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. If you need assistance at any time during the presentation, please press star zero on your phone. I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance, and Risk.
Thank you. Good afternoon, everyone. We appreciate joining our call. The slides we'll reference during today's call are available on IDACORP'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 in our filings with the Securities and Exchange Commission. As shown on slide three, also presenting today we have Lisa Grow, President and CEO, Brian Buckham, CFO, and John Wonderlich, Investor Relations Manager.
Slide four 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 nine months of 2026, diluted earnings per share were $5.76 versus $5.13 in 2025. Those results only include additional tax credit amortization of $6.3 million in the first nine months of 2026 versus $39 million in the first nine 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- $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. Thanks to everyone for joining us today. I will 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 five, our customer count has increased 2.2% since last year's third quarter, including 2.4% growth in the residential segment. Of 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 are seeing significant revenues coming in from large contract customers as they construct their facilities and come online. We are 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 have included photos on slide six, so you can see the scale of these projects as well as a couple others. Our preliminary load growth CAGR for the 2027 IRP is 8.9% for retail sales for the next five 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 . To put this in perspective, that is a load forecast of about 19,000 GWh in 2027, growing to about 29,000 GWh by 2032. This growth is substantial, and we are 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 have already discussed, there is 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 have received 76 inquiries from projects with energy needs greater than one 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 Perpetua Resources' Dibbie Creek project, which will support domestic production of critical minerals and strengthen U.S. supply chains. 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 are proud that our prices remain 20%-30% lower than the national average. As shown on slide eight, since 2016, average national electric rates have increased 41%. Rents in Boise have 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 pays 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 nine, you can see some of the contract protections we target in energy services 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 pays 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 the 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. Additionally, we've installed around 100 mi of conductor. B2H remains on schedule for an in-service date in late 2027. In addition, construction in Nevada continues on the SWIP- 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 three company-owned natural gas-fueled projects. Construction is underway on a 167 MW resource we're 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 MW project scheduled for operation in 2029, as well as the 430 MW Peregrine project, which is slated for 2030. We've executed equipment supply agreements for all three 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 least cost, least risk resources. Looking ahead to additional capacity and energy needs, our evaluation team received more than 100 bids 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 shortlist, and we were pleased to have competitive bids.
In fact, the 2031 South Hills 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 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. Finally, as the Oregon sale goes, we continue to expect the sale to close in the spring of 2027, pending successful regulatory outcomes.
We recently received FERC's approval and the Oregon and Idaho State regulatory processes continue. With that, I will turn the time over to Brian.
Hi, everybody. Thanks for joining. I am 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. 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 are 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 plants and our wildfire 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 is also not surprising because we continue to invest heavily in system infrastructure to support increasing customer demand, so we have more plant 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 through the power cost adjustment mechanisms. That was in large part due to updates to the Idaho jurisdiction PCA mechanism base in last year's rate case. Lower property tax expense also contributed to this benefit and was the result of a change in law in Idaho in 2025. Our non-operating expense increased slightly as higher CWIP balances, driven again by heavy infrastructure investment, led to higher AFUDC, which mostly offset higher interest expense. If you take a look at the balance sheet, you will see CWIP was over $2.1 billion at quarter end, which really illustrates Lisa's point about how busy we have been as a company. That is, of course, the beauty of financial statements.
Sometimes the numbers alone tell a story equivalent to elegant prose. 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. Amy mentioned that Idaho Power recorded just over $6 million of additional ADITCs so far this year, compared to $39 million recorded last year over the same time period, so a positive stark contrast there. I think that is particularly notable given the higher estimated year-end book equity in the Idaho jurisdiction this year, and it is demonstrative of the strong financial performance the company has had so far this year. We have 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 impacts of company-owned projects selected from the 2032 RFP, at least 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. 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. We have intentionally pre-funded our equity needs so we can blend debt and equity to remain around our target 50/50 debt equity capital structure. At the end of Q3, without counting unsettled 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 will refresh it for our Q4 call with the related refresh CapEx look. As you can see on slide 15, we have already solved for the bulk of our current plan's 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 forwards and payment timing, reimbursable customer funding, and other approaches. Related to that, with recent increases in volatility and interest rates, I thought it would be good to talk about interest expense going forward. We are fortunate to have limited long-term debt refinancing requirements over the next five years, with just $80 million maturing in 2030. We also do not 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 to 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 a 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 CWIP to plant in service until 2027.
Those are projects like B2H or other transmission projects, hydroplant refurbishments, and system hardening that benefit all customers, just as a few examples. Contrast that with the infrastructure we build for large contract customers, which we recover 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.
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 two years into more than doubling our rate base over a five-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 at the upcoming EEI Financial Conference in sunny Arizona. As many of you know, it's one of my favorite events of the year. 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-$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-$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 hydropower generation to be within the range of 5.5 million-6.0 million MWh for the year. With that, we're happy to address questions you might have.
