Good afternoon, everyone, welcome to IDACORP's Q2 2026 earnings call. Today's call is being recorded and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP website. If you need assistance at any time during the presentation, please press star zero on your phone. I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance, and Risk. Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we'll reference during today's call are available on IDACORP's website. As noted on slide two, our discussion today includes forward-looking statements, including things like earnings guidance, spending forecasts, financing plans, regulatory plans and actions, and estimates and assumptions that reflect our current views on what the future holds. These are all subject to risks and uncertainties. Those risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements. We've included our cautionary note on forward-looking statements and various risk factors in more detail for your review in our filings with the Securities and Exchange Commission. As shown on slide three, also presenting today, we have Lisa Grow, President and CEO, Brian Buckham, EVP, CFO, and Treasurer, and John Wonderlich, Investor Relations Manager. Slide four has a summary of our Q2 financial results. IDACORP's diluted earnings per share were $1.79, compared with $1.76 for last year's Q2. I want to highlight we didn't record any additional tax credit amortization under the Idaho regulatory mechanism during the Q2 of this year, compared with recording $17.2 million in the Q2 of last year. For the H1 of 2026, diluted earnings per share were $3 versus $2.87 in 2025. Those results only include additional tax credit amortization of $6.3 million in the H1 of 2026 versus $36.5 million in the H1 of last year, which showcases the strong performance so far for 2026. Our key operating metrics, we're raising the lower end of our full-year IDACORP diluted earnings per share guidance range by $0.05 to the new range of $6.30 to $6.45. This increase is driven by our strong operational results in the Q2. It includes our expectation that Idaho Power will use less than $15 million of additional tax credit amortization for the full year, which is a reduction from the less than $30 million in our prior guidance. These estimates also assume historically normal weather conditions for the rest of the year. Now I'll turn the call over to Lisa. Thank you, Amy. Thanks to everyone for joining us today. I'll start my remarks with a look at customer growth. As you can see on slide five, we've seen a customer count increase of 2.3% since last year's Q2, with growth across all customer segments. The customer and load growth that we've seen within our service area remains strong, and we're working hard to meet the increased energy demand. As one data point, industrial revenues, which include large contracts, were up a staggering 17% compared with the Q2 of last year. Thanks to years of thoughtful planning and project execution, we started seeing increased revenues from large contract customers in June, with more to come in the H2 of 2026. I've been providing updates on Micron's expansion and Meta's new data center during our earnings calls for years, it's great to see this hard work come to fruition as these projects ramp up. You can see photos of these massive projects on slide six, along with pictures of some of our other large contract customers like Chobani and INL. Looking at slides seven and eight, we're strong advocates that growth has to be sustainable and responsible so that service to our existing customers remains reliable and affordable. We expect that new agreements with large customers will include appropriate take or pay provisions, termination payments, and certain upfront payments, along with strong credit requirements, just as we've done in the most recent Energy Service Agreements. These elements help ensure that growth pays for growth without shifting costs to other customers, they help de-risk large loads for both our customers and our owners. One of the main draws to Idaho Power service area is affordability, and keeping prices as low as possible remains a priority. Our retail prices are well below the national average, with our average residential price about 30% below national average. I'll also point out that the revenue growth from the large contract customers is a key driver that's helping us stay out of a 2026 general rate case. We'll continue to take this thoughtful approach with our large customer pipeline, which remains strong at multiple gigawatts as businesses across multiple industries look to operate in our region. Moving to slide nine, we're full speed ahead executing on projects to serve our customers and enhance our grids. We recently brought 250 MW of new company-owned battery storage online as scheduled, marking our fourth straight year adding batteries to our system. Since 2023, we've added over 550 MW of company-owned batteries. We also completed the conversion of Valmy Unit 2 from coal to natural gas last month in time to help us meet peak summer loads. Additionally, a 125-MW third-party owned solar generation project was recently commissioned as part of our Clean Energy Your Way program. These resources support our efforts to add capacity, flexibility, and reliable, affordable energy to serve our growing regions. Turning to slide 10, I'll provide an update on our three major transmission projects. We expect all three to come online in the next several years, bringing with them critical system flexibility as well as access to diverse markets and transmission wheeling revenues. Starting with Boardman to Hemingway, work is progressing