Title

Presentation

IDACORP, Inc. beats earnings expectations. Reported EPS is $1.24, expectations were $1.12.

Operator: Good afternoon, everyone, and welcome to IDACORP, Inc.’s First Quarter 2026 Earnings Call. Today’s call is being recorded and our webcast is live. A replay will be available later today for the next 12 months on IDACORP, Inc.’s website. If you need assistance at any time during the presentation, please press 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: Good afternoon, everyone. We appreciate you joining our call. The slides we will reference during today’s call are available on IDACORP, Inc.’s website. As noted on Slide 2, our discussion today includes forward-looking statements including 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, 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 you to review in our filings with the Securities and Exchange Commission.

As shown on Slide 3, also presenting today are Lisa A. Grow, President and CEO; Brian R. Buckham, EVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager. Slide 4 has a summary of our first quarter financial results. Diluted earnings per share were $1.21 compared with $1.10 last year. Our key operating metrics and guidance are unchanged, except for our hydropower generation forecast as we reduced the top end of the range. We are reaffirming our full-year 2026 IDACORP, Inc. earnings guidance in the range of $6.25 to $6.45 diluted earnings per share, which includes our expectation that Idaho Power will use less than $30 million of additional tax credit amortization to support earnings. These estimates assume historically normal weather conditions and normal power supply expenses for the rest of the year.

Now I will turn the call over to Lisa.

Lisa A. Grow: Thank you, Amy, and thank you all for joining us today. I will start my remarks with a look at our continued growth on Slide 5. We have seen an overall customer increase of 2.3% since last year’s first quarter, with growth across all customer segments, including 2.4% for residential. From a load perspective, industrial energy sales grew by 5.7% over the same period. After years of thoughtful planning and execution, we are starting to see the ramp-up in loads and revenues from some of our large industrial customers, and that ramp will accelerate during the year. Two of our industrial customers, Micron and Meta, are examples of that. As you can see in our latest photos on Slide 6, construction of Micron’s first fabrication facility continues to progress, and Micron has started ground preparation for the second fab.

Meta’s data center has reached the testing and commissioning stage. We have worked tirelessly to be ready to serve their needs as they ramp up operation. In addition to these large industrial projects, we continue to see significant interest from core industries—food processing, manufacturing, distribution, and warehousing—as well as inquiries from other large customers in other industries looking to operate in our service area. As we serve one of the fastest-growing areas in the nation, with what we view as a leading rate base growth, we are doing it thoughtfully so that growth pays for growth to help protect our existing customers from cost shifting. As you can see on Slide 7, our approach to contracting with new large industrial projects is focused on protecting both existing customers and shareholders from potential negative financial impacts as well as being transparent and responsive to the new customers.

We provide clarity in how we will serve the new load, including timelines, rates, and other terms. We have used take-or-pay provisions, certain upfront payments, credit and security requirements, termination or exit payments, customized pricing terms, and other contractual features in some cases. Like everything we do, we take a thoughtful approach to our customer pipeline. Turning to Slide 8, we remain focused on affordability. We work hard to keep our costs down and provide exceptional value to our customers, and our rates remain 20% to 30% lower than the national average. Our rates have increased at a much slower pace than averages, increasing by 23% over the past decade compared to 41% nationally. This increase also compares favorably to the consumer price index, which increased 36% over the same period.

The benefits of our low-cost system—and hydro in particular—help with our affordability focus. Our regulatory model in Idaho, a growth-pays-for-growth system, also helps us retain that affordability, and it has been working. Legislation was passed in Idaho this year that codified the way we currently develop large load contracts with one change: it established a deadline of nine months for the PUC’s contract approval process, which had previously been more open-ended. As we discussed on our last call, Idaho Power is not planning to file a general rate case on June 1, and at this point, we are unlikely to file one at all this year. While we are seeing higher depreciation and interest expense associated with growth and our infrastructure build out, as well as wildfire mitigation costs, we expect that revenues from new large load contracts will help offset those additional costs.

We also continue to benefit from careful and thoughtful spending. As we move towards summer, and moving to Slide 9, I am happy to report that the Idaho Commission approved our 2026 wildfire mitigation plan earlier this month. As a reminder, the commission-approved plan establishes the standard of care in Idaho under the Wildfire Standard of Care Act beginning this year. Moving to Slide 10, Idaho Power continues full speed ahead on major infrastructure projects, including three major transmission lines that will add critical flexibility and reliability to our system. Work is progressing quickly on our B2H transmission project, which we expect to be in service in late 2027. Nearly half of the access roads and structure pads have been completed, along with 200 structures, about 15% of the total structures for the project.

