Idacorp (IDA) Q2 2026 earnings call transcript

Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we'll reference during today's call are available on IDA Corp's website. As noted on slide two, our discussion today includes forward-looking statements, including things like earnings guidance, spending forecasts, financing plans, regulatory plans and actions, and estimates and assumptions that reflect our current views on what the future holds. These are all subject to risks and uncertainties. Those risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements.

We've included our cautionary note on forward-looking statements and various risk factors in more detail for your review and our filings with the Securities and Exchange Commission. As shown on slide three, also presented today, we have Lisa Grove, President and CEO, Brian Buckham, EVP, CFO, and Treasurer, and John Wunderlich, Investor Relations Manager. Slide four has a summary of our second quarter of financial results.

IDA Corp'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 IDA 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 $287 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, we're raising the lower end of our full year IDA Corp diluted earnings per share guidance range by five cents to the new range of $630 to $645. 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 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 my remarks with a look at customer growth. As you can see on slide five, 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 low growth that we've seen within our service area remain strong, and we're working hard to meet the increased energy demand. As one 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 microns expansion and Metas 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 of these massive projects on slide six, along with pictures of some of our other large contract customers like Giovanni and INL.

Looking at slide seven and eight, we're 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 pay-per-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 de-risk large loads for both our customers and our owners.

One of the main draws 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 large customer pipeline which remains strong at multiple gigawatts as businesses across multiple industries look to operate in our region.

Moving to slide nine, 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 schedules, marking our fourth straight year adding batteries to our system. Since 2023, we've added over 550 megawatts of company-owned battery. We also completed the conversion of all-me unit two from coal to natural gas last month in time to help us meet peak summer lows.

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 region.

Turning to slide 10, I'll provide an update on our three major transmission projects. We expect all three 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 de Hemingway, work is progressing nicely. As of today, about 70% of the 1,300 structure paths have been completed.

Over 400 towers are built, and we've started stringing wires. It's a huge undertaking, and we're pleased with the progress. We'll continue to expect E2H to be in service by late 2027. On the SWIP 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 Pacific Corps on the Gateway West Transmission Project. As we mentioned last quarter, we filed a joint request for 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 Flight 11, progress continues toward the construction of three company-owned natural gas-fueled projects that I've mentioned on previous calls. Construction is underway on the 1st of 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 CPCN for the 222 megawatt South Hills Project, which is scheduled for operation in 2029, and the 430 megawatt Paragram 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 deficits.

Turning to Flight 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-bid projects remain competitive, and the review team is beginning to narrow the field of contenders. We expect to have a final shortlist in the third quarter and begin contract negotiations soon thereafter.

I'll close 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 OTEC. These filings are being processed, and we expect a 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.

Hey, thanks, Lisa. Hi, everybody. Thanks for joining us today. It's exciting to see all the projects going on right now. We can project executions been particularly important because it helps serve an 8% quarter over quarter increase in industrial loads, and it'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. What's wrong results for the quarter and the year to date? Benefits from the January 1st 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 range and dampened quarterly irrigation sales because we later experienced the drive may in June. Aside from the amount, the timing of precipitation can also notably impact irrigation sales funds.

Before I get into the details, I wanted 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 Flight 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 decline 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 sale 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 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, on an expense was almost $12 million higher in the second quarter. Primary drivers were the amortization of previously deferred costs associated with the Jim Bridger plan and our well part mediation plan.

A large portion of those items we recover in customer rates, so they're also reflected in revenues. Disreciation and amortization expense increased around $5 million for the quarter. No surprise there, given our ongoing infrastructure investment.

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 the decrease in that power supply expenses not accrued through the power cost adjustment mechanism. And now let's do to update the PCA mechanism base in last year's rate case. Non-operating expense increased only marginally with higher AFGDC mostly offset in higher interest expense.

Fairly significant. Important from my perspective, Idaho Power didn't record any additional tax credits under the Idaho earnings support mechanism in the second quarter. That was about $17 million less than what we recorded in the same quarter last year. From a year to date perspective, the roughly $6 million we've recorded for 2026 is compared to over $36 million we've recorded at this same time last year. That lower credit usage even with higher expected book equity this year is really indicative of RF financial strengths and performance this year.

Our next slide, slide 14, reiterates what we discussed about CAFACs on the fourth quarter call. So it's just for reference. What you see in that forecast is admittedly already a large amount of capital. But as a reminder, it doesn't include any assume resources from the 2032 RFP. And relatedly, it also doesn't include resources that 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 three 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 five years under the current plan. We've either issued or we've sold on four of about a billion dollars already. So we've solved for roughly half of our current plan equity needs. We have the equity we need into 2027 and we think the remaining amount and the current plan is with the ATM ranges.