nicely. As of today, about 70% of the 1,300 structure pads have been completed. Over 400 towers are built, and we've started stringing wire. It's a huge undertaking, and we're pleased with the progress. We continue to expect B2H to be in service by late 2027. On the Swift North Transmission Project, we received our CPCN from the Idaho Commission in December, and project construction recently started in Nevada. With such good progress on the project, we expect the line to be completed in 2028. We're also continuing our work with PacifiCorp on the Gateway West Transmission Project. As we mentioned last quarter, we filed a joint request for a CPCN with the IPUC, and we anticipate a portion of the segment described in that filing will come online as soon as 2028. As seen on slide 11, progress continues toward the construction of three company-owned natural gas-fueled projects that I've mentioned on previous calls. Construction is underway on the first, a 167 MW resource next to our existing Bennett Mountain Power Plant. We've secured a CPCN, an air permit, and an EPC contract has a scheduled in-service date of 2028. We've also filed CPCNs for the 222 MW South Hills Project, which is scheduled for operation in 2029, and the 430 MW Peregrine Project, which is slated for 2030. We continue to work toward procuring the necessary materials and construction services to build these gas plants. These dispatchable projects will help us meet our near-term capacity deficits. Turning to slide 12, we're in the process of evaluating bids from our 2032 RFP. All bids have been submitted, including several of our own. At this stage of the process, several of our self-bid projects remain competitive, and the review team is beginning to narrow the field of contenders. We expect to have a final shortlist in the Q3 and begin contract negotiations soon thereafter. I'll close my remarks with an update on the proposed sale of our Oregon distribution system. Over the last few months, we filed applications with the Oregon Commission, the Idaho Commission, and FERC, requesting approval of our sale agreement with OTEC. These filings are being processed, and we expect the sale to close in the spring of 2022, pending successful regulatory outcomes. We've been very busy, as you can see. With that, I'll turn the time over to Brian. Hey, thanks, Lisa. Hi, everybody. Thanks for joining us today. It's exciting to see all the projects going on right now. Recent project execution's been particularly important because it helps serve an 8% quarter-over-quarter increase in industrial loads and it'll do that going forward. That load increase helped drive the 17% increase in industrial revenues that Lisa mentioned. Financial success is linked with operational success, and I think the financial side is just as exciting, with strong results for the quarter and the year to date. Benefits from the January 1st rate change and customer growth were certainly evident during the quarter. I'll also mention that irrigation sales were up for the quarter, which is impressive given that Q2 of last year also had favorable weather conditions for irrigation sales. This year's relatively heavy April rain didn't dampen quarterly irrigation sales because we later experienced the dry May and June. Aside from the amount, the timing of precipitation can also notably impact irrigation sales volumes. Before I get into the details, I wanted to point out that we added a new line to our quarterly reconciliation table. It shows the financial impact from large contract customers, which I think will be helpful going forward as we see the growing impact of these customer contracts. When I quote changes from rates or customer growth generally, these exclude large contract customers because those will land on their own new line. Getting more into the details, let's go to the recon on slide 13. From that, you can see that the biggest movement was from higher retail revenues from the January rate increase and from customer growth. Combined, those were a $32 million benefit for the quarter, and year to date it was over $52 million. Per customer usage was essentially flat for the quarter. Residential usage declined due to milder temperatures; higher irrigation usage mostly offset that decline. The fixed cost adjustment mechanism also benefited retail revenues, which resulted from the lower sale to the residential and small commercial customer classes. On our new line, revenues from our large contract customers increased operating income by $6.5 million for the quarter. As expected, we're now seeing with greater prominence the revenue and load ramp-up from some of our large contract customers taking shape, we expect to see more of that benefit in the H2 of the year. As we expected, O&M expense was almost $12 million higher in the Q2. Primary drivers were the amortization of previously deferred costs associated with the Jim Bridger Plant and our Wildfire Mitigation Plan. A large portion of those items we recover in customer rates, they're also reflected in revenues. Depreciation and amortization expense increased around $5 million for the quarter. No surprise there, given our ongoing infrastructure investment. Other changes in operating revenues and expenses increased operating income by a net $6.3 million. Similar to the impact in the Q1, this benefit resulted primarily from a decrease in net power supply expenses not accrued through the power cost adjustment mechanism, that was due to updates to the PCA mechanism based in last year's rate case. Non-operating expense increased only marginally with higher AFUDC mostly offsetting higher interest expense. Fairly