On the SWIFT North transmission project, we received our CPCN from the Idaho Commission. Several project authorizations remain in progress, including final construction authorization from BLM. The construction contractor plans to break ground this June in Nevada and this September in Idaho, and we expect SWIFT North to be complete as early as 2028. We are also continuing to work with PacifiCorp on the Gateway West transmission project, and we recently filed a joint request for a CPCN with the Idaho Commission. We anticipate a critical section of that line between our Hemingway and Midpoint substations will come online as early as 2028. If all continues to go as planned, customers will be served by three new large transmission lines on our system by 2028, bringing with them the benefits of access to diverse markets and transmission wheeling revenue.

Turning to Slide 11, I have some updates on the new gas plants we discussed last quarter. We have received a CPCN from the Idaho Commission for the company-owned 167 megawatt plant that will be a natural gas plant next to our existing Bennett Mountain Power Plant. We have also secured an EPC contractor as we continue to work toward an in-service date of summer 2028. Since our last call, we have also filed for CPCN in Idaho for two additional natural gas plants. As a reminder, both were included in the CapEx forecast update we shared at year-end. We plan to bring the 222 megawatt South Hills project online in 2029 and the 430 megawatt Peregrine project in 2030. These natural gas projects will provide firm, dispatchable resources we need to meet growing customer demand, and we view these projects as affordable, low-risk solutions to our near-term capacity deficit.

We also have 250 megawatts of new company-owned battery storage that will come online this quarter, and we will be adding 125 megawatts of third-party-owned solar generation to our system later this year. We remain on track to complete the conversion of VOLMI Unit 2 from coal to natural gas before the summer peak this year. These resources support our efforts to add capacity, flexibility, and affordable energy to help serve our customers. As you can see, we are continuing a major expansion cycle, and Idaho Power is an exciting place to be. Turning to Slide 12, Idaho Power received approval of the 2026–2032 RFP from the Idaho Commission. The RFP is aimed at solving a projected capacity deficit of at least 200 megawatts. Idaho’s new procurement rules will allow us to complete a timely and competitive resource evaluation, and we will have additional details about potential resources and projects to meet these energy needs on future calls.

I will close my remarks by following up on last quarter’s announcement regarding the sale of our Oregon service area. The transaction continues to progress ahead, and we plan to make filings in the next couple of months with the Oregon and Idaho Commissions and FERC for the approval of the sale. With that, I will turn the time over to Brian. Thanks, Lisa. Lots going on operationally, which is exciting for us.

Brian R. Buckham: On the financial results side, I wanted to summarize the company’s strong start to the year by highlighting that we saw strong results even with unusually mild weather and several expected headwinds. Our expected headwinds were higher share dilution, higher depreciation and interest expense, and lower accelerated amortization of ADITCs. The use of fewer ADITCs is technically a headwind when you are comparing Q1 of this year to Q1 of last year. Admittedly, that might be counterintuitive, so I will talk more about that as I go through the reconciliation, which is next on Slide 13. IDACORP, Inc.’s first quarter net income increased over $8 million compared to last year. Higher retail revenues from the January rate increase and from customer growth combined for a $23 million benefit.

Usage on a per customer basis decreased operating income by $10.7 million, the result of particularly mild weather that reduced residential and commercial usage. Keying on something that Lisa noted though, industrial use per customer increased notably, in part from a new large industrial customer that ramped up its usage during the quarter. As part of our last general rate case, we updated the FCA mechanism—that was for both the rates and usage per customer base. Combining those updates with lower usage per customer in the residential and small commercial classes from the mild first quarter, we saw increased FCA revenues of over $19 million compared to 2025. As expected, O&M expenses were higher in the first quarter, but the primary drivers were higher wildfire mitigation program expenses and amortization of previously deferred costs associated with the Jim Bridger plant.

A large portion of those items we recover in customer rates, so they are reflected in revenues. In total, O&M expenses were up $13.1 million compared to 2025, but, again, with offsetting revenues for much of it. Depreciation and amortization expense increased around $—million dollars for the quarter [inaudible] from our ongoing infrastructure investment. Other changes in operating revenues and expenses increased operating income by a net $13.6 million. That resulted from lower net power supply costs, a decrease in property taxes due to legislative changes in Idaho last year that became effective this year, and updates to the PCA mechanism base from last year’s rate case that were not unlike the changes to the FCA base. Nonoperating expense increased about $4 million, which was mostly higher interest expense.

