IDACORP's third quarter 2023 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, Director of Investor Relations, Compliance, and Risk. Thank you. Good afternoon, everyone. We appreciate you joining our call. This morning, we issued and posted to IDACORP's website our third quarter 2023 earnings release and the associated Form 10-Q. The slides that accompany today's call are also available on IDACORP's website. We'll refer to those slides by number throughout the call. As noted on slide two, our discussion today includes forward-looking statements, including earnings guidance, spending forecasts, and regulatory plans that reflect our current views on what the future holds, but are subject to risks and uncertainties, including uncertainties surrounding the impacts of future economic conditions. This cautionary note is also included in more detail for your review in our filings with the Securities and Exchange Commission. 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. As shown on slide three, on today's call, we have Lisa Grow, IDACORP's President and Chief Executive Officer, and Brian Buckham, IDACORP's Senior Vice President and Chief Financial Officer. In addition to Lisa and Brian, we have other members of our management team available for a Q&A session following our prepared remarks. Slide four shows our quarterly financial results. IDACORP's third quarter 2023 earnings per diluted share were $2.07, compared with $2.10 during last year's third quarter. Year to date, earnings per diluted share were $4.53, compared with $4.28 for the first three quarters of 2022. The year-to-date results include a total of $7.5 million of additional tax credit amortization under the Idaho regulatory stipulation, which is the amount we recorded in the first half of the year. Today, we raised the bottom end of our previously issued full year 2023 IDACORP earnings guidance by $0.10 to a range of $5.05-$5.15 per diluted share, which includes our current expectation that Idaho Power will use up to $10 million of additional tax credits available to support earnings at the 9.4% return on equity level in the Idaho jurisdiction under our current Idaho Regulatory Settlement Stipulation, which is down from the $15 million we anticipated at the end of the second quarter. Now I'll turn the call over to Lisa. Thanks, Amy, and thanks to everyone for joining us today. I want to begin by addressing three main areas this afternoon: customer growth, infrastructure to address that growth, and rate cases. I'll start by highlighting the strong growth that continues across our region. As you can see on slide five, we've had 2.3% customer growth since last year's third quarter. This growth is in line with our—with the trends we've seen for several years now and is readily apparent throughout our service area. There continues to be a number of power cranes visible near our headquarters in downtown Boise, 26 throughout the Treasure Valley area, to be exact, and construction is booming. You can see on the slide that Moody's GDP growth, is that what their growth forecast is. We're working hard to ensure we continue supplying our growing customer base with the safe, reliable, affordable, clean energy they depend on every day. On the large load front, the Stow Company's facility in Nampa went live in October and will ramp up operations over the next several months. In addition, several dairy biogas projects in the Magic Valley completed construction and started operations in Q3. Interest remains steady from customers across a range of industries, including food processing, manufacturing, and data centers. We're continuing to work with Meta on its innovative data center in Kuna and on the Micron expansion, which had its first official concrete pour earlier this month. Micron is also making a strong push to recruit its suppliers to locate facilities near their expansion, creating the potential for additional load. I'm happy to provide an update on the general rate case we filed in Idaho on June 1. Parties in the case have agreed to a settlement of all issues in the case. We filed the settlement stipulation last week with the Idaho Commission, and some of the details are included on slide six. If approved, the stipulation would provide for an increase in annual retail revenues of $54.7 million, or 4.25% on average for Idaho customers, effective January 1, 2024. That's in addition to moving the recovery of certain costs from other regulatory mechanisms into base rates, and Brian will touch on the details of that in a moment. We believe the settlement demonstrates our continued constructive regulatory environment in Idaho. As a reminder, this is the first general rate case we've filed in 12 years. Our case focused primarily on the infrastructure investments we've made to serve our customer base, which has grown by 23% since our last rate case filing. As we look forward to our capital investment plans over the next several years, we anticipate more frequent general rate case filings. We also expect to file a general rate case in Oregon next month. In another positive regulatory outcome, the Idaho Commission recently approved Idaho Power's Clean Energy Your Way program. This program expands clean energy options available to our customers, including a construction offering that allows industrial customers to partner with Idaho Power to develop new