Operator: Afternoon, everyone, and welcome to IDACORP's Second Quarter 26 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-0 on your phone. I will now turn the call over to Amy I. Shaw, vice president of Finance, Compliance, and Risk.

Amy I. Shaw: Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we will reference during today's call are available on IDACORP's website. As noted on Slide 2, 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 the statements made today, and we caution against placing undue reliance on any forward-looking statements. We have 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 3, also presented today, we have Lisa A. Grow, President and CEO; Brian R. Buckham, EVP, CFO and Treasurer John R. Wonderlich, investor relations manager. Slide 4 has a summary of our second quarter financial results. IDACORP's diluted earnings per share of $1.79, compared with $1.76 for last year's second quarter. I want to highlight, we did not record any additional tax credit amortization under the Idaho regulatory mechanism, during the second quarter of this year compared with recording $172 million in the second quarter of last year. For the first half of 2026, diluted earnings per share were $3 versus $2.87 in 2025. And those results only include additional tax credit amortization of $6.3 million in the first half of 2026, versus $36.5 million in the first half of last year which showcases the strong performance so far for 2026. Our key operating metrics were 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 second quarter. 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 will turn the call over to Lisa.

Lisa A. Grow: Thank you, Amy, and thanks to everyone for joining us today. I will start my remarks with a look at customer growth. As you can see on Slide 5, we have seen a customer count increase of 2.3% since last year's second quarter. With growth across all customer segments. The customer and load growth that we have seen within our service area remains strong, and we are working hard to meet the increased energy demand. As 1 data point, industrial revenues, including large contracts, were up a staggering 17.0% compared with the second quarter 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 second half of 2026. I have been providing updates on Micron's expansion and Meta's new data center during our earnings calls for years. And it is great to see this hard work come to fruition as these projects ramp up. You can see photos of these massive projects on Slide 6 along with pictures of some of our other large contract customers like Giovanni and INL. Looking at Slides 7 and 8, we are 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 have done in the most recent energy service agreement. These elements help ensure that growth pays for growth without shifting cost to other customers and they help derisk large loads for both our customers and for our owners. 1 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 will also point out that the revenue growth from the large contract customers is a key driver that is helping us stay out of a general rate case in 2026. We will 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 9, we are full speed ahead executing on projects to serve our customers and enhance our grid. We recently brought 250 megawatts of new company owned battery storage online as scheduled. Marking our 4th straight year adding batteries to our system. Since 2023, we have added over 550 megawatts of company owned batteries. We also completed the conversion of Valmy unit 2 from cold and natural gas last month in time to help us meet peak summer loads. Additionally, a 125 megawatt 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 needs. Turning to Slide 10, I will provide an update on our 3 major transmission projects. We expect all 3 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 1.3 thousand structure pads have been completed. Over 400 towers are built, and we have started stringing wire. it is a huge undertaking, and we are pleased with the progress. We will continue to expect we continue to expect B2H to be in service by late 2027. On the SWIP-North transmission project, we received our order 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 are also continuing our work with PacifiCorp on the Gateway West Transmission Project As we mentioned last quarter, we filed a joint request for 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 3 company-owned natural gas-fueled projects that I have mentioned on previous calls. Construction is underway on the 167 megawatt resource next to our existing Bennett Mountain power plant. We secured a CPCN, an air permit, and an EPC contract has a scheduled in-service date of 2028. We have also filed CPCNs for the 222-megawatt South Hills project, which is scheduled for operation in 2029. And the 430 megawatt 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 deficit. Turning to Slide 12. We are 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 build projects self bid projects remain competitive. The review team is beginning to narrow the field of contenders. We expect to have a final shortlist in the third quarter and begin contract negotiations soon thereafter. I will 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 2027 pending successful regulatory outcomes. So we have been very busy as you can see. And with that, I will turn the time over to Brian.