Interest expense recorded on the new finance lease, which is our battery tolling agreement, also contributed to the increase. Partially offsetting those items was increased AFUDC from a higher construction work in progress balance, which we still expect will be sustained for some time. Idaho Power amortized $6.3 million of additional tax credits under the Idaho earnings support mechanism in the first quarter. That was $13 million less than what we reported in 2025, so last year’s Q1 benefited from additional ADITC usage much more than this year’s Q1. As I alluded to, that is actually good news from a financial strength and performance perspective for this year. It means we expect to use or need less support from the ADITC mechanism this year to reach the floor level of year-end return on equity in Idaho, and that is despite what we predict to be a considerably higher year-end book equity balance.

I tend to look at that as one helpful barometer of operating performance. Our next slide, Slide 14, reiterates what we discussed about CapEx on the fourth quarter call. I will just note that the forecast does not include any resource that could result from the 2026–2032 RFP, nor does it include some of the projects that often fill the last two years of that plan as we move ahead. So there could be some upside to what is shown on the graph. Moving to Slide 15, I want to point out that we have made a small update to this slide since our last call. You can still see that net cash flow from operations is funding over half of our CapEx needs in the 2026 to 2030 window—and hopefully more than that. Either way, we will still need our growth capital, which we have estimated around $2 billion in equity and $2.9 billion in debt to stay near our target 50/50 capital ratio.

What we have updated is in the equity section under FSAs and equity to be issued. In the first quarter this year, we executed on $155 million of forward sales through our ATM program, and we settled nearly $52 million from prior forward sales through the ATM program. So it would be around $2 billion of equity shown as needed on the slide. When you combine the ATM program with our follow-on from last year, we have now settled or executed forward on over $750 million of the need, which we have broken out separately on the chart. That gets us the equity we needed to 2027 and leaves the remaining amount that we think is within relatively conservative ATM issuance ranges. We have a $300 million ATM that we put in place a couple years ago, and we have now used that one in full, so we are planning to establish a new ATM program in the near term.

Not surprisingly, any additional CapEx needed to serve loads would require some level of financing. If that were the case, that funding would likely be more heavily weighted at the back end of the five-year forecast where operating cash flow should also be higher to offset financing needs in part. A lot of numbers and detail pretty quickly there, and on Slide 16 you can see the forward sales agreements that we have available and the forwards that we have settled to date. It offers a little better, easier picture of where we stand on equity and financing generally. With that, I am going to wrap it up there. I am going to hand it over to John Wonderlich.

John Wonderlich: Thanks, Brian. Turning to Slide 17, you can see our 2026 full-year earnings guidance and key operating metrics. Not much changed from the fourth quarter call. This guidance assumes normal weather for the remainder of 2026 and normal power supply expenses. We expect IDACORP, Inc.’s diluted earnings per share this year to be in the range of $6.25 to $6.45. We still expect that Idaho Power will use less than $30 million of additional investment tax credit amortization in 2026, so less than the $40 million we amortized in 2025. We continue to expect full-year O&M expense to be in the range of $525 million to $535 million. We still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026. As the five-year forecast showed, we continue to expect higher CapEx numbers as we continue to focus on safe and reliable service and to respond to strong growth in our service area.

Finally, given our current forecast of hydropower operating conditions, we expect hydropower generation to be within the range of 5.5 million to 7 million megawatt-hours for the year, so we trimmed the top end of our guidance. Water storage in our system is near or above average across the Snake River Basin. However, low overall snowpack conditions will result in lower water supplies from spring snowmelt. Record-wet April conditions, with more than three times the average precipitation for the Boise area, have helped to increase spring season streamflows and hydropower production, but will not completely offset the lack of winter snowpack. With that, we are happy to address any questions you might have.

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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 press star 1 on your phone. Please ensure your mute function is turned off before you ask a 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 David Arcaro from Morgan Stanley. Your line is live.

Lisa A. Grow: Hi, David.

David Arcaro: Hey there. Thanks so much for taking my questions. Thanks for the comments on the timing of the rate case. I was wondering what you are currently thinking, or what should be the base case expectation. Could it potentially be next June—June 2027—in terms of when a full rate case might be, or how are you characterizing that?