renewable resources through a long-term arrangement.... Meta and Micron have agreements in place to participate in this program, which will help them achieve their clean energy goals, while also complementing our goal of providing 100% clean energy by 2045. We've also seen interest from others as well. As part of our efforts to meet customer demand and keep up with growth, we recently filed our 2023 integrated resource plan. Creating a long-term resource plan is an increasingly complex process, and we remain committed to developing a plan that keeps our system reliable while minimizing price impacts to our customers. Filed in Idaho and Oregon every other year, the IRP offers a 20-year forecast for energy demand and a preferred portfolio of resources to help us meet that demand. Slide 7 summarizes some of the notable changes from our 2021 to our 2023 IRP. I think the IRP is worth a review, and in particular, the preferred portfolio that came out of that process. We've been busy with infrastructure development, and the IRP illustrates what we expect to be focused on for energy and capacity in the coming years. One infrastructure addition in particular I wanna highlight is the Gateway West transmission line. In the 2023 IRP, the need for at least one segment of the transmission line moved into our five-year action planning window, and we're now working with our partner, PacifiCorp, to move that forward. This is in addition to the Boardman to Hemingway transmission line, where we have pre-construction and land acquisition activities happening, and construction is expected to begin in the first half of 2024. We believe both lines will be key to maintaining reliability across our system, particularly as we move toward a clean energy future. Beyond transmission, we're making progress on our other energy and capacity resource procurements, and we've included slide 8 to summarize our status. For the RFPs for 2023 to 2025, we've installed 120 MW of the 293 MW of company-owned storage that resulted from those RFPs. Evaluations continue on the RFPs we issued to meet approximately 350 MW of peak capacity needs in 2026 and 2027, which we estimated could be met by up to 1,100 MW of variable resources. We expect some of that energy may be transmitted by B2H. We received over 180 proposals, including Idaho Power's own self-build project, and are working to develop a shortlist. We expect to make the awards in the first quarter of next year. I'll note quickly that FERC recently revised its schedule for issuing the supplemental environmental impact statement required for relicensing the Hells Canyon Complex. We continue to feel positive about the progress we've made toward relicensing, but this development likely pushes back a new long-term Hells Canyon license until 2025 or later. And last but not least, as I reflect on the summer, I'd like to thank our teams for their great work maintaining reliable service for our customers throughout plenty of 100-degree days. Our employees continue to drive positive results for our customers, our owners, and our company. It's been a very busy year, with our typical workloads increasing with the general rate cases, transmission development, reliability projects, security enhancements, and a host of other objectives we've been pursuing. Our remarkable employees have powered through it, and they continue to impress and inspire me. With that, I'll hand the presentation over to Brian for an overview of our financial results and some additional details on our pending rate case settlement. Brian? Thanks, Lisa. Hi, everybody. I'm gonna start on slide nine, which has our reconciliation of the third quarter's results compared to last year's third quarter. Customer growth of 2.3% increased operating income by $4.6 million. Our residential customer growth rate remains strong at 2.4% over that time period, which is slightly up from a quarter ago. Usage per customer decreased operating income by about $17 million in the third quarter, compared with the third quarter of last year. Higher precipitation and more moderate temperatures led irrigation customers to use less energy to operate their pumps, and it caused residential and commercial customers to use less energy per customer for cooling. The impact of the decrease in sales volumes per customer was partially offset by revenue from the fixed cost adjustment decoupling mechanism for residential and small commercial customers. Transmission wheeling-related revenues decreased comparative operating income by $2.8 million, mainly due to less volatile energy prices in the western U.S., which reduced transmission system demand and revenues. At the same time, that reduced volatility helped with power supply costs further down on the table. O&M expenses were lower due to our ongoing focus on operating efficiently and a couple of other things. One was the impact of lower expenses from scheduled cyclical plant maintenance, with last year having an atypically high amount of that maintenance. The other was the timing of regulatory deferrals. Equally offsetting the O&M savings was depreciation expense, which increased by $4.9 million over last year's third quarter. This isn't surprising, given our infrastructure work and the resulting increase in plant and service, and we expect that to continue at an elevated rate with our increased CapEx going forward. Other