Welcome to IDACORP's Third Quarter 2025 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 IDACORP's website. 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 2, our discussion today includes forward-looking statements, including earnings guidance, spending forecast, financing plans, regulatory plans and actions, and estimates and assumptions that reflect our current views on what the future holds, all of which are subject to risks and uncertainties. These 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 your review in our filings with the Securities and Exchange Commission. As shown on Slide 3, also presenting today, we have Lisa Grow, President and CEO; Brian Buckham, SVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager. Slide 4 has a summary of our third quarter results. IDACORP's diluted earnings per share were $2.26 compared with $2.12 for last year's third quarter. In the third quarter of this year, Idaho Power recorded $2.5 million of additional tax credit amortization under the Idaho Regulatory Mechanism, which is the same amount Idaho Power recorded in the third quarter of last year. For the first three quarters of 2025, diluted earnings per share were $5.13 versus $4.82 for the first three quarters of 2024. Those results include additional tax credit amortization of $39 million in the first three quarters of 2025, compared to $22.5 million in the first three quarters of last year. For our guidance, we're raising our full year IDACORP's diluted earnings per share guidance range for the second time this year. Our new expected range is $5.80 to $5.90 per diluted share. Our current expectation is that Idaho Power will use between $50 million and $60 million of additional tax credit amortization for the full year, a reduction from our estimate last quarter. So we were able to increase our earnings per share estimate for the year while decreasing our estimate of additional ADITC amortization, which is reflective of our strong operational performance this year. These estimates assume historically normal weather conditions and normal power supply expenses for the fourth quarter. Now I'll turn the call over to Lisa.