Lisa A. Grow: You know, I think that has been sort of our traditional cadence, but we will keep doing the math and figuring out when the right timing of the next general rate case would be. It will depend on how this year shapes up and what we see coming for the next year.

Brian R. Buckham: Yeah, Dave, and a couple of factors we are looking at, just following on Lisa’s comments. One is the conversion of Quip to plant in service becoming eligible for rate base treatment. Some of the timing of that dictates when we do rate cases. And then the other aspect is large load revenues—the timing of those coming in and the magnitude of those revenues. Those can both dictate timing of rate cases.

David Arcaro: Got it. Thanks for that. That makes sense. And then I was wondering if you could comment on what you are seeing in terms of new customer, new large load inbounds—the pace of demand in that pipeline? And also, when could you deliver new power? When could you handle new large loads coming into the system at this point?

Lisa A. Grow: Well, it continues to amaze me how strong the pipeline is. There is just an incredible amount of interest in our service area, again, from many different industries. Certainly, there are some data centers included in that. For what we have ahead of us right now between now and, say, 2028, we are probably at our maximum capacity to actually get work done. But if there was someone that was going to come on with modest ramps, perhaps it could go a little bit towards the end of that time period. We are seeing a pipeline that goes well into the 2030s now, and we are really excited about the sustainability of this growth as we look to the future. Adam?

Adam J. Richins: Yeah, David. I do not have a ton to add. In the data centers, we are seeing a fair amount of movement. In the dairy area, biodigesters, base manufacturing, warehousing—so it is pretty diverse in that regard. In terms of keeping up, we feel good about where we are at. We have been able to reserve turbines where needed. Obviously, we have ESAs that are going out the door to make sure we will continue to meet these moving forward. As of right now, we feel good. We are staying ahead of it. Obviously, we have to get our transmission lines built and in place too. Those are all on track, so we feel good about the transmission side too. So far, so good, but it is a constant effort, and we are continuing to focus on it every day.

Operator: Your next question comes from the line of Shar Pourreza from Wells Fargo. Your line is live.

Analyst: Good afternoon, team. It is Ashley Whitney with Telema on for Shar. As we are thinking about rate case cadence, we are also thinking about the credit outlook. Some time back, Moody’s downgraded the holdco to Baa3 as well as Idaho Power. It cited a heavier CapEx cycle and weaker near-term credit metrics, but it also acknowledged supportive offsets like additional parent equity or more frequent general rate cases. From your perspective, is the focus now on simply rebuilding within the new ratings category, or do you still see a path over time to improve credit positioning as recovery cadence catches up with spend?

Brian R. Buckham: Yeah, Whitney, thanks for the question. In terms of where the credit metrics stand right now, we do not issue debt at the holding company level—we do all of those debt transactions at the opco level. The move at Idaho Power to Baa2—part of the rationale for that was when you look at sector credit metrics at Moody’s, a lot of the Baa1 ratings, which is where Idaho Power was before, have a CFO pre-working capital to debt of around 18% on average—maybe even slightly higher in some instances. Ours, as we have talked about in the past, while we met our prior threshold of 13% in both 2024 and 2025, going forward we are not looking to have a credit metric of 18%, at least not for this year and not for next year at Moody’s at the opco level.

Moody’s report has some of the details on that, but from my perspective there was a lot of peer benchmarking that went into that decision, so perhaps the downgrade was not a surprise in that regard. The new positive is the stable outlook, and a new downgrade threshold at 12% for Moody’s. We have received a lot of questions in the past on the negative outlook, but some positive remarks on the new stable outlook. On the IDACORP, Inc. side, you mentioned Baa3—that is part of Moody’s notching policy. We have a higher CFO pre-working-capital metric at IDACORP, Inc. and no holding company debt, so that really is just the Moody’s policy on notching. We have talked before about the need or desire to keep our balance sheet strong at 50/50—and a simple and straightforward balance sheet—so very focused on that.

To your point, that does require some equity issuances that we have signaled for quite some time and actually executed on over time. Maintaining that balance sheet structure for us does require the equity. It keeps us closer to the threshold for S&P and our prior threshold for Moody’s in that 13%–15% zone for a while, expecting to naturally grow off of that with large load revenues and rate cases over time. We do not have an intent to immediately target 18%, for example. We will continue to blend debt and equity. We did a debt offering earlier this year. We will have some equity that we will do later in the year—pull down from forwards—to help blend that in. Our financing strategy does take into account those credit metrics, but balance sheet strength is the most important thing for us as we look to continue our financing.

