do have any types of failures, we're not left in the lurch with those long lead times as well.

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Okay. Great. Thank you. That's my final question. Thank you, vice chair Walden. Commissioner Lopez, any questions at this point? Yeah. Commissioner Marcus Peters has asked all of my great questions. And, but I do have one kind of follow-up. So, again, it is great to see the flexibility that you are doing with, again, supply chain, challenges and you're modifying, depending upon when certain customers may be coming online or being delayed. So, again, shifting around to do that. So kind of a two part question. Have have has supply chain

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issues been able to be compensated by that fully and or have we had to, turn away any customers or not bring them online because of against supply chain issues. Thank you for the question, commissioner. We the supply chain issues continue to exist. There's still long lead times. However, due to the procurement strategy, of acquiring some of these standard items, these standard long lead items ahead of time,

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we have been able to cut down, the lead times that we're seeing. So we're ordering some equipment that are at standard in advance. That's been able to help us bring customers online in their respective time frames. There are certain circumstances where a customer may want to move very quickly, which based on the need for us to maybe acquire land, to do civil work on that land, to acquire not even long lead items, but items within the next year or two, it may be infeasible to connect them based on the customer's, schedule that way.

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So we'll obviously work with the to let them know what we're capable of doing and how we can best support them. We do also come up with other alternatives such as instead of serving them directly from the two thirty kV system immediately, if the customer is willing, we could some we could, supply them with 69 kV power, for the first year or two as they're ramping up to help them get online sooner. So we are doing some additional planning and working with customers as well. So so at this point, as you mentioned, you kinda like and I'm inferring from that statement that you haven't told the customer

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or turned them away and said, no. You can't bring it online. You're working with them to to do what you can to to get me the requirements. You know what I mean? Correct. If if APS is is agreed to serve that customer, the customer will give us their ramp rate. That way we know how quickly we need to move on getting these facilities in there, and we work with them to ensure that those timelines are aligned properly and that they know how fast we can get things in and we know how fast they're able to start ramping up. So it's a good dialogue that we have with them and we're both on the same page.

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Yep. But we're not turning away customers just because we can't get their facilities online in the time frame they're they're requesting. Okay. Perfect. Thank you. That's all that I have. K. I don't have any questions. Staff, do you have any questions before we proceed? Alright. Thank you. Well, we'll get back to the second part of the presentation. K. Thank you for the questions. The next study that we performed that APS performed was the distributed generation and energy efficiency evaluation. This is an overview of a a hypothetical scenario of what if distributed generation and

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energy efficiency that, that we've forecasted for the next five years. What happens if that doesn't come to fruition and it doesn't offset our load? Then ours the system is still able to meet that load. So we we studied two specific cases. As mentioned, their case one is the base scenario. In year five, we're assuming at the time of the study, we were assuming 10,400 megawatts of load. There was going we forecasted 2,000 and sorry, two twelve megawatts of distributed generation as well as five ninety megawatts of energy efficiency.

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So just about 800 megawatts total in load reduction based on those. So when we did our analysis, we we assumed there was 9,600 megawatts and the system was reliable. But then we take the case and we pull that DG and that EE out of it and say, if that doesn't come to fruition, are we still able to supply the the load with a reliable system? In that case, we the results showed that, we were able to maintain a reliable system should there be any delays in distributed

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generation or energy efficiency implementation from the customers. So if there's any question if there's no questions, I will continue on to the next study. The third study we performed is the extreme contingency study. This is a, as the title suggests, a study of what happens should an extreme contingency or an extreme event occur on the system. Primarily, we look at right of ways, entire corridors of transmission lines that are feeding the Metro pocket. Should a wildfire go through and knock out all those lines?

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Can we still supply the Metro load pocket with reliable service and to what extent? What's our maximum load serving capacity, and what is our system import limit? How much can we bring into the valley under these conditions? We look at a 2027 case. So at the time of the BTA, it was about a year or two out, as well as a 2035, a ten year out case, to ensure that during both of those, we're able to maintain a reliable system. Also, this is a very short slide,

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mostly because the extreme contingency study is a CEII type study. It does evaluate and describe critical points on our system. So we do, keep that as confidential, and we're not going to share the results of that directly in this forum. However, in summary, we found that in 2027 and in 2035, ten years out, that we are able to maintain adequate margin to serve the load should these extreme events occur. And the fourth study that we performed was the reliability must run study. This study primarily looks at two import limited areas that we have on our system.

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One being the Yuma load pocket with the transmission lines going in to feed that pocket as well as the Metro Phoenix, Valley load. Both of these have generation inside those pockets, but they also have transmission lines serving them. So the purpose of this study is to identify if there's any, must run generation during certain hours that has to be inside the load pocket that has to be running because there's not there may not be enough transmission line capacity to serve that. So the,

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the in the outputs from the extreme contingency study, the system import limit value, how much we can bring in, as well as the maximum load serving capability, how much can we fully serve, those are inputs to this study. We do this study jointly with SRP since we're so close here in the Valley area. Those two load pockets, there's a trigger to determine whether we need to study those in every single BTA or whether the conditions and the forecast are similar to they were what they were during the previous BTA where we may not need to study them.

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In this BTA, the Yuma load pocket, the the trigger was not met. So there wasn't enough load growth forecasted there. That was different from what we previously studied. So in this VTA, we did not study the Yuma load pocket. We did study the Phoenix load pocket. Since the APS and SRP's combined load forecasts exceeded, I believe it was two and a half percent of the previous BTA. I I jumped the gun a little bit. So in back in the seventh BTA was when that, they we suspended the requirement for performing the RMR in every BTA and and it

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added that trigger in there. Actually, I'm going to let Mike talk about anything on on this. If anybody has any questions on it, in in general though, what we found was there were under certain hours or a certain number of hours in the 2035 and 2030 timeframes where generation was determined to be required to be running inside the load pocket there. However, the projected amount of energy that needed to be provided by those units is relatively small compared to the overall amount that was required.

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So if anybody has any further questions on that, I'd defer to mister Eugenis on those, if anybody has any questions. Vice Chair Welbon, I had a question on that slide, please. Oh, yes. Yeah. Go ahead. Thank you. Yep. Thank you. Just wanted to ask about the the must run. Are those identified just in terms of load growth in certain areas? Are those particular projects that you're identifying? Like, I I guess what's coming to mind is health care facilities and things like that, or is this I guess, can you describe how you'd identify what must run? Thank you for the question, commissioner Marquez Peterson.

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The must run facilities is a delineation that we make whenever generation has to be, put online to support the the broader reliability of the system when there is an insufficient amount of import capability coming from the transmission system itself. And so, it's not necessarily, small scale facilities like you may be thinking with, whether that's generators or backup, for individual, businesses or hospitals or health care facilities so much as it is APS's facilities,

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and large scale generation that's typically running. The the purpose of the study is to understand whether, during times that you have the inability to import additional generation into a particular load pocket, if the generation within that load pocket would already be economically dispatched, or if that generation is coming at a premium compared to what resources outside of that load pocket would cost to customers. What we identified in this study was that there is a very small premium that

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is associated with that local internal generation during peak hours. However, from, the 2030 to 2035 period, there's transmission projects that are going in service, that are alleviating, the constraints on the system that are causing that that generation to need to run. So this this study, shows the the ability of both our resource planning teams and the transmission planning team to work together on identifying those transmission projects that, eliminate any kind of out of merit generation.

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Okay. Thank you. So, what what are the generation resources for RMR? The generation is anything that's located inside of the load pocket itself. So for example, in the Phoenix load pocket, we have several generators. We have the West Phoenix Power Plant. We have the Ocotillo Power Plant. This is a joint study with SRP, and so it also includes their generation as well. So, the things like the San Tan facility as well as, Aquafria and other locations that SRP operates within that Phoenix load pocket. And so it it tends to be,

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natural gas generation that, the utilities are able to dispatch to alleviate any transmission, concerns. Okay. I was gonna ask, are they natural gas peakers? So they are. That that's what you just stated. Correct? It's a combination of both, combined cycle and natural gas peaking units. The West Phoenix, power plant is a great example that has both of those types of technologies with both, several combined cycles as well as a handful of, peaking units to support. Okay. Great. Thank you. No further questions. For, APS, we can turn over to questions. It looks like you were on your last slide.

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Did you have anything else you wanted to add before we see if there's more questions? That concludes my presentation. Alright. Commissioner Lopez? No questions. And I just, have a question about your interconnections to WAPA. And are you seeing anything with with WAPA as they're working on addressing some of the congestion issues? That's a difficult question. I guess, do you have more, description on that that question? Sorry. Congestion related to transmission line congestion? Or Yeah. Congestion on their system. I mean, we we work with our neighbors.

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We work with with WAPA as well. So if they come to us and they say that there's, they're they're seeing congestion on their system, you know, we would work with them to identify, is it something on our system that we could help with? Is it something on theirs? Sometimes there are joint projects where a transmission line of theirs connects into our system. And if they want to increase the capacity of that, or the ability of that line to carry more power, the constraint may be in our switch yard. So in which case, we would then have to upgrade maybe a switch or a breaker or something in order for them to achieve their goal. So we do work closely with them when they identify those issues.