significant, important from my perspective, Idaho Power didn't record any additional tax credits under the Idaho Earning Support mechanism in the Q2. That was about $17 million less than what we recorded in the same quarter last year. From a year-to-date perspective, the roughly $6 million we've recorded for 2026 is compared to over $36 million we'd recorded at the same time last year. That lower credit usage, even with higher expected book equity this year, is really indicative of our financial strength and performance this year. Our next slide 14, reiterates what we discussed about CapEx on the Q4 call. It's just for reference. What you see in that forecast is admittedly already a large amount of capital, as a reminder, it doesn't include any assumed resources from the 2032 RFP. Relatedly, it also doesn't include resources to serve projects like the Micron Fab 2 facility. It doesn't include updates from our annual long-term capital budgeting work. I'll just reiterate there could be some upside to what's shown. We expect to have more intel for you as we work through the RFP, the load forecast update, and our annual capital budgeting process, all three of which are currently in progress. Moving to slide 15. In the Q2, we executed around $260 million of additional forward sale agreements through our current ATM program. We're showing on there around $2 billion of equity content that we need to fund our business for the next five years under the current plan. We've either issued or we've sold on forwards about $1 billion already. We've solved for roughly half of our current plan's equity needs. We have the equity we need into 2027, and we think the remaining amount in the current plan is within ATM ranges. I'll reiterate that any additional CapEx would require some additional debt and equity. We still plan to blend debt and equity on a roughly equal basis for any incremental CapEx, with the goal of keeping our balance sheet strong. Slide 16 helps to summarize the forward sale agreements that we have available and the forwards that we've settled to date. As you can see, we have a balance of about $715 million of forwards available for settlement. I don't have a slide on it, but I think operating cash flow warrants a mention given the deviation from this time last year. It looks low this year on a comparative basis, but it's important to note that much of the deviation is due to timing, including balances of items like accounts receivable and payable, prepayments, and the PCA mechanism. One last note from me. The Idaho Commission recently issued an order in our request for a prudence determination related to our Hells Canyon relicensing effort. The commission, in that case, determined that our project expenditures from the start of 2016 through year-end 2025 were prudently incurred, rendering them eligible for inclusion in retail rates in a future regulatory proceeding. We're pleased with the outcome of that case, in part because, as many of you know, we pride ourselves on being prudent spenders at the company. I'm going to wrap up there. I'm going to hand it over to everyone's favorite IR celebrity, John Wonderlich. Thanks, Brian. Turning to slide 17, you can see our 2026 full year earnings guidance and key operating metrics. We've had some solid improvement in our earnings and ADITC guidance. As usual, we assume normal weather for the remainder of 2026 for our guidance. With strong operating performance in the H1 of the year, we now expect IDACORP's diluted earnings per share this year to be in the range of $6.30-$6.45. We lifted the bottom end of the range. We also see solid improvement in our ADITC expectation, we're cutting our guidance in half. We now expect that Idaho Power will use less than $15 million of additional investment tax credit amortization in 2026, which is much less than the $40 million we amortized for the full year 2025, especially when considering the significant increase in year-end book equity, as Brian noted. We continue to expect full year O&M expense to be in the range of $525 -$535 million. We still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026, though at this point it's fair to say we're trending to the high end of that range. Finally, given our current forecast of hydropower operating conditions, we expect hydropower generation to be within the range of 5.5 -6.5 million MWh for the year. We trimmed a half a million MWh off the top end of our guidance as dry conditions returned in May and June. With that, we're happy to address questions you might have. We're now ready to begin the question- and- answer session for attendees who have joined on the Q&A line. If you would like to ask a question, please do so by pressing star one on your phone. Please ensure your mute function is turned off before you ask your question. We'll take as many questions as time permits on a first come basis. Once again, that is star one on your phone to ask a question now. Your first question comes from the line of Shar Pourreza with Wells Fargo Securities. Please go ahead. Hi there. Hi, team. This is Whitney Mutalemwa on for Shar. Hi, Whitney. Hey there. On resources, you've got 250 megawatts of batteries now in service. You have a number of applications in front of the commission. Is that pace, roughly a project every few months, sustainable, or does it get harder to keep up as the queue grows? A follow-up would be, with all the battery storage going in for Micron, Meta, and the rest of the pipeline, is gas plus batteries the sole long-term answer, or are you also looking at things like SMRs further out? Yeah. Great question. I'll start, and I'll have Adam give some more