We will now begin the question and answer session for attendees who have joined the Q&A line. If you would like to ask a question, please do so by pressing star one on your phone. Please ensure your mute function is turned off before you ask your question. We will take as many questions as time permits on a first come basis. Once again, please press star one on your phone to ask a question. Your first question comes from the line of Shar Pourreza with Wells Fargo. Your line is open. Please go ahead.
Hi, Shar.
Good afternoon. Good afternoon. This is Whitney Mutalemwa on for Shar.
Hi, Whitney.
Yeah. Thank you for taking my question. Assuming the shortlist is larger than the committed forecast, what has to happen before you contract beyond committed need? Does a pipeline customer have to sign and now get commission approval within the 270 days before you would commit to more self-build?
It can be that, but also, anytime a customer, there is a signed ESA or they have made a significant financial commitment, then we would add them to the load forecast.
So it does not have to necessarily go all the way through commission approval.
Okay. Understood. Since the 29,000 GWh 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 MW, and I know that number seems familiar. We've said that number for several calls. Only it's not the same 4,000 MW, because as projects go into construction, we move them out of that as other projects come in. I think, do you want to add something, Adam?
Yeah, I think you mentioned the 4 GW, and that's what we've mentioned in the past. Just a couple quick things. The 4 GW 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 GW we talk about is truly a future pipeline. Of that 4 GW, I'd say 1 GW is what we often refer to as promising. It usually includes a financial commitment, and those entities are moving towards construction or potential construction. We have another 1 GW of the 4 GW 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.
Then around 2 GW of the 4 GW feel preliminary is, a lot of times, what we refer to them as. But we have another 3 GW that have come in the door since we talked about the 4 GW number. So really, 5 GW are preliminary, and again, another 1 GW is promising and another 1 GW is being studied. Just to give you an overall look at where we stand.
Yes, I'm all set. Thank you, Lisa. Thank you, Adam.
Thanks.
Your next question comes from the line of Michael Lonegan with Barclays. Your line is open. Please go ahead.
Hi there.
Hi, good afternoon. Thanks for taking my questions. On the RFP, I understand the total resources on a 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. Then, on the self-builds, can you talk about the timing of when the capital will start being spent and the profile of that investment?
Michael, this is Adam. I think with slide 12 that we showed you, it shows a resource for 2031, and that resource is the 430 MW gas plant. It's actually an advanced simple cycle plant. We have started moving forward with that project. The turbines have been reserved, the EPC contract has been awarded, and it was the number one ranked project for that year. I think the project we're really diving deep into right now is the 2032 project that is 432 MW. That's a combined cycle plant. That was also the number one 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 2020, 2028, 2029, 2030, 2031, and 2032.
We have transmission lines that we're building during that period too. So it stays 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 forward a little bit earlier than we used to. So you'll see some of that spend a little bit, can be years in advance of actual project going into service.
Thank you. Then that spend, I think you alluded to it could be at the incremental capital, could be at 50/50 equity debt. Is that correct?
Yeah. This is Brian.
The incremental cost 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 to that. For example, there may be some instances where a customer upfront funds a portion of one. There may be opportunities for build-transfer arrangements that put the payment schedule later in the cycle. With that I mentioned typically it's milestone payments, but that's something that's up for discussion as we go through our RFP processes. What I will say is, the CapEx forecast you've seen in the past, neither of those two plans are in that CapEx forecast. Those would be entirely incremental to what you see if they were to move ahead.
Thank you. Lastly from me, on Micron Fab 2, just wonder if you could share the status of negotiations, and when you expect to sign an ESA. I think, you previously said before year-end. Is that still the expectation, something very near term, next couple of months?
Well, we certainly are continuing to work with them. We feel like it's going well and certainly we're hopeful that we'll meet those timelines. You'll see the filing when we do.
Okay. Thank you very much for taking my question.
Thank you.
Thanks.
Your next question comes from the line of Chris Ellinghaus with Siebert Williams Shank. Your line is open. Please go ahead.
Hi, Chris.
Hey, everybody. How are you? Just looking at slide 12. You've had a continuous flow of new resources. At what point does a conventional combined cycle start to make sense to sort of fill in or get slightly better efficiencies?
Well, we certainly would've taken a few of those if we could've got them by now. But certainly, when you start looking into the 2032 range, I think that's when, that's a combined cycle.
Yeah, Chris, this is Adam. That 2032 project, that's 432 MW. That is a combined cycle project.
Okay. Can you qualify the quarter in terms of what the weather benefit looked like for the period?
I am not sure if I have that. Do you have that, Brian?