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Okay. That's that's what I was looking for. Yeah. Thank you. And, Steph, do you have any questions? Alright. Well, thank you very much. K. Thank you. Alright. Up next is Tucson Electric Power, TEP and UNS Electric. Actually yeah. Right. Chair, commission, staff, good morning. My name is Josh Kidderman. I'm a transmission planning engineer with, Tucson Electric Power, and I'm here this morning to present, our fourteenth BTA, study, ten year plan results, and BTA study results, on behalf of TEP and UNSC. So thanks for having me. Just a quick agenda,

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for this presentation. So I'll start off by kinda going through our study approach, that we take when we are performing our transmission planning studies and the BTA studies. Then I'll go through a review of, the ten year plans for TEP, as well as the UNSC Mohave County system and the UNSC Santa Cruz County system. And then I'll follow that up with the review of the, BTA specific, studies that we performed for the fourteenth BTA. So just kinda going into, you know, our transmission planning approach. So one of the biggest things that we're looking at,

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in our studies is, you know, addressing reliability concerns. That plays into, you know, looking at not only the NERC reliability standards that, we comply with, but we also adhere to the WEC planning criteria that they have established. We also have our own internal planning criteria and assumptions as well that we review annually. We update that. Like, our criteria for our studies is a little more stringent than the NERC criteria, which they do allow. So we kinda point that out for our system. Our generator interconnection process,

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we are we're, you know, work comply with, for quarter twenty twenty three. Through that process, we are also currently going through our cluster study process. We've completed two of those, and we've just started our, 2026, cluster study process. All of that, process, the methodology, and queue for that is posted on our the TP and the UNSC OASIS websites. And then we look at, transmission load interconnections. So if we have any, large load customers or any customer in general, that's looking to interconnect into our system, we have an economic development department that,

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works with those customers, and then we do specific, system impact studies. And then moving from that, any facility studies, to determine any, you know, type of, infrastructure that may be needed for a particular customer, before that all takes place, before we work those, those facilities and those customers into our traditional into into our actual plans, that would lead into filing a project in the in our ten year plan, to get that customer interconnected. And then we're constantly evaluating, our existing transmission corridors, for any possible expansion, due to the increased,

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of, forecasted load, not just from, you know, our anticipated increase of load forecast, but also any, prospective large load customers that could be, looking to interconnect into our system. I'll move on to our, review of our ten year plan. So I'm first gonna go through the TP ten year plan. We'll be first looking at our, Escher high voltage or EHV facilities, and then we'll be looking I'll go through our, high voltage or HV facilities, within the TEP system. And just to kind of foreshadow this,

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the this ten year plan, we're gonna I'm gonna be doing a comparison of the ten year plans filed for the fourteenth BTA against, what was filed in the thirteenth BTA. Moving into our EHV transmission project. So we did have a completed, project. Since the last BTA, we did have, an installation of a second, 500 to three forty five kilovolt, transformer at our Pinal West, substation. We did identify, three new projects on the EHV system, this BTA since the thirteenth, and these are three new transformers, two of which are at two of our major import points in the city of

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Tucson. These additional transformers were identified due to just the increased load forecast as well as, you know, additional customers coming in, and this is mainly due to the additional need for, crater import capability into the city of Tucson to serve that load. We did have a deferred project of, some reactive, some combustor banks at our Greenlee substation. Then we did, remove one project we did have we were filing. It was a a previously conceptual project, which was a Gila River up and out west, 500 kV line.

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Now I'll move into our, HV, transmission system and review of this ten year plan. So this map here, is really showing kind of the greater Tucson area. And then just as you can kinda see here, some of our major three major import points that we are looking at that we evaluate, within the Tucson load pocket or up north, at the Tortellita North Loop area. And then to the south of the system, we have our Vail and our South Loop substations. Those are our three major import points into the city of Tucson. So we did have three completed projects since the thirteenth BTA. We did complete our,

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Irvington one thirty eight kV transmission line relocation. That was actually a rebuild of the Irvington 138 substation into a breaker and a half. So that, resulted in the relocation of the transmission lines into that breaker and a half configuration as well as, we had a, Patriot to East Loop one thirty eight k v line that we had energized since the thirteenth BTA. And we completed, the loop in of the Vale to Fort Huachuca one thirty eight k v line into a new, wet stone switchyard. That switchyard was, put into service to accommodate, a new 160 megawatt, PV facility down in the Cochise County area.

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I have a list here of, new projects that we had identified since the, since since the thirteenth PTA. Just listed, at the top here, we did identify some new reconductors, reconductor projects that, we needed within the city of Tucson. With these reconductors, TEP, we're evaluating, just the the use of, grid enhancing technology. So we're looking at, utilizing some advanced conductor types for these reconductor projects at the moment, just to look at the, you know, the benefits of any cost savings that we could get from that as well as, you know, any increased,

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rating that we could get, you know, from a a comparable conductor, and then also kind of taking into account lead times on our traditional standard conductor versus, any of these new, conductor types out there, such as a carbon core conductor. Another project here. We're looking at a new switch yard, up near the Tortellita North Loop area. We did, include the, planned Sonoran to, the planned Santa Rita Substation 138 kv line. We're planning that, for 2029, which we recently just received the CEC for last week.

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So thank you for that. Then we do have a a planned, substation, the Tucson Estate substation that had been that has been filed in the past. We just had a name change with that project. We did have a few project advanced prod advancements since the thirteenth BTA. This was really kinda driven just by increased loading that we're seeing in certain areas of the system. So we do have a we accelerated our port substation, since the thirteenth BTA. We currently have a mobile transformer there at the moment, in the vicinity of what we're planning that substation, and that's looping in the Irvington to Patriot 138 Kv line.

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That that area down there is kind of seeing an increase in, commercial and some light industrial, growth in that area. We had the, an acceleration of the, Santa Rita to plant Copper World, switchyard, from that was previously a TBD project that was very dependent on the mine, you know, the mine customer. We now kind of have, kind of firm plans to get, power to that customer. So that was that project was formerly the Toro to Rosemont one thirty eight kV line. The mine has gone through a name change.

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They're now known as Copper World. And the Toro Switch Yard, we have a plan, and it was brought up in the CEC, in the hearing for the Sonoran to Santa Rita line. We're planning to collocate the Toro the plant Toro Switch Yard, which was approved, in case one sixty four to serve the mine. We're planning to co locate the Toro and the Santa Rita, substation, into one yard. The Santa Rita Substation has been filed, in past BTAs for, several years, and that was originally identified just to serve,

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increased, anticipated increased load growth down in the Saudi Rita, area, which is just South of Tucson. We did have a few project deferrals as well. We have a capacitor bank, the one thirty eight bus at our Orange Grove substation. That was deferred. It's actually, been installed and in service now. There was just a there was an issue with getting equipment, to, get that completely installed and put online. So it was planned to go in service last year. We just got it into service beginning of this year. And then we have the arrow our aerospace research campus, transmission project that has been deferred to 2027.

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This is a customer driven project. So we're really kinda waiting, to hear more of when the customer is ready to move forward with that project. We have the plans, and the approved CEC to get the Franco Wash Schlitz Yard into service to serve them. And then these the additional deferrals here are really just loop in projects for new planned substations throughout the city of Tucson, to pick up additional, load. And that's, you know, kind of outside of our, typical outside of our six year capital budget window. And then since the last BTA, we did have, several unchanged projects here,

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which I I consider a good thing. So one of the biggest projects here is our Vail to Tortellita two thirty, kV project. That project is a phased project, with the Tortellita to Demos Petrie two thirty kV line and associated transformers planned to go into service, later this year. That, project, is on track to, be completed later this year or the the, very early next year. And then the second phase of that project is the DMP, Dimas Petrie 2 Vales 230 k b line planned, to be, placed into service next year.

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Some additional unchanged projects that we have had since the the previous since the thirteenth BTA. These are conceptual projects that we continue to file in our ten year plans. Just projects that we continue to monitor, as we're, con continue to do our studies annually. And, you know, if we see the need for any of these projects, we, you know, we would, determine when we would need to get them placed into service, and then we would update our ten year plan and file that accordingly. And then just a a few project removals. These were really just due to, kinda shifts in some of the planned projects that we have already.

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So, the plan Naraha one thirty eight k b cap bank, that's a planned substation that, we're looking at getting, built and placed into service in 2029. We've, identified that we did no longer needed the capacitor bank, at that substation. So we did remove that from the ten year plans. Again, that's something we will continue to evaluate, especially as, load increases, to determine if we do need to get that, once we construct the the substation there. And then these last two removed projects were just kinda changes in existing projects Mohave County projects. So we do have a fairly small footprint up in the Mohave County area.

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We'd all we had, since the last BTA, were two deferred projects, and this has to do with, our planned Black Mountain generation station expansion. That project entails expanding the existing generation station at the Black Mountain, station by adding, four fifty megawatt, natural gas turbines at that station along with an associated two thirty k b, generation tie line. That, project was pushed from 2027 to 2028. And then we do have we did have one, unchanged project, that it actually has a planned in service date,

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and that's our Golden Valley two thirty kV line, which is a two thirty kV line from the existing Harris Substation to It would be to a new, UNSC Mineral Park substation at two thirty k v. We're planning that for 2031. Alright. Moving on to, the UNSC Santa Cruz County system. We did have one completed project since the thirteenth BTA, and that was the installation of a one thirty eight kV cat bank, at our Cantor substation. And then, a deferred project, since the last BTA was the Sonoita to Gateway to Valencia transmission line that was

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originally planned for 2023. We've pushed that outside of the ten year window, and now we're looking at that as more of a conceptual project due to some project shifts that I will talk about here shortly. We did have several unchanged projects since the thirteenth BTA down in Santa Cruz County. Most notably, we're, you know, really looking at, we're looking at putting a new substation, to connect the Sonoita to Valencia line. That'll be our new Kipper substation down there. That's planned to pick up some additional load, in the Rio Rico area due to anticipated growth,

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within kind of the commercial light industrial, sector down there. And then we have, our planned Rio Rico, one thirty eight k b substation. That substation, we're planning on having three, capacitor banks in that substation as well as long as well as the, the line, from Rio Rico to the planned Harshaw Substation. That whole project is planned to go into service next year. Then we do have a few conceptual projects listed here that did not change since the last BTA. Did have a removal of some projects down there once we've, I did we shifted some of the, the reactive support from the Cantor Substation.

