IDACORP, Inc. Q3 FY2025 earnings call

• Customer growth and economic expansion: Customer base grew 2.3% since last year's third quarter, with residential customers growing 2.5%. Robust activity in manufacturing, food processing, distribution, warehousing and technology sectors. Micron's 2 fab projects and Perpetual Resources' mining project progress. Agricultural-related projects in the southern service area.
• Key projects: Boardman-to-Hemingway transmission line project has several towers complete. Gateway West and Swift North transmission lines in regulatory and permitting processes. Jackalope Wind project agreements terminated, exploring short-term market purchases, natural gas projects, solar and battery storage. Bennett Mountain gas-fired power plant expansion: received pre-permit, submitted public convenience and necessity certificate.
• Rate case settlement: Reached settlement with new rates increasing annual revenues by $110 million effective January 1, ROE 9.6%, overall rate of return 7.41%, rate base $4.9 billion. ADITC mechanism remains with $55 million annual cap for 2026 and thereafter.
• Wildfire mitigation: Filed 2026 Idaho Wildfire Mitigation plan pursuant to new law.

IDACORP's diluted earnings per share in the third quarter of 2025 was $2.26, compared to $2.12 in the third quarter of the previous year. For the first three quarters of 2025, diluted earnings per share were $5.13 versus $4.82 in the first three quarters of 2024. Idaho Power recorded $2.5 million of additional tax credit amortization in the third quarter of 2025, the same as the third quarter of the previous year. For the first three quarters of 2025, Idaho Power had additional tax credit amortization of $39 million compared to $22.5 million in the first three quarters of 2024.

• IDACORP's diluted earnings per share guidance range raised to $5.80 to $5.90 per diluted share.
• Idaho Power expected to use $50 million to $60 million of additional tax credit amortization for the full year.
• 2025 O&M expense expected in range of $470 million to $480 million.
• CapEx in 2025 expected between $1 billion and $1.1 billion.
• Hydropower generation in 2025 expected in range of 6.5 million to 7.0 million megawatt hours.

• Policy changes impacted Jackalope Wind project permitting, requiring finding alternative power supply solutions.
• Inflationary pressures on labor and professional services increasing O&M expenses.
• Wildfire mitigation program and related insurance expenses adding to costs.
• Interest rate changes and economic uncertainties affecting customer growth and load projections.

Q: Just a question around the medium generation needs and some of the considerations you are making around the change with the wind farm. So can you just maybe remind us what was in the capital plan for Jackalope? And then what are the sort of potential solutions and the time line for that?

A: Well, I'll start. I'll have Brian go over the numbers. And certainly, as we shifted away from the wind project and we're reviewing what the opportunities are for replacement, we only have the really Bennett to talk about today, but it's worth noting that it was 600 megawatts of wind. So it won't be a megawatt per megawatt replacement. We do -- as I mentioned in my comments, gas is showing up in our IRP and we are certainly looking at those options as well as others as we work our way through the RFP process. So do you want to talk about what was in the budget, Brian? Brian Buckham: Sure, Bill. So one thing I'll mention about the Jackalope Wind project is that the spend for that project was consolidated in the years 2026 and 2027. So when you look at our capital stack, that's where you'll see the generation resource for that. Now 300 megawatts of that was owned, 300 megawatts was PPA. We don't have the exact number to give you in terms of the cost because it's competitive information. But I will say that if you use typical wind pricing on a 300-megawatt project, there's also some interconnection costs associated with that, that given the location were relatively high. Though it was a pretty significant piece of capital in our stack, but as we're looking to the future, I think there's some other pretty significant bias to the upside on capital from some of the other resources that might be coming out of the RFP process.

Q: Residential customer growth slowed sequentially from the last few quarters. Is that telling us anything about sort of how the ramping of staffing of the new customer loads is going? Or is that telling us anything about some slower economy overall? Is that like the labor market has slowed a little bit. What can you say about that?

A: Well, certainly, on the large loads, I mean, right now, it's mostly construction personnel that are there. So I can't really say too much about what their final load growth will be. But I think the interest rates have impact. I think where you are in the year has impact in terms of people's ability and willingness to move. And I do think there probably is a little bit of softening in the economy, just given so much of the uncertainty out there. But there's not really any big trend that we're seeing that we're concerned about.

Q: Given that you're really the only bidder of gas generation in the RFPs, is there an alternative to the RFPs to expedite the process, considering the long lead time to secure turbines, et cetera, and given the profile of your customer and the demand that you need to meet as we move towards the end of the decade. I was just curious if that was even considered?

A: Well, we're certainly considering all options, and there's -- it's just an incredibly dynamic environment from which to try to plan and execute quickly. So we will report back to everyone next quarter when we have a little more insight as to what those alternatives will be.

Q: Could you talk about the priorities for your next rate case and especially related to potential tracking mechanisms. How important is that to your plan? And how do you see the regulatory support for that in Idaho?

A: I just want to make sure that I heard the whole question. So we are very sensitive about rate cases. We want to make sure that we're being careful about meeting our obligation to serve, but also keeping rates as affordable as possible. And so with -- as we go through time, we evaluate each subsequent rate case and based on the need for what we're spending and if we can cover that with revenues that kind of growth. So it really is a very dynamic calculation as we go through time. We want to make sure that we maintain our financial health as we go through this extraordinary period of growth. But certainly, rates are -- rate cases are part of that calculation as we go through time. Is there anything, Tim, that you would add? Tim Tatum: Yes. Thanks for the question, Alex. It's a great one. We just filed our 2025 general rate case settlement stipulation last week. Timely question. I've met with a few folks this morning to start talking about it. And we are working on trying to assess the timing and need of our next case and what elements might be included, whether it's a traditional case, whether it's a case that has a tracker, all of that's on the table at this point. But the plan is in development and in early stages. So we'll have to report back more later.

Q: I just want to follow up on one of the Bill Appicelli's question on the Jackalope project, the loss of 300 megawatts, I guess, in your capital plan, I know you talked about the transmission and maybe you'll meet the generation need. But is there offsetting CapEx that goes into your forecast? Or should we expect a dip from what you previously thought 2027 was going to be now that Jackalope is being canceled?

A: Yes, great question, Anthony. So we typically update our capital forecast every February on the Q4 call. The last couple of years, we've done an interim update just based on the outcome of RFPs and resource procurement. I think you should expect us to do that potentially this time as well. I mean we've talked about the Bennett plant, but that is an inadequate resource to cover the load growth that we have going forward, even for just the customers we've announced so far, the ones that are in the construction phase or that have executed agreements with us. There are incremental generation requirements in there, and they are not reflected yet in the capital stack. But as we solidify those, we will add those to the capital stack. You'll see Jackalope come out, you'll see Bennett go in. And then by the time we get to that update, I would expect to see incremental resources in there as well as project costs and timing adjustments that we typically include in our annual update. So that may be in the Q4 call, it may actually be sooner that you see some of that coming to fruition possibly as early as this year, starting to see some incremental generation resources being added depending on the outcome of our processes