Lisa A. Grow: We just take a very pragmatic view of where we are in our spend and where revenues come in. To the extent those are not matching up, especially during this growth cycle, we will go in for rate relief. But like this year, where we are able to stay out given that those revenues are starting to come in, we will use that as the cadence.

Brian R. Buckham: I think that is right. One of the things I mentioned earlier is looking at the conversion rate of Quip to plant in service and the financial impact that has if you do not do rate cases around that. Some of it will be weighing the impact of that conversion to rate base and taking that to regulators versus filing rate cases when you have large load revenues coming in. The large load revenues do really cover a lot of what would otherwise be rate cases. I cannot say at this point that we would file every year. The word you used was opportunistic—when we need to go in, that is when we will go in. That is how I look at it. Another thing we can talk about is customer affordability. That is important to us, and we can maintain that through these large load revenues, long-lived assets, and other features of the company with a growth-pays-for-growth mentality.

We will look each year at what our rate app would be. We do not want to go in and make really large rate requests, and this growth-pays-for-growth mentality and the way we operate our business from an O&M and affordability perspective help us stay out and use those revenues instead of rate cases in some years.

Analyst: Thank you.

Operator: Your next question comes from the line of Christopher Ronald Ellinghaus from Siebert Williams Shank. Your line is live.

Lisa A. Grow: Hey, Chris.

Christopher Ronald Ellinghaus: How are you? Brian, I thought you were going to get into this—I do not remember what you said in your comments—but can you talk about how you foresee ITC recognition through the years? Do you have some visibility there? And in the guidance, you talk about normal weather, but just looking at NOAA’s forecast it is going to be far from normal. Can you give us any sense of what you are seeing—particularly irrigation—as it is supposed to be super hot with well-below-normal precipitation? What have you seen so far in the spring? What is the soil condition? And what are your thoughts about what the summer will look like?

Brian R. Buckham: For ITCs, we are actually a cash taxpayer, and so we have a tax credit appetite on our returns each year for federal income taxes. We are monetizing those ITCs every year. That appetite continues. I will say there is some diminishing availability of ITCs in the future when you look at some of the legislation that is out there now. We are getting it from our batteries, for example, now—that will go on our tax returns. Over the long term, things could change. We have also looked at PTCs as another avenue for us as well. Right now, one of the important features of the ITCs that we generate is that they do go into the mechanism. So we have a fairly sizable balance of ITCs that are available for ADITC use in the mechanism going forward. But no planned external monetization through sale of the tax credits—we would be recording them on our tax returns.

Lisa A. Grow: On the weather, it is a great question, Chris. Those of us that enjoy winter sports were really bummed out about not having much snow in the hills. We did have some good storage, and we did catch up a little bit with the rain that we had last month, but it is still a little bit short of what we would normally see. Certainly, we like it to be stored up in the mountains as snow and come down on a slower pace. Irrigators have been trying to figure out their strategy given some of the commodity prices, and that may have some impacts. Overall, with hot and dry conditions, our folks on the ground are thinking it could be actually closer to normal than some of that might indicate. Adam has some additional color.

Adam J. Richins: Chris, we have been debating this issue with folks on the ground because it is interesting to see their take. What we have been looking at is that low water years have not correlated to less sales because there are so many other factors involved. This summer, the factors pushing towards more sales are projected warmer weather—you mentioned NOAA—Lisa mentioned our reservoirs. We are actually at average, so that is a good sign. When surface water users get cut off a little bit, they tend to use ground pumps to make some of that up when water is scarce. Those things push towards more sales. On the other side, with low water, you can have the risk of curtailments, which could happen—we have had that in the past.

As we debated these things and looked at what we thought irrigation sales were going to look like in the future, we got to this net-net normal position that Lisa mentioned, and that is really from the folks on the ground talking to farmers, trying to get a feel for what the season is going to look like.

Christopher Ronald Ellinghaus: If I could paraphrase, you are suggesting that you are expecting sort of normal water resources but the demand could be high.

Adam J. Richins: It does feel like the demand—if the weather turns out like it is predicted, like you mentioned—could be higher in terms of the need for energy to pump. The water side could be a little bit low, but we have seen no correlation in the past between low water and low sales. In fact, lots of times we have had low water years that have had higher sales because the temperatures have been higher. There are just puts and takes as we look at both sides of it.

