IDACORP, Inc.

Good afternoon, everyone, and welcome to IDACorp'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's 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, and 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 you to review in our filings to the Securities and Exchange Commission. As shown on slide three, also presented today, we have Lisa Grove, President and CEO, Brian Buckham, EVP, CFO and Treasurer, and John Wunderlich, Investor Relations Manager. Slide four has a summary of our first quarter financial results. IDA Corp's 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 reduce the top end of the range. We're reaffirming our full year 2026 IDA Corp earnings guidance estimate in the range of 625 to 645 diluted earnings per share, which includes our expectation that IDA 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'll turn the call over to Lisa.

Thank you, Amy, and thank you all for joining us today. I'll start my remarks with a look at our continued growth on slide five. We've 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're 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 six, construction of Micron's first fabrication facility continues to progress. And Micron has started ground preparation for the second FAP. META's data center has reached the testing and commissioning stage. We've worked tirelessly to be ready to serve their needs as they ramp up operations. In addition to these large industrial projects, we continue to see significant interest from core industries of 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-based growth, we're doing it thoughtfully so that growth pays for growth to help protect our existing customers from cost shifting. As you can see on slide seven, 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've used pay-per-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 eight, 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 national 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 effectively 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 1st. And at this point, we're unlikely to file one at all this year. While we're 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 nine, I'm 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 paths 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 SWPPP North to be complete as early as 2028. We're also continuing to work with Pacificor 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 revenues. Turning to slide 11, I have some updates on the new gas plants we discussed last quarter. We've received a CPCN from the Idaho Commission for the company-owned 167-megawatt natural gas plant that will be next to the to our existing Bennett Mountain power plant. We've also secured an EPC contractor as we continue to work toward an in-service date of summer 2028. Since our last call, we've also filed for CPCNs 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 deficits. We also have 250 megawatts of new company-owned battery storage that will come online this quarter, and we'll 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're continuing a major expansion cycle, and Idaho Power is an exciting place to be. Turning to slide 12, Idaho Power recently received approval of the 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'll have additional details about potential resources and projects to meet these energy needs on future calls. I'll 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 months with the Oregon and Idaho Commissions and FERC for the approval of the sale. And with that, I will turn the time over to Brian.

Thanks, Lisa. Lots going on operationally, which is exciting for us. 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're comparing Q1 of this year to Q1 of last year. Admittedly, that might be counterintuitive, so I'll talk more about that as I go through the reconciliation, which is next on slide 13. IDCorp'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 FTA mechanism. That was for both the rates and the 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 FTA revenues of over $19 million compared to the first quarter of 2025. As expected, O&M expenses were higher in the first quarter. The primary drivers were higher welfare mitigation program expenses and amortization of previously deferred costs associated with the Jim Bridger plan. A large portion of those items we recover in customer rates, so they're reflected in revenues. In total, O&M expenses were up $13.1 million compared to the first quarter of 2025, but again, with offsetting revenues for much of it. Appreciation and amortization expense increased around $6 million for the quarter, and that was expected 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. Non-operating 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 and 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 the first quarter of 2025. So last year's Q1 benefited from additional ADITC usage much more than this year's Q1. As I alluded to, that's 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's 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'll just note that the forecast doesn't include any resources that could result from the 2032 RFP, and 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's shown on the graph. Moving to slide 15, I want to point out that we've 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'll still need our growth capital, which we've estimated is around $2 billion in equity and $2.9 billion in debt to stay near our target 50-50 capital ratio. What we've updated is in the equity section under FSAs and equity to be issued, In the first quarter this year, we executed on $165 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've now settled or executed forwards on over $750 million of the need, which we've broken out separately on the chart. That gets us the equity we need into 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've now used that one in full, so we're 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 flows should also be higher to offset financing needs in part. I threw out 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've settled to date. It offers a little better, easier picture of where we stand on equity and financing generally. With that, I'm going to wrap it up there. I'm going to hand it over to Coach John Wanderlich.

Thanks, Brian. Turning to slide 17, you can see our 2026 full year earnings guidance and key operating metrics. Not much change from the fourth quarter call. This guidance assumes normal weather for the remainder of 2026 and normal power supply expenses. We expect IDACorp'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 to $535 million. We still anticipate spending between $1.3 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 to 7.0 million megawatt hours for the year. So we trim 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 stream flows and hydropower production, but will not completely offset the lack of winter snowpack. With that, we're happy to address any questions you might have.

