IDACORP, Inc. Aktie

Good afternoon, everyone, and welcome to IDACORP's Third Quarter 2026 Earnings Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP website. [Operator Instructions]

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 will reference during today's call are available on IDACORP's website.

As noted on Slide 2, our discussion today includes forward-looking statements, including things like earnings guidance, spending forecasts financing plans, regulatory plans and actions and estimates and assumptions that reflect our current views on what the future holds. These are all subject to risks and uncertainties, those risks and uncertainties may cause actual results to differ materially from 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, CFO; and John Wonderlich, Investor Relations Manager. Slide 4 has a summary of our third quarter financial results.

IDACORP's diluted earnings per share were $2.73 compared with $2.26 for last year's third quarter. For the first 9 months of 2026, diluted earnings per share were $5.76 versus $5.13 in 2025. And those results only include additional tax credit amortization of $6.3 million in the first 9 months of 2026 versus $39 million in the first 9 months of last year, which showcases the strong performance so far for 2026.

For our key operating metrics, we're raising our full year IDACORP diluted earnings per share guidance range by $0.10 on the bottom and $0.05 at the top of the range. Our new range is $6.40 to $6.50 per share. This increase is driven by our strong operational results in the third quarter. It includes our expectation that Idaho Power will use less than $10 million of additional tax credit amortization for the full year which is a reduction from the less than $15 million in our prior guidance. These estimates also assume historically normal weather conditions for the rest of the year.

Now I'll turn the call over to Lisa.

Thank you, Amy, and thanks to everyone for joining us today. I'll start by highlighting the impressive growth we continue to see across our service area. This growth is diverse, happening across all customer types in a wide variety of industries. As you can see on Slide 5, our customer count has increased 2.2% since last year's third quarter, including 2.4% growth in the residential segment. A particular note for this quarter are industrial revenues, which increased by an incredible 27% since last year's third quarter. After years of diligent planning and project execution, we're seeing significant revenues coming in from large contract customers as they construct their facilities and come online.

We're excited to be part of their success. Meta officially began operations at its data center south of Boise in September and is now ramping up. While Micron Fab 1 and Fab 2 expansions in Boise continue to make impressive progress. We've included photos on Slide 6. So you can see the scale of these projects as well as a couple of others.

Our preliminary load growth CAGR for the 2027 IRP is 8.9% for retail sales for the next 5 years. That increase includes the higher base year load in the calculation. While this is still preliminary, you can see the substantial growth on Slide 7. To put this in perspective, [indiscernible] forecast of about 19,000 gigawatt hours in 2027 and growing to about 29,000 gigawatt hours by 2032. This growth is substantial, and we're working hard to ensure Idaho Power stays ready to meet it and that we do so responsibly. As a reminder, for large contract customers, our preliminary load projections only include the customers who have signed contracts or made significant financial commitment to Idaho Power for infrastructure build-out.

In addition to large customers that we've already discussed, there's a diverse group of new and expanding customers interested in investing in our service area, including manufacturing, mining, food processing, transportation, data centers and other energy-intensive industries. To date, in 2026, we've received 76 inquiries from projects with energy needs greater than 1 megawatt, which is on pace for another year of historically high project activity. These projects have the potential to bring new jobs, investment and long-term economic opportunities. They also reinforce the importance of thoughtful planning to ensure we continue providing affordable and reliable service to our customers.

To highlight a few other projects, Idaho Power broke ground this month on transmission facilities needed to provide electric service to perpetual resources [indiscernible] project, which will support domestic production of critical minerals and strengthen U.S. supply chain. We also recently celebrated the grand opening of Tractor Supply Company's new distribution center in Nampa, another great example of economic growth and business investment happening across our service area.

Idaho Power is focused on affordability as we grow, and we're proud that our prices remain 20% to 30% lower than the national average. As shown on Slide 8, since 2016, average national electric rates have increased 41%. Rent in Boise has increased 85% and CPI inflation has grown 39%, while Idaho Power residential rates have increased 24% over that same period, an average of just 2.2% a year. We're strong advocates of Idaho's growth pace for growth regulatory approach and our contracts with large contract customers seek to protect Idaho Power and our existing customers from risk and cost shifting.

On Slide 9, you can see some of the contract protections we target in energy service agreements with large contract customers. As I mentioned on last quarter's call, the substantial increase in revenues we're seeing from these customers was a key driver for Idaho Power not filing a rate case in 2026, which helps demonstrate the benefit of the growth pace for growth model in Idaho. We're moving full speed ahead, executing on projects to serve our growing customer base and enhance our grid.

As shown on Slide 10, we're making great progress on Boardman to Hemingway transmission line. To date, more than 1,200 structure pads have been built, 1,100 foundations have been installed and about 780 towers have gone up, which represents about 60% of the project total. And additionally, we've installed around 100 miles of conductor. B2H remains on schedule for an in-service date in late 2027. In addition, construction in Nevada continues on the Swift North Transmission Project which we expect to be completed in 2028. On Gateway West Transmission project, we continue to make progress, and we have the transmission line construction out for bid.

Moving to Slide 11. We're continuing to make progress on 3 company-owned natural gas-fueled projects. Construction is underway on a 167-megawatt resource who are building next to our existing Bennett Mountain gas plant. The new Bennett facility has a scheduled in-service date of 2028, and we have a CPCN, air permit and EPC contract in place. We have CPCN applications filed for South Hills, a 222-megawatt project, scheduled for operation in 2029 as well as the 430-megawatt Peregrine project, which is slated for 2030. We've executed equipment supply agreements for all 3 projects. Additionally, we signed an EPC contract for the Peregrine project, and we're negotiating a contract for the South Hills project. The dispatchable energy from these plants will help us meet our projected load deficits and serve our customers with the lease costs, lease resources.

Looking ahead to additional capacity and energy needs, our evaluation team received more than 100 bps for our 2032 RFP and has developed a final shortlist of 11 projects as shown on Slide 12. As has been the case in past RFPs, Idaho Power has multiple company-owned projects on the final short list, and we were pleased to have competitive bids. In fact, the 2031 Self-Build project on the slide is the top-ranked project. The list also includes third-party-owned solar, wind and battery facilities, along with a few market purchase bids. We don't intend to contract with every project on the list as of now. It's a substantial number of megawatts in total, more megawatts than in our updated load forecast through 2032. However, consistent with what we've done previously, our final shortlist can accommodate the potential incremental growth. And it's good to have that optionality. We're working to get contracts in place and expect to move forward with the selected projects by the end of this year, so keep an eye out for CPCN filings.

And finally, as the Oregon sale goes, we continue to expect the sales to close in the spring of 2027, pending successful regulatory outcomes. We recently received FERC approval and the Oregon and Idaho state regulatory processes continue.

And with that, I will turn the time over to Brian.

Hi, everybody. Thanks for joining. I'm going to jump right into the drivers of the quarter's results on Slide 13. You can see the biggest driver was higher retail revenues, resulting from a combination of incremental benefits from current base rates and customer growth. Those were nearly a $44 million benefit for the quarter, and they were about $90 million year-to-date combined. Overall, per customer usage was essentially flat for the quarter, and the fixed cost adjustment mechanism decreased retail revenues for the quarter. That was a result of slightly higher sales to the residential and small commercial customer classes.

The new line we added in the second quarter, revenues from large contract customers, increased operating income by almost $12 million for the quarter. From a year-to-date perspective, it was around $20 million, which illustrates the ramp-up. This piece is important because we're seeing the benefit of large contract customers materializing, and that accounts for much of the 27% increase in industrial customer revenues that Lisa mentioned.

As we expected, O&M expense came in higher in the third quarter, and the primary drivers were the amortization of previously deferred costs for the Jim Bridger and Valmy and our welfare mitigation program. Remember, we recover a large portion of those items through rates and regulatory mechanisms.

Depreciation and amortization expense increased a little over $7 million for the quarter, that's also not surprising because we continue to invest heavily in system infrastructure to support increasing customer demand. So we have more plants in service.

Other changes in operating revenues and expenses increased operating income by $10.6 million, similar to the impact we saw in the first half of the year, this benefit resulted primarily from a decrease in net power supply expenses not accrued to the power cost adjustment mechanisms. That was in large part due to updates to the Idaho jurisdiction PCA mechanism based in last year's rate case. Lower property tax expense also contributed to this benefit and was the result of a change in line Idaho in 2025.

Our nonoperating expense increased slightly as higher [indiscernible] balances driven again by heavy infrastructure investment led to higher [indiscernible], which mostly offset higher interest expense. If you take a look at the balance sheet, you'll equip was over $2.1 billion at quarter end, which really illustrates Lisa's point about how busy we've been as a company. That's, of course, the beauty of financial statements. Sometimes the numbers won't tell a story equivalent to [indiscernible].

Income tax expense, if you exclude ADITCs provided a $6.7 million benefit for the quarter, that was mostly driven by plant-related flow-through items. Lisa mentioned that Idaho Power recorded just over $6 million of additional ADITCs so far this year compared to $39 million reported last year over the same time period, so a positive start contrast there. I think that's particularly notable given the higher estimated year-end book equity in the Idaho jurisdiction this year. And it's demonstrative of the strong financial performance the company has had so far this year.

We've been working through our capital budget forecast, which entails updating project timing and pricing as well as incorporating new projects. The CapEx graph from prior quarters is outdated. And as you might expect, may underrepresent what we expect our capital will look like over the planning window. We plan to provide an updated CapEx forecast on our Q4 earnings conference call on our more typical cadence, and it will incorporate our standard updates as well as the CapEx impact of company-owned projects selected from the 2032 RFP, lease that are far enough along in the process and ready for prime time.

I want to spend a little time talking about financing, ahead of what we expect to be more detail on the Q4 earnings call, and that takes us to Slide 14. In the third quarter, we executed $268 million of additional forward sale agreements through our 2026 ATM program. That added to the $265 million we sold in the first half of the year under that same program. And all of those shares are on forwards. We also still have proceeds available from the unsettled forwards from both our prior 2024 ATM program and our follow-on offering from last year, which you can see in the chart on the slide. I think the main point here is that we have a balance of about $873 million of forwards available for settlement right now.

And we've intentionally prefunded our equity needs so we can blend that equity to remain around our target 50-50 debt equity capital structure. At the end of Q3, without counting on settled forwards, we were at 51% equity of both IDACORP and Idaho Power. So pretty close to our target with a little bit of debt headroom.

We'll refresh it for our Q4 call with the related refreshed CapEx look. But as you can see on Slide 15, we've already solved for the bulk of our current plans equity needs. We have the equity we need for the current plan through 2027 and likely into part of 2028, and we currently expect to address the remaining amount of equity required to fund our current CapEx plan through ATM issuances.

Additional CapEx would require some additional debt and growth equity with the amount dependent in large part on the payment timing for that CapEx. Our approach on financing will continue to be mindful of managing dilution with things like forward and payment timing, reimbursable customer funding and other approaches.

Related to that, with recent increases in volatility in interest rates, I thought it'd be good to talk about interest expense going forward. We're fortunate to have limited long-term debt refinancing requirements over the next 5 years with just $80 million maturing in 2030. We also don't have any holding company debt or long-term variable rate debt. We're also in a more frequent rate case mode, allowing for more timely cost of capital adjustments in a rising interest rate environment. Each of those attributes reduces our exposure to interest rate risk going forward.

On the regulatory front, it's time for us to start running numbers on a potential June 2027 rate case filing. Revenues from the outcome of last year's general rate case, revenues from large contract customers and customer growth across all classes, all helped keep us out of our rate case this year, notwithstanding inflationary pressures. While we have a lot of infrastructure under construction this year, we expect some of the larger projects built for the benefit of our broad customer base won't convert from [ quick ] to plant in service until 2027. Those are projects like B2H through other transmission projects, hydroplant refurbishments and system hardening to benefit all customers just as a few examples.

Contrast that with the infrastructure we built for large contract customers, which we recovered through ESAs with those customers. Having a large portion of our broad customer projects going into service in 2027 increases the likelihood of us filing a general rate case next year, but we will be doing the math on it.

As we head into the last couple of months of the year, we're seeing large contract customer revenues continue to ramp after years of investment by both them and us. We've had strong financial results year-to-date and we're looking good going into year-end for what we expect to be a 19th consecutive year of EPS growth. And we're focused on affordability for our customers while also running full steam ahead, developing and constructing several transmission and generation projects for existing and future customers. We're 2 years into more than doubling our rate base over a 5-year window, we're executing efficiently on our financing plan to do all of that. I like where we're sitting right now, and I like where we're headed.

For those attending, we're excited to see you with the upcoming EEI Financial Conference in sunny Arizona. As many of you know, it's one of my favorite events of the year.

So I'm going to wrap it up there and hand it over to America's top IR professional, John Wonderlich.

Thanks, Brian. Turning to Slide 16. You can see our 2026 full year earnings guidance and key operating metrics, we've had some solid improvement in our earnings and ADITC guidance. As usual, we assume normal weather for the remainder of 2026 for our guidance. With continued strong operating performance, we now expect IDACORP's diluted earnings per share this year to be in the range of $6.40 to $6.50. We lifted the bottom and top ends of the range. We also see improvement in our ADITC expectations. So we're cutting $5 million off of our previous guidance. We now expect that Idaho Power will use less than $10 million of additional investment tax credit amortization in 2026. This is much less than the $40 million we amortized for full year 2025, especially when considering the significant increase in year-end book equity.

We now expect full year O&M expense to be in the range of $535 million to $545 million. We still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026. As noted on the second quarter call, at this point, it's fair to say we're trending to the high end of that range for CapEx. Based on our current forecast of hydropower operating conditions, we now expect hydro power generation to be within the range of 5.5 million to 6.0 million megawatt hours for the year.

With that, we're happy to address questions you might have.

[Operator Instructions] Your first question comes from the line of Shar Pourreza with Wells Fargo.

This is Whitney Mutalemwa for Shar. Yes. Since this -- assuming the short list is larger than the committed forecast, what has to happen before you contract beyond committed need? Like does a pipeline customer have to sign and now get commission approval within the 270 days before you'd commit to more self-build?

It can be that, but we also -- any time a customer really -- there's a signed ESA or they've made a significant financial commitment, then we would add them to the load forecast. It doesn't happen to have to go all the way through commission approval.