Yeah, I can give you some indication on that. One of the big drivers, of course, was with irrigation, 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. 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 does not have as big of an impact on them. But, for industrial and special contract combined was 5.8%, and that is sales volume, so a pretty significant increase. Then Lisa mentioned the other side, the revenue side, 27% increase from the large load customers.
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 was not 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. Brian, given the dividend payout target, you are 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 are willing to get to? Or just what are your thoughts? Because it is not that far off.
Yeah, 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%-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 future. 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, the preliminary numbers in terms of load growth have accelerated a little bit. How much of that is a function of some of the big items, the big-ticket items like Micron Fab 2, and how much of that can you 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 Micron Fab 1 and Micron Fab 2. 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 can't necessarily talk about it, but it has other diverse loads. It includes Perpetua, it includes INL and Chobani. So that's 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-
It is over, yeah.
is residential. We are 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, if Micron were to move forward with a Fab 3 or Diode, which we have 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.
Okay. That is really helpful. I appreciate it. All right. We will see you in a week or so. Thanks. Appreciate it.
All right. See you then, Chris.
Your next question comes from the line of Brian Russo with Jefferies. Your line is open. Please go ahead.
Hi there.
Hi, good afternoon. Just to try to triangulate the 8.9% IRP load growth with the 2032 RFP. In theory, what does that RFP imply in terms of 2032 needs?
Sorry, I didn't hear that last bit.
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 MW combined cycle plant. It feels like it's going in that direction, but we still need to look at the load forecast, a few other things, then we'll make a decision on that front. But to your point, 2032 is likely going to need some resources, or it's going to need something in addition to what we have in 2031.
Okay, got it. Then just given the pipeline that you discussed earlier and this new IRP, should we expect a similar cadence of annual RFPs even past 2032, like we've likely seen the past four or five years? Is there still a lot more load behind, say, Micron Fab 2?
Certainly. As load continues to come in and we continue to negotiate these ESAs, it is possible, absolutely. And that's been the nice part about our growth story, is we are seeing into the 2030s with some of these customers. But of course, it will be contingent upon the final negotiations. But yeah, from where we sit, I think it's possible.
Okay, great. Well, thank you very much.
Thank you.
As a reminder, please press star one to ask a question. Your next question comes from the line of David Arcaro with Morgan Stanley. Your line is open. Please go ahead.
Hi, this is Alexandre Zimmermann for Dave. Thanks for taking my question.
Hi.
Starting with the ADITCs, you now expect to use less than $10 million this year. Looking forward, do you think you could be earning above the minimum ROE in the next two years and no longer be requiring the ADITCs?
Well, that will largely depend on the project timing and the financing plan, but certainly our goal to use as few as possible. What would you add?
Yeah, Alex, just looking at each individual year. This year, with a number of less than $10 million, it is possible to get down to zero and grow above that. It 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 have really focused on is just what is happening operationally in 2027 from a plant closing perspective. So you see a lot of CWIP convert. When that happens, if there is no rate change that will accommodate that at the beginning of a 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.
Then 2028, if we file a rate case in 2027, then 2028 would have the benefit of that rate case.
Again, you have quite a bit of plant going into service, but a lot of that is offset by large contract customer revenues. That is the analysis we have to look at every year. But as I look at 2027 now, we will give our forecast for earnings and ADITC usage in February, but my preliminary thoughts are, I do believe we use ADITCs in 2027.
Got it. Very clear. Then moving to supply chain, you have a large CapEx spend ahead, and you have signed more contracts since the last update. 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? How much of that is already procured or on track?
As far as the turbines go, we either have reservation agreements or supply agreements, so we feel really strong about the plant. Of course, there's always the breakers and transformers and conductor that just seems to be a challenge, but we get ahead of it. 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. 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.
Got it. Very clear. Thank you so much.
Thank you.
Your next question comes from the line of Nicolas Woods with Bank of America. Your line is open. Please go ahead.
Hi. Good afternoon, team. Hey, maybe could you just give me a sense, which data center loads that were mentioned earlier are already included in the demand assumptions underpinning the 2032 RFP?
Yes. This is Adam. So the 2032 RFP would've had just one data center, which is Meta 1.
Okay.
So any other 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. 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?
It's generally, we look to file in June. We have to give a 60-day notice of intent to file in Idaho. That's how we're thinking about it, when we feel like we'll have a good look at what we have coming at us. I think that's generally what we're focused on.
Yeah, and this is Brian. I'll just add that by the time we have the fourth quarter call, we've done some of our early analysis. It takes so long to put a rate case together that we'll at least have some preliminary financials that'll give us the ability to make a preliminary call on whether we file a rate case or not. It is, as Lisa Grow mentioned, that notice of filing that's the definitive moment of that. We may be able to give a little bit of insight on the Q4 call.
Okay. Got it. Thank you so much.
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.