We are now ready to begin the question and answer session for attendees who have joined on the Q&A line. If you'd 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 a question. We'll 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 Acaro from Morgan Stanley. Your line is live.

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

You know, I think that has been sort of our traditional cadence, but we'll keep doing the math and figuring out, you know, when the right timing of the next general rate case is. would be, you know, just depend on how this year shapes up and what we see coming for the next year.

Yeah, there have been a couple of factors we're looking at just following on Lisa's comments. One is the conversion of, you know, equipped plant and service becoming eligible for rate-based treatment. Some of the timing of that dictates when we do rate cases. And then the other aspect is large-scale revenues. timing of those coming in and the magnitude of those revenues, those can both dictate timing of rate cases.

Yep, got it. Thanks for that. That makes sense. And then I was wondering if you could comment on what you're seeing in terms of new customer, new large load inbounds, the pace of demand in that pipeline, and also just when could you deliver new power? When could you handle new large loads coming into the system at this point?

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, and I will have Adam give some more color on it, but I would say, you know, for what we have ahead of us right now, between now and, say, 2028, we're probably at what are just maximum capacity to actually get work done. But if there was someone that was going to come on with modest ramps, you know, perhaps it could go a little bit towards the end of that time period. But we're seeing pipeline that goes well into the 2030s now. And so we're really excited about sort of the sustainability of this growth as we look to the future.

Yeah, David, I don't have a ton to add. In addition to the data centers, we're seeing a fair amount of movement in the dairy area, biodigesters-based manufacturing, warehousing. So it's pretty diverse in that regard. In terms of keeping up, we feel good about where we're at. We've been able to reserve turbines where needed. Obviously, we have these RFPs that are going out the door to make sure we'll continue to meet these moving forward. So as of right now, we feel good. We're staying ahead of it. Obviously, we've got 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, so far, so good, but it's a constant effort, and we'll continue to focus on it really every day.

Okay, great. Thank you.

Thanks, David. Your next question comes from the line of Char Perez from Wells Fargo. Your line is live.

Hi, Char. Good. Good afternoon team it's actually Whitney with dilemma on for char. So obviously as we're thinking about great case cadence we're also thinking about the credit outlook so some time back moody's downgraded hold the code to be double a three as well as Ida Idaho power. So it cited heavier CapEx cycle on just weaker near-term credit metrics, but it also acknowledged supportive offsets like additional parent equity or more frequent general rate cases. So from your perspective, is the focus now on simply rebuilding the metrics within the new ratings category, or do you still see a path over time to improving credit positioning as recovery cadence catches up with spend?

Yeah, Whitney, thanks for the question. This is Brian. So in terms of where the credit metrics stand right now, you know, we don't issue debt at the holding company level. I mean, we do all of those debt transactions at the off-code level. And so the move to Idaho Power or BAA2, part of the rationale for that was just when you look at, you know, sector credit metrics at the Moody's level, a lot of the BAA1 ratings, which is where Idaho Power was at before, have somewhat of a CFO pre-working capital to debt of around 18% on average, maybe even slightly higher in some instances. Ours, as we've talked about in the past, while we met our prior threshold of 13% in both 2024 and 2025, going forward, we aren't looking to have a credit metric of 18%, at least not for this year and not for next year at Moody's at the Ofco level. And so, Moody's report has some of the details on that, but just from my perspective, there was a lot of benchmarking that went into that decision. So perhaps the downgrade isn't a surprise in that regard, but that negative watch hovered out there for quite a while. Part of the upside of that is the stable rating and a new downgrade threshold at 12% for Moody's. We've received a lot of questions in the past on the negative outlook, but some positive remarks on the new stable outlook. So the ID Corp side, you mentioned BAA3. You know, that's part of Moody's notching policy. And as I mentioned, you know, we have a higher CFO pre-working capital debt at IdaCorp and no holding company debt. So that really is just a Moody's policy on notching. You know, we've 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've signaled for quite some time and actually executed on those equity needs. over time. So maintaining that balance sheet structure for us does require the equity. It keeps us closer to the thresholds for S&P and our prior threshold for Moody, you know, on that 13, 14, 15% zone for a while, but expecting to naturally grow off of that with large-flow revenues and rate cases over time. So we don't have an intent to immediately equitize to 18%, for example. We'll continue to blend debt and equity. We did a debt offering earlier this year. We'll have some equity that we'll do later in the year, pull down from forwards to help blend that in. And so 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.