Thanks, Amy, and thanks to everyone for joining us on the call. Let's start with a look at customer growth and economic expansion. As you can see on Slide 5, our customer base has grown 2.3% since last year's third quarter, including 2.5% for residential customers. We continue to see robust activity across several sectors, including manufacturing, food processing, distribution, warehousing, and technology. Micron's two fab projects remain a cornerstone of our industrial engagement. The two fab expansion represents the largest private capital investment in Idaho's history and underscores our region's growing prominence in advanced manufacturing and technology. In parallel, we're actively engaging with several Micron suppliers planning to establish operations in the Treasure Valley. Perpetual Resources, another new large customer, recently achieved a significant milestone in its mining project by transitioning from permitting to development. The project broke ground earlier this month, marking a new phase in Idaho's mining sector. We're also seeing increased momentum in agricultural-related projects in the southern part of our service area. These include cross-vent barnes, rotary milking parlors, and biodigesters that will contribute to load growth while supporting energy production through renewable natural gas. Our new large load pipeline remains very robust. As we've previously communicated, our load forecasting methodology remains conservative and disciplined. We don't include new large projects in our forecast until contracts for the procurement and construction are executed, which occurs after we've identified how to serve the customer. This approach ensures that only viable projects are reflected in our projections. Now the laws of physics are unyielding. So we are working hard on creative options to serve these new large loads while ensuring the system remains reliable and affordable. As we work with these new loads, I want to emphasize Idaho Power's continued commitment to customer affordability. We work hard to keep our prices among the most affordable in the country. And according to national data compiled by the Edison Electric Institute, Idaho Power's customers' bills remain 20% to 30% lower than the national average. We strive to achieve a thoughtful balance between growth and affordability, in part through the design of pricing and contractual provisions for new large load customers, guided by a long-standing growth philosophy. As shown on Slide 6, our residential customers' rate increases since 2014 are much lower than the national average and the steep increase in consumer price index in recent years. Shifting gears and turning to Slide 7. We remain full speed ahead as we execute on key projects. Most notably, work is progressing quickly on the Boardman-to-Hemingway transmission line project. Several towers for that project are now complete. We're thrilled to have steel on the ground on this key resource for helping us access reliable, affordable energy in the Northwest. We continue working through the regulatory and permitting processes on the Gateway West and Swift North transmission lines, and we look forward to moving both of those projects into the construction phase, hopefully soon, as they are necessary resources. As I touched on during the last call, recent policy changes impacted the permitting of the 600-megawatt Jackalope Wind project that we plan to have in service by 2027. As a result, we terminated the agreements we had for that project, both the ownership and the power purchase components. With the wind project's agreements terminated, we're busy identifying power supply solutions to meet future load growth. These solutions could include short-term market purchases, natural gas projects, and potentially additional solar and battery storage resources. We're in a continuous state of planning and execution to affordably serve the growing demand with a reliable mix of generation resources. As described in our IRP, natural gas resources are a good operational fit for our system as well as a least cost, least risk resource. Idaho Power is planning a 167-megawatt expansion of the Bennett Mountain gas-fired power plant, which will help serve load during peak times. In September, we received a pre-permit to construct from the Idaho Department of Environmental Quality, which allows construction to begin. We've also submitted a certificate of public convenience and necessity for the project to the Idaho Commission. If approved, we expect to begin construction in the spring of 2026 and bring the project online in 2028. As you can see on Slide 8, there's lots of work going on in the RFP space and lots more to come. The Bennett project is an important step in helping to solve our future power supply needs. We're continuing to work through the resource selection process, and we anticipate being able to provide some updates on additional selected generation projects on our year-end call, if not sooner. The next two slides highlight the news in our pending Idaho General Rate Case. We recently reached a settlement with new rates designed to increase annual revenues by $110 million or 7.48% effective January 1. Additional details of the rate case settlement include a 9.6% ROE, a 7.41% overall rate of return, and a $4.9 billion Idaho jurisdictional rate base, excluding coal plants that are under separate mechanisms. There were no capital disallowances in the settlement. Our ADITC mechanism remains in place with a $55 million annual cap for 2026 and thereafter. Also, all existing ADITCs not currently included in the mechanism and all investment tax credits generated through 2028 will be added to the mechanism. We view the settlement as a constructive outcome that helps us continue to safely, reliably, and affordably provide electric service to our growing service area. The settlement requires approval by the Idaho Public Utilities Commission. And based on prior cases, we expect the commission will issue an order on the settlement sometime in December. Turning to Slide 11. We filed our 2026 Idaho Wildfire Mitigation plan with the Idaho Commission earlier this month. It's the first wildfire mitigation plan being filed pursuant to Idaho's new Wildfire Standard of Care Act and it outlines our proposed methods of mitigating wildfire risk and hardening our system. As a reminder, the Wildfire Standard of Care Act was signed into law earlier this year. The law empowers the Idaho Commission to set clear and consistent expectations for utilities' wildfire mitigation efforts. Under the law, stated generally, utilities are assumed to be acting without negligence if they follow a commission-approved wildfire mitigation plan and provides up to 6 months for the Idaho Commission to review and approve the plan after it is filed. So with that, I will turn the presentation over to Brian for a financial update.