Okay. Understood. And since the 29,000 gigawatt hours only includes signed or committed customer. How big is the pipeline sitting outside in megawatts given the 76 inquiries this year?

It's sitting right about 4,000 megawatts, and I know that number seems familiar. We've said that number for several calls, only -- it's not the same 4,000 because as projects go into construction, we move them out of that as other projects come in. So I think -- do you want to add something, Adam?

Yes. I think you mentioned the 4 gigawatts, and that's what we've mentioned in the past. Just a couple of quick things. The 4 gigawatts does not include Micron Fab 1 or Meta 1. Meta 1, obviously, as we mentioned in the call, is complete Micron Fab 1 is progressing. So the 4 gigawatts we talk about is truly a future pipeline. And of that 4 gigawatts, I'd say, 1 gigawatt is what we often refer to as promising usually includes a financial commitment and those entities are moving towards construction or potential construction. We have another 1 gigawatt of the 4 that are being actively studied, so we commonly refer to those as the study phase, maybe no major financial commitments yet, but we've been paid to study those projects. And then around 2 gigawatts of the 4 feel preliminary [indiscernible] what we refer to as, but we have another 3 gigawatts that have come in the door since we talked about the 4 gigawatt number. So really 5 gigawatts are preliminary. And again, another 1 gigawatt is promising and another 1 gigawatt is being studied just to give you kind of an overall look at where we stand.

Your next question comes from the line of Michael Lonegan with Barclays.

So on the RFP, I understand the total resources on the final shortlist may exceed your capacity needs. I was just wondering if you could share specific amount of resource and megawatts you expect to procure. And then on the self build, can you talk about the timing of when the capital will start being spent and the profile of that investment?

Michael, this is Adam. So I think with Slide 12 that we showed you, it shows a resource for 2031. And that resource is the 430-megawatt gas plants actually an advanced simple cycle plan. We have started moving forward with that project. The turbines have been reserved, the EPC contract has been awarded and it was the #1 ring project for that year. I think the project we're really diving deep into right now is the 2032 project that is 432 megawatts, that's a combined cycle plant, that was also the #1 project except in 2032, and we're just evaluating load right now to make sure that, that's the project we're going to go forward with.

In terms of CapEx, it's spread out throughout the years. We obviously have projects in '28, '29, '30, '31 and '32, and we have transition lines that we're building during that period too. So it stayed pretty consistent in terms of the spend One of the things we're noticing now is a lot of times these projects, you have to put CapEx for it a little bit earlier than we used to. So you'll see some of that spend a little bit can be years in advance [indiscernible] projects going into service.

And then that's [indiscernible], I think you alluded to, it could be at the incremental capital could be a 50-50 equity debt. Is that correct?

Yes. This is, Brian. The incremental costs above what's in the plan that's out there now. If you look back at our slides from last quarter, you can see a planned capital forecast. Any expenses above what's in that, we would expect to fund 50-50 debt equity. What I will say is there are exceptions for that. For example, there may be some instances, our customers upfront on the portion of one there may be opportunities for build transfer arrangement put the payment schedule later in the cycle. As Adam mentioned, typically, it's milestone payments, but that's something that's up for discussion as we go through RFP processes.

What I will say is the CapEx forecast you've seen in the past, neither of those 2 plants are in that CapEx forecast. Those would be entirely incremental to what you see if they were to move ahead.

And then lastly for me on Micron Fab 2, just wondering if you could share the status of negotiations and when you expect to sign an ESA. I think you previously said before year-end. So is that still the expectation, something very near term the next couple of months?

Well, we certainly are continuing to work with them, and we feel like it's going well. And certainly, we're hopeful that we'll meet those time lines, and we'll certainly see the filing when we do.

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

Just looking at Slide 12, you've had a continuous flow of new resources. At what point does inventional combined cycle start to make sense to sort of fill in or get slightly better efficiencies.

Well, we certainly would have taken a few of those, if we could have got them by now. But certainly, when you start looking into the 2032 range, I think that's when that's -- what combined cycle.

Yes. Chris, this is Adam. That 2032 project, that's 432 megawatts, that is a combined cycle project.

Okay. Can you qualify the quarter in terms of what the weather benefit look like for the period?

Sure. If I have that. Do you have that, Brian?

Yes. I can give you some indication on that. I mean one of the big drivers, of course, [indiscernible] year-over-year. Q3 was actually pretty decent. So we saw some benefit from that. I think maybe the best way I could give you the indication is weather-normalized sales and you can compare that to the non-normalized sales that are in the 10-Q, but our weather-normalized sales overall were 2.9%. I think a lot of the driver of that. If you think about some of the large loads and special contracts that are coming on, the weather-normalized sales, weather doesn't have as big of an impact on them. But for industrial and special contract combined was 5.8%. And that sales volume, so a pretty significant increase.

And then Lisa mentioned the other side, the revenue side, 27% increase from the large load customers. So on the weather side, timing of precipitation in the second quarter led to some irrigation sales pretty consistent with last year in Q3. But beyond that, it wasn't as weather impacted. If you look at heating and cooling degree days, they were deviated from normal, but not as much year-over-year.

Right. Okay. So Brian, given the dividend payout target, you're sort of continuing a pace what you have been doing certainly what the recent dividend increase was, you start to run up against the bottom of the payout range. Is there a hard target there? Is there a minimum you're willing to get to? Or just sort of what are your thoughts because it's not that far off.

Yes, Chris, I'd say we're not too far off of that now as you look at it. We don't have a concern if for some period of time, we fall below that 50% to 60% dividend target range. In fact, we very well may do so as we reinvest capital in the business rather than pay it out as dividends. What that gives us though is very significant dividend horsepower for the set we do recognize the importance of the dividend, but we also recognize the benefit to our owners of reinvesting the capital. So if we were to fall below, I think we'd get pretty significant support from our shareholders in making that reinvestment.

Okay. The IRP preliminary numbers in terms of load growth have accelerated a little bit. How much of that is a function of some of big items, the big ticket items like Micron 2? And how much of that is -- can you sort of characterize given the higher base where you're seeing that acceleration come from?

Go ahead.

This is Adam, Chris. So the 8.9% that we just showed you does include Fab 1 and Fab 2 of Micron. It includes Meta 1, which we talked about that just went online. It also includes another data center that's been unnamed at this point, so I can't necessarily talk about it. but it has other diverse loads, it includes Perpetual, includes [indiscernible] and Chobani. So that's kind of what makes up that load growth. Obviously, we're seeing a fair amount of residential growth, too. I think it was right around 1% of that growth is residential. We're seeing some irrigation growth. I think over 0.5% of it was irrigation loads. What that does not include that 8.9% does not include for example, with Micron were to move forward with a Fab 3 or diode, which we've talked about before or any other data centers, just to give you a little bit of color on what it does and does not include.

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

Just to try to triangulate the 8.9% IRP loan growth with the 2032 RFP. I mean, in theory, how what does that RFP imply in terms of 2032 needs?

Sorry, I didn't hear that last bit...

So this is Adam. I think we've touched on this just a little bit, but the biggest question on the 2032 is again, that 432-megawatt combined cycle plant. It feels like it's going in that direction, but we still need to kind of look at the load forecast, the few other things, and then we'll make a decision on that front. But to your point, 2032 is likely going to need some resources. But it's going to need something in addition to what we have in '31.

Okay. Got it. And then just given the pipeline, that you discussed earlier and this new IRP? And should we expect like a similar cadence of like annual RFPs even past '32 that we would likely see the past 4 or 5 years. I mean, is there still a lot more load behind, say, Micron Fab 2?

Certainly, I mean, as load continues to come in and we continue to negotiate these ESAs, it is possible, absolutely. And that's been kind of the nice part about our growth story is we are seeing into the with some of these customers. But of course, it will be contingent upon the final negotiations. But yes, I mean, from where we sit, I think it's possible.

[Operator Instructions] Your next question comes from the line of David Arcaro with Morgan Stanley.

This is [indiscernible] for Dave. So starting with the ITC, you now expect to use less than $10 million this year. So looking forward, do you think you could be earning above the minimum ROE in the next few years and no longer be required in the ADITCs?

Well, that will largely depend on sort of the project timing and sort of how the financing plan. But certainly, our goal to use as few as possible, what would you add?

Yes, Alex, just looking at each individual year this year with a number of less than $10 million, if possible to get down to 0 and grow above that would take very strong operating performance in the fourth quarter for that to happen, some of it probably weather-driven. If you look ahead to 2027, one of the things that I've really focused on is just what's happening operationally in 2027 from a plant closing perspective. So you see a lot of quick convert. When that happens, if there's no rate change that will accommodate that at the beginning of the year, then you do end up with the loss of AFUDC and you take on depreciation. That makes it hard to get through 2027 without some ADITC usage.

And then '28, if we filed our rate case in 2027, then '28 would have the benefit of that rate case. Again, you've got quite a bit of plan going into service. But a lot of that's offset by large contract customer revenues. And so that's the analysis we have to look at every year. But as I look at 2027 now, we'll give our forecast for earnings and ADITC usage in February. But my preliminary thoughts are, I do believe we use in 2027.

Got it. Very clear. And then moving to supply chain. You have a large CapEx stand ahead and you have signed more contracts since the last update. So could you comment on where do you see the main supply chain bottlenecks from your perspective? And also how you are preparing to execute on that plan and on the potential incremental CapEx to be announced in the next update? Like how much of that is already procured or on track?

As far as the turbines go, we either have reservation agreements or supply agreement. So we feel really strong about the plan. Of course, there's always the breakers and transformers and conductor that just seems to be it's a challenge, but we get ahead of it. So I feel like we're in a really good spot for those projects. Is there anything you would add, Adam?

No, the only thing maybe is that the EPC contractor market has been tough, too, and we've been really fortunate in that area to be able to award and select EPC contractors for every one of these plants, but one at this point. So that was something we were a little worried about. I think contractors are very interested in our diverse load, and so they've been interested in bidding into these projects, and we've been pleasantly surprised with the variety of contractors we've received and the bids we've received.

Your next question comes from the line of [ Nicholas Woods ] with Bank of America.

Maybe could you just give me a sense which data center loads that were mentioned earlier already included in the demand assumptions underpinning the 2032 RFP?

Yes. This is Adam. So the 2032 RFP would have had just 1 data center, which is Meta 1. So data centers that are looking at us or I mentioned an unnamed data center that we feel pretty confident about those were not included in that load forecast, which I think was based on 2025 IRP.

Got it. And then you mentioned about you guys are running the numbers to see if you guys file a 2027 rate case. When could we expect an update on whether you guys do proceed on doing that or not?

Generally, we kind of look to file in June. We have to give a 60-day notice of intent to file in Idaho. So that's kind of how we're thinking about it when we feel like we'll have a good look at what we have coming at us. So I think that's generally what we're focused on.

Yes, this is Brian. I'll just add that. By the time we hit we have the fourth quarter call, we've done some of our early analysis. It takes long to put a rate case together that we'll at least have some preliminary financials that will give us the ability to make a preliminary call on whether we file a risk case or not. It is, as Lisa mentioned, that notice of filing the definitive moment of that. But we may be able to give a little bit of insight on the Q4 call.

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

Well, thank you, everyone, for joining us today and for your continued interest in IDACORP. I look forward to seeing you all at EEI. And I hope you have a great evening, and I wish you a very Happy Halloween. I hope you get all dark chocolate. Thanks.

This concludes today's call. Thank you for attending. You may now disconnect.

Good afternoon, everyone, and welcome to IDACORP's Second Quarter 2026 Earnings Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP website. [Operator Instructions] 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 things like earnings guidance, spending forecast, 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 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, EVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager. Slide 4 has a summary of our second quarter financial results. IDACORP's diluted earnings per share were $1.79 compared with $1.76 for last year's second quarter. I want to highlight, we didn't record any additional tax credit amortization under the Idaho regulatory mechanism during the second quarter of this year compared with recording $17.2 million in the second quarter of last year.

For the first half of 2026, diluted earnings per share were $3 versus $2.87 in 2025. And those results only include additional tax credit amortization of $6.3 million in the first half of '26 versus $36.5 million in the first half of last year, which showcases the strong performance so far for 2026. Our key operating metrics were raising the lower end of our full year IDACORP diluted earnings per share guidance range by $0.05 to the new range of $6.30 to $6.45. This increase is driven by our strong operational results in the second quarter. It includes our expectation that Idaho Power will use less than $15 million of additional tax credit amortization for the full year which is a reduction from the less than $30 million in our prior guidance. These estimates also assume historically normal weather conditions for the rest of the year. Now I'll turn the call over to Lisa.

Thank you, Amy, and thanks to everyone for joining us today. I'll start with remarks with a look at customer growth. As you can see on Slide 5, we've seen a customer count increase of 2.3% since last year's second quarter with growth across all customer segments. The customer and load growth that we've seen within our service area remains strong, and we're working hard to meet the increased energy demand. As 1 data point, industrial revenues, which includes large contracts, were up a staggering 17% compared with the second quarter of last year. Thanks to years of thoughtful planning and project execution, we started seeing increased revenues from large contract customers in June with more to come in the second half of 2026.

I've been providing updates on Micron's expansion and Meta's new data center during our earnings calls for years, and it's great to see this hard work come to fruition as these projects ramp up. You can see photos at these massive projects on Slide 6, along with pictures of some of our other large contract customers like Chobani and INL. Looking at Slide 7 and 8. were strong advocates that growth has to be sustainable and responsible so that service to our existing customers remains reliable and affordable. We expect that new agreements with large customers will include appropriate take-or-pay provisions, termination payments and certain upfront payments, along with strong credit requirements, just as we've done in the most recent energy service agreements. These elements help ensure that growth pays for growth without shifting cost to other customers, and they help derisk large loads for both our customers and our owners.

One of the main drivers to item Power service area is affordability and keeping prices as low as possible remains a priority. Our retail prices are well below the national average with our average residential price about 30% below national average. I'll also point out that the revenue growth from the large contract customers is a key driver that's helping us stay out of a 2026 general rate case. We'll continue to take this thoughtful approach with our enlarged customer pipeline, which remains strong at multiple gigawatts and as businesses across multiple industries look to operate in our region. Moving to Slide 9. We're full speed ahead, executing on projects to serve our customers and enhance our grid. We recently brought 250 megawatts of new company-owned battery storage online as scheduled, marking our fourth straight year adding batteries to our system.