Great Thank you Brian and just as a mini follow up, obviously, this is also in the remarks, but how are you moving towards. Just how are you thinking about the current capex cycle, what is more frequent rate relief practically mean from here. Are you moving towards a regular cadence that you know we can underwrite or is there still more opportunistic based on capital timing and obviously the regulatory conditions.

Yeah, we just take a very pragmatic view of sort of where we are in our spend, in where revenues come in. And to the extent those aren't matching up, especially during this growth cycle, we will go in for rate relief. But like this year where we're able to stay out given that those revenues are starting to come in, we will use that as the sort of cadence, I guess. Anything that you would add, Brian?

I think that's right, Lisa. You know, one of the things I mentioned from an earlier question is this idea of looking at the conversion rate of QIP to plant-in service and, you know, the financial impact that that actually has if you don't do rate cases around that. So some of it will be just weighing the impact of that conversion to rate pay and taking that into regulators versus filing rate cases when you've got large load revenues coming in. So, the large load revenues do really cover a lot of what would otherwise be rate cases. So, I can't say at this point that we'd file every year. I think, you know, the word you used was opportunistic. You know, when we need to go in, that's when we'll go in. That's how I'd look at it.

I see.

And another thing I think we should talk about is just customer affordability, right? I mean, that's 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 phase for growth mentality that really do bring about an affordability aspect. We will look each year at what our rate ask would be. We don't want to go in and make really large rate requests, and it's this growth phase for growth mentality and really the way we operate our business from an O&M and affordability perspective that help us stay out and use those revenues instead of rate cases in some years.

Sounds good. Thank you, Lisa. Thank you, Brian. Thank you.

Your next question comes from the line of Chris Ellinghaus from Cybert Williams. Your line is live.

Hi, Chris. How are you? So, Brian, I thought you were going to get into this. I don't remember what you said in your comments, but I kind of thought you were going to talk about this. But can you just talk about how you foresee Uh, recognition through the years. Do you have some visibility there?

Yeah, for, we're actually a cash taxpayer and so we have a tax credit appetite on our return each year federal income taxes. So, we're actually monetizing those every year that, you know, that appetite continues. Um. I will say there's some diminishing availability of ITCs in the future when you look at some of the legislation that's out there now. We're getting it from our batteries, for example, now, and that'll go on to our tax returns. So over the long term, I think things could change. We've also looked at PTCs as another avenue for us as well to look at. Right now, I think one of the important features of the ITCs that we generate is that they do go into the mechanism. So we could have a fairly sizable balance of ITCs that are available for what I'll call 80 ITCs for use in the mechanism going forward. But no planned external monetization through sale of the tax credits. It would be recording them on our tax returns.

Okay, so directly. So in the guidance, you talk about normal weather, but just looking at sort of the traditional tax a NOAA forecast that you guys usually show, it's going to be far from normal. So can you give us any sense of, you know, what you're seeing, you know, particularly irrigation as usual, but it's supposed to be super hot with pretty well below normal precipitation. So, you know, what have you seen so far in the spring? What's the, you know, soil condition look like? And sort of what are your thoughts about what the summer will look like?

Well, it's a great question, Chris, and certainly you know those of us that enjoy winter sports were really bummed out about not having much snow and hills. But you know, we did have some good storage and we did catch up a little bit with the with the rain that we had in this last month, but still is is a little bit short of what we would normally see, and certainly we like it to be stored up in the mountains of snow and come over come down on a slower pace. But all that being said, Irrigators have been trying to figure out what's their strategy, just given some of the commodity prices, and so that may have some impacts. But I think 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. And I know that Adam has some additional color for that as well.

Yeah, Chris, we've been debating this issue with folks on ground because it's interesting to see their take. What we've been looking at is that low water years have not correlated to less sales because there's just so many other factors involved. And this summer, I think you mentioned some of the factors. The factors pushing towards more sales are projected warmer weather. You mentioned NOAA. Lisa mentioned our reservoirs were actually at average, so that's a good sign. And the other thing that's interesting is when surface water users do get cut off a little bit, they tend to use ground pumps to make some of that up when water is scarce. So those things would all push towards more sales. On the other side, obviously, with low water, you can have the risk of curtailments, which could happen. We've had that in the past, but as we debated these things and went back and forth to look at what we thought irrigation sales were going to look like in the future, we did get to kind of this net-net normal position that Lisa mentioned, and that is really from the folks that are on the ground talking to farmers, trying to get a feel for what the year is going to look like.