detail. Certainly, when we're looking at what we are going to need to serve our load, we go through an exercise of the IRP, the Integrated Resource Plan. We're really looking for the least cost, least risk answer. We have a total of 550 megawatts of batteries. No, that's not the answer to everything. It's great energy that will sort of fill in when the solar energy starts to diminish as the sun sets. It's a great resource for the summer, but it's not a great source for the winter just because of shorter days and we don't get a chance to refill the battery before we need them again, and they last for four hours. Some of the operating characteristics just make it so that it's a great energy resource, but we don't really consider it a real capacity resource more than those first four hours. It is an absolute sprint to keep up with this growing load and getting the resources online and in time. We've mentioned our pipeline before. That continues to be evaluated as we go on beyond what we've shown here. I think, Adam, you want to fill in? Yeah. Thanks for the question, Whitney. Happy to walk you through year by year how we're looking. In 2027, it's largely batteries and solar. We have a fair amount of that, probably 400-ish, 500 MW of solar, another 100 MW of batteries. From that point, it does go turn a little more on the gas side. 2028, we talked about it, Lisa and her comments, we have Bennett 2. 2029, we have South Hills, which is also a gas project, 222 MW. In 2030, we have a project called Peregrine 1, which is also gas, 430 MW. Idaho Power's origination team for 2031 and 2032, we bid in eight projects. Six of them were gas projects. Two of them were storage projects. That should help give you at least a little bit of a mix of where we're at in terms of gas versus storage versus solar in the next several years. In terms of SMRs, we've spent a fair amount of time learning about these new technologies. I'm on the customer advisory committee for one of the key technologies and companies. We spent a fair amount of time with INL and we've met, I would say, with most of the key developers in that space. Our summary is that we like SMR technology. At this time, we don't love the pricing, which as you probably know, is likely over $150 a MWh at this point. Again, we like SMRs, but we're probably not going to be the first, and we're probably not going to be the last to look at them. We'll continue to keep an eye and evaluate those technologies over the next several years. The timing also when they would be available. Of course, in addition to the CapEx and the generation projects I mentioned, Lisa in her comments also mentioned B2H. We're making great progress there. Southwest Intertie Project broke ground recently, which is just a great milestone there. Of course, Gateway West too, which we're looking to work on and construct over the next several years. It's always good to point out, I think, that transmission is a big part of our plan as well. The generation mixed with transmission is what makes it all work out together. All right. That sounds good. Thank you. Then just if I could squeeze in a tiny question. On wildfire mitigation, obviously not trying to get ahead of the Mountain Home investigation, since it's early, but you'd just gotten the 2026 Wildfire Mitigation Plan approved right before this happened. Does an incident like this change anything about how you're implementing it, or is it too soon to say? How are you seeing the plan be put into practice? Yeah. You're right. We do have a mitigation plan, and now the Wildfire Standard of Care Act here in Idaho applies to that mitigation plan. Certainly, the wildfire was impactful to that community, and we worked really hard to make sure that we are there for that community to help them get back on their feet and repair, replace what was lost. It was a relatively small fire, and when it's all said and done, it will not be a material impact to our company, but we are taking it very seriously. I wouldn't say that we are changing anything about our plan. We certainly continue to implement it. That is the key focus. That it's one thing to write the plan. It's quite another to make sure that we are following it. In this case, it actually was followed. We feel really good about the implementation of that plan. I think that's probably about all I would have to say about that. Well said. Thank you. Your next question comes from the line of Michael Lonegan with Barclays. Please go ahead. Hi, Michael. Hi. Thanks for taking my question. On Micron fab 2, just wondering if you could share the status of negotiations and when you expect to sign an ESA, anything you could share regarding the size of that investment that could be added to your planning. Could this be a Q3 update when you update your load forecast? Those are often confidential, we have to rely on our customer as to whether or not they want to make that public. I will say that the negotiations are very active. Adam, do you have any details? We're progressing well. In terms of the site, a ton of work is going on. It's amazing to see what a $50 billion site looks like, they have started ground preparations on fab 2. We are in ESA discussions, as Lisa mentioned, those are confidential, we can't really speak to those. In terms of the CapEx side, Brian can speak to this, fab 2 is not in the 8.3% IRP CAGR that we've shown. It's outside of that as well in terms of spend. Yeah, just to add on to what Adam said, most of our CapEx that you see in the slides was premised on the 2015 IRP load growth rate, the 8.3% that we mentioned. 