Welcome to IDACORP First Quarter 2025 earnings conference 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 you 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 earnings guidance, spending forecasts, financing plans, regulatory actions and plans, 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. Our cautionary note on forward-looking statements and various risk factors are included in more detail for your review in our filings with the Securities and Exchange Commission. As shown on slide three, we have Lisa Grow, President and CEO; Brian Buckham, Senior EVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager, presenting today. We also have other members of our management team available for a Q&A session following our prepared remarks. Slide four shows a summary of our first quarter results. IDACORP's diluted earnings per share were $1.10 compared with $0.95 for last year's first quarter. Our key operating metrics and guidance are unchanged except for our hydropower generation forecast, which has improved. We're reaffirming our full-year IDACORP diluted earnings per share guidance range of $5.65–$5.85. This includes our expectation that Idaho Power will use between $60 million and $77 million of additional tax credit amortization. These estimates assume historically normal weather conditions and normal power supply expenses for the rest of the year. Now I'll turn the call over to Lisa. Thanks, Amy, and thanks to everyone for joining us on the call today. I'll start with a look at the continued customer growth and economic expansion happening across Idaho Power's service area, as you can see on slide five. Our customer base has grown 2.6% since last year's first quarter, including 2.9% for residential customers. The first quarter featured several significant new customer investments in the food processing and warehousing sectors. Our existing customer, Chobani, announced a $500 million expansion of its facility in southern Idaho, increasing production by 50% and adding 500,000 sq ft to its plant. The expanded plant will total 1.6 million sq ft, with 24 production lines making it the largest natural food production facility in the country. In addition, the Tractor Supply Company broke ground on a new distribution center in Nampa. The 865,000 sq ft facility represents an investment of nearly $225 million. Many of our large customers are far along in their projects, as you can see the magnitude of two of those projects on slide six. Recall we have another large customer that made a financial commitment and whose load ramp is expected to start in 2029. You can see interest remains high from businesses looking to locate and expand within Idaho Power's service area. As a reminder, prospective customers would be incremental to both our existing anticipated load growth rates and our capital plans. Turning to slide seven, the five-year forecast for retail sales growth is 8.3% annually. This forecasted growth continues to drive our need for additional system investments and power purchases to help meet projected load deficits. Like our customers, we're very much in execution mode. We're making great progress on the projects being built to support our customers. Our 80-megawatt 2025 battery project is on track to be operational later this spring, along with a 150-megawatt storage agreement. In addition, our Boise Bench Battery Storage Project was recently permitted. Our agreements on the 600-megawatt Jackalope wind project, 300 megawatts of which will become our first company-owned wind resource, are pending approval from the Idaho Commission. A solar PPA project associated with our Clean Energy Your Way program also came online. Our update on the ongoing RFP process for 2028 is on slide eight. On March 31, the OPUC acknowledged the 2028 final shortlist, which includes both owned resources and third-party projects. We're currently working through the negotiating and contracting process, and we anticipate providing an update later this year. Transmission is also vital to meeting demand, and our three major projects are highlighted on slide nine. We're working towards breaking ground on the Boardman to Hemingway project this year, with an anticipated in-service date as early as 2027. As I mentioned on the year-end call, we've also entered into an agreement to become a partial owner of the SWIP North project. We expect construction to begin as early as this year and take approximately two years to complete. The Gateway West transmission line also remains in our plans. We've initiated permitting and preliminary design activities and are coordinating with PacifiCorp on the timing to best meet customer and system needs. We're pressing full speed ahead on bringing these important projects online to help meet customer demand. As we work to put steel in the ground on new infrastructure projects, we've had a lot of questions about tariffs and executive orders. Idaho Power is actively monitoring the situation as we remain focused on affordability for our customers. We've reviewed countries of origin for our supplies, the potential impacts, and alternative plans to mitigate those impacts. Tariffs on battery storage assets, in particular, are something we're monitoring because we have several projects in progress. At the same time, we're committed to meeting customer demand and must have the energy and capacity available when and where our customers need it. Switching resources for in-process projects is