Since 2023, we've added over 550 megawatts of company-owned batteries. We also completed the conversion of Volme Unit 2 from coal to natural gas last month in time to help us meet peak summer loads. Additionally, a 125-megawatt third-party-owned solar generation project was recently commissioned as part of our Clean Energy Your Way program. These resources support our efforts to add capacity, flexibility and reliable, affordable energy to serve our growing reaches. Turning to Slide 10. I'll provide an update on our 3 major transmission projects. We expect all 3 to come online in the next several years, bringing with them critical system flexibility as well as access to diverse markets and transmission wheeling revenues. Starting with Boardman to Hemingway, work is progressing nicely. As of today, about 70% of the 1,300 structured cats have been completed.

Over 400 towers are built and we've started stringing wire. It's a huge undertaking, and we're pleased with the progress. We'll continue to expect -- we continue to expect 2H to be in service by late 2027. On the Swift North transmission project, we received our CPCN from the Idaho Commission in December, and project construction recently started in Nevada. With such good progress on the project, we expect the line to be completed in 2028. We're also continuing our work with PacifiCorp on the Gateway West transmission project. As we mentioned last quarter, we filed a joint request for a CPCN with the IPUC, and we anticipate a portion of that -- of the segment described in that filing will come online as soon as 2028.

As seen on Slide 11, progress continues towards the construction of 3 company-owned natural gas fuel projects that I've mentioned on previous call. Construction is underway on the first, a 167-megawatt resource next to our existing Bennett Mountain power plant. We secured a CPCN, an air permit and an EPC contract has a scheduled in-service date of 2028. We've also filed CPCNs for the 222-megawatt South Hills project, which is scheduled for operation in 2029 and the 430-megawatt Peregrin project, which is slated for 2030. We continue to work toward procuring the necessary materials and construction services to build these gas plants. These dispatchable projects will help us meet our near-term capacity deficit. Turning to Slide 12. We're in the process of evaluating bids from our 2032 RFP. All bids have been submitted, including several of our own.

At this stage of the process, several of our self-build projects -- self-bid projects remain competitive. And the review team is beginning to narrow the field of contenders. We expect to have a final short list in the third quarter and begin contract negotiations soon thereafter. I'll pose my remarks with an update on the proposed sale of our Oregon distribution system. Over the last few months, we filed applications with the Oregon Commission, the Idaho Commission and FERC, requesting approval of our sale agreement with OTC. These filings are being processed, and we expect the sale to close in the spring of 2022, pending successful regulatory outcomes. So we've been very busy, as you can see. And with that, I'll turn the time over to Brian.

Thanks, Lisa. Hi, everybody. Thanks for joining us today. It's exciting to see all the projects going on right now. recent project execution has been particularly important because it helps serve an 8% quarter-over-quarter increase in industrial loads and we'll do that going forward. That load increase helped drive the 17% increase in industrial revenues that Lisa mentioned. Financial success is linked with operational success. And I think the financial side is just as exciting with strong results for the quarter and the year-to-date benefits from the January 1 rate change and customer growth were certainly evident during the quarter. I'll also mention that irrigation sales were up for the quarter, which is impressive given that Q2 of last year also had favorable weather conditions for irrigation sales. .

This year's relatively heavy April rain didn't dampen quarterly irrigation sales because we later experienced the dry May and June. Aside from the amount or the timing of precipitation can also notably impact the irrigation sales volume. Before I get into details, I want to point out that we added a new line to our quarterly reconciliation table. It shows the financial impact from large contract customers, which I think will be helpful going forward as we see the growing impact of these customer contracts. So when I quote changes from rates or customer growth generally, these exclude large contract customers because those will land on their own new line.

All right. So getting more into the details, let's go to the recon on Slide 13. And from that, you can see that the biggest movement was from higher retail revenues from the January rate increase and from customer growth. Combined, those were a $32 million benefit for the quarter. And year-to-date, it was over $52 million. Per customer usage was essentially flat for the quarter at residential usage declined due to milder temperatures, but higher irrigation usage mostly offset that decline. The fixed cost adjustment mechanism also benefited retail revenues, which resulted from the lower sales for the residential and small commercial customer classes.

On our new line, revenues from our large contract customers increased operating income by $6.5 million for the quarter. As expected, we're now seeing with greater prominence of the revenue and load ramp-up from some of our large contract customers taking shape and we expect to see more of that benefit in the second half of the year. As we expected, O&M expense was almost $12 million higher in the second quarter. Primary drivers were the amortization of previously deferred costs associated with the Jim Bridger plant and our Welfare mediation plan. A large portion of those items will recover in customer rates, though they're also reflected in revenues. Depreciation and amortization expense increased around $5 million for the quarter. No surprise there, given our ongoing infrastructure investments. Other changes in operating revenues and expenses increased operating income by a net $6.3 million, similar to the impact in the first quarter, this benefit resulted primarily from a decrease in net power supply expenses not accrued through the power cost adjustment mechanism. And now it's due to updates to the PCA mechanism based in last year's rate case.

Nonoperating expense increased only marginally with higher AFUDC mostly offsetting higher interest expense. Fairly significant, important from my perspective, Idaho Power didn't record any additional tax credits under the [indiscernible] earnings support mechanism in the second quarter. That was about $17 million less than what we reported in the same quarter last year. from a year-to-date perspective, the roughly $6 million we've recorded for 2026 as compared to over $36 million we recorded at the same time last year. that lower credit usage, even with higher expected book equity this year is really indicative of our financial strength and performance this year.

Our next slide, Slide 14, reiterates what we discussed about CapEx on the fourth quarter call, so it's just for reference. And what you see in that forecast is admittedly already a large amount of capital. But as a reminder, it doesn't include any assumed resources from the 2032 RFP. And relatedly, it also doesn't include resources to serve projects like the Micron Fab 2 facility. And it doesn't include updates from our annual long-term capital budgeting work. So I'll just reiterate, there could be some upside to what's shown. We expect to have more intel for you as we work through the RFP, the low forecast update and our annual capital budgeting process. all 3 of which are currently in progress.

Moving to Slide 15. In the second quarter, we executed around $260 million of additional forward sale agreements through our current ATM program. We're showing on there around $2 billion of equity content that we need to fund our business for the next 5 years under the current plan. We've either issued or we've sold on forward about $1 billion already. So we've solved for roughly half of our current plans equity needs. We have the equity we need into 2027, and we think the remaining amount in the current plan is within ATM ranges. I'll reiterate that any additional CapEx would require some additional debt and equity. We still plan to blend debt and equity on a roughly equal basis, bring incremental CapEx with the goal of keeping our balance sheet strong.

Slide 16, I helped to summarize the 4 sale agreements that we have available and the forwards that we've settled to date. As you can see, we have a balance of about $715 million of forwards available for settlement. I don't have a slide on it, but I think operating cash flow [indiscernible] to mention, given the deviation from this time last year. It looks low this year on a comparative basis, but it's important to note that much of the deviation is due to timing including balances of items, like accounts receivable and payable, prepayments and the PCA mechanism. One last note for me, the Idaho Commission recently issued an order in our request for a prudence determination related to our health can and relicensing efforts.

The commission in that case, determines that our project expenditures from the start of 2016 through year-end 2025 were prudently incurred and rendering the eligible for inclusion in retail rates and future regulatory proceedings we're pleased with the outcome of that case in part because, as many of you know, we pride ourselves on being prudent spenders at the company. I'm going to wrap up there. I'm going to hand it over to everyone's favorite IR celebrity, John Wonderlick.

Thanks, Brian. Turning to Slide 17, you can see our 2026 full year earnings guidance and key operating metrics. We've had some solid improvement in our earnings and ADITC guidance. As usual, we assume normal weather for the remainder of 2026 for our guidance. With strong operating performance in the first half of the year, we now expect IDACORP's diluted earnings per share this year to be in the range of $6.30 to $6.45. We lifted the bottom end of the range. We also see solid improvement in our ADITC expectation, so we're cutting our guidance in half. We now expect that Idaho Power will use less than $15 million of additional investment tax credit amortization in 2026, which is much less than the $40 million we amortized for the full year 2025, especially when considering the significant increase in year-end book equity, as Brian noted.

We continue to expect full year O&M expense to be in the range of $525 million to $535 million. and we still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026, though at this point, it's fair to say we're trending to the high end of that range. Finally, given our current forecast of hydro power operating conditions, we expect hydropower in the range of 5.5 megawatt hours we trimmed 0.5 million megawatt hours off the top end of our guidance as dry conditions returned in May and June. With that, we're happy to address questions you might have.

We're now ready to begin the question-and-answer session for attendees who have joined on the Q&A line. [Operator Instructions] Your first question comes from the line of Shar Pourreza with Wells Fargo Securities. .

This is Whitney Mutalemwa, on for Shar. On resources, you've got 250 megawatts of batteries now in service, you have a number of applications in front of the commission. Is that pace roughly a project every few months sustainable? Or does it get harder to keep up as the Q growth? And a follow-up would be with all the battery storage going in for Micron, meta and the rest of the pipeline is gas plus batteries, the whole long-term answer? Or are you also looking at things like SMRs further out?

Yes. So great question. So I'll start, and I'll have Adam give some more detail. Certainly, when we're looking at what we are going to need to serve our load, we go through exercise of the IRP, the integrated resource plan. So we're really looking for the least cost, least risk answer. So we have a total of 550 megawatts of batteries, but no, that's not the answer to everything. That fits kind of -- it's great energy that will sort of fill in when the solar energy starts to diminish as the sunset, so it's a great resource for the summer, but it's not a great source for the winter and certain -- just because of shorter days and -- and so we don't get a chance to refill the battery before we need them again and they last for 4 hours.

So some of the operating characteristics just make it so that it's a great energy resource, but it doesn't -- we don't really consider it a real capacity resource more than those first 4 hours. So an absolute sprint to keep up with this growing load and getting the resources online and in time. And so we've mentioned our pipeline before. That continues to be evaluated as we go on beyond what we've shown here. So I think Adam, do you want...

Thanks for the question, Whitney, happy to walk you through kind of year-by-year, how we're looking. In 2027, it's largely batteries in solar. We have a fair amount of that price 400-ish, 500 megawatts of solar another 100 megawatts of batteries. From that point, it does go turn a little more on the gas side. 2028, we talked about it listener comments. We have been to 2029. We have South Hills, which is also a gas project, 222 megawatts in 2030, we have a project called Permian, which is also gas, 430 megawatts, and then Idaho Power's origination team for 2031 and 2032. We've been in 8 projects, 6 of them were gas projects, 2 of them were storage projects. So that should help give you at least a little bit of a mix of where we're at in terms of gas versus storage versus solar in the next several years.

In terms of SMRs, we spent a fair amount of time of learning about these new technologies. I'm on the customer advisory committee for 1 of the key technologies and companies. We spent a fair amount of time with I&L, and we've met, I would say, with most of the key developers in that space, our summary is that we like the SMR technology. At this time, we don't love the pricing which, as you probably know, is likely over $150 a megawatt hour at this point. So again, we like SMRs, but we're probably not going to be the first, and we're probably not going to be the last to look at them, and we'll continue to keep an eye and evaluate those technologies over the next several years.

And the timing also when they would be available. .

And of course, in addition to the CapEx and the generation projects, I mentioned, Lisa and her comments also mentioned B2H. We're making great progress there. Southwest intertie project broke ground recently, which is just a great milestone there. And of course, Gateway West to which we're looking to work on and construct over the next several years. So it's always good to point out this the transmission is a big part of our plan as well. Kind of the generation mix of the transmission is what makes it all work out together. .

All right. That sounds good. And then just if I could squeeze in a tiny question. on wildfire mitigation, obviously not trying to get ahead of the Mountain Home investigation, such as early, but you've just gotten the 2026 wildfire mitigation plan approved right before this happens, doesn't incident like this change anything about how you're implementing it? Or is it too soon to say? How are you seeing the plan to put into practice? .

Yes. So you're right, we do have a mitigation plan, and we do have -- it is now the Standard of Care Act here in Idaho applies to that mitigation plan. So certainly, the wildfire was impactful to that community, and we worked really hard to make sure that we are there for that community to help them get back on their feet and repair replace what was lost. But it was a relatively small fire. And when it's all said and done, it will not be a material impact to our company, but we are taking it very seriously. So I wouldn't say that we are changing anything about our plan. We certainly continue to implement it. That is the key focus that it's 1 thing to write the plan. It's quite another to make sure that we are following it. And in this case, it actually was followed. I mean, we felt really good about the implementation of that plan. So I think that's probably about all we have to say about that.

Your next question comes from the line of Michael Lonegan with Barclays.

So on Micron 2, just wondering if you could share the status of negotiations and when you expect to sign an ESA. And then anything you could share regarding the size of that investment, that could be added to your planning. Could this be a Q3 update when you update your [indiscernible] forecast? .

Well, those are often confidential. So we have to rely on our customer as to whether or not they want to make that public. I will say that the negotiations are very active. Adam, do you have any details on .

Yes, we're progressing well -- just in terms of the site, a ton of work is going on. It's amazing to see what a $50 billion site looks like, and they have started ground preparations on [indiscernible] are in ESA discussions. But as Lisa mentioned, those are confidential, so we can't really speak to those. In terms of the CapEx side and Brian can speak to this, but Fab 2 is not in the 8.3% IRP CAGR that we've shown. So it's outside of that as well in terms of spend.

Yes. Just to add on to what Adam said. Most of our CapEx that you see in the slides was premised on the 2015 iblow-growth rate, the 8.3% that we mentioned 2025, yes. Thank you. So it excludes customers like Fab 2, along with several other promising loads, as we call them that we're working with right now. And those incremental loads all generate additional capacity and energy needs with some of our related spending for the infrastructure -- power infrastructure related to that occurring pretty urgently, I'd say, in our 5-year window, not all of it on the outside of that window. So while the 2025 [indiscernible] point, we're tasked with serving load as it materializes. So the in-process transmission lines and the outcomes of the 2032 RFP will all be part of how we solve that low growth that materializes that will end up getting reflected in our CapEx refresh and also a low growth update that we'll do for the 2027 IRP. .