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We ended up shifting that to the Rio Rico Substation, just to kinda get more reactive support down in that area South Of Cantor. And I'll move into the our, Santa Cruz reliability project. So this has been filed, over the past couple years. It was filed in the thirteenth PTA. That is a three phase project. We have shuffled some of the phases over the past year or two. The first phase, though, is our, new one thirty eight k v line connecting the TEP Canoa Ranch substation to the Cantor 138 Substation. That project did not change since the last BTA,

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and that plant project is planned to go into service in '28. Phase two of the Santa Cruz Reliability Project, we are looking at reconductoring the Wapna Nogales tap to contour portion of what is now the Vale to contour one thirty eight kV line. We're looking to reconductor about roughly 24 miles, to increase the rating on that line. That was previously the third phase of the project. We bumped it up to phase two, planning to get that in in 2029. And then the third phase of the project, will be a new UNS TDB switchyard,

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that'll be near the existing Valencia substation down in Nogales, and then a new, Cantorta UNS TDB one thirty eight kV line, as well as, Rio Rico to UNS TDB and then a line from UNS TDB to the Valencia. We're planning that in 2031. That's gonna create the redundancy loop that is really the the sole purpose of this project. K. I'll, pause there, for any questions on, any of the plans that we have currently for TEP or UNSC. Thank you.

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Commissioner Marcus Peterson, do you have questions? Yes. Thank you, Josh, for your presentation. My first question is around the system impact studies that you're doing with each, new large load. When at what point is that shared with the staff? What's the process? Vice chair Walden, commissioner Marquez Peterson, thank you for the question. That the system impact study takes place very early on in that process, and we, you know, we determine when that's needed. And I think if we have to go in for, if we need to come in for a CEC, to get, you know, for any new transmission lines or any switch yards that may need to get built,

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I believe that is the the process that that would get shared with staff, I think. But prior to that, we would we would end up filing that in our ten year plan once we have the the firm plan to get service to that customer. So I think the ten year plan would be the first, kinda mentioned to staff and to the commission. Okay. Thank you. And so quick question for staff. When that is presented to you, what what are you evaluating? Vice chair commissioners, commissioner Marshguez Peterson. For the system impact studies, those are usually associated with line sighting cases and the CECs.

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So we usually just look at the impacts of the study and the general overview since, we just kinda see if the the project could improve the Arizona grid, basically. Okay. But our staff engineers and so on are looking at it at that point when it's filed with the CEC application? Vice chair commissioners, commissioner Marcus Peterson. That's correct. Okay. Thank you. And, Josh, back to you. We just wanted to see I saw the advanced conducting work. I think that's great. Great use of a way to maximize our distant minds. Question that I asked APS around supply chain issues. What how are you kind of coordinating or understanding lags and time for purchasing certain

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types of equipments? Is there any one source you can go to as an industry to find out what is occurring, and are you back ordering key pieces of equipment for future use? Vice chair, commissioner, Marquez Peterson. We currently have a, alliance partnership, with certain vendors, that we've we evaluate and, determine what we need to order for any particular projects based on its planned and service date. And then we do also, place, you know, back orders to make sure that we can, you know, meet the the the lead times to make sure that we can get these projects,

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placed in service in time. We have also been kind of looking at potential, additional alliances with other vendors, to see if we can kind of shorten that lead time to get any of, you know, the equipment that we may need to get a project in service. As mister Robinson with APS mentioned earlier, you know, the lead times on, you know, transformers, circuit breakers, disconnect switches, only continues to increase. So it's something that we monitor very closely. And we also as a transmission planning department, we do have a, what we call a spare equipment strategy. And so we work internally,

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with our asset management department and engineering departments, within the company to ensure that we have a the proper amount of, spare equipment, to you know, just in case we have, we lose a breaker, you know, at a one thirty eight kV substation or, you know, if we need to place a a a mobile transformer, for instance, as I mentioned at our planned port substation. You know, we've we maintain a spare equipment list and make sure that we can meet that, annually. Okay. Thank you. And I'm assuming that that your planning organization is you're involved with Westech also,

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and this is the same kind of data you're presenting to Westech. Is that correct? Vice chair, commissioner Marquez Peterson. So TEP has not been actively participating in Westech. We have, provided, technical data and modeling and project updates, for their ten year and twenty year, the studies that they are doing. But we are not actively participating in any of the the committees, that are that were formed within Westech. However, we do, we are very active in the West Connect, fork order 1,000 process, the regional planning process there.

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So we actively participate, within West Connect, each planning cycle, as well as, the the SWOT subregional planning group. And I will and I'll talk more about SWOT, here in my the next presentation. But we do actively participate in that and coordinate project updates and any planned projects, with the the sub the other entities within the SWOT and West and WestConnect. Okay. Then I I might have follow-up questions for you related to that when he presents it. So my last question is really about your last IRP when we went through that process. What's what are the primary differences?

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I'm assuming you're seeing large load growth like our other utilities. Can you talk about the difference between what we'd see in your IRP in terms of projections and what this transmission planning process looks like? Vice chair, commissioner Marcus Peterson. So similar to APS, we we do work, fairly closely with our resource planning department, you know, with the IRP. We have we still use the data from our 2023 IRP, and a lot of that feeds into, you know, resources that were identified then. We continue to plan for those, but as well as the increase in,

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in resources that we've been seeing coming through the generation interconnection process, but also, you know, this increase in load that we've been seeing over the past year or two, we'd we've been factoring that into our studies, and we get a lot of that information from our resource planning department as well. So I believe a lot of that will be reflected in our 2026 of IRP, which should be filed later this year. Okay. Great. Thank you. No further questions. Thank you. Commissioner Lopez, any questions? Alright. Any questions from staff at this point?

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I just have a question on the Mohave County on the transmission projects. The deferral of Black Mountain, was that due to supply chain management issues? Vice chair Walden, commissioners, I don't I can get back to you on that. I'm not entirely sure what the the reasoning was for that. I know there's additional studies that are going on, for that project, especially with, within coordination, with WAPA at the moment. So I think just kinda due to timing, that of those studies that's been, that has been deferred. Alright. Thank you. Thank you for the question. And I will we'll proceed with your presentation.

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Alright. Thank you. So moving on, I'm gonna go through the BTA studies that, TP and UNSC took part in. So I'm gonna talk about the tenth year snapshot a little bit, as well as the, the distributed generation and energy efficiency study that we performed. And then I will talk a little bit about, the extreme contingency analysis. One bullet I missed here was I'll also talk briefly about the business confidential report, and kinda congestion study that we performed as well. And then I'll go into the the SIL, which is the system import limit,

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the reliability must run, and the maximum load serving capability study that was performed, for, Santa Cruz County. So for the tenth year snapshot, TEP and UNSC participated in the study. That study is coordinated, within what is the Southwest Area Transmission that is SWOT, the sub regional planning group. TEP, we were actually the, the chair for what is called the SWOT BTA task force. We chaired that subcommittee, for this fourteenth BTA. I do I will be presenting, the results of that tenth year snapshot at the conclusion of this study,

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just on behalf of that, task force and the other Arizona entities. So I'll move on to the, the DG and EE study. So TEP and UNSE did participate in the DG and EE study as well, which is coordinated within SWAT. TEP, we conducted the study, for TEP as well as UNSE. The study, looked at a, fifth year. So for the fourteenth PTA, this was the, 2030, heavy summer forecasted conditions. Our load summary table is listed here. So we looked at, the forecasted load not only for the Tucson load pocket, but also for Santa Cruz County,

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due to the fact that Santa Cruz County is served from the TEP one thirty eight kV system. We do have an additional load here, at Thornydale, which is up on the North Northwest Side Of Tucson. They're a a load customer of ours. So similar to what mister Robinson had discussed, we took the the DG and EE program, those forecasted values for that fifth year, and we added them back in to that case. And then we've, ran steady state and transient stability analysis to determine if, there was any,

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any projects that needed to be pushed out or avoided. We did not identify any projects that needed to be deferred or void voided due to the exclusion of the DG or EE program. Next, I'll talk about, the TEP and UNSC extreme contingency analysis. So as it was mentioned earlier, extreme contingency analysis is filed, under CEII. So I'm just gonna give a, kind of high level presentation and summary of that study and what took place. I can't share exact results with that study, in this forum. So our extreme contingency analysis,

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looked at a 2027 and a 2035 heavy summer, power flow case and forecasted load. The entire integrated Arizona power system was represented, so those cases were coordinated with the other Arizona entities to include their, updates and ten year plans. The what we were looking at particularly in the extreme contingency analysis, is we look at corridors, that must contain three or more, transmission lines as well as substations, that contain three or more transformers, EHV, system currently since they're served from our January.