2025. Sorry, 2025. Yes. Thank you. It excludes customers like Fab 2, along with several other promising loads, as we call them, that we're working with right now. Those incremental loads all generate additional capacity and energy needs. With some of our related spending for the power infrastructure related to that occurring pretty urgently, I'd say, in our five-year window, and not all of it on the outside of that window. While the 2025 IRP is a data point, we're tasked with serving load as it materializes. The in-process transmission lines and the outcomes of the 2032 RFP will all be part of how we solve for that load growth that materializes. That'll end up getting reflected in our CapEx refresh, and also a load growth update that we'll do for the 2027 IRP. Thank you. Then, regarding your next rate case, I know you've indicated that June 2027 was a possibility. How are you thinking about that now? Can we expect this to be a modest request given all the large load coming in? I know you often get asked about a depreciation and interest tracker. Could that be in there as well? At this point, we're not really looking at a depreciation or interest tracker, it is because the revenues of these large loads are helping to cover those costs. We continue to look at a possible June 2027 filing, we obviously do the analysis, we sort of wait and see if that is what is needed. If things go as we are sort of forecasting, that's, I would say, a high probability, we wait to see what the data actually indicates. Michael, this is Brian. I think from the financial side, what we look at is you've got large load revenues on one side that certainly are helpful. The other side of the equation, though, is plant that goes into service. In 2026 and in 2027, we expect quite a bit of our CapEx to convert to plant in service. If you look at the balance sheet now, it's over $1.8 billion of CapEx. There's a lot that sits there as of today. When that converts to plant in service, obviously, depreciation starts and AFUDC stops. We get into a situation where we do the evaluation of keeping in mind things like cash flow, affordability for customers, all of those attributes, whether or not we file a rate case. We'll have to do that math pretty early in 2027 as we look as to whether or not we'll file a rate case. As Lisa mentioned, it's looking relatively probable at this point. Again, we're in somewhat of what I call an envious position compared to prior years, where we have to do the math on that every year. That's beneficial. We did it this year and decided we didn't have to file a rate case, in large part because of those large customer revenues that are coming in for the company. The other thing I'd mention, just on the tracker component, if you file relatively frequent general rate cases because you have so much plant converting, the tracker doesn't have as much value. You also have to be careful because a tracker wouldn't be shifting costs to customers that aren't driving the expense. The tracker would have to be structured in a way that to the extent it applies to residential customers, it would be for the projects that are benefiting the residential customers, not the large load growth customers. We're very cognizant of that when we think about the types of mechanisms that we use on the regulatory side. Thank you. Obviously you're using less of the ADITCs, presumably your earned ROEs are higher than you expected. With all the large load coming in, how do you see the earned ROEs trending over the forecast period? Is the chance you earn above, you're allowed or obviously you don't give long-term EPS growth guidance, but anything you could share on earned ROEs? Sure. It's a projection that we do all the time in our forecasting. There's a possibility that occurs, but I think the thing to look at is the amount of depreciation and interest expense that we have to overcome in any given year, given a historic or hybrid test year that we have in Idaho. While it's possible those revenues could be large enough to over earn in some years, I'd say in the near term, that's less likely just given the construction cycle that we're in. That said, you've seen us reduce our ADITC expectations for the year already this year, and they're significantly lower than last year. Things like weather conditions or outperformance on large load expectations compared to what we have in our forecast certainly drive us more towards over earning, certainly the base level for the ADITC mechanism, and then potentially even up from there. Great. Thank you for taking my questions. Thank you. Your next question comes from the line of Chris Ellinghaus with Siebert Williams Shank. Please go ahead. Hi, Chris. Hey, everybody. How are you? Good. Brian, thanks for that new line. That's helpful. In terms of the large customer load ramp, can we just think about that similarly to retail in its seasonality, based on your temperatures? I wouldn't look at it that way, Chris, because while residential and some of the small commercial can be pretty sensitive to weather conditions, the industrial loads themselves are not. They tend to be driven more by what sort of equipment is installed and turned on at any given point. You can see Micron's load ramp in their special contract. You can see that there's step-ups. They're certainly not linear. Right. There are take or pay obligations in that. They don't reflect seasonality necessarily. If you look at things like data centers, their ramp-ups can be premised on what server racks are installed and when they're turned on. I wouldn't look at it that way. One thing I would note is, if you think about that line that we added, really you only have one month of Micron revenues in there for Fab 1. You