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

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

Yes. Michael, this is Brian. I think from the financial side, what we look at is that you've got large load revenues on 1 side that certainly are helpful. The other side of the equation, though, is plant that goes into service. right. So in 2026 and in 2027, we expect quite a bit of our quip to convert to plant in service. If you look at the balance sheet now, over $1.8 billion of Quip. So there's a lot that sits there as of today. When that converts plant and service, obviously, depreciation starts and the DC stop. So we get into a situation where we do the evaluation of keeping in mind things like cash flow, affordability for customers, all of those attributes whether or not we file a rate case.

So we'll have to do that math pretty early in 2027 as we look as to whether or not we'll file a rate case. As Lisa mentioned, it's looking relatively probable at this point. But again, we're in somewhat of a what I call an envious position compared to prior years where we have to do the math on that every year. That's beneficial. We did it this year and decided we didn't have to file a rate case. -- in large part because of those large customer revenues that are coming in for the company. The other thing just on the tracker component, if you file relatively frequent general rate cases because you have so much plant converting, the tracker doesn't have as much value. You also have to be careful that a tracker wouldn't be shifting costs to customers that aren't driving the expense. And so the tracker would have to be structured in a way that -- to the extent it applies to residential customers, it would be for the projects that are benefiting the residential customers, not the large load growth customers. So we're very cognizant of that when we think about the types of mechanisms that we use on the regulatory side.

And then obviously, you're using less of the ADITC. So presumably, your earned ROEs are higher than you expected. With all the large loads coming in, how do you see the earnest trending over the forecast period? Is there a chance you earn above your allowed? Or any -- obviously, you don't give long-term EPS growth guidance, but anything you could share on earned or lease? .

Sure. I mean it's a projection that we do all the time in our forecasting. There's a possibility that, that occurs. But I think the thing to look at is the amount of depreciation and interest expense that we have to overcome in any given year. given a historic or hybrid test year that we have in Idaho. So while it's possible, those revenues could be large enough to overearn in some years. I'd say in the near term, that's less likely just given the construction cycle that we're in. That said, you've seen us reduce our ADITC expectations for the year already this year, and they're significantly lower than last year. So things like weather conditions or outperformance on large load expectations compared to what we have in our forecast, certainly drive us more towards over earnings certainly the base level for the ADITC mechanism and then potentially even up from there. .

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

Brian, thanks for that new line, that's helpful. In terms of the large customer load ramp, can we just think about that similarly to retail in its seasonality based on your temperatures?

I wouldn't look at it that way, Chris, because while residential and some of the small commercial can be pretty sensitive to weather conditions, the industrial loads themselves are not. They tend to be driven more by what sort of equipment is installed and turned on at any given point. You can see Micron's load ramp in their special contract. You'd see that there's step-up. They're certainly not linear. But there are take-or-pay obligations in that. They don't reflect seasonality necessarily. And then if you look at things like data centers, their ramp-ups can be premised on what server racks are installed and when they're turned on. .

So I wouldn't look at it that way. One thing I would note is if you think about that line that we added really only have 1 month of Micron revenues in there for Fab 1, and then you do see some of the meta ramp-up reflected in there. But a lot of that is early stages, and we'd expect to see that more of a steady ramp up over the second half of this year.

Right. Yes, I was really not the timing of incremental on for these customers, but in terms of their cooling requirements -- is there seasonality to the usage portion once something is online?

We haven't really forecasted that way. We look at more of a steady state from equipment operation, not from a cooling system, though it is possible in some of the hotter summer months, there could be incremental load from cooling systems.

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

Not much. I mean, we have anecdotal evidence that July was a little warm for us. But in general, we covered off at the end of the quarter and then just predict normal weather conditions for the remainder of the year. So it does turn out to be hotter than we expect there to be some incremental benefit there.

Okay. Is there any rationale for you guys to use any parent leverage as you get into really heavy spend?

We talk about that from time to time. One thing we have to watch for on that is credit rating implications of that, that the credit rating agencies have complemented us as have many of our investors on the fact that we don't have holding company debt. When we go to market at Idaho Power for debt, we tend to be very well received. So our regular way financing approach has been successful for us in terms of interest rates and otherwise, just interested in the marketplace. So our preference is for that relatively simple balance sheet. When you start adding holding company debt, you do add some complications, some regulatory items that we have to address and otherwise.

So we've really focused a lot on regular way financing, of course, through our equity transaction at IDACORP, but in terms of hybrids, mandatory convertibles. I would say those are not something that we've taken off the table, but it's not our go to when we think about the structure of our balance sheet. The other thing I mentioned is there are other ways for us to address a large contract needs for EDCs and our generation resources and are just big CapEx build-out. And we've done some of those. It's things like requiring payments from some of the customers upfront for some of this, so we have other mechanisms in place that we use, but we did an exercise recently where we laid everything out on a piece of paper in terms of what all of our options are, and we have the lure of being able to select them based on ranked priority. So in a really good spot from my perspective on keeping the balance sheet healthy without unnecessary complication.

Great. That helps. One last thing regarding the SMR discussion was useful. Pricing has been rising for these large load customers pretty much across regions. And there's some, I'd say, price and sensitivity, it seems. While SMRs might be price today as time goes by a lot of things will happen in the next decade. But does pricing necessarily matter in the grand scheme of things if electricity markets are very constrained and some of these tech firms really are just constrained by electricity. Do you think the $150 a megawatt hour ultimately might make sense for that customer class.

I think that's entirely possible, Chris. I mean it's just -- I couldn't have forecasted what's happening to us right now 5 years ago or 10 years ago, but I think the bigger constraint right now is just the commercial availability because I don't even know if the $150 million is a price that you could actually go by 1/4. So I think there's a little bit of TBD on when they're going to be available and what price. But your question being, will there be a time where some customers will pay any price, maybe. I don't know. I do find though that when we are negotiating with them, it turns out price does matter still. So I think we'll have to wait and see on what happens in the future. .

Your next question comes from the line of Julian Dumoulin-Smith with Jefferies.

Brian, on for Dumoulin. [indiscernible] is it still 200 megawatts for 31 and then greater than 200 megawatts for '32 or could it possibly incorporate some of the incremental load that Micron Fab 2 might need as you move through the year, potentially signed an ESA.

Yes, Brian, this is Adam. That 200 megawatts was, first of all, it's a perfect capacity, so as opposed to kind of renewable capacity, but it really was the minimum from our standpoint. We used 2013 -- excuse me, '25 IRP to develop that number. And since then, obviously, we've had large loads come in and change what our outlook is. So we anticipate probably having to go a little bit higher than that in terms of how high and we'll have to see how the forecasts come in, which I think we'll be providing to you all a November time frame. .

Okay. So that scenario excludes any Micron Fab 2 capacity. In theory, you issue another RFP for, I guess, incremental capacity when the time .

It's a good question, Brian. At that point, we I mean we have a fair amount of projects. We're going to have a short list, so we're going to be able to work through that short list. And we may issue an RFP for 2033, but for Fab 2, we would probably just increase the amount of resources we would either build or purchase through the 2032, 2031 IRP.

I see, and that's where the 6 gas projects -- the 6 gas projects of self-build in the current RFP might accomplish that?

Correct. Yes. We had 8 overall projects that we've been in 6 of our forecasts. But of course, other entities bidding projects, too. So we were pretty pleased with the way the results are looking. And I think we will have a short list here available in the next month or so, and we'll be able to talk about whether the Idaho power projects made that short list or not. But at this time, we feel really good about the projects we've been in. They're competitive from our standpoint, and so we'll see how they compete in the RFP. .

Your next question comes from the line of Alex Kania with BTIG. .

I apologize, I probably should look at for this in the Q. But just what's the current aided balance on the balance sheet as of June 30.

It's about $156 million as of June 30, and then we'll ask some incremental credits this year through battery storage assets that we install and all [indiscernible] state ITCs that will be added to the mechanism. .

Okay. So then I'm just kind of putting -- trying to triangulate this with the -- maybe with the rate case strategy as well. So I mean, is it kind of reasonable to think I'm just kind of spit balling a little bit here that to the extent that you've got quip that's entering kind of rate base as it were, depreciation goes up. But again, kind of noncash, it feels like maybe the [indiscernible] mechanism could help offset some of that. But then maybe if you're thinking about kind of more of the cash expenses such as interest that those may be things that, again, would be kind of for the call for rate cases. And I'm just trying to think about this from a rate case perspective is just how important that is that aided balance that and how much flexibility can that add in terms of your timing call on the rate case?

Yes, Alex, it's a great point. I mean that's 1 of the factors that we consider in deciding whether or not to file a rate case is the ADITC mechanism and how many credits we feel we may need to use the evaluation we'll do under this 1 is for 2028, right? And so we'll be looking at what are large to revenues in 2028. Would we need to use the ADITC mechanism to cover what we might otherwise get from a rate case to cover depreciation and interest expense and the return on some of those assets. I mean a lot of those assets are in service, serving customers, but we're not recovering anything on those.

So in that case, we may decide to file the rate case depending on how that math turns out. The other thing is in the last rate case we did, we imposed a CAP in the settlement of $55 million per year on ADITCs, and so we look at where we might be relative to that threshold level in determining whether or not to file a rate case.

Great. Okay. I appreciate that. And then maybe just 1 follow-up question just on trying to think of the updates on the RFP and kind of better sense of what the generation resources might end up panning out to be, which I think for the previous question we might know within the next month or so. And then is that going to come out maybe before we even get kind of the full details, I guess, just in terms of what the demand outlook ends up being under the updated IRP, which if I'm getting this right, may end up getting released a little bit later? Just trying to think about kind of the kids on timing here. for those outlooks?

Yes, Alex, this is Adam. The RFP results have come out here, we'll say, in the next month or so and then the new forecast related to the new IRP I think, would be released to you all right around November. Is that right, Brian?

That's about right. That's the time that we have to have our new forecast established. You eventually have to lock it down for purposes of 27 IRPs. So we'd have to have that end of October, early November under our normal IRP process. The thing that I'll mention, though, is things change over time. So while we'll have results from the 2032 RFP, if there's incremental load that shows up even beyond the forecast, we included in our IRP, some of those resources depending that are on the short list, depending on the timing, we may pull more of those resources than we originally thought in terms of implementing resources from the list or if their online dates are further out, then you start doing what Adam mentioned, which could be a 2032 or later RFP for some of the incremental growth.

So again, the IRP is a point in time, but we have to serve load as it materializes and that requires a lot of preplanning, so we're certainly doing pre flatting around those loads already.

Yes. It's just a great point. And I think we talk a lot about our pipeline. As though it seems like it's the static number, but it is a tremendous amount of activity of resources and loads that sort of go into construction like Micron that's no longer in the pipeline, but there's another tranche of new requests that fill that space that was in the pipeline. So there is -- it's really, really active. So it's changing all the time, and we have to do the analysis to the extent those customers want to go forward with those construction, construction agreements or analysis. So it's a tremendous amount of work, exciting times for sure.

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

[Operator Instructions] That concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

Thank you to everyone for joining us today and for your continued interest in IDACORP. It's always great to hear from you. So I hope you all have a great evening, and we will see you all soon. Thank you.

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

[Audio gap] Mike Kennedy, Scott Madison, Karen Miller, Susan Morris and Dr. Mark Peters. All of our directors and nominees with the exception of myself qualify as independent directors. All of the current directors have been nominated for reelection at today's annual meeting, and we have one new nominee as candidate for our Board, Sharon Miller. Sharon recently retired as President North America of Lamb Weston. She brings a wealth of global business sales, customer operations and supply chain insights to our Board, along with strong ties to Idaho Power service area. Information on each director and nominee can be found in the proxy statement for this annual meeting.

Before I move on, I'd also like to recognize our officer team. Their leadership and service make us the successful organization we are today. Their impressive and varied biographies are on the IDACORP website. We have an outstanding leadership team that is excited about our business and committed to serving our customers, employees and you, our owners.

For today's meeting, we'll start with the formal business, and then Brian Buckham and I will provide additional comments about our company. We'll end with a Q&A session. And of course, our management team welcomes questions from our owners outside of this meeting as well. Today's presentation contains forward-looking statements that relate to future events or expectations. I'd like to remind everyone that the company's future results could differ from those discussed at this meeting. Factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission, including our 10-K and 10-Q reports. I encourage you to review those documents, other documents we file with the SEC and our press releases for material information about our company.

It is now my pleasure to officially call the 2026 Annual Meeting of IDACORP shareowners to order. The annual meeting is being held to address three items: To elect 10 directors for a 1-year term, to address an advisory resolution to approve executive compensation, and to ratify the appointment of Deloitte & Touche as our independent registered public accounting firm for 2026.

IDACORP has approximately 139,000 shareowners located throughout the United States and internationally. The results of shareowner voting for the annual meeting are typically determined by the return of proxies from shareowners who are not present, and we have those results today.

Before moving on, there are a few administrative matters that need to be addressed. First, a majority of the shareowners voting power outstanding is represented at this meeting by proxy. Consequently, we have a quorum. Second, in accordance with the IDACORP bylaws, no matters other than those stated in the proxy statement or that have been properly raised by a shareowner in advance can be considered at this meeting. Finally, if you have not already voted your shares, you may do so now by following the voting instructions provided in the virtual meeting e-mail sent to you this morning.

The first item of formal business is the election of directors. 10 director nominees are up for election at this meeting. All 10 have been nominated for 1-year terms to expire at the 2027 Annual Meeting. The second order of business is the advisory resolution to approve executive compensation commonly referred to as the say-on-pay vote. The third order of business is to ratify the appointment of Deloitte & Touche as IDACORP's independent registered public accounting firm for 2026. The company's Board of Directors has unanimously recommended a vote for each of these proposals.

The IDACORP proxy holders have voted all shares represented by proxy as submitted on all three matters. Based on the proxies, the preliminary results of voting indicate that each of the 10 director nominees named in the proxy statement has been elected for a 1-year term, and all proposals have passed. At this time, the voting has now closed.

This concludes all items scheduled for action at this annual meeting. The business portion of the meeting is now adjourned.

As we move to the informal portion of the meeting, I'd like to start by thanking our employees for the great work they did during an especially busy and exciting year for IDACORP and Idaho Power. Their dedicated service continues to drive strong results for our customers and our owners. During 2025, our company produced its 18th consecutive year of earnings per share growth, sold a record amount of energy to customers, broke ground on the Boardman to Hemingway Transmission Project and achieved the best reliability scores in Idaho Power's history. I'm so impressed with the incredible work our team is doing to help build a secure energy future for our company and our customers.