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Excuse me. So that we did not look at any, contingencies for the UNSE system. As I mentioned, that report and results are filed, under confidentiality. This is, something that we do continue to monitor. We don't only look at these contingencies, not only for the extreme contingency analysis, but we do look at this, regularly within our, internal planning studies. And a lot of some of these extreme events are also outlined within the, the current version of the NERC t p l dash zero zero one standard. K. I'll move on to the our business confidential report.

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This was as you may recall, this was a new, kind of new study that was requested after the thirteenth PTA. I think it was very beneficial to look at. We filed this, business confidential report. Again, we filed it under CEII just kinda due to the sensitive nature of the study, and the, you know, the cut the the outcome of that study. The report includes a map of the identified load growth pockets, within the TEP and UNSC service territories. Much of that is just of we're looking at a lot of the, you know,

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kind of key points within the TEP load pocket. That report also contains a list of projects, that we identified to mitigate any, loading or congestion issues, within those load growth pockets due to, increased increased load within those areas. So any projects that we identify, from that study get filed within our ten year plan or, you know, get worked into our plans moving forward. I'll just mention that this is something that we will continue to monitor, not just with this study, but annually within our, traditional transmission planning process,

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to determine any additional, areas of congestion, that we may need to address. And any identified deficiencies within those, load pockets, we will address those in future ten year plan and IRP filings. And just to note, the that TEP and UNSE, we're currently looking at the the the holistic approach, data request that was, issued by ACC staff. We are currently evaluating that, going through that, and we will be addressing those, questions within that data request, by, August 31 of this year. Alright. Next, I'll move into the, the Santa Cruz County,

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our SIL, RMR, and MLSC analysis. So the RMR study, this was suspended after the seventh BTA. After this the seventh BTA decision, it create they created criteria, that could trigger, having to restart the RMR studies. And I have those four criteria listed here. So it's really looking at, an increase in actual load versus the forecasted load from the previous RMR, and then any planned retirements of, transmission, lines or substations, as well as, any, generation units, that could affect an an RMR load pocket.

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And just to mention, that the the suspension of the RMR requirement has continued, to, take effect in subsequent BTAs, since the seventh BTA. Regarding Santa Cruz County, based on the criteria, that I've kind of high level spoke to on the previous slide, the UNSC Santa Cruz County system did meet the requirements of that and that was, the, the two and a half percent load increase from what was forecasted from the previous BTA. So based on that, suspension from the seventh BTA, we were looking at the Santa Cruz County load from 2021 since that was the

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last year that the seventh BTA studied. The forecasted load for Santa Cruz County for 2021, which would have been the tenth year of that study, was forecasted at just under 84 megawatts. The actual peak load in Santa Cruz County, for the year 2021 was 91 megawatts, so that hit the, two and a half percent increase from the forecasted load triggering the RMR study. So our RMR study, we look at three, scenarios. We look at the 2027, 2030, and 2035 study years,

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to perform the study on. As I had mentioned earlier, those cases, were developed from approved, WEC, base cases, but then also, coordinated with the other Arizona entities entities to include their most up to date, ten year plans and, plant projects for those years. Little background on Santa Cruz County. At the moment, Santa Cruz County is served via radial one thirty eight k b line from the our, Vale TEP's Vale substation. That one thirty eight k b line traverses, south to our existing Valencia 138 K B Substation in the,

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city of Nogales. At the moment, in the event of, the 138 K B line going down, or if the load, exceeds the capacity of the line, we have to use, four, thermal generating units that we have currently at the Valencia Substation, to serve that load if we lose the one thirty eight kV tie or we also have a backup 46 k b system that can serve the load in the loss in the, you know, in the if we happen to lose the one thirty eight k b line down to Santa down Santa Cruz County. This table here is really just it's,

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kind of a it's a table of results, that we saw for each of the three years that were studied. As you can see kind of on the second, from the left column here, this was the forecasted load for each of the three years that were studied. And then, we performed the system import limit. So we're looking at, how much the, Santa Cruz County system, can import without the generation, the Valencia generation down in that area being dispatched. And then we do the maximum load serving capability where we look at the maximum amount of load that can be served,

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in Santa Cruz County by by dispatching the generation that we have, at the Valencia Substation. And I will note here, that, the Valencia Substation, there are four, thermal gas generating units, that their total combined output is limited to 30 megawatts, and that is due to some gas pressure limitations down in that area. So the name plate for each of those units is actually larger, but due to that gas limitation, we are only limited to 30 megawatts in that area. So the results of the RMR study for Santa Cruz County,

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did show that, the the the system down there is capable of serving its forecasted peak load in all three years that were studied. Again, due to the radial nature of the system being radial up until 2028, 2027 was able to serve more load, without using the generation in, down there. That is due to some of the planned, reactive devices that we have, going into service in 2027, being able to support some of the additional load, in the Santa Cruz County area. And then as I had mentioned earlier in our ten year plan for Santa Cruz

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County, the Santa Cruz reliability project, significantly increases the load serving capability down in that area even without the aid of the Valencia generation. And not only that, it'll the Santa Cruz reliability project is eliminating the radial nature of that system down there. So once we get all three phases of that built, it will be completely looped, into the TEP one thirty eight k v system. And that'll do it for the TEP and UNSE presentation. I'll take any questions on the BTA studies. Thank you.

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Commissioner Marcus Peterson? Yes. Thank you. Thank you, Josh. And just a quick question on SWAT. What is the membership comprised of? Who are the members? So SWAT is as I've mentioned earlier, is a it's a sub regional planning group kind of under under West Connect. So we have the Arizona entities as well as, LADWP, as a member. And I believe we do, we have, Public Service of New Mexico and El Paso Electric are members of that, as well as some of the other, we have some, independent transmission developers that are members of SWAT as well.

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Okay. Thank you. Yeah. I was curious about the other states involved. And then on your slide that talked about forecasted road, I'm familiar with the South 32 project. Is that encompassed in those numbers in terms of road growth in Santa Cruz County, or is it served by Pima County? I'm not not quite sure. Vice chair Walden, commissioner Marquez Peterson, we do factor in the South 32, what we call the we call it the Hermosa load. We do factor that into the Santa the overall Santa Cruz County load. We just break that out in our studies. So, typically,

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we'll show, the Santa Cruz County forecasted load, and then the the mine load is kind of a separate load itself, but it all gets studied kind of it all gets studied combined. Okay. So it's not necessarily on the slide you showed about forecasted load then. Correct? I'll I can go back to that. So, yeah, our forecasted load here, it is, included in all three of these. So, the we we have the four the the ramp schedule, the proposed ramp schedule from the South 32 Hermosa Mine. That was combined in this total forecasted load here for Santa Cruz County for all three years.

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Oh, okay. Great. Okay. No further questions. Thank you. Thank you. Commissioner Lopez. Yes. Only question similar to last one was, again, any customers, having to be postponed or unable to meet online request for any customers due to either supply chain issues or, I mean, construction? Vice chair Walden, commissioner Lopez, we have not had any, delays or anything to for any of the projects down there. The the the Rio Rico and the Harsha substations, which are,

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being built to serve the mine down there, are actually under construction at the moment. So we are planning on meeting the planned and service date for that customer down there, but we have not had, any other projects that have we've had to delay or defer because of any, supply chain issues. Kind of as I mentioned earlier, go it kinda goes into our, the partnerships that we have with some of the vendors, just getting things ordered ahead of time and then making sure that we have sufficient, spares on hand. Yes. Thank you. That's all I have. Thank you. Any questions from staff?

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Thank you, vice chair commissioners. I just had one quick question. When you're looking at the load forecast, table that we just looked at, there's quite a big jump from 2027 to 2030. Can you talk a little bit? Do you have additional customers coming on, or is there a reason for that forecasted load growth? Vice chair Walden, commissioners, staff, thank you for the question. So as I've kinda mentioned earlier, we have the the South 32 Hermosa mines. They're planned to go into service in, in 2027, but we do have a, we have the load ramp for that.

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So between 2027 and 2030, the mine is planning on getting, up to their close to their full ramp schedule. So kind of full operation at that at the mine. So that's the reason for that jump. And then there is, there is a slight increase in the forecasted load for Santa Cruz County due to just some planned light industrial and some warehousing, infrastructure that, we've were taken into our account in our, forecasting. Thank you. Alright. Thank you. We'll proceed. Alright. So as I mentioned earlier, I will be going through the tenth year snapshot study on behalf of the,

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the SWAT BTA task force, and the the other Arizona entities. I'd like to lead off by just, thanking, my colleagues at, APS, SRP, WAPA, and APCO for their coordination, collaboration, and just getting this effort taken care of, and swiftly and just being overall great people to work with. So the tenth year snapshot, study, this is a commission study, for the BTA. Really, there's two main object objectives for this study. It's to analyze, how each of the Arizona entity tenure plans perform,

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in the regional environment, in the tenth year. So we are looking at, the tenth year, of the the study time frame. And then we're also we assess the effects of omitting, any of the individual entities, planned transmission projects, within that tenth year to see if the the the, interconnection can handle any delays or deferrals of these projects. That's what we call, an iOS case, which is initially out of service. That leads me into my next slide. So to build an iOS case,

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we take the base case, which is, as I mentioned earlier, was a 2035 heavy summer that we looked at, that has all of the plans, all the entities, ten year plans, and projects in that case. And then we we take, what the one of the the projects that are listed in the upcoming slides. We take that out of service or we switch it to status off In the case, so I have an example here, is the the SRP plan project of, the Jojoba to Pinal West, second 500 kV line, and then the second Duke to,

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500 to two thirty kV transformer. Plan for 2028, we would take that project, set it to status off in the case, and then we would rerun it. We would adjust the case, make system adjustments as necessary, and then we would run our contingency analysis on that case. So a little background, for the tenth year snapshot study. As I had mentioned earlier, the the the BTA task force was formed last year. SWAT oversight committee, actually established that task force, in the second quarter of twenty twenty five. TEP, volunteered as chair to chair that task force.