Christopher Ronald Ellinghaus: Did you get any sort of feedback about the impact that the Iran situation is having on your agricultural customers?

Adam J. Richins: We did not get feedback on that. We got a little feedback, as Lisa mentioned, on the commodity side. Some of the pricing for potatoes and beets are a little bit lower than our farmers would like, and so there are some cases when they planted maybe slightly less of those products, which could impact water use. But they did not touch on the Iran issue directly.

Christopher Ronald Ellinghaus: Lastly, you touched on the strength of the pipeline. Can we assume that your queue is basically unchanged from what you talked about on the fourth quarter?

Lisa A. Grow: I think we have even had a few more inquiries since the fourth quarter. It seems like it is never-ending, honestly. A few new ones come into the queue; a few others might drop out. Overall, it is up.

Adam J. Richins: I think that is right, Chris. Just a quick reminder, we have been hanging at that 8.3% IRP growth for a while now. I think we are going to update that as part of the next IRP in Q4. There should be some upside in that.

Lisa A. Grow: And it is important to remember that we do not put any prospective load into that number until we have either a sizable financial commitment or a signed contract or something that feels a lot more than a tire-kicker. While the pipeline and the 8.3% are not exactly correlated, there is some lag in between.

Christopher Ronald Ellinghaus: Sure. It just helps when you quoted that 4 thousand megawatt queue—it puts things into perspective. I was curious if that number had made any kind of advance or decline.

Adam J. Richins: The problem on those issues and talking about the large loads is so many of them are confidential. We just cannot come out with them until they go public, and so a lot of times we are in a holding pattern for them.

Christopher Ronald Ellinghaus: Sure. Makes sense. Okay. Thanks a bunch. Appreciate it.

Lisa A. Grow: Thank you.

Operator: Next question comes from the line of Michael Lonegan from Barclays. Your line is live.

Michael Lonegan: Hi there. Thanks for taking my question. Just wondering if there is any update you can provide on Micron Fab 2—when you expect an ESA to be signed, and when we could expect it to be implemented into your capital plan?

Adam J. Richins: The ESA for Fab 1 has been signed and is being reviewed by the commission. We expect to hear from the commission. On Fab 2, we are still negotiating the ESA. What I can say about Micron is there is an absolute ton of work that is going on on-site. It is really amazing to see what a $50 billion project looks like as you walk around. Brian, Lisa, and I were able to do that not long ago. In terms of their in-service date, they anticipate initial wafer output for their first fab around mid-2027. On the second fab, they are already moving forward with ground preparations for Fab 2. We have revenues potentially coming in the door mid this year related to Fab 1. On the ESA side for Fab 2, we are still working with Micron. Hard to say exactly the timing of that, but we will let you know when it becomes more public.

Michael Lonegan: Thanks. And then you highlighted the capital plan as conservative. You touched upon the 2026–2032 RFP as being incremental. Is there anything you could say about your targeted ownership in the investment opportunity set there?

Lisa A. Grow: We always want to go in with some company-owned assets or projects, and we do. Historically, we have won about 50% of those. We certainly have a desire to own as many of the resources as we can, and we do so in a competitive way.

Adam J. Richins: I will just add we do have several projects that we will put into the 2026–2032 bid, so we will compete like we do each year.

Brian R. Buckham: Michael, on the CapEx impact as well—the CapEx forecast that we have in the slides does not have any resources for the 2026–2032 RFP in it. We do not assume any sort of win rate for purposes of our CapEx. We put it in there when we know it is going to happen. There is some amount of CapEx in the graph that will help a portion of Micron’s second fab, but only what we expect would be in the very earliest year or years of operation. Our large transmission projects will help with that. We need more generation resources too, and like Adam said, the amount of CapEx actually depends on the ESAs we sign and how we serve our load growth rate, which we are working on right now. The IRP is filed in June 2027, but we will lock down some form of load growth rate more in fourth quarter this year so that we can do our modeling off of that.

If you want to serve load several years from now, you have to start the process now, which means spending some amount in the near term for things like turbine reservations and early payments, and then higher amounts as things get fabricated and delivered and the project gets constructed. So you could start to see some of those payments show up in the current five-year window—maybe weighted more towards 2029 and 2030 than in the very near term. That is how we look at the CapEx upside on that graph.