If I could paraphrase, you're suggesting that you're expecting sort of normal water resources, but the demand could be high?

It does feel like the demand, if the weather turns out like it's predicted, like you mentioned, could be higher in terms of the need for energy pumps. The water side could be a little bit low, but again, we've seen no correlation in the past between low water and low sales. In fact, lots of times we've had low water years that have had higher sales because the temperatures have been higher. as we look at both sides of it.

Right. Did you get any sort of feedback about the impact that the Iran situation is having on your agricultural customers?

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 I think our farmers would like. There are some cases when they planted maybe slightly less of those products, which could impact water use. But at the end of the day, they didn't touch on the Iran issue directly.

Okay. And I guess 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?

Gosh, I think we've even had a few more inquiries since the fourth quarter. I think it seems like it's never ending, honestly. And certainly, you know, a few new ones come into the queue. A few others might drop out. But I would say overall, it's up.

I think that's right, Chris. And just a quick reminder, we've been hanging at that 8.3% IRP growth for a while now. I think we're going to update that as part of the next IRP in Q4. So I think when you see that update, you know, there should be some upside in that.

Yeah, and it's important to just remember that we don't put any load, prospective load into that number until we have either, you know, a sizable financial commitment or a signed contract or something that feels a lot more than the entire kicker. So, well, the pipeline and the 8.3% aren't exactly correlated. There's some lag in between.

Sure. It just kind of helps that when you quoted that 4,000 megawatt Q, it just sort of kind of puts things into perspective. So I was just kind of curious if that number had made any kind of advance or decline. Okay.

Chris, just quickly, the problem on those issues is, you know, talking about the large loads, so many of them are confidential. We just can't We can't come out with them until they go public. And so a lot of times we're in a holding pattern for them. Sure. Makes sense. Okay. Thanks a bunch. Appreciate it.

Thank you.

Thanks, Chris. Next question comes from the line of Michael Lonegan from Barclays. Your line is live.

Hi, thanks for the question. Just wondering if there's any update you can provide on Micron Fab 2 when you expect an ESA to be signed and, you know, when we could expect it to be implemented into your capital plan?

This is Adam. So the ESA has been signed, still being reviewed by the Commission. We expect to hear from the Commission any day now.

This is on Fab 2.

Oh, on Fab 2? Yeah, we're still negotiating Fab 2 ESA. What I can say about Micron is There is an absolute ton of work that's going on on-site. It's 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. But in terms of their in-service date, they anticipate initial waiver output for their first FAB around mid-2027. And on the second FAB, they are already moving forward with ground preparations for FAB 2. And of course, we have revenues potentially coming in the door mid this year related to Fab One. So on the ESA side, we're still working with Micron on that. Hard to say exactly the timing of that, but we'll let you know when it becomes more public.

Thanks. And then you highlighted the capital plan is conservative. You touched upon the 2032 RFP as being incremental. Anything you could say about your targeted ownership in the investment opportunity set there?

I mean, we always want to go in with some company-owned assets or projects, and we do. And, you know, historically, we've won about 50% of those. And so, you know, we have certainly a desire to own as many of the resources as we can, and we do so in a competitive way.

And maybe I'll just add, we are, this is Adam, we do have several projects that we'll put into the 2032 bid, so we'll compete like we do each year.

Yeah, Michael, if I can add to that, I think you referenced the CapEx impacts as well. And so, you know, the CapEx forecast that we have in the slides that we're showing right now doesn't have any resources for the 2032 RFP in it. We don't assume any sort of win rate for purposes of our CapEx. We put it in there when we know it's going to happen. There is some amount of CapEx in the graph that'll help serve a portion of micron second FAB, but only what we expect would be in the very earliest years of operation. That's our large transmission projects will help with that, some of our generation. We need more resources for FAB too. Like Adam said, the amount of CapEx actually depends on the ESAs we sign and how we serve our load growth rate, which we're working on right now. It's filed in June of 27, but we'll lock down some form of growth rate, low growth rate, more fourth quarter this year so that we can do our modeling off of that. You know, if you want to sort of 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. But that's how we look at the CapEx upside on that graph.

Great, thanks. And then lastly for me, 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, I just wonder if you could talk about the profile of issuances, broadly speaking? Should we expect it to profile with CapEx and also incremental capital? Should we still anticipate that to be financed with your 50-50 structure?