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There was coordination, to develop a study plan for the tenth year snapshot amongst the, the BTA task force, and that was taken to the SWAT oversight committee that was approved in September 2025, after a review and comment period within the entire, SWOT, commit the SWOT group. And then we coordinated on developing that 2035, heavy summer peak case, as I've mentioned. That was coordinated and updated by all the Arizona entities. And then each of the companies created, their own contingency list,

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provided their contingency list and outages, and then SRP, performed the technical analysis, for this study on behalf of the BTA task force. Upon completion of that study, the the results of that of the analysis, were developed into a draft report, which was presented to SWOT, on 12/29/2025. We allowed a two week comment period, throughout SWOT to review, and provide any comments or feedback on that draft report. And then SWOT approved, the final report on January 9, which was subsequently filed with the commission,

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on January 30. So next, I'll go through the projects that met the criteria, for the tenth year snapshot study. The the criteria for this really, for a project to be included is we're really looking at, any transmission project to, two thirty kV and above. So anything below the two two thirty kV level, we don't consider that, for this study. So APS had, 11 projects that we included in this study. SRP, had three. So I can just go through real quick here. We've got them listed by number.

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So APS projects, included the runway, two thirty k v lines, an additional transformer at Sun Valley, some two thirty k v, underground, underground line upgrades, the Bianco two thirty k v lines, and the Toyota Chevalon three, three forty five kV, loop into the Sitgreaves Switch yard. They also had the, included the wafer project, which included a new wafer substation, and then looping in two lines into the wafer, substation. They had we had the Pinnacle Peak two thirty k v series reactor additions,

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the Yocateo Pinnacle Peak two thirty k v line rebuilds project. APS o nine was the North Gila to Orchard project, which included, a second, North HeLa 500 to two thirty kV transformer and a second, North HeLa to Orchard two thirty kV line. We had the Agua Fria to Contrail two thirty kV project. And then the, APS 11 was the cotton transmission corridor projects. I will note here, this is a late typo that I noticed, but the third and the third bullet points,

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I've included the North Gila to Orchard project in there. I can get that corrected and provide a updated presentation to staff at the conclusion of this workshop. Moving on to SRP projects. As I mentioned, they had three projects that we included in this study. With the South Mountain two two thirty kV project, the Rudd, fifth 500 to two thirty kV transformer, and then the Jojoba To Pinal West 500 kV line, and second Duke 500 to two thirty transformer. TEP, UNSE, ATCO, and WAPA, we did not identify any,

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project delay scenarios that qualified or met the criteria as I mentioned earlier to be included in this study. So we are really only looking at the 11 APS projects and the three SRP projects for the tenth year snapshot. When we're performing the study, we do have monitoring criteria for that we take into account, when we perform the analysis. So we look at, the planning events, what we call a p zero, which is no outage. That's normal system conditions. Criteria for that, under normal conditions, no element can exceed a 100% of its normal facility rating. And then our the voltage criteria is listed here.

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So it'd be point nine five, and no greater than one point o five, and that's per unit, voltage. Under, p one planning events, that is a single contingency event. So the thermal criteria for that is no elements can exceed a 100% of its emergency facility rating. So just a little background, most, most elements, transformers, breakers, that transmission lines, they have a normal or continuous rating and an emergency rating in, most situations. And then the the voltage criteria for single contingency, is no,

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no less than point nine per unit and no greater than 1.1 per unit. And then any voltage deviation that we notice, from a single contingency cannot exceed, 88% or greater under those conditions. I'll move into the base case results. So this was the case without any of the projects taken out of service. So this is what we call the base case. All the prior, we didn't find any thermal or voltage, violations under normal conditions or the p zero condition. And then under the single contingency condition,

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which was the p one condition, we did identify one overload in that base case, and that was, due to the an outage of the Griffith to Peacock two thirty k v line, caused an overload of the Griffith to Meconico two thirty k v line up in the Mohave County area. There are there's a study going on to, eliminate that, that overload at the moment. So that should be, taken care of, in upcoming ten year plans. Moving on to the iOS study results. So a p s o one,

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which was their runway, two thirty kV lines project, due to the delay of that project, we did identify two thermal overloads, due to contingency. And that was, the RUD to Goodyear two thirty k v line outage, caused an overload of the RUD to respect two thirty k v line and the respect to white tanks two thirty k v line. We also found that, a the Boba Fett to West Wing two thirty k v outage caused an overload of the rud to respect two thirty k v line as well. The single contingency power flow analysis,

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we did not find any concerning voltage issues or voltage deviation issues, resulting from the delay of this project. Next up, APS o two, o three, and o four. Delay of those projects did not cause, any thermal overloads or any voltage issues or exacerbate any additional issues within the base case. Same with APS o five, o six, and o seven. Delay of those projects did not cause any additional, thermal overloads, voltage issues, or deviation issues within the case or exacerbate any existing issues. Same can be said for a p s o eight,

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o nine, and a p s 10. Again, no issues were identified, or exacerbated due to the delay of these three projects. Moving on to a p s 11, the Cotton Transmission Corridor project. Delay of this project, and if you recall there were several elements, to this project. Delay of this project, we did see some thermal thermal overload issues. Four of those are listed here. So a, Palo Verde to RUD 500 kV outage caused an overload of the Liberty to RUD 230 line. The Red Rock To Saguaro one fifteen kV outage caused an overload of the 85

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to 84, one fifteen k v line. The Cholla to Sitgreaves, three forty five line number two outage caused an overload of the Cholla To Sitgreaves two thirty line. And then a the Bianco To Desert Basin two thirty k v outage caused an overload of the test track to Santa Rosa two thirty k v line. So those were the four overloads observed. We did not identify any, voltage violations or voltage deviation issues due to the, delay of this project. And then the three SRP projects, delay of these three, we did not identify any thermal overloads,

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any or any voltage issues or exacerbation of existing issues within the case. So in summary, the tenth year snapshot, indicated that the plan 02/30, 2035 Arizona transmission system is generally robust. We did identify two project delay scenarios that did result in thermal overloads of certain lines. Delay of these projects could have a limited impact on the the Arizona BES, but may also have impacts on underlying local load serving facilities as well. And then since the study really only looks at the p zero and p one

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planning events, delay of these projects could have, additional, effects on the system if they were to be studied, as delayed under multiple contingency, analysis or events, that the NERC t p l dash zero zero one dash 5.1, is required, to study. And with that, I will open it up to questions. Thank you very much. Yeah. Thank you. Commissioner Marquez Peterson. Yeah. Thank you for the presentation. I think SWOT looks like it's a very worthwhile regional effort and important to ensuring our reliability on our grid. So and thank you again to TEP for chairing this effort.

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No questions. Thank you. Commissioner Lopez. No questions. Morning. Alright. And, staff, any questions? Alright. Thank you. I really, appreciated this and, especially presenting this this snapshot on these case results. Was very good. And I think we're probably the only office in Arizona where you're gonna hear Boba Fett in our meetings. And I'm gonna be honest when you said it, like, episode six started going to my head, and I'm like, Boba Fett, where? Because that's what Hans says in the in the pit. Right. Yeah. Yeah. Is it a Star Wars reference? I I I I would assume it is with it being an APS project.

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I'd have to let them speak a little bit more to that. Now they're shaking their heads. Yes. Okay. Yeah. So there's my nerdom on display. Like, immediately, quote started going through my head. Yeah. But, this is really good information. Thank you so much. I'm gonna have us take a a ten minute break. And so we'll be back at, 10:50, ten minutes to eleven. Great. Thank you. Yeah. Thank you. Sorry. I muted. Okay. There we go. We will return to our workshop. And up next is Arizona Electric Power Corporation. Good morning. Can you hear me alright? Yes.

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Thank you. Hello, vice chair, commissioners, and staff. My name is Ben Boroviak, and I'm a transmission planning engineer with the Arizona Electric Power Cooperative. And today, I will be presenting our ten year plans. And I am also supported by my manager Charles Jones who is on the Webex call. Next slide, please. I'm gonna begin with some background on Arizona Electric Power Cooperative, and we are the non for profit generation transmission and energy services provider for six Class A member distribution cooperatives. We also have three all requirements members and three partial requirements members.