almost impossible given the demands on our system. Turning to regulatory matters, we submitted to the Idaho Commission a notice of intent to file a general rate case in Idaho as early as the end of May. We expect the process for this full general rate case to take approximately seven months, with rates effective no earlier than January 2026. We expect this comprehensive filing will be similar to the full general rate case we filed in 2023. This filing is necessary to recover on the substantial capital investments we've been making to keep our system safe and reliable. We shared some good news with our customers this spring. The combination of the annual power cost and fixed cost adjustments, along with a filing related to additional collection of AFUDC, resulted in Idaho Power requesting a substantial rate decrease for all Idaho customers. It would be a net 8.3% decrease for residential customers. The power cost adjustment rate decrease was largely due to completing the final year of collection of the 2023 PCA. The AFUDC filing requests recovery of an additional $30 million of financing costs annually related to the investments we've made in relicensing the Hells Canyon Complex. The intent of this filing is to provide incremental cash collection and mitigate future rate impacts once the license is received. We've also requested a price decrease for Oregon customers in our annual spring power cost adjustment. Shifting our attention to slide ten, we received good news from this year's legislative session in Idaho, with Governor Little signing the Wildfire Standard of Care Act. Under this new law, Commission-approved wildfire mitigation plans will establish the standard of care and facilitate access to land for wildfire mitigation work. Some additional details on the legislation are in the 10-Q. Idaho Power has had a wildfire mitigation plan, which includes PSPS, in place for several years, and we continue to actively enhance our plan as we pilot new technologies and approaches. I'll close with a look at hydro conditions. We had a great winter with heavy snow in the mountain ranges that helped fuel our 17 hydroelectric projects on the Snake River and its tributaries. Our snowpack currently sits at 100%, 108% of normal, which bodes well for another year of solid reservoir storage and ability for us to generate reliable, affordable hydropower. With that, I will hand the presentation over to Brian for an overview of our financial results. Hey, thanks, Lisa. Hi, everyone. I'm going to start on slide 11, which has our reconciliation of first quarter results. As you can see, IDACORP's net income increased $11.4 million for the first quarter this year when compared with the first quarter last year. To summarize the quarter, the increase was mainly driven by Idaho Power's higher retail revenues from the January 1 rate case increase, from customer growth, and from recording incremental tax credits this year under the Idaho regulatory mechanism. Those benefits, though, were partially offset by higher depreciation and interest expense from our infrastructure projects. I'd expect to see those trends continue throughout the year. Getting into specifics, a net increase in retail revenues per megawatt hour, which is net of power cost adjustment mechanisms, increased operating income by $11.3 million on a relative basis. This benefit was mostly from the increase in Idaho base rates from the limited issue rate case Idaho Power filed last year. Customer growth increased operating income by $7.3 million, with no slowdown in customer growth during the past year. Usage for retail customer was relatively consistent quarter over quarter. Residential usage per customer increased because lower temperatures in the first quarter this year resulted in residential customers using more energy for heating purposes. That increase was offset by a slight decrease in industrial usage per customer and the effects of customer mix changes, with some customers moving between rate classes with different rate structures. Last, on the revenue side, an increase in the deferral of revenues through the fixed cost adjustment mechanism reduced retail revenues slightly. Other O&M expenses in the first quarter of this year were $7.2 million higher. This was partially related to a roughly $3 million increase in wildfire mitigation program and related insurance expenses. They also increased $1.8 million due to a decrease in grant funding for maintenance work compared to the prior year's first quarter, and standard labor-related costs also contributed to the increase. Depreciation expense increased $5.8 million for the year, which was an expected increase from our continued investment. On a net basis, other changes in operating revenues and expenses increased operating income by $1.9 million. That resulted primarily from a decrease in Idaho Power's share of net power supply expenses that were not deferred for future recovery in rates. That is thanks to less volatile natural gas and power market prices in the quarter. On a net basis, non-operating expense increased $2.2 million in the first quarter. Higher long-term debt balances and an increase in interest that Idaho Power is required to pay on transmission customer deposits were what contributed to the increase. This was partially offset by an increase in AFUDC because the average construction work in progress balance was higher. The decrease in income tax expense that you see was mostly the result of