do see some of the Meta ramp-up reflected in there, but a lot of that is early stages, and we'd expect to see that more of a steady ramp-up over the H2 of this year. Right. Yeah, it was really not the timing of incremental on for these customers, but in terms of their cooling requirements. Is there seasonality to the usage portion once something's online? We haven't really forecasted that way. We look at it more of a steady state from equipment operation, not from a cooling system, though it is possible in some of the hotter summer months, there could be incremental loads from cooling systems. Okay. In raising the guidance, is that purely a look through the Q2, or does that include any of the July? Seems like it was materially warmer than last year and still dry. Does that include any look into what you know about July so far? Not much. We have anecdotal evidence that July was a little warm for us. In general, we cut it off at the end of the quarter and then just predict normal weather conditions for the remainder of the year. If it does turn out to be hotter, then we expect there to be some incremental benefit there. Okay. Is there any rationale for you guys to use any parent leverage as you get into really heavy spend? We talk about that from time to time. One thing we have to watch for on that is credit rating implications of that. The credit rating agencies have complimented us, as have many of our investors, on the fact that we don't have holding company debt. When we go to market at Idaho Power for debt, we tend to be very well-received. Our regular way financing approach has been successful for us in terms of interest rates and otherwise, and just interest in the marketplace. Our preference is for that relatively simple balance sheet. When you start adding holding company debt, you do add some complications, some regulatory items that we have to address, and otherwise. We've really focused a lot on regular way financing, of course, through our equity transaction at IDACORP. In terms of hybrids, mandatory convertibles, I would say those are not something that we've taken off the table, but it's not our go-to when we think about the structure of our balance sheet. The other thing I mentioned is there are other ways for us to address large contract needs for EDCs and our generation resources and our just big CapEx build-out. We've done some of those. It's things like requiring payments from some of the customers up front for some of this. We have other mechanisms in place that we use, but we did an exercise recently where we laid everything out on a piece of paper in terms of what all of our options are, and we have the luxury of being able to select them based on ranked priority. In a really good spot from my perspective on keeping the balance sheet healthy without unnecessary complication. Great. That helps. One last thing: regarding the SMR discussion was useful. Pricing has been rising for these large load customers pretty much across regions, and there's some, I'd say, price insensitivity, it seems. While SMRs might be pricey today, as time goes by, and a lot of things will happen in the next decade, does pricing necessarily matter in the grand scheme of things if electricity markets are very constrained and some of these tech firms really are just constrained by electricity? Do you think the $150 a megawatt-hour ultimately might make sense for that customer class? I think that's entirely possible, Chris. I couldn't have forecasted what's happening to us right now five years ago or 10 years ago. I think the bigger constraint right now is just the commercial availability. I don't even know if the $150 is a price that you could actually go buy one for. I think there's a little bit TBD on when they're going to be available and what price. Your question being, will there be a time where some customers will pay any price? Maybe. I don't know. I do find, though, that when we are negotiating with them, turns out price does matter still. I think we'll have to wait and see on what happens in the future. Sure. Okay. Thanks a bunch. Appreciate it. Thank you. Thanks, Chris. Your next question comes from the line of Julien Dumoulin-Smith with Jefferies. Please go ahead. Hi there. Brian, on for Julien. How are you? Hi, Brian. Hey, just on the 2031, 2032 RFP, is it still 200 MW for 2031 and then greater than 200 MW for 2032, or could it possibly incorporate some of the incremental load that Micron Fab 2 might need as you move through the year and potentially sign any DSA? Yeah, Brian, this is Adam. That 200 MW was, first of all, it's perfect capacity, so as opposed to renewable capacity. It really was a minimum from our standpoint. We used a 2013, excuse me, 2025 IRP to develop that number, since then, obviously, we've had large loads come in and change what our outlook is. We anticipate probably having to go a little bit higher than that. In terms of how high, we'll have to see how the forecasts come in, which I think we'll be providing to you all November timeframe. Okay. That scenario excludes any Micron Fab 2 capacity. In theory, you issue another RFP for, I guess, incremental capacity when the time comes? No, that's a good question, Brian. At that point, we have a fair number of projects. We're going to have a short list, so we're going to be able to work through that short list. We may issue an RFP for 2033, but for Fab 2, we would probably just increase the number of resources we would either build or purchase through the 2032, 2031 IRP. Oh, I see, that's where the six gas projects of self-build in the current RFP might accomplish that. Correct. Yeah. We had 8 overall projects that