IDA - NYSE

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 Wonderlich, 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 support 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 values of 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's 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's yogurt production 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 agreed 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 -- 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 case 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 file a 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 the 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 should 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 it 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 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 requests for CPCNs for other new resources in the relative near term. You'll see those requests on the Idaho Commission website when we file them. In other news on generation resources, in 2025, Unit 1 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 Oregon Trail Electric Cooperative for the sale of our distribution system and some transmission assets in Oregon. After the transaction, we'd have no regulated retail operations in Oregon, so we provide power to OTEC 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 OTEC 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 OTEC 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 OTEC 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, I will 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. And 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 basis 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 free 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 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 that 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-of-use asset. 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 recovery of costs of the new battery finance lease through the power cost adjustment mechanism. The expense for the new battery financing lease hit interest expense and amortization, but they're offset in the power cost adjustment mechanism. So ultimately, it's a near zero 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 balances increased. Interest on the new finance lease also contributed to the increase, though, as I noted before, this is offset in the power cost adjustment mechanism. Partially offsetting those items was increased AFUDC 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, and 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 in the chart probably have some upside that might materialize as we refine our plans and projects for that later time span. And 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 Lisa discussed, they have fair share of system costs and aren't subsidized by existing customers. As we look at the possibility of not filing a rate case this year and also the estimated potential magnitude of cases in the future, we see a 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 roll 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. And 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 is 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 QIP 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 50-50 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's 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'll still need growth capital, which we estimated at $2 billion in equity and $2.9 billion in debt to stay at 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 of less than $300 million of equity per year for the full 5-year forecast period if you exclude equity already sold on forwards, 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 look to offset some of the equity needs 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 sale 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 helped moderate our financing needs and leaves IDACORP with a 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 string of 18 years of consecutive GAAP earnings growth. So we baseline our growth expectations off of a very strong year with no non-GAAP exclusions or exceptions. Again, elegance and 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.

Look, 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 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 of a broken record -- this is Adam, saying the same thing. The inquiries continue to be strong. it's kind of a diverse amount of inquiries, everything from data centers to manufacturing. For example, we have a data center that's looking at a service territory that has a conditional use permit called Diode, it's the Gemstone Technology Park. We have Idaho National Lab that's growing. We obviously have Perpetua 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. We should see an update 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 studies, generation studies. We have energy service agreements that we're looking at for a fair amount of megawatts. So when we talk about inquiries, a lot of times it 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 repairs tax 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 repairs 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 flow, 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 a significant incremental amount of CapEx that we have in the forecast. So some of the adjustment that you see in that waterfall is a result of what cash was 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 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 Lonegan 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 the path.

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-ups. 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, though 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 S&P is 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, and the cash flows 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 call an exotic for lack of a better term. And we don't have any upcoming maturities through 2030 other than $160 million pollution control revenue bond this year to refinance. So from a balance sheet perspective, we're sitting very strong, and I think the rating agencies will recognize that.

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

This is Whitney Mutalemwa on for Shar. So you currently 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 of 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.

Yes, Brian Russo on for Julien. You mentioned the downward slope in 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, say, 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 one for 2028. We had one for 2029. The 2029 and later RFP really only provided natural gas project. That was the project that -- [ Bennett ] that 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. I think Lisa mentioned it 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 Peregrine...

Yes, Peregrine 1, 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 '26, 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, that -- 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 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.

And Brian, what I would add is I think one way to look at this is take a look at the rate base growth slide that we talked about today on the call. And you can see that 2026 and '27 have 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 closely 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 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 snow 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 that 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 looked like Christmas here. So we're starting to see some storms. So ain't over till it's over, I guess. So we aren't necessarily done with the snowpack 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 seasons. And 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 over the last 5 years. I think in 2021 and 2022, we were 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 we can -- we tell people before we do it. Anything you would add, Tim?

Yes. Chris, this is Tim Tatum. The only thing I would add is, in the past, we have filed general rate cases in the fall, targeting a 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 keep 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 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 any 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 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 FCA 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 don't. 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 out into the 2030s actually being pretty significant ramp years for us.

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

I would say not necessarily. I wouldn't assume that. There's a few different factors that influence ADITC usage. One of them is just a book equity number at the end of the year is what the calculation is 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 rate cases is another aspect of that. So it's not linear in any given sense that ADITC usage would go down. What we're seeing 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. And with our hybrid test year or our historic test year, depending on 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, it was important to us to have that as an element of the settlement is to smooth out some of those years where ADITCs 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, if 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 rather 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 one more that I wanted to check in with you on. 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 determined 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 impacts 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.