Brian R. Buckham: Thanks, Lisa. Hi, everybody. Thanks for joining us today. it is exciting to see all the projects going on right now. Recent project execution has been particularly helpful because it helps serve an 8.0% quarter-over-quarter increase in industrial loads and they will 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 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 will 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 did not dampen quarterly irrigation sales because we later experienced the drier May and June. Aside from the amount or 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. So when I quote changes from rates or customer growth generally, these exclude large contract customers because those will land on their own, new line. All right. So, getting more into the details, let's go to the recon on Slide 13. And from that, you can see that the biggest movement was from higher retail revenue 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. Customer usage was essentially flat for the quarter, and residential usage declined due to milder temperatures but higher irrigation usage mostly offset that decline. The fixed cost adjustment mechanism also benefited retail revenues which resulted from the lower sale for 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 are now seeing with greater prominence the revenue and load ramp up from some of our large contract customers taking shape. And we expect to see more of that benefit in the second half of the year. As we expected, O&M expense was almost $12 million higher in second quarter. The 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, so they are 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 first quarter this benefit resulted primarily from a decrease in net power supply expenses not recovered through the power cost adjustment mechanism. And that was due to updates to the PCA mechanism based on last year's rate case. Nonoperating expense increased only marginally with higher AFUDC mostly offsetting higher interest expense. Fairly significant and important from my perspective, Idaho Power did not report any additional tax credits under the Idaho earnings support mechanism in the second quarter. 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 have recorded for 2026 compares to over $36 million we would 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, Slide 14 reiterates what we discussed about CapEx on the fourth quarter call, So it is just for reference. What you see in that forecast is admittedly already a large amount of capital. But as a reminder, it does not include any assumed resources from the 2032 RFP. And, relatedly, it also does not include resources to serve projects like the Micron Fab 2 facility. And it does not include updates from our annual long term capital budgeting work So I will just reiterate, there could be some upside to what is shown. We expect to have more information for you as we work through the RFP. The load forecast update and our annual capital budgeting process. All 3 of which are currently in progress. Moving to Slide 15. In the second quarter, we executed around $260 million of additional forward sale agreements. through our current ATM program. We are showing on there around $2 billion of equity content that we need to fund our business for the next 5 years under the current plan. We have either issued or we have sold on forwards of about $1 billion already so we have 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 will reiterate that any additional CapEx will require some additional debt and equity. We still plan to blend debt and equity on a roughly equal basis. Bringing 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 have settled to date. As you can see, we have a balance of about $715 million of forwards available for settlement. I do not have a slide on it, but I think operating cash flow to mention, given the deviation from this time last year. It looks low this year on a comparative basis, but it is 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. 1 last note for me the Idaho Commission recently issued an order in our request for a prudence determination related to our Hells Canyon and relicensing effort. The commission, in that case, determines that our project expenditures from the start of 2016 through year-end 2025 are prudently incurred. Rendering them eligible for inclusion in retail rates. In a future regulatory proceeding. I was pleased with the outcome of that case in part because, as many of you know, pride ourselves on being prudent spenders of the company. I am gonna wrap up there. I am gonna hand it over to everyone's favorite IR celebrity, John R. Wonderlich,

John R. Wonderlich: Thanks, Brian. Turning to Slide 17, you can see our 26 full year earnings guidance and key operating metrics. We have 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 first half of the year, we now expect IDACORP's diluted earnings per share this year to be in the range of $6.30 to $6.45. We lifted the bottom end of the range. We also see solid improvement in our ADITC expectation so we are 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 million to $535 million And we still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026 at this point, it is fair to say we are 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 million to 6.5 million megawatt-hours for the year. We trimmed a half a million megawatt hours off the top end of our guidance, as dry conditions returned in May and June. With that, we are happy to address questions you might have.

Operator: We are 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-1 on your phone. Please ensure your mute function is turned off before you ask your question. We will take as many questions as time permits on a first come basis. Once again, that is star-1 on your phone to ask a question. Your first question comes from the line of Shar Pourreza with Wells Fargo Securities. Please go ahead.

Whitney Mutalemwa: Hi there. Hi. Hi, team. This is Whitney on for Shar.

Lisa A. Grow: Hi, Whitney. Hey there.

Whitney Mutalemwa: On resources, we have got 250-megawatts of batteries now in service. You have a number of applications in front of the commission. Is that paced roughly a project every few months, sustainable or does it get harder to keep up as the queue grows? And a follow-up would be, with all the battery storage going in for Micron, Meta, and the rest of the pipeline, is gas plus battery. The sole long term answer, or are you also looking at things like SMRs further out?