Thanks, Lisa. Hi, everybody. I'm going to start today with the financial results on Slide 12. As you can see, IDACORP's net income increased $10.8 million for the third quarter of this year when compared with the third quarter last year. Just to summarize, that increase was mainly driven by higher retail revenues from the January rate change and from customer growth. On the other hand, we saw lower usage per customer, and that's because we're comparing to a very hot, very dry third quarter of last year. We also saw higher O&M expense, and as expected, depreciation and interest expense increase from our continued build-out of the infrastructure to support the growth that Lisa talked about. To add some detail on that, a net increase in retail revenues per megawatt hour increased operating income by $17.6 million on a relative basis, resulting mostly from the rate changes from the limited issue rate case Idaho Power filed last year. Our customer growth increased operating income by $7.8 million. That was the result of adding 15,000 customers over the last year. And although cooling degree days in Boise were 14% higher than normal, we saw an impact from a relative decrease in usage per customer of $5.7 million. That's not intuitive, when it was so warm this year, but it's because the third quarter last year was even more abnormally hot and dry, which affects comparability. Of the customer classes, irrigation usage per customer decreased most significantly, with higher precipitation and lower temperatures during the quarter compared with the third quarter of last year. Other O&M expenses were $4.2 million higher, that was driven by inflationary pressures on labor and professional services and some wildfire mitigation program and some related insurance expenses. As the system grows, we also expect to see higher O&M expenses to maintain an expanding system, the natural result of that growth. That said, we plan to keep our culture of measured and thoughtful spending fully intact as we go forward. And depreciation expense increased $8.1 million quarter-over-quarter, again, as we expected from our infrastructure development and the placement of additional assets into service. Other net changes in operating revenues and expenses increased operating income by $4.3 million. This was due primarily to a decrease in net power supply expenses that weren't deferred through the power cost adjustment mechanisms. And then nonoperating expense increased $9.8 million from the third quarter on a net basis. As we continue to grow, we continue to experience higher interest expense to finance it. Also, we had an increase in interest that Idaho Power is required to pay on transmission customer deposits. And as I noted on our Q2 call, a portion of our higher interest expense is driven by our new finance lease related to a third-party energy storage agreement, and that affects comparability as well. I think it's important to remember that the additional financing costs and the amortization related to that right-of-use lease asset is recovered as a pass-through cost in the power cost adjustment mechanism. The increase in nonoperating expenses was partially offset by an increase in AFUDC; that's from higher average construction work in progress balances. Just as a barometer of how busy we've been as a company, our QIP balance was $1.6 billion at the end of the quarter. And at the same time, IDACORP's total assets went over $10 billion for the first time. Income tax expense, in this case, excluding additional ADITC amortization under the mechanism decreased by $9.1 million. I'd attribute this mostly to annual income tax return adjustments and recurring regulatory flow-through tax items. So to sum it up on financial results, it was a strong quarter, and it's been a strong year-to-date. And because of that, we've decreased our full year expectation of additional ADITC amortization, while at the same time raising our expectations on earnings for the year. Now moving on to Slide 13, I'll talk about the cash side. Our operating cash flow through September were $464 million, which was $6 million higher than the comparative period last year. This continues the trend of steadily improving cash flows from our rate cases and operation of our mechanisms. At the end of September, the Idaho Commission approved our request for additional pre-collection of Hells Canyon AFUDC. On an annual basis, this will increase cash collection by about $30 million. Now there's no income statement impact from that, but it's positive on the cash side and it's beneficial for our credit metrics. We think the order demonstrates the Idaho Commission's intent to support the financial health of the company, and also a willingness to make decisions to help keep financing costs low for the benefit of our customers. It was another busy quarter. The fourth quarter surely offers no reprieve. We're working through resource acquisitions, building infrastructure like the Bennett expansion and our major transmission projects, and undoubtedly other projects to meet load and reliability obligations, and we're otherwise executing on our strategy. So we're hard at work. We're glad you're with us, and we're excited to share additional information on projects and the resulting in new CapEx expectations in the relative near term as soon as we have some. I'd be remiss if I didn't mention that we're excited to see many of you at the EEI financial conference coming up in a little over a week. Lisa, Amy, John, and I will all be there. And now over to John for an update on our 2025 guidance.

Thanks, Brian. Moving to Slide 14. You can see our updated 2025 full year earnings guidance and key operating metrics. This guidance assumes normal weather and normal power supply expenses for the rest of the year. Amy and Brian already mentioned this, but with continued positive operating results, we raised our guidance and now expect IDACORP's diluted earnings per share this year to be in the range of $5.80 to $5.90, with the assumption that Idaho Power will use $50 million to $60 million of additional investment tax credit amortization. Our expectation for full year O&M expense increased to a range of $470 million to $480 million as we continue to experience inflationary pressures on labor and professional services, and added work on wildfire mitigation efforts. We still expect to spend between $1 billion and $1.1 billion on CapEx in 2025. Finally, we still expect pretty good hydropower generation in 2025, though we've updated our range to 6.5 million to 7.0 million megawatt hours for the year. With that, we're happy to address any questions you might have.

Your first question comes from the line of Bill Appicelli with UBS.

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 timeline for that?

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?

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 are 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 are some other pretty significant biases to the upside on capital from some of the other resources that might be coming out of the RFP process.

Just so I'm going to have Adam just give a little highlight on the RFP process.