I'll reiterate that any additional capex would require some additional debt and equity. We still plan to blend that equity on a roughly equal basis for any incremental capex with the goal of keeping our balance sheet strong.

Slide 16 has helped to summarize the forward sale agreements that we have available and the forwards that we've settled today. 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 warrants are mentioned 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 prudent determination related to our health care and licensing effort. The Commission in that case determines that our project expenditures from the start of 2016 through year end 2025 are prudently incurred and rendering them eligible for inclusion and retail rates in a future regulatory proceeding. We're pleased with the outcome of that case. In part because, as many as you know, we pride ourselves on being prudent spenders at the company.

I'm going to hop up there. I'm handed 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 Ida Corps' 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 to $535 million.

And we still anticipate spending between $1.3 and $1.5 billion on CAPX 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 hydropower operating conditions, we expect hydropower generation to be within the range of $5.5 to $6.5 million megawatt hours for the year. We trimmed a half 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.

Yeah, 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, you know, 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 certainly just because of shorter days.

So we don't get a chance to refill the battery before we need them again and they last for four 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 a real capacity resource more than those four hours. So we, you know, an absolute sprint to keep up with the growing load and getting the resources online and in time. And so, you know, 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, you want to step up.

Thanks for the question, Wendy. Happy to walk you through kind of year by year how we're looking in 2027. It's largely batteries and solar. We have a fair amount of that price 400 ish 500 megawatts of solar and other 100 megawatts of batteries. From that point, it does go turn a little more on the gap side.

We talked about it. We sent her comments. We have been to 2029. We have South Hills, which is also a gas project, 222 megawatts and 2030. We have a project called Peregrine 1, which is also gas 430 megawatts. And then idle powers, origination team for 2031 and 2032. We've been in eight projects, six of them were gas projects, two 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 gap versus storage versus solar in the next several years.

In terms of SMRs, we've spent a fair amount of time learning about these new technologies. I'm on the customer advisory committee for one of the key technologies and companies. We've spent a fair amount of time with INL 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 to make what hour at this point. So, again, we like SMRs, but if we're probably not going to be the first, 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 CAPX and the generation projects, I mentioned, Lisa and her comments also mentioned B2H. We're making great progress there. Southwest Entertainment Project broke ground recently, which is just a great milestone there. And, of course, Gateway West, which we're looking to work on and construct over the next several years. So, it's always good to point out, I guess, that transmission is a big part of our plan as well.

Kind of the generation makes the transmission is what makes it all work out together.

Yeah, so you're right. We do have a mitigation plan and we do have it is now the Canada Care Act here in Idaho applies to that mitigation plan. So, certainly, you know, 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 is one thing to write a 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 we feel really good about the implementation of that plan. So, I think that's probably about all I would have to say about that.

Well, those are often confidential. So, we have to, you know, 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?

Yeah, 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 CAF-2. We are in ESA discussions, but as Lisa mentioned, you know, those are confidential. So we can't really speak to those in terms of the CAF-X side and Brian can speak to this. But FADU is not in the 8.10 IRP calendar that we've shown.

So it's outside of that as well in terms of spend.

Yeah, just add on to what Adam said, you know, most of our CAF-X that you see in the slides was premised on the 2015 IRB load growth rate, the 8.3%, as we mentioned. 2025. Yes, thank you. So it excludes customers like CAF-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.

And with some of our related spending for the infrastructure, power infrastructure related to that occurring pretty urgently, I'd say, in our five-year window. Not all of it on the outside of that window. So while the 2025 IRP is at the data point, we're tasked with serving load as a materializes so that in process transmission lines and the outcomes of the 2032RSP will all be part of how we solve for that load growth that materializes. That will end up getting reflected in our CAF-X refresh and also a load growth update that we'll do for the 2027 IRP.

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, I would say a high probability. But we wait to see what the data actually indicates.

And Michael, this is Brian. I think from the financial side, what we look at is that you've got large load revenues on one side that certainly are helpful. The other side of the equation though is plant that goes into service. So in 2026 and then 2027, we expect quite a bit of our quip to convert to planted service. If you look at the balance sheet out, it's over 1.8 billion of quip. So there's a lot that sits there as of today. When that converts to plant and service, obviously depreciation starts and a few DC stops. 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 profitable at this point. But again, we're in somewhat of a what I call an NDS 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 I mentioned is on the tractor component. If you file relatively frequent general rate cases because you have so much plant converting, the tractor doesn't have as much value. You also have to be careful to attract a tractor wouldn't be shifting costs to customers that aren't driving any expense. And so the tractor 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.