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We serve, 12 counties, numerous cities, eight tribes, and our class a members account for roughly 170,000 meters. We have approximately eight sixty six miles of transmission lines and 36 substations. Also, APCO adheres to NERC reliability standards, WEC reliability criteria, and our own internal planning criteria, similar to the previous presenters. Next slide, please. This is a overview of the, APPCO footprint. And our high voltage transmission assets are located in the vicinity and interconnected to those

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blue class a members. Next slide, please. For the, fourteenth BTA update, APCO submit filed our ten year transmission plan and technical study report on 01/30/2026. We also submitted our business confidential report. And at this time, we continue to maintain the conclusions regarding congestion and load pocket growth that was submitted in that confidential report. Next slide, please. And now I'm gonna present our ten year plans broken up by different regions on the APCO transmission. And so for these three projects,

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shown on this page, they're not shown explicitly on the diagram because they are located at the Apache generation Substation. The first project listed here was completed in March of this year, and that is the Cochise 230 kV substation. And it effectively, expands our two thirty yard, to accommodate more generation. And that is the same to be said for the next project there, the Apache generation two thirty kV ring bus. And that provides just a a more reliable connection for our new generation assets. And that will be completed by the end of this month going into August,

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it looks like. And then an additional project for this area is a replacement of the second one fifteen sixty nine kV transformer at Apache. This existing second transformer has been on service for quite some time, but it's been determined that in, 2030, 2031 time frame, we will need the second transformer to accommodate growing loads in the area. So we, tentatively have it selected for 2029 to have that installed prior to its need for reliability purposes. Next slide,

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please. For our Southern Region, we have not determined any, reliability needs for the ten year plan horizon. However, we are constantly assessing this, region of our system every year, and new, new, system developments or load growth may determine reliability needs in this area in the future. Next slide, please. For our Western Region, we have the Marana Substation rebuild, which loops in the existing 85 and rattlesnake, lines from WAPA. This provides a more reliable connection for us and WAPA.

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Previously, we were tapped into this existing line, and now it is going to be broken up at our substation, so it's not just one long line of transmission without protection. And that was completed in June of this year. And we are also looking at a project with APS. It is our Apache Hayden to San Manuel line. We are still determining the date for this, but we're looking at tentatively for 2028. And what this project does is it, loops in the existing Apache Hayden line to a Reddington switching station.

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And from that switching station, we will be connected to APS's San Manuel substation. Next slide, please. And in our Northwest region and so on this diagram, you'll see the ANSA APPCO class a member in California, and then also our member, Mojave Electric Cooperative. And they are located in North in Mohave County in Northwest Arizona. For this area, we just in the Mohave area that is, we are looking to construct the Mohave Valley 69 kV substation in December of this year, and that's to accommodate new generation on the 69 kV system.

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Next slide, please. That concludes all of APCO's ten year plan projects, and I'd like to open it up to commissioners and staff for any questions that may have come up. Thank you very much. Commissioner Marquez Peterson. No. Thank you very much for the presentation. No questions. Commissioner Lopez. No questions. And any questions from staff? Alright. Well, thank you very much. I I don't have any questions myself. I I appreciate you, presenting. And Thank you. Next up, we'll be hearing from SRP. Good morning, vice chair Walden. Commissioners, pleasure to be here with you today.

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My name is Justin Lee. I'm the senior manager of the transmission analysis department at Salt River Project. My team is responsible for our six year capital planning process, ten year transmission plan, as well as the large generator interconnection process and large load interconnection process. Today, I wanna share with you a little bit about our ten year transmission plan. To do that, I'm gonna first review the current projects that are included in the 2026 report and also discuss with you the changes from our 2024 report to the 2026 BTA report and as well reviewed the BTA studies that we were involved with.

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This is a high level map of the SRP owned transmission system in the state of Arizona to discuss the projects that have, that we have in our tenure plan this year. I'm gonna zoom in a little bit just to make them a little more visible, and I'm gonna work on the right hand side first starting with a Coolidge expansion project in 2026. This is a new 500 kV gin tie line and switch chart at the existing Coolage Generating Station. It's immediately adjacent to the existing Coolage Generating Station. It loops in and out of the Pinal Central Browning 500 kV line. This project is already partially built.

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Six of the units went in service prior to summer twenty twenty six, and the remaining portion will go in service in 2027. Moving to the left, you'll see the Duke Pinal Central 500 kV number two line. This line is proposed to follow the existing Pinal Central Duke line. As far as the corridor, it is needed to provide greater access to generation resources that are being developed in that area. SRP does not currently have a CEC for this project. Next and to the left of the Duke Pinal Central, we see the Marigold Energy Center. This consists of a five hundred two thirty kV switchyard that'll be looped into the

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Duke Pinal Central 500 kV line and will also consist of four miles approximately four miles of double circuit two thirty kV to a collector station and will be used for, collecting resource generation resources connected in that two thirty kV system. This is an SRP requested and driven project and is triggered by, load growth and the generation resources to serve that load growth. SRP is anticipating filing a CEC for this project, later this year. Continuing on to the left, you'll see the Duke Pinal West number two line. Similar to the Duke Pinal Central number two,

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it's proposed to follow the existing line. It's needed for greater access to the resources that are being developed in this area, and we currently do not have a CEC for that project. Alright. Then moving kind of up to the left there, you'll see the Hassayampa Pinal West number 2 line. This line is also proposed to follow the existing line. It's needed to provide access to plan generation in the West. So think more out of the Palo Verde Haciampa hub area. It increases SRP's capacity to import market resources from the West. Other load serving entities with an ownership interest in this project have been identified,

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as necessary within the next ten years to meet system load growth and improve reliability. The portion of the project that's gonna be built in 2028 is the portion from Jojoba to Panaue West. You'll notice that the existing line that it originally did go from Haciampa to Panaue West has been looped in and out of Jojoba. This one, will do the same thing with the portion from Jojoba to Panaue West being built in 2028. And that one we do currently have a CEC for. Last but not least least is the, South Mountain Transmission Project shown kinda right in the middle of the of the map there. I know it's a little bit hard to see,

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but it's there's a little faint black line pointing to that red box is what that is is pointing to to kinda to the left of the word Kyrene. The purpose of this project is to serve future industrial and commercial customers in the Laveen area. This project consists of approximately 4.1 miles of double circuit two thirty kV transmission from the existing Ormond Anderson two thirty k transmission to a new station called Hodgkin's, which is the red box shown there that's gonna be a five hundred two thirty kV substation. Received the CEC for this project in January of last year and is good for ten

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years. Alright. Next, I'll give you a high level look of our two thirty kV system, that helps serve our our load pocket. Once again, these are the SRP owned, transmission projects in the area. I'm gonna zoom in a little bit so I can talk about some of the more specific details. First one I'll hit is there kind of on the bottom center of the slide. You'll see the South Mountain transmission. This is that two thirty component of the project I was just talking about on the 500 kV side. Today, there exists double circuit towers from Orem down to Anderson. We're gonna be cutting into that and looping it in in and out of the

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Hodgkin's two thirty switch yard that will be located there. Next, I'm gonna move a little bit to the east and also south. I'll start at the very top there. You'll see in the middle center middle of a project called Redhawk. This project actually consists of multiple phases, much of which has been built already. The the box just above actually, I should clarify. It is once again kinda hard to see, but there's a faint line pointing over to that red box just above the word Scott. And that's where the Redhawk project is gonna be located. This is this this phase of the project that's being built in in service in

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2026 is an addition of a high voltage distribution line from the Sidewinder two thirty kV switcher to a new customer owned two thirty to thirteen eight kV substation named Nexus. And that piece is going in in 2026. I believe there's an additional phase of the project that will go in service either 2027 or 2028. And then also towards the bottom, kinda center left of the slide, you'll see once again, this is the two thirty side of that Marigold project that I referenced on the 500 kV map. This is just showing the kind of the two thirty side connection.

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This, once again, is 4.1 miles in the dash blue line. There are there are the two thirty kV circuits that will be used to connect to generations being developed in that area. And once again, we anticipate filing a CEC for this project later this year. I'm gonna head much further out east on our system. We have a one fifteen kV system that serves much of our mining load to the east. And there's several projects here. I will start off by saying many of these projects, if not all of them, I believe, are customer driven with exception of one. And so they are to be determined on date. They don't have dates associated with them.

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First one I'm gonna talk about is actually consists of two of them that are identified there, but it's really one project. It's known as the Silver King To East Plant, West Plant two two thirty kV project. This project's about seven and a half miles of two thirty kV transmission. It starts at the existing Silver King station. You'll see they're kind of on the right hand side of the map. It then runs Southwest to a new two thirty kV station known as East Plant and then continues Southwest to another station called West Plant. Then the new West Plant station will be looped into the existing Goldfield Silver King two thirty kV line.

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This is a single customer requested and driven project. It's not triggered by system load growth. SRP does not have a CEC for this project and will pursue one when the customer tells us they're ready to move forward. Also on this map, if you look on the most, kind of on the bottom center, if you will, there's a you'll see a telling switchyard. This is part of the Silver King Telling's Oak Flat one fifteen k b project. This project will bisect the existing Silver King Oak Flat 1 15 k b line and will run southeast as a double circuit one fifteen k b line to a new station that you see there called tailings or a new switchyard.

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The location of the Tailings switchyard is still being determined. And once again, this is a customer driven project. We do not have a CEC for this project, and we will start pursuing that when the customer is ready to move forward. Also, you'll see on the map, the Superior To Silver King 115 kv line reroute. That's shown kind of in the top center of the map or the one in red, the, the top center of the map. The purpose of this project is to re allocate or relocate a section of that one fifteen kV line off the customer's property. They are looking to expand their mining operation and need those transmission a portion of

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that transmission line moved. We do have, a CEC for this project that is good for another ten years. Last but not least on this slide is at the very bottom kind of left side of the slide, you'll see the Coolidge Hayden reroute. There's a short segment of this Coolidge Hayden line that is located on the Gila River Indian community. SRP is currently negotiating an extension of the current land grant, for the line. SRP may elect to move forward this portion of the line onto private land if negotiation with the, Gila River Indian community are unsuccessful. If SRP determines it's or if we determine it's in the best interest of our

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customers, we do not currently have a CEC for this project, but we will pursue one if and when necessary. I wanna share with you also some of the other additions that are showing up in our ten year plan. I'll start off first by talking about the reactive devices. In in our case, we are adding five different sets of what's called series reactors. For two different purposes, some of these series reactors are installed on the system to mitigate what's called fault current concerns that we're having. That is our, the reactors located at Pinocle Creek Wapa Line as well as our Kyrene East and Kyrene West. Whereas the series reactors being put on the Liberty red line and NOx lines are

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more to restrict power flow in those areas. However, the five ohm reactor on the Liberty red line is also helping mitigate some fault current issues showing up in the red area. We also have five different reconductor projects shown in our plan. A little bit couple notes about a few of these. One of them or several of them are using advanced conductor. At SRP, we consider ACSS to be advanced conductor. That's in alignment with what, EPRI considers an advanced conductor. We some of these are are already ACSS or advanced conductor and are being added additional, conductors to those to make them bundled conductors.