Yes. So we're still working through the 2028 and 2029 RFP processes. Just as a reminder, the 2028 process, Idaho Power has three projects on that final shortlist. On the 2029 shortlist, we have four projects. Lisa mentioned the Bennett Project. So we're going to continue to work through those to see how to replace that capacity in 600 megawatts, but Jackalope was mainly an energy resource for us. The effective load carrying capability was about 90 megawatts. So that's what you'll see us try to replace from a capacity perspective. Lisa also mentioned the IRP shows gas in the future in 2029 and 2030. There was only one gas bid that made the 2029 RFP. So we'll have to consider other options there as we evaluate our future in the gas space.

Okay. And then was the Bennett project in the capital stack, Brian, in February or now?

We had a resource that was in there somewhat as a proxy in the most recent capital update that we gave, but it's not a full reflection of the '28, '29 RFPs.

Okay. And then just my only other question was around customer growth trends. It seems like that's not an issue based on the amount of growth that you guys are talking about. But I just did note that the 12-month trailing did tick down a little bit. Any color there or just thoughts on those trends moving forward?

Are you talking about the load growth or the actual?

Sorry, the customer growth, yes, the actual that you cite there, I think it was 2.3% year-over-year on a trailing 12-month basis. I think that had been a little bit less, and that was 2.5%, so?

Yes. I think those have been pretty much...

We've been consistent in our growth at about 2.3% to 2.4%. That's the growth per customer or customer meters. The area where we anticipate seeing more significant growth is in manufacturing, and we expect that to occur and increase over the next couple of years.

Right. And just to sort of put a finer point on it, too, that prospectively, we're looking at around 8.3% growth overall.

Right, in terms of total load growth, right?

Yes. And that's each year over the next five.

Bill, I want to go back to your question on whether or not the gas plant was included in the capital stack. So if you go back to February, we didn't have a CPCN on that, and the RFP wasn't known. So that project is actually an incremental add since then. So you take the wind out, and the 167-megawatt Bennett project is actually an incremental add.

And then we'll expect additional adds beyond that in the future.

Your next question comes from the line of Chris Ellinghaus with Siebert Williams Shank.

So 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?

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 impacted. 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.

Okay. The sales growth for the quarter was actually, I thought, a little surprisingly good despite the usage impact. Is that just sort of the year-over-year progression of customer growth? Or are there other factors there, given cooling degree days were down double digits? So to have your sales level be up as much as it was on the residential and commercial side may be a little surprising. Have you got any thoughts there?

Yes. I mean I think it does speak to growth. Weather was a little wonky this year. So I think that kind of had us kind of dampened some of it, but yes, I think I would point to growth mostly.

Yes. Chris, this is Adam. It's been interesting looking at the operational side. Every single day, we look at the load and where it's going versus the temperatures, and I think if you ask our operators, they would say they definitely noticed kind of an uptick even when the weather maybe wasn't as strong this year. So when I see that every single day, I view it as we're starting to see the manufacturing load increase. A lot of the large projects are starting to get construction power. We're starting to see that come through our loads. So I thought it was a pretty positive year when you consider the weather that we had. I agree with you.

Can you say the same about irrigation? I really kind of thought it might be even lower given what the weather was, particularly sort of the way that precipitation fell during the quarter. So was there something going on with ag where it was particularly strong to keep irrigation as high as it was?

I believe that the start of spring and summer was quite warm and dry, which likely gave us a good boost. We did experience rain on the 4th of July and in August. Fortunately, it never became excessively hot for long periods, which is typically when we see those significant peak demands. Overall, we are projecting a slight increase for the year compared to last year, even though it may not follow the usual trend throughout the year. Adam, do you have anything to add?

From a boots-on-the-ground perspective, it seems that the demand has been quite strong and steady, which aligns with our expectations for the year based on discussions with farmers. We observed a consistent level of energy usage throughout the year, although there were some fluctuations. The demand remained robust, and Brian has the specifics on the numbers.

Yes. And this is Brian. If you look at just the third quarter, a modest downtick in irrigation loads. But if you look at the first nine months of the year, kind of a modest increase, right, that you see overall. So June usage was high both years. June 2025 didn't have precipitation, right? And that's a big driver. It turns out the amount of precipitation, not just the temperature. We saw an uptick in precipitation actually, in the third quarter, but nonetheless, still has a pretty strong quarter for irrigation.