Lisa A. Grow: Yeah. So great question. So I will start, and I will have Adam give some more detail. Certainly, when we are looking at what we are going to need to serve our load, we go through the exercise of the IRP, the integrated resource plan, we are really looking for the least cost least risk answer. So we have a total of 550-megawatts of batteries, but, no, that is not the answer to everything. That fits kind of a— it is great energy that will sort of fill in when the solar energy starts to diminish as the sun sets. So it is a great resource for the summer, but it is not a great source for the winter and certain—just because of shorter days and, we do not get a chance to refill the battery before we need them again, and they last for 4 hours some of the operating characteristics just make it so that it is a great energy resource. But it does not we do not really consider it a real capacity resource more than those first 4 hours. So it is an absolute sprint to keep up with this growing load and getting the resources online and in time and so, you know, we have mentioned our pipeline before that continues to be evaluated as we go on beyond what we have shown here. So I think Adam, do you want to Yeah.

Adam Richins: For the question, Whitney. Happy to walk you through kind of year by year how we are looking In 2027, it is largely batteries. it is solar. We have a fair amount of that priced at 400-ish, 500 megawatts of solar, another 100-megawatts of batteries. From that point, it does turn a little more on the gas side. 2028, we talked about it. we sent our comments with Bennett. 2029, we have South Hills, which is also a gas project. 222 megawatts In 2030, we have a project called Peregrine 1, which is also gas, 430 megawatts. And then the Idaho Power's origination team for 2031 and 2032. We bid in 8 projects. 6 of them were gas projects. 2 of them were storage projects. So that should help give you at least a little bit of a mix of where we are at. Terms of gas versus storage versus solar in the next several years. In terms of SMRs, we spent a fair amount of time learning about these new technologies. I am on the customer advisory committee for 1 of the key technologies and companies We spent a fair amount of time with INL and we have 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 do not love the pricing. Which as you probably know is likely over a $150 a megawatt hour at this point. So you know, we again, we like SMRs, but we are probably not gonna be the first, and we are probably not gonna be the last to look at them, and we will continue to keep an eye and evaluate those technologies over the next several years. And the timing also of when they would be available. And, of course, in addition to the CapEx and the generation projects I mentioned, Lisa and her comments also mentioned B2H, we are making great progress there. Southwest Intertie Project broke ground. Recently, which is just a great milestone there. And, of course, Gateway West to which we are looking to work on and construct over the next several years. So it is always good to point out. I think the transmission is a big part of our plan as well. Kind of the generation mix with transmission is what makes it all work out together.

Whitney Mutalemwa: Okay. That sounds good. Thank you. And 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 is early. But you have just gotten the 2026 wildfire mitigation plan approved right before this happened. Does an incident like this change anything about how you are implementing it? Or is it too soon to say? How are you seeing the plan you put into practice?

Lisa A. Grow: Yeah. So, yeah, you are right. We do have a mitigation plan, and we do have it is now the standard of care. The act here in Idaho applies to that mitigation plan. So, certainly, you know, 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. But it was a relatively small fire, and when it is all said and done, it will not be a material impact. To our company, but we are taking it very seriously. So I would not say that we are changing anything about our plan. We certainly continue to implement it. That is the key focus that it is 1 thing to write a plan. it is quite another to make sure that we are following it. And in this case, it actually was followed. I mean, we feel really good about the implementation of that plan. So I think that is probably about all I would have to say about that. Well said. Thank you.

Operator: Your next question comes from the line of Michael Lonegan with Barclays. Please go ahead.

Michael Lonegan: Hi there. Thanks Hi. For taking my question. So on Micron Fab 2, just wondering if you could share the status of negotiations and when do you expect to sign an ESA? And then, anything you could share regarding the size of that investment that could be added to your plan? And could this be a Q3 update when you update your load forecast?

Lisa A. Grow: Well, those are often confidential, so 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? Yeah.

Adam Richins: We are progressing well. Just in terms of the site. Ton of work is going on. it is amazing to see what a $50 billion site looks like. And they have started ground preparations on Fab 2 We are in ESA discussions, but as Lisa mentioned, those are confidential, so we cannot really speak to those. In terms of the CapEx side, Brian can speak to this, but Fab 2 is not in the 8.3% IRP CAGR that we have shown. So it is outside of that as well in terms of spend.

Brian R. Buckham: Yeah. Just add on to what Adam said. You know, 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. Or 2020. 2025. Yes. Thank you. So it excludes customers like, you know, fab 2 along with several other promising loads we call them that we are working with right now and those incremental loads all generate additional capacity and energy needs. And with some of our related spending for the infrastructure, power infrastructure related to that occurring, pretty urgently, I would say, in our 5 year window. Not all of it on the outside of that window. So while the 2025 IRP data point, we are tasked with serving load as it materializes. So 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 will end up getting reflected in our CapEx refresh and also a load growth update that we will do for the 2027 IRP. Thank you.