Customer growth remains strong for Idaho Power. Our customer base grew by 2.3% in 2025. We now serve more than 660,000 customers and a population of more than 1.4 million. The growth across our region is robust, and it's happening across most customer classes, spurred by extensive residential, commercial and industrial construction. We expect this growth to remain strong as our local economy continues to outperform national trends.

Notable large customer projects are making significant progress. Micron's new semiconductor facility is advancing towards completion, and we're also working through the details of Micron's second fabrication facility announced last year. Meta's Data Center has reached the testing and commissioning stage. We're starting to see loads and revenues increase from these projects, which will continue throughout this year.

Idaho Power brought several additional industrial projects online in 2025, including the new Tractor Supply distribution warehouse and a major expansion of Chobani in yogurt production facility. We continue to see steady interest from many of our core industries of food processing, manufacturing, distribution and warehousing as well as inquiries from other energy-intensive customers looking to operate within our service area. We work closely with prospective customers to set realistic time lines to meet their energy needs while ensuring they are not shifting costs to other customers. As we serve one of the fastest-growing areas in the nation, we're doing it thoughtfully to ensure that growth pays for growth.

As we work to meet growing energy needs, affordability remains a top priority. We work hard to keep our costs down and provide exceptional value for our customers, and our rates remain 20% to 30% lower than the national average. Our rates are also increasing at a slower pace than many other utilities, 23% over the past decade compared to 41% nationally. Our price history also compares favorably to the consumer price index, which has gone up 36% over the same period.

The benefits of our low-cost system and hydro generation, in particular, helped with our affordability focus. We also work with our regulators to help keep rates low. Our 2025 general rate case in Idaho reached a constructive outcome via a settlement. The new rates are helping us to recover costs to support our operations, and based on current projections, we are not planning to file a general rate case in 2026. We are full speed ahead on the major transmission projects we are building to serve our customers. After breaking ground on B2H last year, 260 towers have been completed, representing about 20% of the towers for the project.

In addition, we have completed nearly half the access roads and structure pads for the project. We expect B2H to be in service by late 2027, and we're excited to add this important transmission resource to our system. Permitting is nearly complete on the SWIP-North transmission project, and we expect construction on that line to begin this year. We anticipate SWIP-North will be done as early as 2028. We're also working with PacifiCorp on the Gateway West Transmission project. We anticipate a critical section of that line between our Hemingway and midpoint substations will come online as early as 2028.

Permitting transmission lines takes a lot of time and effort, and I want to recognize the great work that teams across our company have done to move these projects forward. We continue to add generation and storage resources that will help us maintain excellent reliability as demand grows. In 2025, the 200-megawatt Pleasant Valley Solar project came online as part of our Clean Energy Your Way program, and we added 230 megawatts of battery storage to Idaho Power's resource portfolio. We are adding another 250 megawatts of batteries and 125 megawatts of solar this year. Both of those projects are nearly complete.

Idaho Power has announced plans to construct 167 megawatts of natural gas fuel generating capacity next to the existing Bennett Mountain Power Plant, which is slated to be online in 2028. We're proud this company-owned project was the most cost-effective resource in the RFP. We're also working hard to solve the generation needs in 2029 and 2030, and we're working to procure additional resources to solve those deficits.

We filed CPCN for two additional natural gas plants. We plan to bring the 222-megawatt South Hills project online in 2029 and the 430-megawatt Paragon Project is slated for operation in 2030. Both units of the Valmy plant have been converted from coal to natural gas and are ready for our summer peak this year. This February, Idaho Power entered into an agreement with the Oregon Trail Electric Cooperative for the sale of our distribution system with some transmission assets in Oregon. If the transaction is approved, we would have no regulated retail operations in Oregon, so we provide power to OTEC for some time under a power purchase agreement.

Base purchase price is $154 million, and the deal is subject to approval from state and federal regulators. Oregon represents a small portion of our service area, projected to be less than 3% of total sales by 2030. We're confident OTEC will provide a strong local focus and dedicated service for Eastern Oregon, while Idaho Power concentrates on supporting our rapidly growing Idaho community. While Idaho Power would no longer directly serve the Oregon customers, we would retain ownership of our Oregon generation facilities and most of our Oregon transmission, including B2H. We're working closely with OTEC to prepare for a smooth transition.

I will now turn the time over to Brian for a financial update.

Hi, thanks, Lisa. We spent a lot of time talking about the financial side of the company on our recent earnings call. So I'll be brief in my comments today on that. I'll start by pointing out that we had another strong year in 2025. We achieved the unprecedented 18th consecutive year of earnings growth that Lisa mentioned earlier. The customer growth, constructive regulatory outcomes and our Idaho earnings support mechanism have all helped the company continue this impressive trend, all while maintaining affordability for our customers. We just spoke about what we're doing on the operational side to address growth and the continued reliability of our system.

On the financial side, we're working in parallel, executing our plan to finance and earn our return on the investments that we're making. On the fourth quarter earnings call, we noted that we're forecasting spending around $1.4 billion per year on average over the next 5 years and a total 5-year CapEx plan of $7 billion. As was the case last year, we're again doubling our average annual spend compared to the past 5 years. In fact, our 2026 to 2030 forecast is a 26% increase in CapEx compared to our prior 2025 to 2029 forecast of CapEx. And I note that there's still potential upside to the forecast. It depends on the outcome of our latest RFP and potential resource needs from prospective incremental industrial projects.

Financing and building, the needed infrastructure is just one element of our execution. We also have to convert it to rate base to keep the utility financially healthy and to provide returns to the debt and equity holders that are funding our growth. Coming out of our most recent Idaho case, our rate base at the end of 2025 was about $5.3 billion. And a similar story to last year, we estimate rate base more than doubling over the next 5 years, increasing to around $11 billion by the end of 2030.

That will require us to be thoughtful about frequent regulatory actions and also balancing the financial needs of the company and customer affordability. As we look ahead to funding our growth, we have a strong balance sheet, and we intend to keep it that way through this growth cycle with an average 50-50 debt equity capital ratio target as of now. The external financing, we noted on our fourth quarter call, we estimate we need for 2026 to 2030. Just for the capital that we have in the plan as of right now is about $2 billion in equity, about $2.9 billion in debt today at that ratio.

We already executed or settled on forward sale agreements on around plus $750 million of that equity need as of the end of the first quarter. So we're well on our way to executing on the plan. I want to reiterate something else Lisa mentioned, as we progress through the growth cycle, we're remaining focused on maintaining affordability for our customers.

Our approach to contracting with new large industrial projects is focused on protecting the existing customers and our shareholders from potential negative financial impact as well as being transparent and responsive to the new customers. Customer growth in the denominator of our regulatory equation helped to absorb what might otherwise be larger rate increases for our existing customers. And we're fortunate that the Idaho regulatory process has a growth-pays-for-growth methodology. This year and more so next year, we anticipate some notable industrial revenue growth, and that's a large part of why we're not planning to file a rate case this year.

It demonstrates that the growth-pays-for-growth construct in Idaho works. As we've noted in the past, when we continue to believe IDACORP is among the leading earnings growth and earnings quality profiles in the industry. We have a demonstrated CapEx needs for our growing customer base. We have a path to affordable conversion to rate base and earnings. Our commitment is that we'll keep focusing on solid execution.

I'll close with a quick note on our dividend, which increased 2.3% last year, that was our 14th consecutive year with dividend increase with cumulative growth of 193% during that span. We're proud our company has paid a dividend every quarter since 1944.

And with that, I'll turn the presentation back over to Lisa.

Thank you, Brian. As we conclude, I want to reiterate my thanks to our outstanding employees and leadership team. These are exciting, challenging times in the energy industry and thankfully, this is where we thrive. IDACORP and Idaho Power are committed to balancing safe, reliable energy with affordable prices as we grow. Our employees are dedicated to our core values with safety first, integrity always and respect for all as we work to support the communities we serve, the environment we share and the places we call home. Their hard work and innovation -- innovative problem solving continues to drive strong results for our company, our customers and our owners.

Thank you for your continued trust in IDACORP as an investment, and thank you for joining us for this annual meeting.

With that, we're ready to begin the question-and-answer session. You should see a QA icon near the bottom of the webcast screen. You can click that and submit a question, and we'll take as many questions as time permits on a first come basis.

So we'll start with a question about really the growth-pays-for-growth methodology, just given the increase of all these big data centers and big loads, what is that doing to rates for customers?

And again, in Idaho, we actually are very careful. We've talked about that in our comments. We want to make sure that there isn't the cost shift and our regulator requires us to conduct a no-harm analysis when we submit the energy services agreements for approval. So as Brian mentioned, that is showing that it works. And that the costs are being appropriately directed to who's causing the cost. And so we're -- we feel really good about that.

Another question -- there's a couple of questions sort of asking about what's going on in the Middle East, and how is that affecting our business and our plans?

And certainly, in general, inflation and some of the supply chain constraints have impacted us over the past few years, not just the Iran conflict. So we've been sharing that in our quarterly calls and update. It is worth noting, though, that we have a very large fleet of vehicles because we drive 10 million miles a year. But certainly, we're seeing the increased cost in O&M there, just from the increased gas prices as an example.

Another couple of questions are really asking about our portfolio, our generation portfolio, our clean energy goal and just sort of how we're navigating through this large load -- large growth cycle?

So it is true that we set a goal for -- to be 100% clean into 2045, but it's a goal, and it's an aspirational goal. And we have said all along that we would really need technology to produce resources that we could afford that are commercially available and at competitive prices to reach that goal. And again, we set that goal prior to this growth cycle. We still -- our primary business goal is our obligation to serve. So we have to serve this load, and we have to do it in a way that is safe, reliable and affordable, and clean, if we can manage the first three first. It has to be in that order. So we are working through all of that. And as we work through our IRP, that is where we look at the portfolio, and we produce the least cost least risk portfolio, and that is what binds our decision making.

And right now, gas is about the only thing that you can build in the time frames we need that have the operating characteristics that -- to serve this load reliably. So it isn't -- we continue through the IRP process to model a 100% clean portfolio. The world has changed a lot. And so we are still navigating through it. And we will continue to still look at it, and we're hopeful that things like SMRs or hydrogen or some other fuel cells, something will show up that would be able to -- we could add to our portfolio so that we can continue to serve in a safe, reliable, affordable way. So it isn't that we're backtracking. It's just simply that we're moving forward and adapting to the world we live in. So -- and we will continue to do so.

So I think that pretty much closes out the questions that that are -- we've seen so far. So I think with that, I will say thank you again for attending the annual meeting and for your questions, and we appreciate your investment in IDACORP, and we look forward to connecting again at future annual meetings. And hope you have a great day. Thank you.

All right. Thank you, everyone.

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. [Operator Instructions] 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 will reference during today's call are available on IDACORP's website. As noted on Slide 2, our discussion today includes forward-looking statements, including things with earnings guidance, spending forecast, 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 with the Securities and Exchange Commission. As shown on Slide 3, also presenting today, we have Lisa Grow, President and CEO; Brian Buckham, EVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager. Slide 4 for a summary of our first quarter financial results. IDACORP'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 hydro power generation forecast as we reduced the top end of the range.

We're reaffirming our full year 2026 IDACORP's earnings guidance estimate 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'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 5. 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 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'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 base 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 7, our approach to contracting with new large industrial projects is focused on protecting both existing customers and shareholders from potential negative financial impact as well as being transparent and responsive to the new customers. We provide clarity in how we will serve the new load, including time lines, rates and other terms. We've 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 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 pace 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 1 change. It established a deadline of 9 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're unlikely to file one at all this year. While we're seeing higher depreciation and interest expense associated with growth in 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 continued to benefit from careful and thoughtful spending.

As we move towards summer and moving to Slide 9, 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 3 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 to 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 the September in Idaho, and we expect to port to be complete as early as 2028. We're 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 3 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 plant that will be -- 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 4 CPCNs in Idaho for 2 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 Paragon 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'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 Valmy 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 of 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. A lot 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.

IDACORP'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 results of particularly mild weather that reduced residential and commercial usage. Keying off 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. Now it's 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 FDA 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 welter 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'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. Depreciation 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 based from last year's rate case that were not unlike the changes to the FCA basis.

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 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 you, 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 1 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/or does it include some of the projects that often till the last 2 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 at around $2 billion in equity and $2.9 billion in debt to stay near our target 50-50 capital ratio. What we've updated it 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 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 forward 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 of years ago, and we've not 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 5-year forecast, where operating cash flow should also be higher to offset financing needs in part.

I threw 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 Wonderlich.

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 million to $535 million. We still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026.

As the 5-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 7.0 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 snow melt. Record wet April conditions with more than 3x the average precipitation for the Boise area has helped to increase spring season stream flows and hydropower production but will not completely offset the lack of winter snow head. With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question comes from the line of David Arcaro from Morgan Stanley.

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, June 2027 in terms of when a full rate case might be possible? Or how are you characterizing that?

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

Yes, David, a couple of factors we're looking at just following on Lisa's comments. One is the conversion of equipped 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 largely revenues, timing of those coming in and the magnitude of those revenues, those can both dictate timing of rate cases.

Yes. Got it. 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 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, perhaps it could go a little bit towards the end of that time period. But we're seeing a 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. But Adam?

Yes, 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, base 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 at 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 far, so good, but it's a constant effort, and we're continuing to focus on it really every day. .

Your next question comes from the line of Shar Pourreza from Wells Fargo.

It's actually Whitney Mutalemwa on for Shar. So obviously, as we're thinking about freight case cadence, we're also thinking about the credit outlook. So time back, Moody's downgraded holdco to BAA3 as well as Idaho Power -- so it cited heavier CapEx cycle on just weaker near-term credit metrics, but it also acknowledge 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 improve it credit positioning as recovery cadence catches up with spend?

Yes. Whitney, thanks for the question. This is Brian. So in terms of where the credit metrics stand right now, we don't issue debt at the holding company level. I mean we do all of those debt transactions at the OpCo level. And so the move to Idaho Power or BAA2, part of the rationale for that was just when you look at 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 preworking 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%, 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 OpCo level. And so Moody's report had some of the details on that. But just from my perspective, if there was a lot of peer benchmarking that went into that decision. So perhaps the downgrade isn't a surprise in that regard, but that negative watch covered out there for quite a while. The new part of the upside of that is stable ratings, right? 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 pause remarks on the new stable outlook.

