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Welcome to IDACORP's Third Quarter 2025 Earnings Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP's website. [Operator Instructions]. I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

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

Thanks, Amy, and thanks to everyone for joining us on the call. Let's start with a look at customer growth and economic expansion. As you can see on Slide 5, our customer base has grown 2.3% since last year's third quarter, including 2.5% for residential customers. We continue to see robust activity across several sectors, including manufacturing, food processing, distribution, warehousing and technology. Micron's 2 fab projects remain a cornerstone of our industrial engagement. The 2 fab expansion represents the largest private capital investment in Idaho's history and underscores our region's growing prominence in advanced manufacturing and technology. In parallel, we're actively engaging with several Micron suppliers planning to establish operations in the Treasure Valley. Perpetual Resources, another new large customer recently achieved a significant milestone in its mining project by transitioning from permitting to development. The project broke ground earlier this month, marking a new phase in Idaho's mining sector. We're also seeing increased momentum in agricultural-related projects in the southern part of our service area. These include cross-vent barnes, rotary milking parlors and biodigesters that will contribute to load growth while supporting energy production through renewable natural gas. Our new large load pipeline remains very robust. As we've previously communicated, our load forecasting methodology remains conservative and disciplined. We don't include new large projects in our forecast until contracts for the procurement and construction are executed, which occurs after we've identified how to serve the customer. This approach ensures that only viable projects are reflected in our projections. Now the laws of physics are unyielding. So we are working hard on creative options to serve these new large loads while ensuring the system remains reliable and affordable. As we work with these new loads, I want to emphasize Idaho Power's continued commitment to customer affordability. We work hard to keep our prices among the most affordable in the country. And according to national data compiled by the Edison Electric Institute, Idaho Power's customers' bills remain 20% to 30% lower than the national average. We strive to achieve a thoughtful balance between growth and affordability in part through the design of pricing and contractual provisions for new large load customers guided by a long-standing growth pace for growth philosophy. As shown on Slide 6, our residential customer rates -- our residential customers' rate increases since 2014 are much lower than the national average and the steep increase in consumer price index in recent years. Shifting gears and turning to Slide 7. We remain full speed ahead as we execute on key projects. Most notably, work is progressing quickly on the Boardman-to-Hemingway transmission line project. Several towers for that project are now complete. We're thrilled to have steel on the ground on this key resource for helping us access reliable, affordable energy in the Northwest. We continue working through the regulatory and permitting processes on the Gateway West and Swift North transmission lines, and we look forward to moving both of those projects into the construction phase, hopefully soon as they are necessary resources. As I touched on during the last call, recent policy changes impacted the permitting of the 600-megawatt Jackalope Wind project that we plan to have in service by 2027. As a result, we terminated the agreements we had for that project, both the ownership and the power purchase components. With the wind project's agreements terminated, we're busy identifying power supply solutions to meet future load growth. These solutions could include short-term market purchases, natural gas projects and potentially additional solar and battery storage resources. We're in a continuous state of planning and execution to affordably serve the growing demand with a reliable mix of generation resources. As described in our IRP, natural gas resources are a good operational fit for our system as well as a lease cost, lease risk resource. Idaho Power is planning a 167-megawatt expansion of the Bennett Mountain gas-fired power plant, which will help serve load during peak times. In September, we received a pre-permit to construct from the Idaho Department of Environmental Quality, which allows construction to begin. We've also submitted a certificate of public convenience and necessity for the project to the Idaho Commission. If approved, we expect to begin construction in the spring of 2026 and bring the project online in 2028. As you can see on Slide 8, there's lots of work going on in the RFP space and lots more to come. The Bennett project is an important step in helping to solve our future power supply needs. We're continuing to work through the resource selection process, and we anticipate being able to provide some updates on additional selected generation projects on our year-end call, if not sooner. The next 2 slides highlight the news in our pending Idaho General Rate Case. We recently reached a settlement with new rates designed to increase annual revenues by $110 million or 7.48% effective January 1. Additional details of the rate case settlement include a 9.6% ROE, a 7.41% overall rate of return and a $4.9 billion Idaho jurisdictional rate base, excluding coal plants that are under separate mechanisms. There were no capital disallowances in the settlement. Our ADITC mechanism remains in place with a $55 million annual cap for 2026 and thereafter. Also, all existing ADITCs not currently included in the mechanism and all investment tax credits generated through 2028 will be added to the mechanism. We view the settlement as a constructive outcome that helps us continue to safely, reliably and affordably provide electric service to our growing service area. The settlement requires approval by the Idaho Public Utilities Commission. And based on prior cases, we expect the commission will issue an order on the settlement sometime in December. Turning to Slide 11. We filed our 2026 Idaho Wildfire Mitigation plan with the Idaho Commission earlier this month. It's the first wildfire mitigation plan being filed pursuant to Idaho's new Wildfire Standard of Care Act and it outlines our proposed methods of mitigating wildfire risk and hardening our system. As a reminder, the Wildfire Standard of Care Act was signed into law earlier this year. The law empowers the Idaho Commission to set clear and consistent expectations for utilities wildfire mitigation efforts. Under the law, stated generally, utilities are assumed to be acting without negligence if they follow a commission-approved wildfire mitigation plan and provides up to 6 months for the Idaho Commission to review and approve the plan after it is filed. So with that, I will turn the presentation over to Brian for a financial update.