Michael Lonegan: And then know, regarding your next rate case, I know you have indicated that June 2027 was a possibility. How are you thinking about that now? And should we expect this to be a modest request given all the large load coming in? And I know you often get asked about a depreciation and interest tracker. Could that be in there as well?

Lisa A. Grow: At this point, we are not really looking at a depreciation or interest tracker. And it is because the revenues of these large loads are helping to cover those costs. And so we continue to look at a possible June 2027 filing, but we obviously do the analysis. So we sort of wait and see if we if that is what is needed. But if things go as we are sort of forecasting, that is a I would say a high probability, but we wait to see what the data actually indicates. Yeah.

Brian R. Buckham: And, Michael, this is Brian. I think from the financial side, what we look at is that we have got large load revenues on 1 side that certainly are helpful. The other side of the equation, though, is the plant that goes into service. Right? So in 2026 and then 2027, we expect quite a bit of our equipment convert to planted service. If you look at the balance sheet out, over $1.8 billion of CWIP. So there is a lot that sits there. As of today. When that converts to plant and service, obviously, depreciation starts. They AFUDC stops. So we get into a situation where we do the evaluation of, you know, keeping in mind things like cash flow, affordability for customers, all of those attributes. Whether or not we file a rate case. So we will have to do that math pretty early. In 2027 as we look to whether or not we will file a rate case. As Lisa mentioned, it is looking relatively probable at this point. But, again, we are in somewhat of a what I call an envious position compared to prior years where we have to do the math on that every year. that is beneficial. We did it this year and decided we did not 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 mentioned just on the on the tracker component, you know, if you file relatively frequent general rate cases, because you have so much plant converting, the tracker does not have as much value. You also have to be careful that a tracker would not be shifting costs to customers. That are not driving the expense, and so the tracker would have to be structured in a way that you know, 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. So we are very cognizant of that when we think about the types of mechanisms that we use on the regulatory side.

Michael Lonegan: Thank you. And then, you know, obviously, you are using less of the ADITC. So, 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 there a chance you earn above your allowed? Or any—obviously, you do not give long term EPS growth guidance, but anything you could share on earned ROEs Sure.

Brian R. Buckham: I mean, that is a it is a projection that we do all the time in our forecasting. there is a possibility that occurs, but I think 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. So while it is possible those revenues could be large enough to over earn in some years, I would say in the near term, that less likely just given the construction cycle. That we are in. That said, you know, you have seen us reduce our ADITC expectations for the year already this year, and they are significantly lower than last year. So know, things like weather conditions or outperformance on large load expectations compared to what we have in our forecast could certainly drive us more towards over earning. Certainly, the base level for the ADIT mechanism and then potentially even up from there. Great.

Michael Lonegan: Thank you for taking my questions.

Lisa A. Grow: Hey. Thank you.

Operator: Your next question comes from the line of Christopher Ellinghaus with Siebert Williams Shank. Please go ahead.

Christopher Ronald Ellinghaus: Hi, Christopher. How are you? Good.

Brian R. Buckham: Brian, thanks for that new line that is 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 would not look at it that way, Christopher, because, you know, 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, you know, there is there is step up They are certainly not linear. But there are take or pay obligations in that. They do not reflect seasonality. Necessarily. And then, you know, if you look at things like data centers, their ramp ups can be, you know, premised on what server racks are installed and when they are turned on. So I would not look at it that way. Thing I would note is if you think about that line that we added, really, you only have 1 month Of Micron revenues in there for Fab 1. And then you do see some of the meta ramp up reflected in there. But a lot of that is early stages, and we would expect to see that more of a steady ramp up over the second half of this year. Right.

Lisa A. Grow: Yeah.

Christopher Ronald Ellinghaus: I was really not the timing of incremental adds for these customers, But in terms of their cooling requirements, can we-- is there seasonality to the usage portion once something's online?

Brian R. Buckham: We have not really forecast it that way. We look at it more of a steady state from equipment operation, not from a cooling system, though it is possible that some of the hotter summer months, there could be incremental loads from cooling systems. Okay.