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Once again, these are needed to help serve the load growth developing in these areas. We have a bunch of transformer additions. I'm I'm not gonna hit on all of these, individually, but know that a majority of these, especially the ones that say two thirty to 69, those are being driven by our load growth in our in the system or in that particular area. Some of them are not. You'll see there, for example, the RUD fifth two thirty transformer, that's being more driven by not only load, but generation and battery developing in that area. Here's some more on the next slide. Once again,

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majority of these are being driven by load growth to serve the 69 kV system, as our load develops over the years. You'll see the Duke second five hundred two thirty kV transformer on that list. That one was mentioned earlier as part of the, the Jojoba, Panaue West project. That one's needed for transmission scheduling capacity. On the next slide, you'll see several more. Once again, most of them serving load. There is a RUD six transformer that's also needed for load or generations, in that area. Battery, excuse me, battery developing in that area. And the very last three that's shown up there in 2035,

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those are being replaced due to end of life of that equipment. Alright. Now I wanna share with you some of the changes that we've seen since the last BTA. First, I'll walk through the ones that went in service in 2024. I'm not planning to hit all of these. Just note that there's several projects that have gone in service in 2024. Of note, the high-tech interconnect project, or we call it project HIP, was placed in service. That was the the two overhead two thirty kV lines from Henshaw to Parlett, and then an underground two thirty kV line from Parlett to Schrader went into service.

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Also, the Orem Rud line, number one and two reconductoring went into service. That is an area of our system where we put in advanced conductors. The the carbon core type conductor went in, in that area to meet the demand to serve the load in that area. Once again, it's an area we were just constrained on land, and so it made a lot more sense to use the advanced conductor to get the higher capacity because we couldn't, add additional lines into that area. And then last, you'll see the Southeast Power link is another kinda significant project of note. We looped in the Abel Santan two thirty line into Scott two thirty,

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and we added a prickly pear two thirty kV and looped it into into and out of the existing Scott Browning two thirty kV line. Majority of these projects or more than half of them are in kind of our Southeast area of our system. We are seeing a lot of growth in that area as well as generation being developed in that part of our system. Also, a few other projects that were, placed in service in 2025. You can see we had a couple transformer additions in our Papago Butte Station as well as a fourth transformer at our Schrader station. Once again, these are needed to serve a load growth occurring on our 69 kV system.

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Next, I'm gonna walk through some of the, projects that haven't gone in service yet, but our changes in our plan from the twenty twenty four BTA to this twenty twenty six BTA. There are several slides of this, so I'm once again, I'm not gonna hit all of these. I'll hit kind of the ones, that are new to the 2026 that weren't reflected in '24 and talk a little bit about those. And then those are highlighted in red. The the year is highlighted in red. The first one, you'll see the Kyrene Papago Buttes. This project shows up in 2026. This need is driven by generation additions, particularly in the East side of our system under certain scenarios we saw with all

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this new generation coming in on the East. When it's all on at certain times, it was causing overloads on this particular transmission line. The good news is it is a line drop that is being overloaded, which is a very short segment and can be replaced relatively quickly, and that will be done, this year. The next slide, a few more additional ones that showed up in 2026. One I already mentioned, which is the Liberty Rudd series reactors. As we're seeing significant load growth in that Liberty and Red areas, not only in SRP system, but APS system as well, it is causing high flow on that Liberty Red line.

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Once again, there's kinda some land constraints in that area. It made a lot more sense to install series reactors to restrict the load flow on that line to keep it under its rating. In addition, as I mentioned earlier, we do have some fault current issues also on the Rudd 230 KV Switchyard, and that those reactors help to mitigate, the fault current as well. We have the Anderson transformers as well as the Prickley pear transformer, both needed for increased load growth in those areas. I mentioned earlier the Marigold Energy Center showing up, the 230 portion particularly in 2028 as needed,

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as previously said, is needed to, to help deliver planned generation resources showing or being developed in the Marigold area. Anderson Bank number three, this is needed for economic problems. We have we do have a reliability must run constraint in that area. And by adding a third transformer at Alexander, it allows us to not have to run our agro free gas generation nearly as often. And then so it we've had this problem for a long time. It's just getting to a point now where it makes economic sense to put the transformer in. Historically, it was very minimal hours, and so it wasn't it wasn't,

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right at that time to install the transformer. And we also show the brand of fourth two thirty sixty nine kV addition. Once again, was added because of load growth that we're seeing with our updated forecast. Last, you'll see the Duke Pinal West number two line, and I'm gonna talk about these two together, and the Duke Pinal Central number two k line. As I mentioned previously, these are really being put in to help us gain access to the generation resources being developed in the Southeast portion of our system that we didn't have a need for in our last BTA. A few projects were removed from,

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since our last BTA. The first one is the Abel, capacitor bank and which was originally shown in 2029. We no longer need that with the transmission system additions we have planned now. The voltage problems we were seeing at ABLE went away, so that has been removed. The Anderson fifth two thirty sixty nine kV transformer edition has been replaced with us upgrading the existing Anderson, one, two, and three transformers instead. Nate two thirty kv, we no longer need a CEC for that project, so it's been removed from the plan. However, this is still going to be constructed. Okay. I'll go ahead and stop there first to see if there's any questions on the

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ten year plan before I go into the ten year plan before I go into the technical studies and reports. Thank you. Commissioner Marquez Peterson, do you have any questions on the ten year plan? Yes. Thank you. Thank you, mister Lee. So with all the projected new transmission and transformer additions you mentioned, can you speak a bit about load projection for data centers and other large load? When are they considered firm enough to be included in in your plan? Commissioner Peterson or vice chair Walden, commissioner Peterson, thank you for the question. That's a that's an interesting and challenging question.

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As we have large loads coming to our system, I'll walk you a little bit through our study process. Large loads today, they come into our process. They enter into a queue in which we study them as one big cluster. And we do a bunch of analysis with them, and they're kind of speculative at that point. We do significant studies to understand the impacts they have to the grid, which is usually significant because there's a bunch of them at once. We then develop cost estimates and share with them the cost that they would, the cost that would for them to, connect to our grid under those conditions. At that point, it usually triggers many of them to drop out of the process.

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And so then we get down to a more realistic group of who are the projects that are kind of real, if you will. We then go to a second phase of studies. And I should say, at that point, they have to put down some money, a milestone payment to stay in our cluster study process. So they we know they're real. We know that these are projects that are, serious about pursuing development. At that point, we then do a second study. It's similar to the first one. We reevaluate now that there's fewer projects in the cluster process. We reevaluate and determine, what the network upgrades or what mitigations they have to do to the transmission system with the new configuration with a limited number of projects.

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And they have a second opportunity to then withdraw from the process, once we get through that study as well because we may come back even though there's fewer customers in the cluster. It may be that there's more, cost to them because there's certain network upgrades that even though there's fewer, they still trigger significant upgrades, and so there's fewer of them splitting the the cost. In some cases, their their costs go down. And so they would have to make a decision at that point to stay in or not. Once they if they do make the decision to stay in, then they make a second significant milestone project. And at that point, once they sign what's called a design construction operating agreement,

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they are entered into, we we treat them as more firm load that would then be modeled in our studies. That's great. I appreciate the detail. I think that, that was very interesting. And and then a similar question to what I asked, APS and TEP, can you talk about supply chain coordination? Are you coordinating with our regulated utilities, APS and TEP? Because you have so much growth in additions and transformers and upgrades you just spoke about. How are you handling that growth in terms of having the components to be able to build? Yeah. Similar to I believe it was, t e TEP that responded earlier.

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Yeah. We have strong relationships with our vendors for our supply chain issues. This is definitely a challenge in our industry. I I will go back and say first, you know, one thing we're we're doing new this year as we go through our capital planning process, we hold a meeting. When we first develop our new transmission projects that we need to fix, we sit down and meet with a bunch of our internal substation design, transmission line design folks, and do what we call a fatal flaw meeting to walk through our proposed mitigations at that stage to see if there's any fatal flaws with those. But what we find also valuable in that meeting is we do have the folks,

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our apparatus engineering groups and others that would be ordering this long lead equipment are in those meetings and being made aware of our needs that are coming. And so we found that useful to start communicating that much sooner. Also in our studies, we because of the long lead times, we're having to look out further. Not we've always looked out the sixth year, but we're giving a lot more credence, I guess you could say, in making orders and placing orders for equipment sooner than we would have. But from the supply chain issue side of it, it does help that we're requesting equipment sooner. We do have, strong relationships with existing vendors. We do have a vetting process that SRP uses to make sure those vendors meet

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our specifications. We've expanded that list of vendors. In addition, we are developing strategic agreements with specific vendors to help supply, our needs as well. So any I don't know if that's in response to your question there. No. That think that's helpful. We're hearing a lot of anecdotes about the large load actually kind of competing with our utilities for different pieces of equipment. Are you experiencing that same situation? And is there any association or entity out there, regional or national, thank you, commissioner Marcus Peterson. Yes. We are seeing some of those issues in the sense that all of us are competing for the same elements.