So the answer to the second question is yes. For any incremental amounts that are in the plan, you should plan on 50-50, right? For the stuff that's already in the plan, I think we've quoted more like a 30-70 split, but anything incremental above that, to maintain our balance sheet structure, assume 50-50. The nature of the issuances, I mean, one of the things we've talked about in the past is it's probably not linear, and part of that is because you've got, you know, large customer revenues coming in more, you know, operating cash flow in the latter years of the window, so maybe a little bit more front-end loaded. I think the best way we've been able to tell people is to model it somewhat like the CapEx profile is right now, and then if there's incremental upside, or to the capex in the plan, build a little more in in that window, but definitely not linear. And we can look at it from the perspective of if we were to have ATM issuances with forwards on it, the financing plan for equity based on the amount you saw on the slide is something that's within, you know, reasonable ATM issuance amounts. I think I mentioned in my more prepared marks earlier. And with those forwards, you know, we have the ability to shape the equity a little easier to match the timing of payment.

Great. Thanks for taking my question. Thanks, Michael.

Your next question comes from the line of Julian DeMoulin Smith from Jefferies. Your line is live.

Hi there.

Hi. It's Brian Russo on for Julian.

Good afternoon. We never know which of you is really going to answer, so nice to hear from you, Brian.

Thank you, likewise. It's nice to see ground prep beginning at the micron FAB2. I'm just wondering, what are the next milestones that could trigger an ESA, or is it just the parameters of the contract that you're negotiating? And then secondly, what load is upside that would be incremental to the prior IRP's 8.3% that would be reflected in this updated IRP? And will Micron's FAB2 also be included in that load forecast?

Brian, this is Adam. So FAB2 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 kind of where they're at. Anything beyond that is not public. I think they publicly said that again they anticipate initial waiver output for the first FAB in mid 2027. Beyond that, we just we can't get into the details of when they'll hit different targets or not. So to do that, we can attract what they said publicly, and that's what they said publicly.

OK, and then I apologize if I missed this earlier, but could you remind us of? What has changed in the RFP bidding process that might give you guys a slight advantage, possibly, on the win rate?

This is Adam again. I don't know that I would say it's an advantage as much as it's faster than it was under the Oregon rules. One of the things we're running into, and I think you know this, Brian, 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 just a lot longer than what we needed to get these projects in place. The other thing that's out there is we don't submit a benchmark bid anymore. We just compete equally with all other, you know, independent power producers out there. So that would set up an advantage as much as it's just putting us in an equal playing field, and that's a playing field we were not in several years ago. Lisa mentioned we've been kind of at a 50% hit rate, so we're continuing to try to do that, and hopefully this new process will make it go faster. And then, of course, not having a benchmark bid allows us to compete equally with everyone else.

Understood. Thank you very much.

Thanks, Brian. Thanks, Brian.

Your next question comes from the line of Anthony Crowdell from Mizuo. Your line is live.

Hi, Anthony. Hey, how's it going? I appreciate the update on the beet crop. I have one quick follow-up. Slide 12, you talk about the 2032 RFP update. The 200 megawatts of capacity you're talking there, is that associated with any particular committed customer or committed load?

This is Adam. So one thing we mentioned there, you'll notice it says at least 200 megawatts. We view that as a little bit of a minimum. This 200 megawatts is perfect capacity, and it's tied to the 8.3% IRP growth rate that we've been talking about. Again, we're going to update that figure in the future. The way it works in the RFP side is we'll get a variety of different projects. We'll be able to review those projects that are on the short list. And then depending on our need at that time, we'll be able to pull the trigger on as many projects as we need to meet the load forecast at that time. Again, Idle Power will bid several projects in the 2032 IRP. And then on the CapEx side, Brian, maybe worth mentioning, I guess, what's included in the CapEx in the 2032 resource plan.

Yeah, thanks, Adam. I'll just reiterate, we don't actually have anything in there at all from the 2032 RFP. It's a common question. that, you know, we don't actually have any assumed win rate. You know, to Adam's point, we'll compete on equal footing in the RFP, and what shows up from that that our company owns would be additive to the CapEx.

Great. That's all I had. Congrats on a good quarter.

All right.

Thank you.

And 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. Groh, I will turn the conference back to you.

All right. Thank you. Thanks, everyone, for joining us today and for your continued interest in IDACOR, and I hope you all have a great evening. Thanks.