So the IDACORP side, you mentioned BAA3, that's part of Moody's notching policy. And as I mentioned, we have a higher CFO preworking capital to debt at IDACORP and no holding company debt. So that really is just the Moody's policy on notching. 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. Still 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 on that 13%, 14%, 15% zone for a while, but expecting to naturally grow off of that with large load revenues and rate cases over time.

So we don't have an intent to immediately equitize the 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 forward 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. And just as many 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 we can underwrite? Or is there still more opportunistic based on capital timing and obviously, the regulatory conditions?

Yes. We just take a very pragmatic view of sort of where we are in our spend, and 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. 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 there's the financial impact that, that actually has if you don't do rate cases around that. So some of them will be just weighing the impact of that conversion to reg and taking that into regulators versus filing rate cases. when you've got large load revenues coming in. So the larger revenues to 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 the word you used was opportunistic. When we need to go in, that's when we'll go in. That's how I'd look at it.

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 pace for growth mentality that really do bring about an affordability aspect. We will look each year at what our rate app would be. We don't want to go in and make really large rate requests, and it's this growth pace 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.

Your next question comes from the line of Chris Ellinghaus from Seibert Williams.

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 ITC recognition through the years? Do you have some visibility there?

Yes. For ITCs, we're actually a cash taxpayer, and so we have a tax credit appetite on our returns each year federal income taxes. So we're actually monetizing those ITCs every year. That appetite continues. 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 will 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 generated 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 ADITCs 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 now a forecast that you guys usually show, it's going to be far from normal. So can you give us any sense of what you're seeing particularly irrigation as usual, but it's supposed to be super hot with pretty well below normal precipitation. So what have you seen so far in the spring what's the 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, those of us that enjoy winter sports were really bumped out about not having much snow in Hills. But we did have some good storage, and we did catch up a little bit with the rain that we had in this last month. but still 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 are -- have been trying to figure out what's their strategy, just given some of the commodity prices, and so that may have some impact. 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.

Yes, Chris, we've been debating this issue with the folks on ground because and 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 NOA. 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 can get to kind of this net-net normal position that Lisa mentioned in 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 to be a little bit low. But again, we see no correlation in the past between low water and low sales. In fact, a lot of times, we've had a low water years that have had higher sales because the temperatures have been higher. So there's just puts and takes 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 beats are a little bit lower than I think our farmers would like. And so there are some cases when they plan to maybe slightly less of those products, which could impact water use. But at the end of the day, [indiscernible] touched on the Iran issue directly. .

Okay. And I guess, lastly, you touched on the strength of the pipeline. Can we assume that your Q is basically unchanged from what you talked about on the fourth quarter?

Chris, 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, 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, there should be some upside in that.

Yes. And it's important to just remember that we don't put any load -- 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 tire kickers. So while 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 queue, it just sort of kind of put things into perspective. So I'm just kind of curious if that number had made any kind of advance or decline.

Chris, just quickly, the problem on those issues, talking about the large loads is 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. .

Next question comes from the line of Michael Lonegan from Barclays.

Just wondering if there's any update you can provide on Micron Fab 2, when you expect an ESA to be signed and when we today expected 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.

This is Fab 2 .

This is on Fab 2. Yes, we're still negotiating tab to 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 long ago. But in terms of their -- in service, they anticipate initial waiver output for their first fab around mid-2027. And on the second fab, they are already moving forward with the ground preparation for Fab 2. And of course, we have revenues potentially coming in the door mid this year related to Fab 1. 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.

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

I mean we always want to go in with some company-owned assets or projects and we do. And historically, we've won about 50% of those and so we have -- certainly, we have 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 bids. So we'll compete like we do each year.

Yes, Michael, if I can add to that, I think you referenced the CapEx impacts as well. And so the CapEx forecast that we have in the slides that we're showing right now doesn't have any resources for the 2032 RFP. 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 will help serve a portion of Micron's second fab, but only what we expect would be in the very earliest year or years of operation. That's our large transmission projects will help with that. Some of our generation. We need more resources for Fab 2 and like Adam said, the amount of CapEx actually depends on the ESAs we signed and how we serve our load growth rate, which we're working on right now.

Again, the IRP gets filed in June '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. If you want to serve the load several years from now, you have to start the process now, which means spending some amount in the near term for things like Truven reservations and early payments and a higher amount 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 5-year window, maybe weighted more towards 2029 and 2030. -- in the very near term. But that's how we look at the CapEx upside on that graph.

Great. 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 wondering 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 large customer revenues coming in more 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 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 forward on it. the financing plan for equity based on the amount you saw on the slide is something that's within a reasonable ATM issuance on balance. I think I mentioned in my more prepared remarks earlier. And with those forwards, we have the ability to shape the equity a little easier to match the timing of payment.

Your next question comes from the line of Julian Dumoulin-Smith from Jefferies.

It's Brian Russo on for Julian.

We never know which really going to answer. So nice for Brian. .

Likewise. And just -- it's nice to see ground prep beginning at the micron at to. 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 IRPs, 8.3% that would be reflected in this updated IRP. And will Micron fab to also be included in that load forecast.

Brian, this is Adam. So Fab 2 is not in the 8.3%. We do anticipate that it will be an 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 they'll hit different targets or not. So to do that, we can attract what they've said publicly and that's what they've said publicly.

Okay. 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 to 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 time line 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 independent power producers out there. So that would set up the advantage as much as it's just putting us in an equal playing field and that the 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 data allows us to compete line with everyone else.

Your next question comes from the line of Anthony Crowdell from Mizuho.

I appreciate the update on the beet crop. Just I have 1 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 1 thing we mentioned there, you'll note it has 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 to meet the load forecast at that time.

Again, Idaho 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 play.

Yes, thank .I'll just reiterate. We don't actually have anything in there at all from the 2032 RFP. It's a common question. that we don't actually have any assumed win rate. [indiscernible] will compete on equal footing in the RFP and what shows up from that the company-owned would be additive to the CapEx. .

[Operator Instructions] There are no further questions. That concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

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

That concludes today's meeting. You may now disconnect.

Welcome to IDACORP's Fourth Quarter and Year-End 2025 Earnings Call. Today's call is being recorded, and our website is live. A replay will be available later today and for the next 12 months on the IDACORP website. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance and 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, EVP, CFO and Treasurer; and John Wunderlich, Investor Relations Manager.

Slide 4 shows a summary of our full year financial results. IDACORP's diluted earnings per share were $5.90 compared with $5.50 last year. This made 2025 our 18th consecutive year of EPS growth, as noted on Slide 5. We ended up $0.15 per share above the midpoint of our original EPS guidance for 2025. These results include additional tax credit amortization of about $40 million for 2025 compared to almost $30 million of additional tax credit amortization in 2024.

Today, we initiated our full year 2026 IDACORP earnings guidance estimate 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 the core earnings. These estimates assume historically normal weather conditions throughout the year and normal power supply expenses.

Now I'll turn the call over to Lisa.

Thank you, Amy, and thanks to everyone for joining us today. As we look back on 2025, it was a particularly busy and exciting year for IDACORP. Our employees continue to shine achieving strong results for our customers and owners. Our company produced its 18th year of consecutive earnings per share growth, as Amy mentioned. We sold a record amount of energy to our retail customers, broke ground on the B2H transmission project and recorded among the best reliability scores in company history.

And we did it all while staying true to our core value to Safety first, integrity always and respect for all. We also settled our general rate case proceeding in Idaho with a constructive outcome for our company and our customers. I want to again thank -- extend my thanks to our outstanding employees for their hard work and commitment to helping us build a secure energy future that powers our customers' lives and businesses.

As you can see on Slide 6, growth remains robust across Idaho Power service area, outperforming national trends and highlighting our region's economic vitality. In 2025, our customer base grew 2.3%, including 2.5% for residential customers, bringing the number of metered customers we serve to more than 660,000. This growth is happening across most customer classes with extensive residential, commercial and industrial construction continuing throughout our service area.

In 2025, Micron's new semiconductor facility continued to advance towards completion. The size is impressive, as you can see on Slide 7. Meta also made significant progress on construction of its data center, which you can see on Slide 8, and that project began taking power last year.

Additionally, Idaho Power helped bring several other major industrial projects online, including a tractor supply distribution warehouse and a major expansion of Chobani yogurt production factory or facility. Along with steady interest from our core industries of food processing, manufacturing, distribution and warehousing, we're also seeing increased inquiries from other energy-intensive customers looking to operate within our service area. We work closely with prospective large customers to set realistic and thoughtful time lines to meet their energy needs while ensuring they are not imposing costs on our other customers.

The solution to serving load growth from new large customers in our mind has several important elements. We first have to comply with the [ laws of physics ] in delivering power. It has to be at a price the customer will pay. We need to procure reliable resources and have them available on the time line we agree to with the customer. It has to be appropriately derisked operationally and on the credit side through special contracts with the customer and it cannot be subsidized by other customers.

As far as we've been able to find, we're serving the fastest load growth rate in the nation, and we're doing it with a thoughtful and measured approach to ensure there are benefits to our company and its owner at the same time, mitigate what might otherwise be a risk of cost shifting to our other customers were it not for our growth pace for growth regulatory model in Idaho.

Notably, last year, Micron announced it would build a second semiconductor facility in Boise. The load and CapEx projections we're providing today don't yet include this expansion, but we're working through the details with Micron. As we've noted previously and continues to be our practice, Idaho Power's public growth projections only include projects that have signed contracts or large financial commitments for customer-funded infrastructure.

With this approach, our growth forecast for large load customers is based only on committed projects. We also have a significant pipeline that includes a diverse mix of prospective large load customers and that pipeline exceeds our current 4,000 megawatt peak load. But we don't have -- if we don't include any of them in our load projections as speculation and hope are not how we like to forecast.

Turning to Slides 9 and 10. Affordability continues to be one of Idaho Power's key focus areas. We work hard to keep our costs down and provide exceptional value for our customers, and our rates have increased at a much slower pace than national averages. We believe that even after implementing our 2025 Idaho General Rate base outcome, our prices remain well below the national average. We're proud of our low rates and despite considerable infrastructure investment and expansion of our customer base, we expect rates to remain in check with our regulatory methodology in Idaho.

Case in point for affordability based on current projections, we're not planning to buy general rate case in Idaho on June 1 of this year. While we anticipate higher depreciation and interest expense associated with growth and infrastructure build-out as well as wildfire mitigation costs, we expect revenues from new large load contracts will help offset those additional costs. And we continue to benefit from our culture of careful and thoughtful spending. We'll watch revenues and cash flow during the year as part of our continuing assessment of the need and timing of a rate case.

As seen on Slide 7 -- or Slide 11, we continue to be full speed ahead on our major infrastructure projects. Work is progressing quickly on our B2H project with 80 towers already completed and many more under construction. We expect B2H to be in service by late 2027. Permitting is nearly complete on the SWIP-North transmission project, and we expect construction to begin this year as well.

We anticipate the project will be completed as early as 2028. We also continue to work with PacifiCorp on the Gateway West transmission project. We anticipate a critical section of the line between our Hemingway and Midpoint substations will come online as early as 2028. With those expectations, we have several new large transmission projects added to our system in '27 and '28. Transmission takes a great deal of time to permit, so we're glad we got started early.

Moving to resource planning. We recently received acknowledgment of our 2025 IRP from our Idaho and Oregon Commission.

Turning to Slide 12. Idaho Power is adding generation and storage resources that will help us maintain excellent reliability as demand growth. In 2025, the 200-megawatt Pleasant Valley Solar project came online as part of our Clean Energy Your Way program, and we added 230 megawatts of battery storage to the resource portfolio. Additional projects are underway to help us continue meeting growing customer demand, including 250 megawatts of batteries and 125 megawatts of solar, which are both set to be in service later this spring.

Idaho Power has announced plans to construct 167 megawatts of natural gas fuel generating capacity next to the existing Bennett Mountain power plant in 2028. We're proud that this company-owned project was the most cost-effective resource in the RFP. As we've mentioned on prior calls, we're working hard to solve the generation needs in '29 and '30, which is a deficit of around 200 megawatts of incremental firm capacity needed each year. We expect to procure additional resources to solve for those deficits.

The additional gas plant near Bennett Mountain as well as other resources we expect to construct are included in our CapEx forecast that Brian will discuss. We filed a request for a CPCN for the capacity addition next to the Bennett Mountain plant, and we plan to file a request for CPCNs for other new resources in the relative near term. You'll see those requests on the Idaho Commission website when we file those.

In other news on generation resources, in 2025, Unit one of the Valmy coal-fired power plant was converted to natural gas. And we also burned the last of our coal at our other Valmy unit, which is currently being converted to natural gas. We expect that conversion to be completed this summer. I'll end by discussing this morning's announcement regarding our Oregon service area. We've entered into a definitive asset purchase agreement with the Organ Trail Electric Cooperative for the sale of our distribution system and some transmission assets in Oregon.

After the transaction, we have no regulated retail operations in Oregon, so we provide power to OTECH for some period of time under a power purchase agreement. The base purchase price for the transaction is $154 million, which is subject to various adjustments. Completion of the transaction is subject to a number of conditions, including approval by the Idaho and Oregon Public Utility Commission and from FERC. Oregon represents a small portion of our overall service area, projected to be less than 3% of our total sales by 2030.

We're confident [ OTECH ] will provide a strong local focus and dedicated service for Eastern Oregon, while Idaho Power concentrates on supporting rapidly growing Idaho communities. If the sale is approved, Idaho Power's 20,000 customers in Oregon will transfer to [ OTECH ] service. While Idaho Power would no longer directly serve Oregon electric customers, it would retain ownership of its Oregon generation facilities and a large majority of its Oregon transmission assets, including B2H, which will help serve Oregon residents and businesses. We're working closely with [indiscernible] to prepare for a smooth transition and make the appropriate regulatory filings to support the sale. It's too early to determine, but we expect regulatory approval could take 10 months or longer.

And with that, we'll turn the time over to Brian.

Thanks, Lisa. I'm going to start on Slide 13, which has our usual reconciliation of year-end results. just running through the table, IDACORP's net income increased over $34 million compared to 2024 and higher operating income at Idaho Power from the January rate increase and from customer growth combined for a roughly $75 million benefit. Usage on a per customer base has decreased operating income by $6.5 million and that was because temperatures were milder in 2025 versus the prior year, though both years did have above average cooling 3 days.