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Right? When a large load customer comes in and they develop their station, especially if it's, like, at the two thirty k v level, they're ordering from the same vendors that we are for the same for a transformer of that size. It's we're all competing for those same vendors. I'm I'm probably not the right person to ask on the vendor stuff. That's that's our apparatus engineering group, and I could get back to you on more detail on any regional coordination, but I'm not aware of that. Okay. Thank you. And I do see Manny sitting behind you, so I will follow-up with him too. But thank you. No further questions. Thank you. Commissioner Lopez, any questions?

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No questions. And, any questions from staff? Alright. Thank you. We'll continue. Thank you. Alright. Next, I'll share with you our technical studies and reports. I'll first talk about our ten year plan technical study. That's the point where I'll address the requirement, the new requirement. Also I'll briefly review the joint studies, but I think a lot of these have been covered well by my counterparts at APS and Tucson Electric. A little bit about our ten year plan technical study. This was submitted in January 2026. This study was or this report was submitted under a protective agreement.

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We do consider it critical energy infrastructure information. But this report does document the technical analysis that was performed in support of our ten year plan. In that report, you'll find all of our power flow analysis, our transit stability analysis that we do for each year of the plan. So 2026 through twenty twenty twenty five, you'll find those results also in that plan. For for this year, our report the system performed well within the thermal voltage and transient stability boundaries for the steady contingencies, with the projects in the ten year plan the proposed projects in the ten year plan in service.

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Technical study, largely because of the uncertainty of load growth or future resource replacement, and that's listed here. As mentioned, the ones at the bottom are the ones for those Eastern mining areas. There's a lot of uncertainty around if and when those will be built. So those were not included. The other ones, although some of them do have a c even a CEC, they were excluded because there's still some uncertainty at this stage around the timing of when those go in and when we would model those. And so they were not they were excluded from the technical study. In the technical study, you will also find where we address the new requirement regarding areas of line congestion

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and projection of low growth pockets. And SRP took a similar approach to what I think APS and Tucson have shared today. I I kinda wanna walk you through what's you'll find in the report. It's found in appendix c. We'll address this. And the first thing you'll find is a list of tables that show the lines that were loaded above 90% for each of the years. So there's gonna be a series of 10 tables. First table is gonna be the year 2026, and it's gonna identify all the lines that were loaded 90% or higher in that year. I do wanna point out that you won't see lines loaded above a 100%. And the reason why that is is if their lines are overloaded a 100% above

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a 100%, then we go develop a transmission solution for them. So you'll see, like, in the very first table of the year 2026, there'll be a line that shows up at 97%, and then the next year, that line doesn't even show up in 2027. And the reason that is is there was a fix put in place between those two years, and so the the loading on that line goes down and it drops off as being congested. To show that on a geographic perspective, you're gonna see a map that looks almost identical to this in that appendix c, except for those lines that show up as loaded above 90%.

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And each of those years will be highlighted in red on this map. Also, we highlighted for you all the transformers that we're overloading because you do have a significant number of them, not overloading, but that are heavily loaded or congested. And that's those boxes on the on this map. Those are where we have substations where those transformers are located. So if there was a transformer in that substation that was loading above 90%, that substation is also identified in red. And then on the map, you'll have overlaid on top of this, similar to what you saw with APS today, kind of circles or or bubbles showing where our load growth is happening. We got our load growth primarily from our load cluster,

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queue. We see where the projects are being requested on our system. That gives us an idea geographically where we're expecting them to come in. Alright. Also, I'll continue on in our technical studies and reports. This year SRP performed the eEDG study. I believe APS also discussed this on their on their presentation as well, but it was performed by SRP on behalf of both APS and SRP. We looked at the 2,030 heavy summer forecasted conditions. As as was discussed previously,

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when we do the e e d g study, what we're looking at is what happens if the energy efficiency programs aren't adopted by our customers or if they don't adopt distributed generation as much as we expect them to. And what we're trying to identify is, are there projects that today are potentially being masked? Because as APS pointed out, when we model the eEDG in our system, it lowers the load. So it makes it look more optimistic, in a in a sense because the load is lower. And we wanna make sure that we're not under building our system in case these projects don't get, don't come to fruition or in case these impacts don't come to fruition.

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And our study is mentioned previously by APS. We found that there were no projects that have been deferred or avoided due to the inclusion of DG and EE in that study. We also participated in these three studies. I don't I'm not gonna talk to detail to these today's today, I think these were covered well by my counterparts at APS in Tucson. Other than to say SRP actively participates, in SWAT in which some of these studies, I believe the tenth year snapshot study was completed, and we also coordinate with APS and our counterparts to support these studies and provide any necessary data or in some cases perform analysis if and when needed.

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SRP does continue to seek opportunities for stakeholder input. To meet our FERC order eight ninety, we do hold public stakeholder meetings in the second and fourth quarter of each year. We do that jointly with APS. We also continue to actively participate in the regional and subregional base coordination, primarily done through SWAT. And in both of those forms, we have not received any input from our stakeholders. And then lastly, I did wanna talk a little bit about SRP's regional transmission planning efforts. SRP is a member of the Western Electricity Coordinating Council.

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A little bit about WEC. WEC is a nonprofit corporation approved by the Federal Energy Regulatory Commission to serve as the regional entity, and they are tasked with ensuring the reliable ensuring a reliable bulk electric system in the geographical area known as the Western Interconnection. And the Western Interconnection spans from Canada, most of the 14 Western United States, and portions of Northern Mexico. SRP actively participates in WET committees. Members of my staff serve as chairs or members on various committees within WEC, and they participate in those committees and help integrate new system and generation models.

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They create WEC wide base cases, establish WEC reliability criteria, and coordinate planning methodologies. SRP is also a participant in the Western Transmission Expansion Coalition, also known as Westech. This is a West wide effort to develop an actionable transmission study to support the needs of the future integer grid. The final deliverable will be a West wide transmission needs study looking out over the ten and twenty year periods. Westech recently released the ten year study. I believe the twenty year study is gonna be released later this year. The West Wing Power Pool is coordinating this project,

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which spans the West and includes regional partners representing a broad swath of industry sectors, states, and tribes. SRP is funding and actively participating in Westech's study process and is a member of both the Westech assessment technical task force, also called WAT, as well as the Westech steering committee. And then last on our list is the Southwest Area Transmission. I know Josh did a good job earlier today describing this this, the subregional planning group. But SRP is also a member of the the SWOT, which is a subregional planning group, which addresses future needs transmission needs on a subregional Desert Southwest basis.

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SRP participates in SWOT activities to help meet obligations for the ACC and tenure transmission plan filing. SWAT disseminates its work publicly and cord coordinates its studies and data with other subregional planning groups. With that, any questions? Thank you. Commissioner Marquez Peterson, any questions? Oh, just wanna thank you for covering the regional engagement that SRP is involved in and no questions. Commissioner Lopez. No questions. I do not have any questions. Staff, do you have any questions? Alright. Thank you very much. Thank you. Thank you to, our utilities that came in and presented or presented remotely.

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There's, an agenda item for public comment, but no one has signed up. So we'll move on, to scheduling, and I'll turn this over to staff to go over the dates. Adam Beckerman again for staff. Just wanna provide a quick overview of the remainder of the fourteenth BTA process. I can provide this to stakeholders as needed as well. So today was the first BTA workshop. The plan is to have the first drafted BTA report docketed by September 18, and we'd have a comment period for about a month and a half ending on October 30,

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for the first draft. And then using those comments, we would develop the final draft of BTA report, and that'll be docked docketed next year on January 8. And then March or April 2027, we'll discuss the fourteenth BTA at the ACC open meeting. Any questions? I I don't have any questions. Any questions from my fellow commissioners? Nothing here. No question. Alright. Well, we will move on to any final closing remarks or or comments, and we'll start with commissioner Marcus Peterson. Yeah. Just wanna thank all of our utilities for preparing for today, and thank you to our staff for leading this effort.

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This is very important to the state of Arizona, so appreciate everybody's engagement. Commissioner Lopez. K. Yeah. Also, thank you all to the presenters and staff. I think this is very important that, I know all the utilities there are doing the right things, and it looks like they're planning well ahead. But, we appreciate you coming and educating us on all you're doing and the public. Thank you. Alright. And, staff, do you have any closing comments you'd like to add? Well, thank you. I found these presentations more thorough and, up to date. They were, I think,

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different than last year, and that's a really good thing because they encompassed a lot of information and probably why we had less questions today. I think everyone was really prepared in giving us an overview of the landscape in Arizona. I think what we've heard today shows that we are why we're top tier in reliability. I was really encouraged to hear about the coordination amongst, entities, understanding more about the proactive procurement processes that our utilities have so that, you're trying to stay ahead of the supply chain management issues,

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which is out of anybody's, control. And it's really encouraging to hear about the very good relationships, that everyone's working to build together and especially in working on agreements with your vendors. I I really liked the studies on the distributed generation and energy efficiency and being able to show in that modeling that, even without those pieces that Arizona is still going to be able to meet energy demand and reliability even in those extreme contingencies. So very good things today. Thank you everybody for being here,

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and this meeting is adjourned.