an increase in additional ADITC amortization. Based on current expectations of full year financial results, Idaho Power reported $19.3 million of additional ADITC amortization under the Idaho regulatory settlement stipulation during the first quarter. That was compared with $12.5 million of additional ADITC amortization in the first quarter last year. Remember, we record the ADITCs rationally each quarter based on our full year expectations of financial results. Moving to slide 12, this is really just a reminder on the CapEx forecast we shared on our year-end call. That forecast has us spending $5.6 billion on CapEx over the next five years, and that's double what we spent in the prior five years. Again, the CapEx stack in the two out years isn't fully refined. That's in part because that's a ways out, and we're also still in the RFP process for additional resources, and we expect the costs of any owned resources could land largely in those years. Lisa mentioned that Idaho Power continues to have discussions with prospective new large load customers, and signing additional large load customers could also result in additional CapEx at the far end of our plan to meet those incremental customers' needs. You can now plainly see the actual CapEx materializing in our financial statements. In the 2024 Form 10-K, if you look at the cash flow statement, you'll see additions to PP&E exceeded $1 billion for the first time. Spending continued in the first quarter of this year, and CWIP on the balance sheet as of March 31 is around $1.4 billion. We've been busy executing a capital plan designed to meet customer needs. Our customers have a lot of steel in the ground on their projects, and I think the photos that Lisa showed earlier were illustrative of that. We are working in lockstep to ensure they have the energy when they need it. As we talked about on the last earnings call, building the needed infrastructure is just one step in our execution. We also need to convert it into rate base to keep the utility financially healthy and to provide returns to the debt and equity holders funding our growth. We've replicated slide 13 from our 2024 year-end call, where you can see our then current 2025–2029 estimated rate base and growth rate. Upside to that five-year CAGR could come from things like additional RFP wins or from a change in our regulatory methodology to eliminate some of the regulatory lag we've experienced. Either way, we expect to at least double our rate base in a five-year period. Another part of our execution is our financing plans. I'll have you flip to slide 14 for that. Operating cash flow alone is insufficient, obviously, to finance what we're doing given the magnitude. It is no surprise that we'll need growth capital, like I've mentioned in the past. As we go through this cycle of growth, we're focused on keeping our balance sheet strong, still targeting a 50/50 debt-equity capital ratio. At March 31, you can see that our balance sheet is slightly debt-heavy, which resulted from the $400 million debt issuance we did during the quarter. Not shown on the equity side is around $90 million of stock issuance proceeds held at IDACORP from the November 2023 equity offering, along with over $144 million in to-date forward sales under the ATM program, none of which we've drawn thus far. The balance would be closer to our structural target with those amounts included, likely near 49% equity, 51% debt. At March 31, we also had a relatively large amount of cash on the balance sheet. The bulk of that balance is proceeds from the March debt issuance, which we'll use in the relative near term to fund our infrastructure projects. Slide 15 is another one we included on the Q4 call, replicated here. It shows the amount of external financing we estimated we need for 2025 through 2029 based on capital already in the plan at that time, which is about $1.4 billion in equity and about $2.2 billion in debt. We believe those amounts allow us to stay at our target capital ratio and fund the projects in our plan. This is over a five-year period, and as I've mentioned, the amounts needed in each year will not be equal, but we do have a degree of optionality to be opportunistic on the timing and nature of our debt and equity issuances. With significant revenues anticipated in the later years of our plan, we do anticipate a step down in the amount of our external capital needs further out, but we still expect incremental financing would be necessary for any additional company-owned projects resulting from the 2028 and 2029 RFPs or otherwise. To conclude, I'm going to double down on what Lisa said. We're in execution mode, and we're seeing the benefits of the thoughtful planning we've already done. Several factors are helping with that execution. Starting the permitting of our transmission projects well over a decade ago has been key because the timeline to build transmission is very long. We're issuing annual RFPs for resources to keep up with energy and capacity needs and ensure we get the best price and terms for our customers. We are negotiating with large load customers on thoughtful contract terms that fairly allocate costs and reduce risks. We're focusing on our constructive relationship with our regulators and working to ensure affordability of the service we provide to our customers. To top it off, our team of employees at Idaho Power are some of the smartest and hardest working people in the business. All of those