O&M was another offset, albeit smaller than we originally anticipated. Total other O&M expenses increased less than $10 million, mostly from increased labor-related costs. We ended up at the low end of our O&M guidance range for the year. So good outcome there. Depreciation and amortization expense increased nearly $28 million for the year, which was expected with the increase in system investments we've made and the assets have gone into service. In the second quarter last year, a new leased battery storage facility began operations and that modestly increased expense due to amortization of our [ related right to use ] assets. So something new on our financial statements for last year.

Other changes in operating revenues and expenses decreased operating income by a net $3.8 million, and this was because of the year-over-year impact of the conclusion of property tax litigation in 2024, that resulted in refunds that year. Also the timing of recording and adjusting regulatory accruals and deferrals positively impacted 2024 results. But those items didn't recur at that level last year. Those items were partially offset by a recovery of costs of the new battery finance lease through the power cost adjustment mechanism.

The expense for the new battery financing lease had interest expense and amortization, but they're offset in the power cost adjustment mechanism, so ultimately, it's a near 0 impact to operating income. The decrease in power supply expenses that weren't deferred also provided a benefit when compared to 2024. Nonoperating expense increased by about $23 million. That was mainly driven by an increase in interest expense because our long-term debt balance has increased. Interest on the new finance lease also contributed to the increase.

So as I noted before, this is offset in the power cost adjustment mechanism. Partially offsetting those items was increased [indiscernible] from higher construction work in progress balance, which we predict will be sustained for the next several years. Idaho Power amortized $40.3 million of additional tax credits under the Idaho mechanism to reach the 9.12% floor level of Idaho return on year-end equity. That was only an increase of $10.5 million compared to the prior year.

And also related to taxes, the $20.4 million relative decrease in income tax expense, excluding the additional ADITC amortization was primarily driven by income tax return adjustments for state taxes and then standard plant-related flow-through items. That's it for the recon table.

And moving to Slide 14, we've updated our 5-year CapEx forecast as promised. You can see that it increased considerably. We're currently forecasting spending $1.4 billion per year on average over the 2026 to 2030 forecast period. With a total 5-year CapEx amount of around $7 billion, that's a doubling of our average annual actual spend of around $700 million for the past 5 years and near our current market cap. And to give you some perspective on our update, our 2026 to 2030 forecast is a 26% increase in CapEx compared to the 2025 to 2029 forecasted CapEx that we shared at this time last year.

If you look at the CapEx graph, the bars are shaped a lot like they were at this time last year, but the difference is in the scale on the left side of the chart, it's much different in terms of magnitude. And as usual, the last 2 years and the chart probably have some upside that might materialize as we refine our plans and projects for that later time span.

Some of that upside to our forecast results from the fact it doesn't yet include the resources that are needed to serve Micron's second fab or some of the other expected load growth. Amidst all of this investment, I think, it's important that we reiterate the importance of affordability for all of our customers. We're fortunate that our regulatory processes and rules ensure that the new large load customers [indiscernible] they have fair share of system costs and aren't subsidized by existing customers.

As we look at the possibility of not filing rate cases this year and also the estimated potential magnitude of cases in the future, with the future where affordability remains achievable, notwithstanding the significant magnitude of our investments. We also need to keep the utility financially healthy, meaning we need to convert our capital investments into rate base and provide returns to our debt and equity holders funding our growth.

On Slide 15, we rolled forward our rate base forecast for the 2026 to 2030 period. Our total system rate base coming out of our 2025 Idaho General Rate Case was $5.3 billion, it was $4.6 billion coming out of the 2024 Idaho Limited scope rate case, so a big upward reset for our base year. We forecast that by 2030 rate base could reach over $11 billion, which is more than double our 2025 rate base. That's an incredible amount of growth in rate base.

Case in point, we project it to be a 16.7% rate base growth CAGR for the 5-year period from 2026 to 2030. Last time this year, our forecasted rate base CAGR was 16.1% for 2025 to 2029. And today's higher CAGR even after rolling forward to the considerably higher base year that I mentioned. If you look at the cash flow statement, you'll see additions to PP&E in 2025 were nearly $1.2 billion and on the balance sheet is over $1.7 billion. And I think that illustrates how busy we've been over the past few years as a company.

And amidst this increasingly long growth cycle, it's obviously important that IDACORP and Idaho Power keep their balance sheet strong. As part of that, we continue to target an average [ 50 ] debt equity capital ratio and a simple balance sheet. We don't have any holding company debt or any particularly sizable maturities coming up and our capital structure has just medium-term notes and common stock in it right now. And I'd say there is great elegance in that simplicity.

Moving to Slide 16. You can see the net cash flow from operations is funding over half of our CapEx needs in the 2026 to 2030 window. We still need [ growth ] capital, which we estimated at $2 billion in equity and $2.9 billion in debt as they add our target 50-50 capital ratio. But we need to dig a little deeper on that. We've already executed on over $600 million of equity through forward sales agreements that will settle in 2026, which leaves a lesser net amount of $1.4 billion of net equity sales to occur through 2030. That equates to our future capital markets transactions being comprised of about 2/3 debt, 1/3 equity, and it's an average less than $300 million of equity per year for the full 5-year forecast period if you exclude equity already sold on forward, which is within a reasonable ATM issuance range for us, and that gives us a lot of optionality on how we raise our equity growth capital.

Cash flows from operations are expected to increase as we move through the forecast window, particularly with large load revenues coming in with greater volumes over time. And it's important to note that any additional CapEx needed to serve additional load would require additional financing. If that were the case, additional funding would likely be more heavily weighted to the back end of our forecast.

Lisa already mentioned the execution of a definitive agreement to sell Idaho Power's Oregon distribution assets. I'll just add that from a financing perspective, we'd look to offset some of the equity -- I talked about with the net after-tax proceeds of the transaction. That transaction would give us business simplification as Lisa noted, but also another source of capital to fund our rapid growth related investment in Idaho. In the financing table, we haven't applied any proceeds from the prospective sale.

We estimate the onetime gain from the asset sale would be immaterial, and that's not the thesis for it. We expect the asset sales to be only slightly accretive earnings accretive in the year it closes, but also provide an ongoing benefit to EPS from lower dilution.

On Slide 17. Cash flows from operations eclipsed $600 million for the first time in company history. Customer growth, the benefits of the general rate case outcomes and moderate power supply costs, all helped to achieve that milestone. The strong cash flows also help moderate our financing needs and leaves IDACORP with strong cash position as of today.

What I'll end with today is to reiterate something I noted at this time last year because it still rings true. Over the forecast window we talked about today, we expect to see what we believe to be among the leading actual earnings growth and earnings quality profiles in the industry. I think it's important to note that when you do your analysis, our expectations are on a GAAP basis and basing off a long stream of 18 years of consecutive GAAP earnings growth. So we based on our growth expectations off of a very strong year with no non-GAAP exclusions or exceptions, again, elegance in simplicity.

We're mindful of those providing the debt and equity capital for our growth and recognize the importance of generating returns for them. We're focused on the things that matter to them. Strong risk mitigated execution and already in process infrastructure build-out, sustained affordability for customers, actual rate base growth from permitted and in-flight projects, real near-term earnings accretion, customer revenue diversity and long-term durability of our earnings growth and returns.

That's the paradigm we've been working under and what I know you've all come to expect from us. And with that, I'll turn it over to John.

Thanks, Brian. This marks my 1-year anniversary of conference calls in my IR role. So Brian asked me to give a new fun fact about myself. Last year, I noted that I was an assistant coach for a third-grade basketball team, and I'm happy to let you know that I was promoted from the role of assistant to the head coach to a full assistant coach this year. And I moved up the ladder to fourth grade basketball.

Turning to Slide 18. You can see our 2026 full year earnings guidance and key operating metrics. This guidance assumes normal weather throughout 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. The midpoint of this range reflects an [ 8% ] EPS growth rate over 2025 actual results, premised on what we would consider a conservative set of assumptions.

We expect that Idaho Power will use less than $30 million of additional investment tax credit amortization in 2026, so less than the amount in 2025. We expect full year O&M expense to be in the range of $525 million to $535 million. And I'd like to provide some context on that range. The largest driver of the increase over the prior year is wildfire mitigation costs, which are offset by revenues from the general rate case.

So it's not apples-to-apples comparison between 2025 actuals and the 2026 estimate. As we continue to expand our system to accommodate growth, we do expect to also see higher O&M expense. We also continue to experience inflationary pressure on labor and professional services, but our culture of spending wisely to help ensure affordability for our customers is very much intact. We continue to focus on keeping costs as low as possible while keeping the system safe and reliable.

We anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026. As the 5-year forecast showed, we continue to expect higher CapEx numbers as we 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 7.5 million megawatt hours for the year.

With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question comes from the line of David Arcaro of Morgan Stanley.

I was wondering if you could give an update on maybe your customer load pipeline. What are the latest discussions you're having in terms of either expansions of current large load customers and how is the pipeline shaping up for new companies coming into your service territory?

Well, I'll get it started. We certainly -- it just continues to -- we get a lot of inquiries, a lot of folks that are very interested some big than others and really from across many industries. So it isn't focused on on just one. I'll let Adam give a little more color. And it's true, too, that we have NDAs. So there's some things that we can't talk about.

Yes, I feel like a little bit about broken record. This is Adam, saying the same thing, the inquiries continue to be strong. It's kind of [indiscernible] amount of inquiries, everything from data centers to manufacturing. For example, we have a data center that's looking at a service territory that the conditional use permit called Diodes, it's the gemstone Technology Park. We have Idaho National Lab that's growing. [indiscernible] that is a mine up north that's looking at starting operations there, too. So it's pretty robust. Again, a lot of them are under confidentiality. So I can't get into the details but feel like the growth is strong.

And David, just one thing I'll add is the last time you've seen a formal load growth update from us was associated with the 2025 IRP. So that was from quite some time ago. We do plan to update that. The load growth at some point during the year, usually towards the end. But there's a lot of customers that we've talked about that just aren't in that 8.3% load growth update or load growth number that we have out there as of right now. You should [indiscernible] later this year.

And maybe I'll add that, of those customers, a lot of them aren't just inquiries. They're actually doing construction study, generation studies. We have energy service agreements that we're looking at for a fair amount of megawatts. So when we talk about inquiries, goes beyond just people kind of touching and feeling and actually going to the next stage of looking at what it looks like to come to our service territory.

Got it. I appreciate that color. That's helpful. I wanted to also just ask about on the equity needs side of things with the refresh here. Maybe there are a couple of moving pieces, but I was wondering if you could just give a sense for what the rule of thumb would be, Brian, maybe just on -- for incremental CapEx, how do you think about the funding split in terms of external equity from where we stand now, given your latest operating cash flow kind of outlook here? And maybe in the context there, I was curious, any repairs tax impact from the guidance there.

Yes, David, sure. On the repair stack side, the assumptions that we use in our forecast tend to stay relatively stable. It does adjust from time to time each year, but not a major update in our repair tax deduction. On the equity needs side, any incremental CapEx that we add to the forecast is probably financed 50-50 debt equity, at least beyond what we have now and the update that we provided this morning.

What I will say, though, is in a lot of instances, these large load customers come with large load cash flows, and that can certainly impact ultimately what our need is. And if you look at the equity number that we put in our estimate right now, it does have some conservative assumptions about what cash flow will look like. If you look at the incremental increase in cash flow in the bar chart for our financing waterfall February of last year versus February of this year, you can really see -- you can see some movement there.

And that's to fund the significant incremental amount of CapEx that we have in the forecast. So some of the adjustments that you see in that waterfall is a result of what cash is on the balance sheet and where forward drawdowns were on our equity programs at any given time. So that gives you a little bit of a skewed view of not apples-to-apples comparison year-over-year on equity needs. So the number does move around, certainly with cash flows.

It could be impacted like I noted by the sale of the Oregon service territory. So there's a lot that can move the equity number. I'd say it's pretty conservative at this point. And so even the 50-50 debt equity split could be somewhat of a conservative approach on how we would look at our equity needs over time.

Your next question comes from the line of Michael Lanigan of Barclays.

So obviously, you mentioned your current capital plan does not include Micron Fab 2. Would you be able to help us understand the size of that investment opportunity in the latter part of your plan?

We're just working with Micron to determine that. So we don't have anything to share in terms of size today. So more to come as we work our way through that.

Yes, Michael, this is Adam. They haven't given publicly a load ramp. The size of their first fab is public, but they haven't come out with the second fab yet. So when we are able to share that, we will.

Okay. Great. And then secondly for me, obviously, a sizable CapEx increase with today's update, modest increase in equity content needs. You're on track for significant cash flow generation increases, like you said, with the large customer ramp-up. Just wondering where did you end 2025 on FFO to debt? And where do you anticipate being over the course of your plan? And do you think there's an opportunity for Moody's to take your rating off negative watch?

Yes, Michael, thank you for the question. I think the answer to that is yes. I think there is an opportunity for that. So we do have a pretty substantial capital investment. And so we are maintaining a very strong simple balance sheet, as I mentioned, of 50-50. And I think that's been a good factor from a rating agency perspective. .

We have, at the end of 2025, I'd say on Moody's, I think we were at about 14.3% at Idaho Power. And on S&P, we were just barely sub-14%, if I remember correctly, on FFO to debt. Our threshold at Moody's is 13% and at S&P at 14%. So as of right now, we're somewhat navigating that floor level. We expect to come out of that with large load revenues, as you mentioned, in the cash flow to support it. But again, we're maintaining a really strong balance sheet. The outcomes of our rate cases helped the rate case that we did in 2025 had a result that will help credit metrics in 2026.

So I could see us being at or near those levels again in 2026 before we make a gradual move up off of those numbers. But again, we usually do better than what our internal forecast suggests. And so I think Moody's and S&P both understand that. And we'll be meeting with them in March actually to have a conversation about where things are headed.

So we don't have, as I mentioned, holding company debt. That helps. We don't have anything on our balance sheet that all fall in exotic for lack of a better term. And we don't have any upcoming maturities through 2030 other than $116 million [indiscernible] control revenue bond this year to refinance. So from a balance sheet perspective, we're sitting very strong. I think the rating agencies will recognize that.