Christopher Ronald Ellinghaus: In raising the guidance, is that purely a look through the second quarter? Or does that include any of the July data? Seems like it was materially warmer than last year and still dry. So does that include any look into what you know about July so far?

Brian R. Buckham: Not much. I mean, we have anecdotal evidence that July was a little warm, but in general, we covered off at the end of the quarter. And then just predict normal weather conditions for the remainder of the year. So if it does turn out to be hotter, then we expect there to be some incremental benefit out there. Okay.

Christopher Ronald Ellinghaus: Is there any rationale for you guys to use any parent leverage as you get into really heavy spend?

Brian R. Buckham: You know, we talk about that from time to time. You know, 1 thing we have to watch for on that is credit rating implications of that. That, you know, the credit rating agencies have complimented us. As have many of our investors on the fact that we do not have holding company debt. When we go to market at Idaho Power for debt, we tend to be very well received. So our regular way financing approach has been successful for us. In terms of interest rates and otherwise. And just interest in the market marketplace. So our preference is for that relatively simple balance sheet. When you start adding holding company debt, you add some complications, some regulatory items that we have to address and otherwise. So we have really focused a lot on regular way financing, of course, our equity transactions that at IDACORP. But in terms of hybrids, mandatory convertibles, I would say those are not something that we have taken off the table, but it is 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, you know, large contract needs for EDCs and our generation resources and are just big CapEx build out. And we have we have done some of those. it is things like requiring payment from some of the customers upfront for some of this. So we have other mechanisms in place that we use, but you know, 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. So in a really good spot from my perspective on keeping the balance sheet healthy, without unnecessary complication.

Christopher Ronald Ellinghaus: Great. That helps. 1 last thing. Your regarding the SMR discussion was useful. You know, pricing has been rising for these large load customers. Pretty much across regions. And there is some I would say, price insensitivity, it seems. While SMRs might be pricey today, you know, as time goes by, you know, and a lot of things will happen in the next decade. But 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. You know, can do you think the $150 a megawatt hour ultimately might make sense for that customer class?

Lisa A. Grow: I think that is entirely possible, Christopher. I mean, it is just I could not have forecasted the you know, what is happening to us right now 5 years ago or 10 years ago. But I think the bigger constraint right now is just the commercial availability. Because I do not even know if the 150 is a price that you could actually go buy 1 for. So I think there is a little bit TBD on when they are going to be available and what price. But your question being, will there be a time where some customers will pay any price Maybe. I do not I do not know. I do find, though, that we are negotiating with them, turns out price does matter. Still. So I think we will we will have to wait and see on what happens in the future. Sure. Okay. Thanks a bunch. Appreciate it.

Brian R. Buckham: Thank you. Thanks, Christopher.

Operator: Your next question comes from the line of Julien Dumoulin-Smith with Jefferies. Please go ahead.

Brian Russo: Hi there. Brian Russo on for Julien. How are you?

Lisa A. Grow: Hi. Hi, Brian.

Brian Russo: Hey. Just on the 32 RFP, is it still 200 megawatts for 2031 and then greater than 200 megawatts for 2032? Or could it possibly incorporate some of the incremental load that Micron Fab 2 might need as you move through the year, potentially sign an ESA?

Adam Richins: Yeah, Brian. This is Adam. That 200 megawatts was first of all, it is perfect capacity. as opposed to kind of renewable capacity. But it really was a minimum from our standpoint. We used the 2020 IRP to develop that number. And since then, obviously, we have had a large loads come in and change what our outlook is. So we anticipate probably having to go a little bit higher than that. In terms of how high, and we will have to see how the forecast come in. Which I think we will be providing to you all at November time frame. Okay.

Brian Russo: So and that scenario excludes any Micron Fab 2 Capacity. In theory, would you issue another RFP for I guess, incremental capacity when, you know, when the time comes? No.

Adam Richins: that is a good question, Brian. At that point, we mean, we have a fair amount of projects. We are gonna have a short list, so we are gonna be able to work through that short list. And we may issue an RFP for 2033, but for, fab 2, we would probably just increase the amount of resources we would either build or purchase through the 2032, 2031 IRP. Oh, I see. And that is where are the 6 gas projects-- the 6 gas projects of self-build in the current RFP might accomplish that Correct. Yeah, We had 8 overall projects that we have been in, 6 of them were gas, but, of course, other entities bid in projects too. So 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 will be able to talk about whether the Idaho Power projects have made that short list or not. But at this time, we feel really good about the projects we bid in They are competitive from our standpoint, and so we will see how they competed in the RFP.