factors help us execute in this period of unprecedented growth. With our customers already far along in their projects, power has to be there when they flip the switch on their facilities, and we're working full speed ahead operationally and financially to ensure we meet that important commitment to our customers. We appreciate that our shareholders and debt holders have been with us as we execute. With that, I'm going to turn it over to John to step through our 2025 guidance and estimated key operating metrics. Thanks, Brian. Moving to slide 16, you can see our 2025 full year earnings guidance and key operating metrics. Not a lot of change from our Q4 2024 conference call. This guidance assumes normal weather and normal power supply expenses for the rest of the year. We continue to expect IDACORP's diluted earnings per share this year to be in the range of $5.65–$5.85, with the assumption that Idaho Power will use $60–$77 million of additional investment tax credit amortization. That $77 million top end is what we currently have remaining in the mechanism. We have the ability to request that the Idaho PUC allow Idaho Power to add additional credits to the mechanism, either from legacy credits on our balance sheet or credits from our current battery projects. We will consider that option in the context of our broader regulatory strategy going forward. Our expectation for full year O&M expense continues to be in the range of $465–$475 million. We still anticipate spending between $1 billion and $1.1 billion on CapEx in 2025, although we have not adjusted our forecast for new tariffs as we continue to evaluate and monitor the situation. Finally, we expect good hydropower generation in 2025, ranging from 7–8.5 million megawatt hours for the year. We have solid carryover from the prior year, and snowpack has been favorable this year as well, as noted by Lisa. With that, we're happy to address any questions you might have. We are now ready to begin the question and answer session for attendees who have joined on 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, that is star one on your phone to ask a question now. Your first question comes from David Arcaro with Morgan Stanley. Please go ahead. Hi, David. Hey, David. Hey, thanks so much for taking my question. Maybe on, let's see, you know, on the wildfire legislation, I was just curious, do you expect any changes to your wildfire mitigation plans on the back of that legislation or just generally any changes to programs that you would anticipate? We don't anticipate any changes in the program. We are hard at work at deploying that now. We are taking a look at the plan as it's written today and may make some modifications, but it would not necessarily be changing any of the actual activities. More to come on that, but we feel really confident in what our plan has us doing now, and we'll continue to evolve it over time. Got it. Okay. Thanks. That's helpful. Looking ahead to the rate case, I was just wondering if you'd be able to share thoughts on what kind of mechanisms or trackers you might be contemplating filing for, whether it's capital trackers or otherwise, just efforts to improve earned ROEs from here. I'm going to have Tim Tatum answer that. He's our VP of Regulatory Affairs. Yeah, thanks for the question, David. We're right in the middle of preparing our case right now. We're considering a number of different options. I can say that we will take some action in the case to request that the Commission help us to reduce regulatory lag going forward or the negative effects of regulatory lag. The details on exactly what we're doing at this point are still sort of in flux and certainly more to come in the next month or so. Yeah, David, and this is Brian. One thing I'd also point to is the Hells Canyon filing that we made on AFUDC that we've talked about in terms of helping to reduce regulatory lag. That's more of an earnings-neutral item, but it does help from a cash flow perspective. That helps on cash lag outside of the general rate case. Yep. Okay. Excellent. I'll leave it there. Thanks so much. Okay. Thank you. David. Your next question comes from Chris Ellinghaus with Siebert Williams Shank & Co. Please go ahead. Hi, Chris. How are you today? Hey, Chris. Lisa, you talked about some of the business development. Obviously, you still have a lot of interest in expansion and moving into your service territory. Have you noticed anything through sort of this chaotic period, any effects on, say, the agricultural community and what kind of crops they're working on, given their expectations on their ability to export or, say, discretionary in-migration or tourism or any of those kinds of things? Yeah. I think, like us, it's a little bit too early to tell. A lot of the agricultural customers, they've made the decision what they're going to plant last season. What they might do in the next season, I think, remains to be seen. I will say there's concerns just given how uncertain things are. I can't really say that there has been anything very measurable at this point in time. We are still getting a lot of interest in what is the inquiries we get. As far as tourism goes, I think that still remains to be seen how that shapes up. This is a state that people that love the outdoors come to, and we haven't seen— I guess we'll just have to let the season sort of play out. I think, Brian, what would you add to what you're seeing out there? Hi, Chris. Yeah. I actually