Sure. I mean, it's a projection that we do all the time in our forecasting. There's a possibility that occurs, but I think to look at it as 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 over earn 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 know, you've seen us reduce our ADI-TC expectations for the year already this year, and they're significantly lower than last year. So, you know, things like weather conditions or outperformance on large load expectations compared to what we have in our forecast certainly drive us more towards over earning, certainly the base level for the ADI-TC mechanism and then potentially even up from there.

I wouldn't look at it that way, Chris, because, you know, 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 my problems load ramped in their special contract. You can see that, you know, 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, you know, if you look at things like data centers, their rampups can be, you know, premenced on what, you know, server racks are installed 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 you only have one 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.

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

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

You know, we talk about that from time to time. You know, one thing we have to watch for on that is, you know, credit rating implications of that, that, you know, the credit rating agencies have complimented 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 of financing approach has been successful for us in terms of interest rates and otherwise, and just interest 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, to our equity transaction that I support. But in terms of hybrids, mandatory convertibles, I would say those are not something that we've taken off the table, but it's thought 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, you know, large contract needs for EDCs and our generation resources. And are just big capex build out. And we've done some of those things like requiring payments from some of the customers up front for some of this.

So we have other mechanisms in place that we use, but, you know, 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 loves 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.

I think that's entirely possible, Chris. I mean, it's just, I couldn't have forecasted, you know, what's happening to us right now five years ago or ten years ago. But I think the bigger constraint right now is just the commercial availability, because I don't even know if the $150 is a price that you could actually go buy once for. So I think there's a little bit of TDD 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, turns out price does matter still. So I think we'll have to wait to see on what happens in the future.

Thanks, Red.

Hi, Brian. Hey, just on the 21, 2031 32 RFP. Is it still 200 megawatts for 31 and then greater than 200 megawatts per 32 or could it possibly incorporate some of the incremental load that micron FAP to might need. As you move through the year, potentially signed to the ESA.

This is Adam. That's 200 megawatts was, first of all, it's a perfect capacity. So as opposed to kind of renewable capacity, but it would really was a minimum for our standpoint.

We use the 2013 20, excuse me, 25 IRP to develop that number and since then, obviously we've had a large load to come in and change change what our outlook is. So we anticipate probably having to go a little bit higher than that in terms of how high we'll have to see how the forecast come in, which I think will be providing to you on a November time frame.

No, it's a good question, Brian. At that point, 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 FAP to, we would probably just increase the amount of resources we would either fill their purchase through the 2032 2031 IRP. Well, I think that's where the six gas projects, the six gas projects of self build in the current RFP might might accomplish that.

Yeah, we had eight overall projects that we've been in six of them were cast, but of course, you know, other entities been in 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 auto power projects that made that short list or not. But at this time, we feel really good about projects. We've been in their competitive from our standpoint. And so we'll see how they competed in the RFP.

About 156 million as of 30. And then we'll ask the incremental credits this year through battery storage assets that we installed. And I'll put it in line of state ITCs that will be added to the mechanism.

Yeah, it's a great point. I mean, that's one of the factors that we consider in deciding whether or not to file a rate case is the ADITC mechanism. And how many credits do we feel we may need to use? The evaluation we'll do under this one is for 2028, right? And so, we'll be looking at what are large load 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 in 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, we may decide to file the rate case depending on how that mass 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 ADITC. And so, we look at where we might be relative to that threshold level in determining whether or not to file a rate case.

Yeah, Alex, this is Adam. The RFP results would come out here in the next month or so, and then the new forecasts related to the new IRP, I think would be released to you all right around November.

That's all right. That's the time that we have to have our new forecast established. You eventually have to lock it down for purposes of the 2027 IRP. 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, you know, 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 include 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, you know, implementing resources from the list. Or if their online days 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 pre-planning. So we're certainly doing pre-planning around those loads already.

It's just a great point. And I think, you know, we talk a lot about our pipeline. And so it seems like it's this 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, you know, another tranche of new requests that build 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 analyses to the extent those customers want to go forward with those construction agreements or analyses. So it's a tremendous amount of work, exciting times for sure.

And maybe just one quick note, even though we may have a short list, we often 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 negotiation that could take another couple months.

Thank you to everyone for joining us today, and for your continued interest in IDA course. Always great to hear from you. So I hope you all have a great evening, and we will see you all soon.