Michael Lonegan: Great. Thanks. And then lastly, you executed on the ATM program this year. You talked about a new ATM program. You have some forward settling later this year. For the balance of your equity financing plan, can you talk about the profile of issuances, broadly speaking? Should we expect it to profile with CapEx? And also, for incremental capital, should we still anticipate that to be financed with your 50/50 structure?

Brian R. Buckham: The answer to the second question is yes. For any incremental amounts that are in the plan, you should plan on 50/50. For the stuff that is already in the plan, I think we have quoted more like a 30/70 split, but anything incremental above that—to maintain our balance sheet structure—assume 50/50. On the nature of the issuances, one of the things we have talked about in the past is probably not linear. Part of that is because you have large customer revenues coming in—more operating cash flow in the latter years of the window—so maybe a little bit more end-loaded. The best way we have told people is to model it somewhat like the CapEx profile is right now. Then, if there is incremental upside, build a little more in that window, but definitely not linear.

We can look at it from the perspective that, if we were to have ATM issuances with forward settlement, the financing plan for equity—based on the amount you saw on the slide—is within reasonable ATM issuance amounts. With those forwards, we have the ability to shape the equity a little easier to match the timing of payments.

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

Analyst: Hi. It is Brian Russell on for Julien. It is nice to see ground prep beginning at Micron Fab 2. What are the next milestones that could trigger an ESA, or is it just the parameters of the contract that you are negotiating? And secondly, what load is upside that would be incremental to the prior IRP’s 8.3% that would be reflected in this updated IRP? Will Micron’s Fab 2 also be included in that load forecast?

Adam J. Richins: Fab 2 is not in the 8.3%. We do anticipate that it will be in the upcoming Q4 load forecast. In terms of timing, I shared where they are at. Anything beyond that is not public. They have publicly said they anticipate initial wafer output for the first fab in mid-2027. Beyond that, we cannot get into the details of when they will hit different targets. We can track what they have said publicly, and that is what they have said publicly.

Analyst: I apologize if I missed this earlier—could you remind us of what has changed in the RFP bidding process that might give you a slight advantage, possibly, on the win rate?

Adam J. Richins: I would not say an advantage as much as it is faster than it was under the Oregon rules. One of the things we are running into—and I think you know this—is that turbine procurement you have to do well in advance of what we used to do because of supply chain constraints and the timeline related to the regulatory process. The review was a lot longer than what we needed to get these projects in place. The other thing is we do not submit a benchmark bid anymore—we just compete equally with all other independent power producers. That does not set us at an advantage as much as it puts us on an equal playing field, and that was not the playing field we were in several years ago. Lisa mentioned we have been at about a 50% hit rate, so we are continuing to strive to do that. Hopefully, this new process will make it go faster, and not having a benchmark bid allows us to compete equally with everyone else.

Analyst: Understood. Thank you very much.

Operator: Your next question comes from the line of Anthony Crowdell from Mizuho. Your line is live.

Anthony Crowdell: Hey. How is it going? I appreciate the update on the beet crop. One quick follow-up: on Slide 12, you talk about the 2026–2032 RFP update. The 200 megawatts of capacity you are talking about there—is that with any particular committed customer or committed load?

Adam J. Richins: One thing we mentioned there—you will note this as “at least” 200 megawatts. We view that as a minimum. This 200 megawatts is firm capacity, and it is tied to the 8.3% IRP growth rate that we have been talking about. Again, we are going to update that figure in the future. The way it works in the RFP is we will get a variety of different projects. We will be able to review those projects that are on the short list, and then, depending on our need at that time, we will be able to pull the trigger on as many projects as we need to meet the load forecast at that time. Idaho Power will bid several projects in the 2026–2032 RFP.

Brian R. Buckham: I will reiterate: we do not actually have anything in CapEx from the 2026–2032 RFP. It is a common question. We do not assume any win rate. We will compete on equal footing in the RFP, and what shows up from that that is company-owned would be additive to CapEx.

Anthony Crowdell: Great. That is all I had. Congrats on a good quarter.

Lisa A. Grow: Thank you.

Operator: A final opportunity—press star 1 to signal for a question. There are no further questions. That concludes the question and answer session for today. Ms. Grow, I will turn the conference back to you.

Lisa A. Grow: Thank you. Thanks, everyone, for joining us today and for your interest in IDACORP, Inc., and I hope you all have a great evening. Thanks.

Operator: That concludes today’s meeting. You may now disconnect.

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