spoke with our irrigation customer representatives a couple of weeks ago. From a planting perspective, they said it appeared to be a relatively normal season. I think commodity prices are not great. Certainly, at some point, the tariffs could have an impact. The boots on ground, the Idaho Power employees that are out there, did not believe it would impact this year. I might also add in terms of on the irrigation side of things, the water conditions are positive as well. That should provide some help to the farmers. Okay. That's great. Given the filing coming up on the rate case, can you give us any thoughts? I guess some of the mitigation efforts that you might put into the filing might give us better insights into this later. Should we sort of be thinking about this as the normal cadence of what you would expect unless there is some kind of breakthrough on trackers or some other kind of mitigating mechanism? I think that's fair to say given the amount of capital in our near-term plans. Of course, as these customers come on and start generating revenue, that may delay some of future rate cases. If there are any sort of mechanisms that come through this rate case, it certainly could change the cadence. Based on what we know we need to spend to meet our customers' needs, we will continue to be filing rate cases more frequently than we certainly have in the past. Anything you would add? I know they have expressed some—I don't know what word to use. Dismay is maybe too strong, but have expressed some issues with their workload. Do you have any capacity to propose anything along the lines of a multi-year mechanism? As far as the PUCs go? Yeah. Yeah. We're willing to talk with them about any sort of creative solutions. We do know that, like our regulatory group, it is a lot of work to process these filings. We'd certainly be open to anything that would help with that. I don't know what else we would add, Tim. Yeah. It's certainly an option that we'll consider. We want to be mindful of the impact of the volume of filings that might have on our commission staff. At this point, I don't think that that's a tool that we're looking at currently, but certainly maybe something going forward that might work. Okay. In light of the success of SB 1183, that's sort of one level of wildfire liability mitigation or alleviation. Would you be wanting to pursue or would be hopeful for another step at the legislature to sort of codify more direct limitations legally on what potential litigants can pursue other than just sort of this type of legislation which says, "We have followed the plan" type of legislation? I think it's important to remember that in Idaho, we have had tort reform. I don't know that we have anything imminent that we would be pursuing. We do feel like this has been a good step to define what a standard of care plan looks like just so that it isn't decided after the fact. We feel like we're in a pretty good spot. Anything you would add, Julia? Hi, yes. This is Julia Hilton. I'm the company's General Counsel. Idaho has really favorable damage caps for both punitive damages and non-economic damages. In wildfire litigation, what we have seen is that the non-economic damages are the ones that tend to really run away. Having those statewide damage caps on non-economic damages is very favorable in Idaho. Okay. Yeah, that's what I'm getting at. Lastly, you continue to have some pretty sizable development in your area. Have you revised at all your thinking on when you need your next dispatchable resource at all? That's absolutely taken into consideration when we do our IRP. We are in the process of doing that right now. Dispatchable resources are showing up in the portfolio for sure. Can you tell us what that timeframe is at this point that they're showing up? Adam, I'm not sure what we have shared publicly yet if it's in a place yet where we're ready to. Okay. We have shared two of the timeframes. 2029 shows a dispatchable resource in 2030 as well. It was kind of a question of whether we might see something in the next couple of years after that as well. We will know more as we work through the IRP process. Certainly, as of right now, it is showing at least 2029 and 2030 and could be more over the next couple of years after that. Okay. That helps. Are you seeing additional or incremental large load customers coming to you, say, over the last couple of quarters seeking interconnection? I do not want to say at a brisker pace, but are you still seeing interconnection requests continue to build in the queue? As far as interconnection requests, that's a little further down in the process. We are still seeing, I would say, the same inquiries, which would then start a process that involves construction studies, etc. I think those are on a pretty similar pace as we've seen in the past. Adam, what would you say about the interconnection requests? That seems like that's at the sort of end of the large load process. I agree. It's been a steady flow of inquiries and requests from large loads. What we're seeing in our queue too is a lot of generation resources showing up across our service territory to help meet that potential load growth. Chris, it's been pretty strong and continues to be strong. Okay. That's helpful. That's exactly what I was trying to get at. I appreciate it. Thanks for the details. Thanks, Chris. Your next question comes from the line of Julien Dumoulin- Smith with Jefferies. Please go