Your next question comes from the line of Shar Purreza of Wells Fargo.

This is Whitney Makalima on for Shar. And any congratulations to John on the promo to...

So you probably have precedent for large load arrangements, including a certain tariff that's tied to, I think, it's tariff schedule 33 tied to a special contract. Do you expect to move towards a standardized large load tariff rather than negotiating special contracts case by case? And if so, what would drive that decision?

At this point, we don't have plans for that. Each customer really comes with their own unique needs. And so we really try to make sure that we understand them and meet them -- so they really are tariffs at one, if you will, that are very catered to the customer.

Okay. So nothing in the near term.

That's correct. Yes, nothing in the near term from our perspective.

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

You mentioned the downward sloping CapEx in the outer years, and you take a conservative approach to what you include, what could be upside there? Is there anything left on the '28 and '29 RFPs that would be additive? Or is this another RFP that would be needed for the post 2030 time frame?

Yes, Brian, this is Adam. Yes, we are looking at an RFP in the post 2031, '32 time frame. As you know, we had 1 for 2028. We had one for 2029. The 2029 and later RFP really only provided on natural gas project. That was the project that [indiscernible] you've heard us speak about that's getting built right now. We're actually moving that project into 2028. And so as we look at 2029 and 2030, we're going to have to evaluate some options to increase power production there. And we hope to give you an update on that here relatively soon. And I think Lisa mentioned it [indiscernible] in her opening comments that we do have some options there, and they will go public here in the near future. .

Right. Is one of those options brownfield development, I think it's a [indiscernible].

Yes, absolutely. We have an energy site there. And just as a quick reminder, too, we don't have any generation resources for Micron Fab 2, Fab 2, is not in the load resource balance, nor is diode, so you would see additional CapEx there as long as well as additional generation resources to meet that growth. .

Okay. Great. And then the less than 30 million ADITC usage in '20 notable, as you mentioned earlier, would that be like the inflection or with the likely stay out this year of filing a rate case, how should we look at post 2026 support for earnings?

Well, certainly, as the large loads start to come online, we start to see those revenues help push out the need for rate cases and hopefully lower the need for the use of ADITCs. And so, so far, we're keeping on schedule, and we're optimistic. And so we -- I don't know that I would call it an inflection point necessarily, but certainly, we are starting to see some of that revenue come in.

It's Brian. What I would add is I think one way to look at this is -- let's take a look at the rate base growth slide that we talked about today on the call. And you can see that '26 and '27 has significant rate base growth. But when you look to '28, there's a very large amount of growth. So there's still the company still will earn based on rate base over time, in addition to large load customers.

We are at a point though where we have to look more globally every year as to which one is the better outcome.

Okay. And then just lastly, obviously, not surprising the assumption on the hydropower forecast. But could you just talk more or just share some thoughts on what the current hydro conditions are and drought conditions, understanding that you've got very strong mechanisms. But I'm just curious with the dynamic with irrigation sales as we move into the spring, I mean, is there a high probability of a dry and hot irrigation season?

Yes. It's really interesting. If you're a skier out west, it's been kind of a bummer of a winter, but what our hydrologists are telling us is that we actually in the -- on the east side of our system, we're actually, it's really at normal levels, and that's where we get the most generation from because it flows through all of our hydro resources. And then certainly, at lower levels, there is less no than we historically see.

But it's been actually quite wet this winter, so it didn't necessarily become snow at the lower levels, but that also helps keep those soils wet, so the runoff from the higher elevations make it to the river. So overall, we're actually pretty optimistic. I will also tell you that yesterday, it looks like Christmas here. So we're starting to see some storms. So it ain't over till it's over, again so we aren't necessarily done with the snow pack accumulation.

But of course, we live out west, so we're pretty used to having fluctuations. There are drought cycles that happen. And yes, we have mechanisms. And then we also work very carefully as we prepare for summer operations, knowing what we're -- with the conditions as we go into those operating season. Adam, I don't know what you would add.

No, I agree you covered it. I think the range reflects that. We've been much lower than that 5.5 last 5 years, I think, in 2021 and 2022, we are below that 5.5 number. So we're actually feeling somewhat optimistic that it's higher than what you would think, and that's why the range is what it is. .

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

So if you're going to forgo the middle year rate case for this year, would you expect to stay on a similar midyear cadence going forward?

Well, that's sort of been our cadence historically, but we are constantly looking at our financial situation and make a determination then. So if something changed and we needed to do it sooner or later, we would do it at that time. We do have a requirement that we have to give notice when we're going to file. So you can we tell people before we do it [indiscernible]

Anything you would add, Tim?

Chris, this is Tim Tatum. The only thing I'd add is, in the past, we have filed general rate cases in the fall, targeting at June 1 effective date. So we would have the opportunity there. We look at June 1 because that coincides with our annual power cost adjustment updates and our fixed cost adjustment update. So that's another time that we could look at to file. We'll be monitoring and certainly only file if we absolutely have to, but that's a potential option as well.

Okay. The customer growth continued sort of a little more moderate in the back half of the year. Do you have any better sense today what's affecting residential growth that is it the interest rate environment or whatever you might know about?

I mean those are always the key drivers. It does seem like there's been a little bit more activity, if you will, of buying and selling. It kind of was frozen up as people were kind of stuck in their homes and interest rates, and that seems to have been relieved a little bit. I don't know if people just got used to it or needed to do something for other reasons, but I don't think it is necessarily -- I mean, we still have good growth.

And so whether it's it sort of ebbs and flows with the seasons or what drives it. We don't necessarily know. But overall, we still think it's pretty strong, and there's lots of subdivisions that are getting flatted and getting ready to be built, if not already under construction. So some really massive subdivisions sort of to the east and to the west. So we're excited about that. And certainly, with some of these big employers like Micron, they're going to need places for their employees to live. So that's really driving a lot of this growth as well.

Yes. I wanted to say, given the large new employers, is there going to be some lumpiness to what the residential customer growth looks like for the next 5 years?

It very well could. You know it's never perfectly matched. So it looks like people are gearing up to provide housing for sure.

Okay. Brian, do you have an estimate for what the weather impact was for the year?

I don't have a specific number. I can show you the way I would look at it is from a sales volume perspective, if you look at a 1.5% year-over-year sales growth on a weather-adjusted basis, it's 2.3%. So weather did certainly have its impact on the year. We had a great third quarter as a result of some of the, say, drier conditions and very hot conditions. But again, cooling degree days in both of the last 2 years were high and that impacted our sales.

If you look at, say, November, December, they were very warm months. What I would note, though, is the FTA does have some impact on the outcome of that or the impact of weather on our results. But again, no, I would say there are parts of the year that were more moderate conditions that had an impact on those sales numbers. .

Okay. Do you have an estimate for your large load growth for 2027 that mitigates the large CapEx and equity dilution and whatnot. Have you got an estimate for what 2027 looks like?

In terms of financing?

No, in terms of large load growth.

But we can tell you, Chris, that that's when a lot of that growth is going to start to ramp up when you're going to see a lot of these in-service dates for Micron and others. But I don't think we have an exact number unless you guys do.

No, we just have the 5-year CAGR out there as of now. And I think as we've mentioned, that number has been there for a while, somewhat more back-end loaded, but I would include 2027 as one of those larger ramp years

'25 or '26, '28, '29 and that is out into the 2030s actually being a pretty significant ramp years for us.

Okay. I was just checking because 2027 looks like a big year by my calculation. What -- so with acceleration in the CapEx and AFUDC and the rate case does that lead -- should that lead us to believe that 2025 was peak ADITC usage?

Not necessarily. I wouldn't assume that. There's a few different factors that influence ADITC usage. One of them is just book equity number at the end of the year as well as the calculations based on. So that's impactful. Other things can be, what's the amount of depreciation and interest expense that's unrecovered that's not offset fully by AFUDC and whether or not we file rates is another aspect of that.

So it's not linear in any given sense that ADITC usage would go down. What we're doing this year though, if you think about even into 2027, you could see something similar. It's a little too far out to know for now. But in the further out years, when you look at some of that rate base growth, we've talked about that does have to be financed with our hybrid test year, our historic test year, how you want to look at it, there is lag that sometimes has to be covered by ADITCs. And that's really why in the rate case that was important to us to have that as an element of the settlement is to smooth out some of those years where ADITC is may be a little higher.

Sure. I just don't see the big sag in the ROE that would require it to be much bigger than last year thus far. So also, you sort of reduced the dividend payout target with the dividend increase in September. Can you give us any thoughts about what do you see as a minimum that's -- can you -- do you feel like you can dip below 50%? Is there really a range that you're wanting to maintain at a minimum or a minimum growth rate have you got any insights there?

We're always looking at that, certainly, we're just trying to make sure that we're not issuing equity to pay dividends and whether it's been sort of the consensus that it's better to invest in the company and get the returns there. But I don't really know that we have -- we do have that stated range, but we sort of take it as we go through this time period and try to make recommendations to our Board that makes sense.

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

Just 1 more that I wanted to check in with you. I was wondering just any thoughts on the prospect here for depreciation and interest expense tracker just going forward from a regulatory standpoint, whether that's something you might seek again in the future?

Well, certainly, something that we have looked at and talked about. And when we looked at our forecast for this year and sort of determine that we don't need to go in for a rate case immediately, we didn't see that we -- there was a need this year, but it's definitely something that we will keep a close eye on because as you know, with this big capital program, that those are significant impact to our financials. So we are interested in that. We'll continue the dialogue on that. It's just not something that we're working on right this minute. .

[Operator Instructions] With no further questions, that concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

Thank you again to all of you for joining us today and your continued interest in IDACORP and John's basketball career. coaching career, and we hope you all have a great evening. Thank you.

This concludes today's conference call. You may now disconnect.

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 the IDACORP's website. [Operator Instructions].

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 3 quarters of 2025, diluted earnings per share were $5.13 versus $4.82 for the first 3 quarters of 2024. Those results include additional tax credit amortization of $39 million in the first 3 quarters of 2025, compared to $22.5 million in the first 3 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 2 fab projects remain a cornerstone of our industrial engagement. The 2 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 pace for growth philosophy.

As shown on Slide 6, our residential customer rates -- 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 lease cost, lease 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 2 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 the 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 and 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.

[Operator Instructions] 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 time line 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'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.

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 3 projects on that final shortlist. On the 2029 shortlist, we have 4 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 1 gas bid that made the 2029 RFP. So we'll have to consider other options there as well 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 just 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 kind of in the -- this is Adam, the 2.3%, 2.4%. That's meter growth. That's per customer or customer meters, really where we're going to see and continue to see more substantial growth is in the manufacturing area, and we expect that to happen here and ramp up 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 5.

Bill, I want to go back to your question on the -- 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 -- is an incremental add since then. So you take the wind out and the 167 megawatts 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 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.

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 is we're starting to see the manufacturing load increase. A lot of the projects -- there are 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?

Well, I think that the way that the spring and summer started, it was quite warm and dry. So I think we've got a good bump there. And then of course, it rained on the 4th of July, we had rain in August. It was -- it never really got miserably hot for extended periods of time, which often is where you see some of those super peaks show up. But overall, what we're projecting for the year, it is slightly up over last year, even though it sort of not -- doesn't have the historic shape as you go through the year. Anything you would add, Adam?

Maybe I'll just hit the kind of boots on ground perspective. And then, Brian, I know you have some numbers on it. Talking to our ag reps, they kind of have said that the demand has been pretty strong. It's been pretty steady. So that -- I think that's what we expected going into the year based on our conversations with farmers, and I think that's what we ended up seeing as a pretty steady amount of energy used throughout the year. Ebbs and flows, Brian, I know you have the numbers, but it was -- the demand was strong.

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 9 months -- the first 9 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 precept, 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?

Well, certainly, with a lot of the policy changes, that has changed the economics of renewables for sure. So that has an impact in how those inputs go into the model. And we'll see sort of what -- on the short-listed projects, their ability to meet the terms that they were selected on given those changes in policy. Anything you would 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 1 gas plant that was part of that RFP. So just by virtue of seeing what's lease costs, lease 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 Julien Dumoulin-Smith 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?

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.

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 3 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?

Well, I mean, we're -- again, we're looking at all options to see what can we actually get as quickly as we need. So I don't know that we have more than that to really say about it today. Is there anything that you'd add?

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 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?

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.

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 element 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 -- 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.

Your next question comes from the line of Anthony Crowdell with Mizuho.

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?

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.

The driver that we would see in the update in 2025, is it approval of the settlement? Or is it something else that would cause us to see in '25?

No. It's just getting through the procurement process. Sometimes that can be a relatively lengthy process and it is a competitive process. So identifying whether or not we've been the successful bidder, negotiating with the actual suppliers and vendors and ensuring we can meet time lines are all factors that go into whether or not that will be a 2025 announcement or not. And it's also a confidential process that we have as we negotiate with those vendors.

So there's not much we can release until we've gotten to a point where we're very comfortable in the fact that is a winning project. And then we'll announce what it is and magnitude and add it to the capital stack.

Great. And when do you expect approval of the settlement, I apologize if you've already put it in the 8-K on when the commission would vote on it?

Yes, we're expecting that sometime in December as they have done historically, so probably late December.

Great. And then lastly, Brian, you talked about, I guess, you're carrying a QIP balance of $1 billion. I believe Moody's has you on a negative outlook for your rating. Do you plan on working down that QIP balance in '26 or it stays at that level? And with the negative outlook and that large QIP balance that maybe accelerates equity needs?

Actually, I would think the equity need would go the other direction in the near term, Anthony. And the reason for that was I mentioned the Jackalope Wind project had 2 large payment obligations in 2026 and 2027. As we look at removing that and replacing it with potentially more traditional timing of payment like for a gas plant, for example, those tend to be spread out longer and that can actually reduce our near-term equity need by pushing out the capital requirements until further in our 5-year window. So we can see a reduction in near-term equity and overall equity just as a result of the payment timing for CapEx.

On the credit metrics side, we did have this rate case outcome. We do believe it to be -- the settlement is a balanced settlement certainly and constructive, but it does help on the credit rating side as does the outcome of the Hells Canyon AFUDC case. So we see ourselves naturally progressing out of being near the threshold for both Moody's and S&P without having to issue incremental equity in the near term.

[Operator Instructions] 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.