Okay. Lastly, if I recall correctly in the IRP with the preferred portfolio, I think you had a scenario in there with reduced renewables, probably in anticipation of the Jackalope issue. And if I recall correctly, sort of gas was next up in the queue there. Is that kind of what you're thinking? And given the sort of RFP results, do you anticipate sort of opening that up at all to see if there's additional interest, given the sort of gas environment that we see ourselves in today?

Certainly, many of the policy changes have altered the economics of renewables. This will affect how these inputs are incorporated into the model. We will evaluate the shortlisted projects based on their ability to meet the criteria they were selected on, considering these policy changes. Is there anything you would like to add?

Chris, maybe I'll just add, you're right. 2029 had a gas plant, 2030 had a gas plant. If you look at our 2029 RFP, and it was actually 2029 and later, there was only one gas plant that was part of that RFP. So just by virtue of seeing what's least cost, least risk in our resource portfolios, we're going to have to start looking to see what might exist beyond the RFPs in that 2030 range.

Your next question comes from the line of Brian Russo with Jefferies.

It's Brian Russo on for Julien. I think you may have just answered my question, but I'll just ask it again anyway. 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?

We're definitely exploring all options, and it's a very fluid environment that requires swift planning and execution. We will provide an update next quarter when we have more clarity on what those alternatives might be.

Okay. Great. And then I think given that you can only get Bennett in service by 2028, right, that's a year after you were hoping to have the Jackalope capacity. And you mentioned three alternative short-term purchases, I think the second one was gas and the third was solar and battery storage. I suppose that your preferred choice is to own something, but it doesn't seem realistic to own any gas generation that soon. So with solar or battery storage, be kind of the next preferred scenario to replace Jackalope?

We are exploring all options to determine what we can actually achieve quickly. I don't believe we have more to add on this today. Is there anything you would like to include?

Brian, this is Adam. I mean, I think you're right. You're seeing a gap there. And certainly, we have a couple of PPA projects that were going to help fill that gap. But to your point, we've got to start considering what other options exist because what the IRP is showing is it's most cost effective right now to go forward with a gas facility. So we are taking a look at that, and hopefully, we'll be able to update you next quarter.

Yes. And to just add too, our transmission projects also help get us to market to bring resources in. So those are also important.

And on those, just quickly as a reminder, 2027 is the in-service date for B2H. So that's pretty significant. We will bring resources in using that resource. And then 2028, we have both the Southwest Intertie project down south and a portion of Gateway West. So when you look at '27 and '28 from a CapEx perspective, they're going to be pretty busy setting aside the generation side of things.

And I guess I'd just tie it up and just remind you that certainly, we have our obligation to serve, and we do also procure those resources competitively. So that doesn't change.

Your next question comes from the line of David Arcaro with Morgan Stanley.

This is Alex Herman on for Dave. 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?

I just want to ensure that I understood the entire question. We are very mindful of rate cases and want to balance our obligation to serve with keeping rates affordable. As time goes on, we assess each rate case based on our spending needs and whether that can be funded through revenue growth. It's a dynamic assessment that we constantly revisit. We aim to maintain our financial stability during this significant growth period, and rate cases are an integral part of that process. Tim, do you have anything to add?

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 the early stages. So we'll have to report back more later.

Got it. No, very clear. And then shifting to the earnings outflow going forward. As our new large load customers start to come online, do you think you could earn an ROE above the minimum level of 9.12%?

Yes, Alex, this is Brian. So at some point along the way, yes, there's a convergence of just revenues coming in from customers that caused our earned ROE to increase above the 9.12% level. In fact, that's what we've been looking to do is increase the ROE every year. We've done that with cases over the last few years. We have removed some elements of regulatory lag by doing that and eventually hope that the magnitude of frequency of cases would decline and the revenues from large load customers would, in fact, come in and cover the infrastructure that's being developed for them. So those large load, large volume customers pay for their share and that, therefore, would reduce the need for rate cases and still allow earning at or above that 9.12% floor and then not needing ADITC support.

That concludes the question-and-answer session for today. Lisa, I will turn the conference back to you.

All right. Well, thank you very much for everyone for joining us today, and I hope you all have your Halloween costumes picked out and that you have a very safe and happy Halloween. So thank you.

That concludes our conference for today. You may now disconnect. Thank you, and have a great day.