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

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

[Operator Instructions] Your first question comes from the line of Bill Appicelli with UBS.

Just a question around the medium generation needs and some of the considerations you are making around the change with the wind farm. So can you just maybe remind us what was in the capital plan for Jackalope? And then what are the sort of potential solutions and the time line for that?

Well, I'll start. I'll have Brian go over the numbers. And certainly, as we shifted away from the wind project and we're reviewing what the opportunities are for replacement, we only have the really Bennett to talk about today, but it's worth noting that it was 600 megawatts of wind. So it won't be a megawatt per megawatt replacement. We do -- as I mentioned in my comments, gas is showing up in our IRP and we are certainly looking at those options as well as others as we work our way through the RFP process. So do you want to talk about what was in the budget, Brian?

Sure, Bill. So one thing I'll mention about the Jackalope Wind project is that the spend for that project was consolidated in the years 2026 and 2027. So when you look at our capital stack, that's where you'll see the generation resource for that. Now 300 megawatts of that was owned, 300 megawatts was PPA. We don't have the exact number to give you in terms of the cost because it's competitive information. But I will say that if you use typical wind pricing on a 300-megawatt project, there's also some interconnection costs associated with that, that given the location were relatively high. Though it was a pretty significant piece of capital in our stack, but as we're looking to the future, I think there's some other pretty significant bias to the upside on capital from some of the other resources that might be coming out of the RFP process.

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

Yes. So we're still working through the 2028 and 2029 RFP processes. Just as a reminder, the 2028 process, Idaho Power has 3 projects on that final shortlist. On the 2029 shortlist, we have 4 projects, Lisa mentioned the Bennett Project. So we're going to continue to work through those to see how to replace that capacity in 600 megawatts, but Jackalope was mainly an energy resource for us. The effective load carrying capability was about 90 megawatts. So that's what you'll see us try to replace from a capacity perspective. Lisa also mentioned the IRP shows gas in the future in 2029 and 2030. There was only 1 gas bid that made the 2029 RFP. So we'll have to consider other options there as well as we evaluate our future in the gas space.

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

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

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

Are you talking about the load growth or the actual?

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

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

We've been consistent kind of in the -- this is Adam, the 2.3%, 2.4%. That's meter growth. That's per customer or customer meters, really where we're going to see and continue to see more substantial growth is in the manufacturing area, and we expect that to happen here and ramp up over the next couple of years.

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

Right, in terms of total load growth, right?

Yes. And that's each year over the next 5.

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

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

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

So residential customer growth slowed sequentially from the last few quarters. Is that telling us anything about sort of how the ramping of staffing of the new customer loads is going? Or is that telling us anything about some slower economy overall? Is that like the labor market has slowed a little bit. What can you say about that?

Well, certainly, on the large loads, I mean, right now, it's mostly construction personnel that are there. So I can't really say too much about what their final load growth will be. But I think the interest rates have impact. I think where you are in the year has impact in terms of people's ability and willingness to move. And I do think there probably is a little bit of softening in the economy, just given so much of the uncertainty out there. But there's not really any big trend that we're seeing that we're concerned about.

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

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

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

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

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

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

Yes. And this is Brian. If you look at just the third quarter, a modest downtick in irrigation loads. But if you look at the 9 months -- the first 9 months of the year, kind of a modest increase, right, that you see overall. So June usage was high both years. June 2025 didn't have precept, right? And that's a big driver. It turns out the amount of precipitation not just the temperature. We saw an uptick in precipitation actually, in the third quarter, but nonetheless, still has a pretty strong quarter for irrigation.

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

Well, certainly, with a lot of the policy changes, that has changed the economics of renewables for sure. So that has an impact in how those inputs go into the model. And we'll see sort of what -- on the short-listed projects, their ability to meet the terms that they were selected on given those changes in policy. Anything you would add...

Chris, maybe I'll just add, you're right. 2029 had a gas plant, 2030 had a gas plant. If you look at our 2029 RFP, and it was actually 2029 and later, there was only 1 gas plant that was part of that RFP. So just by virtue of seeing what's lease costs, lease risk in our resource portfolios, we're going to have to start looking to see what might exist beyond the RFPs in that 2030 range.