ahead. Hi, Julianne. Hi, Julia. Hi. Hi. Hi, it's Brian Russo for Julian. Hello. Oh, hi. Hey, just curious about the 2028 and 2029 RFPs. If there are new large load customers, would that be captured in those RFPs, or would you need subsequent RFPs to meet any incremental demand above what's embedded in that 8.3% load growth rate in the IRP? Yes. When new loads would come on or come into making a request to us, it would depend on what year they would start for sure. It is possible that if we have a number of projects that would meet a need as the need changes, we could certainly contract with those as well. If the customer needs are beyond that in time or amount, we may have to do some other kind of RFP. Yeah. We have to wait and see what is real before we would make that kind of commitment. Okay. Got it. I think on the last call, you discussed that contract negotiations were ongoing with another data center. Is that still the updated status, or is there anything that's transpired since then? Yeah. That is still ongoing. Okay. It looks like, as you highlighted, three transmission projects, right, you can look at your CapEx forecast, and there are some incremental investments there. How should we think about the timely recovery of those types of projects? Would that be separate filings from your traditional base rate filings, or how confident are you for timely recovery of some of these kind of larger projects? Sorry about that. We're not looking at each other. Yeah. I think at this point, we are looking—this is Tim Tatum from regulatory affairs—looking at the rate case and other potential mechanisms to help provide more timely cost recovery of these investments. As I mentioned earlier, those methods are still in the process of being developed and evaluated internally. Our efforts to reduce regulatory lag, provide more timely cost recovery, are certainly underway, and we're hopeful for success in that area. Brian, what I would add—this is Brian—we have not shied away from one-off cases in the past. You have seen us do quite a few of them. To the extent the in-service date of a transmission line lined up well with a general rate case or some form of tracking mechanism, that is another avenue that we have. I would say all options are on the table for those larger transmission projects at this point. Okay. Great. Lastly, could you just remind us how much capacity is in the shortlist that was acknowledged by the OPUC for the 2028 RFP? Adam, do you have that number? I don't have that exact number. I mean, it was several hundred megawatts, maybe even more than that. Just as a reminder, there was an Idaho Power project on that list as well for 2028. It was a fair amount of projects. All right. Great. Thank you very much. Thank you very much, Brian. Your next question comes from the line of Anthony Crowdell with Mizuho. Please go ahead. Hi, Anthony. Hey, good afternoon, team. Good afternoon. Sorry. I think those guys asked all nine of my questions. Just, I guess, a quick follow-up was just on the wildfire legislation. Just anything in the legislation you guys were hoping to get or the utilities in the state were hoping to get that was not included in what passed? I feel like we were really happy that it passed at all, to be quite honest. I can't think of anything offhand that we wanted that we ultimately didn't get. We knew that this is a first step at trying to define the standard of care. That's essentially what this bill did. Is there anything you would add, Julia? I think that this bill does a really great job of establishing a first step and establishing that standard of care, like Lisa mentioned. There was an earlier run of the bill that did not go through. I think that the bill that ultimately passed contained the majority of the protections that we were seeking to achieve. I do think that it's a great result, and we were able to get different industry groups comfortable with it with the final version that passed. Do you see the company in the future looking to push for a fund? It seems that I know every state has their own issues with respect to wildfire, but it seems investors—I think in another state, they were trying to get a fund going. It did not happen, or it is not moving the legislature. Is that something that is on the radar in Idaho, or you do not believe so? It was certainly something that we discussed. The hard part is that Idaho is very small. The amount of money that would be needed to create a fund would fall on a few people. When you have the state of California that can put billions of dollars into a fund, it's not really something that Idaho could do. It was, "Do you look at a multi-state sort of arrangement?" That is always the sort of, "Who pays and who gets the benefit?" It was not one that really we thought was something we could do now, but it's something we could certainly think about. It is also important to remember we do have insurance, and there might be other strategies like a captive insurance product or something along those lines. Great. That's all I had. Thanks for taking my questions. Of course. Thanks for calling in. Thanks, Anthony. A final opportunity. Press star one to signal for a question, and we'll pause for just a moment. That concludes the question and answer session for today. Ms. Grow, I will turn the conference back to you. Thank you again for everyone joining us today. We really appreciate your continued interest in IDACORP, and we hope you have a great evening. Thank you.