we bid in. 6 of them were gas, but of course, other entities bid in projects too. We were pretty pleased with the way the results are looking, and I think we will have a short list here available in the next month or so, and we'll be able to talk about whether the Idaho Power projects have made that short list or not. At this time, we feel really good about the projects we bid in. They're competitive from our standpoint, and we'll see how they competed in the RFP. Okay. Good. Thank you very much. Thanks Brian. Your next question comes from the line of Alex Kania with BTIG. Please go ahead. Hi there. Hi there. Good afternoon. I apologize, I probably should look for this in the queue, just what's the current ADITC balance on the balance sheet as of June 30th? It's about $156 million as of June 30th. Okay. We'll add some incremental credits this year through battery storage assets that we install. Great. Some Idaho State ITCs that'll be added to the mechanism. I'm just trying to triangulate this maybe with the rate case strategy as well. Is it reasonable to think, I'm just spit-balling a little bit here, that to the extent that you've got equip that's entering rate base, as it were, depreciation goes up. Again, non-cash, feels like maybe the ADITC mechanism could help offset some of that. Maybe if you're thinking about more of the cash expenses, such as interest, that those may be things that, again, would be for the call for a rate case. I'm just trying to think about this from the rate case perspective is just how important is that ADITC balance and how much flexibility could that add in terms of your timing call on the rate case? Yeah, Alex, it's a great point. That's one of the factors that we consider in deciding whether or not to file a rate case is the ADITC mechanism and how many credits we feel we may need to use. The evaluation we'll do under this one is for 2028, right? We'll be looking at what are large load revenues in 2028. Would we need to use the ADITC mechanism to cover what we might otherwise get from a rate case to cover depreciation and interest expense and the return on some of those assets. A lot of those assets are in service serving customers, but we're not recovering anything on those. In that case, we may decide to file the rate case, depending on how that math turns out. The other thing is, in the last rate case we did, we imposed a cap in the settlement of $55 million per year on ADITCs. We look at where we might be relative to that threshold level in determining whether or not to file a rate case. Maybe just one follow-up question just on, trying to think of the updates on the RFP and better sense of what the generation resources might end up panning out to be, which I think for the previous question, we might know within the next month or so. Is that going to come out maybe before we even get the full details, I guess, just in terms of what the demand outlook ends up being under the updated IRP, which, if I'm getting this right, may end up getting released a little bit later? Just trying to think about the cadence of timing here for those outlooks. Alex, this is Adam. The RFP results would come out here, we'll say, in the next month or so. The new forecast related to the new IRP, I think, would be released to you all right around November. Is that right, Brian? Got it. That's about right, because that's the time that we have to have our new forecast established. You eventually have to lock it down for purposes of the 2027 IRP. We'd have to have that end of October, early November under our normal IRP process. The thing that I'll mention, though, is things change over time. While we'll have results from the 2032 RFP, if there's incremental load that shows up even beyond the forecast we include in our IRP, some of those resources that are on the short list, depending on the timing, we may pull more of those resources than we originally thought in terms of implementing resources from the list. Or if their online dates are further out, then you start doing what Adam mentioned, which could be a 2032 or later RFP for some of the incremental growth. Again, the IRP is a point in time, we have to serve load as it materializes, that requires a lot of pre-planning. We're certainly doing some pre-planning around those loads already. Yeah. It's just a great point, I think we talk a lot about our pipeline as though it seems like it's this static number, it is a tremendous amount of activity of resources and loads that sort of go into construction, like Micron, that's no longer in the pipeline. There's another tranche of new requests that fill that space that was in the pipeline. It's really, really active. It's changing all the time; we have to do the analyses to the extent those customers want to go forward with those construction agreements or analyses. It's a tremendous amount of work. Exciting times, for sure. Maybe just one quick note. Even though we may have a short list, we still have to negotiate those deals. The short list will be what it is, obviously we'll be able to talk about that. In terms of negotiation, that could take another couple of months. Great. That's very helpful. Thanks so much. Thank you. Thank you. A final opportunity, press star one to signal for a question. We'll pause for just a moment. That concludes the question- and- answer session for today. Ms. Grow, I will turn the conference back to you. Thank you to everyone for joining us today and for your continued interest in IDACORP. It's always great to hear from you. I hope you all have a great evening, and we will see you all soon. Thank you. Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.