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

It's Brian Russo on for Julien. I think you may have just answered my question, but I'll just ask it again anyway. Given that you're really the only bidder of gas generation in the RFPs, is there an alternative to the RFPs to expedite the process, considering the long lead time to secure turbines, et cetera, and given the profile of your customer and the demand that you need to meet as we move towards the end of the decade. I was just curious if that was even considered?

Well, we're certainly considering all options, and there's -- it's just an incredibly dynamic environment from which to try to plan and execute quickly. So we will report back to everyone next quarter when we have a little more insight as to what those alternatives will be.

Okay. Great. And then I think given that you can only get Bennett in service by 2028, right, that's a year after, you were hoping to have the Jackalope capacity. And you mentioned 3 alternative short-term purchases, I think the second one was gas and the third was solar and battery storage. I suppose that your preferred choice is to own something, but it doesn't seem realistic to own any gas generation that soon. So with solar or battery storage, be kind of the next preferred scenario to replace Jackalope?

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

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

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

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

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

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

This is [ Alex Herman ] on for Dave. Could you talk about the priorities for your next rate case and especially related to potential tracking mechanisms. How important is that to your plan? And how do you see the regulatory support for that in Idaho?

I just want to make sure that I heard the whole question. So we are very sensitive about rate cases. We want to make sure that we're being careful about meeting our obligation to serve, but also keeping rates as affordable as possible. And so with -- as we go through time, we evaluate each subsequent rate case and based on the need for what we're spending and if we can cover that with revenues that kind of growth. So it really is a very dynamic calculation as we go through time. We want to make sure that we maintain our financial health as we go through this extraordinary period of growth. But certainly, rates are -- rate cases are part of that calculation as we go through time. Is there anything, Tim, that you would add?

Yes. Thanks for the question, Alex. It's a great one. We just filed our 2025 general rate case settlement stipulation last week. Timely question. I've met with a few folks this morning to start talking about it. And we are working on trying to assess the timing and need of our next case and what elements might be included, whether it's a traditional case, whether it's a case that has a tracker, all of that's on the table at this point. But the plan is in development and in early stages. So we'll have to report back more later.

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

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

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

I just want to follow up on one of the Bill Appicelli's question on the Jackalope project, the loss of 300 megawatts, I guess, in your capital plan, I know you talked about the transmission and maybe you'll meet the generation need. But is there offsetting CapEx that goes into your forecast? Or should we expect a dip from what you previously thought 2027 was going to be now that Jackalope is being canceled?

Yes, great question, Anthony. So we typically update our capital forecast every February on the Q4 call. The last couple of years, we've done an interim update just based on the outcome of RFPs and resource procurement. I think you should expect us to do that potentially this time as well. I mean we've talked about the Bennett plant, but that is an inadequate resource to cover the load growth that we have going forward, even for just the customers we've announced so far, the ones that are in the construction phase or that have executed agreements with us. There are incremental generation requirements in there, and they are not reflected yet in the capital stack. But as we solidify those, we will add those to the capital stack. You'll see Jackalope come out, you'll see Bennett go in. And then by the time we get to that update, I would expect to see incremental resources in there as well as project costs and timing adjustments that we typically include in our annual update. So that may be in the Q4 call, it may actually be sooner that you see some of that coming to fruition possibly as early as this year, starting to see some incremental generation resources being added depending on the outcome of our processes.

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

No. It's just getting through the procurement process. Sometimes that can be a relatively lengthy process and it is a competitive process. So identifying whether or not we've been the successful bidder, negotiating with the actual suppliers and vendors and ensuring we can meet time lines are all factors that go into whether or not that will be a 2025 announcement or not. And it's also a confidential process that we have as we negotiate with those vendors. So there's not much we can release until we've gotten to a point where we're very comfortable in the fact that is a winning project. And then we'll announce what it is and magnitude and add it to the capital stack.

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

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

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

Actually, I would think the equity need would go the other direction in the near term, Anthony. And the reason for that was I mentioned the Jackalope Wind project had 2 large payment obligations in 2026 and 2027. As we look at removing that and replacing it with potentially more traditional timing of payment like for a gas plant, for example, those tend to be spread out longer and that can actually reduce our near-term equity need by pushing out the capital requirements until further in our 5-year window. So we can see a reduction in near-term equity and overall equity just as a result of the payment timing for CapEx. On the credit metrics side, we did have this rate case outcome. We do believe it to be -- the settlement is a balanced settlement certainly and constructive, but it does help on the credit rating side as does the outcome of the Hells Canyon AFUDC case. So we see ourselves naturally progressing out of being near the threshold for both Moody's and S&P without having to issue incremental equity in the near term.

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

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