Brian Russo: Okay. Thank you very much.

Lisa A. Grow: Thanks.

Operator: Your next question comes from the line of Alex Herman with BTIG. Please go ahead.

Alex Kania: Hi there. Hi there. Good afternoon. I apologize. I probably should look at this and look for this in the in the Q. just what the what is the current ADITC balance on the balance sheet as of June 30th?

Brian R. Buckham: it is about $156 million as of June 30th. And then we will add some incremental credits this year through battery storage assets that we install. And also, some state ITCs will be added to the mechanism. Okay.

Alex Kania: So then, you know, I am just going to-- I am trying to triangulate this with the maybe, with the rate case strategy as well. So, I mean, is it kinda reasonable to think I am just you know, kinda spitballing a little bit here that, you know, to the extent that you have got you know, CWIP that is entering, you know, kind of rate base as it were, depreciation goes up. But, you know, again, kind of noncash-- you know, feels like maybe the, you know, the ADITC mechanism could help offset some of that. But then, you know, maybe if you are thinking about kinda more of the cash expenses such as interest, that those, you know, maybe things that, you know, again, would be the call for a rate case. And I am just trying to think about this from the rate case perspective, is just how important is that ADITC balance that, you know, and how much flexibility can that add in terms of your timing call on a rate case?

Brian R. Buckham: Yeah. Alex, it is a great point. I mean, that is 1 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 will do under this 1 is for 2028. Right? And so we will 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 cover depreciation and interest expense and the return on some of those assets. I mean, a lot of those assets are in service serving customers, but we are not recovering anything on those. So in that case, we may decide to file the rate case depending on how that math turns out. So 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. And so we look at where we where we might be relative to that. Threshold level in determining whether or not to file. A rate case.

Alex Kania: Great. Okay. Appreciate that. And then maybe just 1 follow-up question on I am trying to think of the, you know, the updates on the on the RFP and kind of 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. And then you know, is that gonna come out maybe before we even get the kind of the full details, I guess, just in terms of what the what the demand outlook ends up being under the under the under the under the updated IRP, which if I am getting this right, may end up getting, you know, released a little bit later. Just trying to think about kind of the cadence of timing here for those for those outlooks.

Adam Richins: Yeah. Alex, this is Adam. It would the RFP results would come out here, we will say, in the next month or so, and then the new forecast related to the new IRP I think, would be released to you all at right around November.

Brian R. Buckham: Is that right, Brian? Got it. that is alright. Because that is the time that we have to have our new forecast established. You eventually have to lock it down for purpose of the 2027 IRP. So we would have that end of October, early November. Under our normal IRP process. The thing that I will mention though is things change over time. So while we will have results from the 2032 RFP, if there is incremental load that shows up even beyond the forecast we include in our IRP, Some of those resources, depending on what are on the short list depending on the timing, we may pull more of those resources than we originally thought in terms of you know, 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. So, it is the IRP is a point in time, but we have to serve load as it materializes. And that requires a lot of preplanning. So we are certainly doing preplanning around those loads already.

Lisa A. Grow: that is just a great point. And I think, you know, we talk a lot about our pipeline, and so it seems like it is this static number, but it is a tremendous amount of activity of resources and loads that sort of go into construction like Micron that is no longer in the pipeline, but there is another tranche of new requests that fill that space that was in the pipeline. So it is really, really active. So it is changing all the time, and we have to do the analysis to the extent those customers wanna go forward with those construction agreements and their analysis. So it is tremendous amount of work.

Alex Kania: Exciting times for sure.

Adam Richins: And maybe just 1 quick note, even though we may have a short list, we still have to negotiate those deals and so the short list will be what it is, and, obviously, we will be able to talk about that. But in terms of negotiation, that could take another couple months.

Alex Kania: Great. that is very helpful. Thanks so much.

Brian R. Buckham: Thank you.

Lisa A. Grow: Thank you.

Operator: And for a final opportunity, press star-1 to signal for a question. And we will pause for just a moment. That concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

Lisa A. Grow: Thank you to everyone for joining us today and for your continued interest in IDACORP. it is always great to hear from you. So I hope you all have a great evening, and, we will see you all soon. Thank you.

Operator: Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.