changes in operating revenues and expenses increased operating income by $5.3 million, primarily due to lower property taxes and a decrease in net power supply expenses that were not deferred for future recovery and rates through power cost adjustment mechanisms. Lower wholesale power purchase volumes and prices decreased net power supply expenses compared with the third quarter of last year. Non-operating expenses increased slightly on a net basis. The allowance for funds used during construction increased as the average construction work in progress balance was higher. Also, interest income increased due to higher interest rates on our cash and investments. These increases were partially offset by higher interest expense on long-term debt. Finally, we didn't record any additional amortization of accumulated deferred investment tax credits in the third quarter, and it's based on our current expectation for the full year. As a reminder, we have a regulatory mechanism that allows us to use a portion of Idaho Power's tax credit balance to help lift Idaho Power's earnings up to a 9.4% return on year-end book equity in the Idaho jurisdiction. At the end of the second quarter, we'd recorded $7.5 million of additional ADITCs, and as Amy mentioned, we now expect to use up to $10 million for the full year. So we didn't report any additional tax credit amortization in the third quarter. We already had it on the books. Combined with nominal impacts from other IDACORP subsidiaries, we saw a $1.1 million decrease in net income over last year's third quarter. But for the year to date, we saw a $13 million increase in net income over the first nine months of last year. Idaho Power moved closer to the company's target debt-to-equity ratio compared to where we were at the year-end. As I've mentioned before, our goal is to maintain our current stable credit ratings, as well as a capital structure near 50 or 51% equity, all in the face of our CapEx plans over the coming years. And to do that, we're still planning to blend debt and equity issuances. We don't have any sizable maturities to address in the next few years, which helps on the debt side and also with our credit ratings. Also, our September debt issuance enhanced our cash, cash position for the near term, and our rate settlement, if approved, would help with cash flows, and that increases our flexibility and our ability to act opportunistically on our equity issuance, timing, and approach. Turning to slide 10, cash flow from operations improved after starting the year, seeing the effects of regulatory lag from abnormally high power and fuel costs. As we discussed on the last call, starting on June 1, we received approval from the Idaho Commission to collect a $200 million increase in power supply costs from customers. Those are for higher power and gas costs over the past year, with collection from June 1 of this year through May of 2025. That rate change has helped improve cash flows from operations, as has moderation in power supply cost volatility as the year's gone on. Again, the rate changes from the Idaho rate case settlement, assuming it's approved, would also benefit cash flows. Looking back in September, IDACORP's board of directors approved a roughly 5% increase in the quarterly cash dividend on IDACORP's common stock from $0.79- $0.83 per share. They've approved a 177% increase in quarterly dividends over the last 12 years. I think that's reflective of our company's commitment to its owners, while at the same time, we've maintained some of the lowest energy prices in the nation for our customers. As Lisa mentioned, relating to our Idaho general rate case filing, parties in the case have agreed to a settlement of all issues. If you joined us late, our summary of the pending settlement is on slide 6. The stipulation provides for an increase to annual retail revenues of $54.7 million, effective this upcoming January 1. That's net of some transfers of cost recovery of base rates, including $168.3 million from current PCA rates and $3.5 million from the energy efficiency rider. The settlement includes an ROE of 9.6%, which would set our overall rate of return at around 7.247%, with an unspecified capital structure cost of debt. The vast majority of the additional reduction from our original ask is regulatory lag, so not capital disallowances, but instead, delayed collection that results from Idaho's use of a historic test year, with only certain known and measurable adjustments, including using a 13-month average on rate base and a retrospective look at labor costs. A part of it is also moving certain items to mechanisms like riders and deferrals for certain costs. That lag in collection, given our CapEx outlook, is what will likely put us in front of the commission with another general rate case or another form of rate request, potentially as soon as 2024. There's no stay out provision in the settlement, so it can accommodate an upcoming request. One important attribute to the settlement that I want to highlight pertains to the ADITC mechanism. The sharing line for the mechanism will now be at 9.6%, and the ADITC usage mark will be reset to 95% of that, which is a 9.12% return on year-end equity in the Idaho jurisdiction. Under the settlement, the investment tax credits generated by the batteries we're installing in 2023 would be added to the existing mechanism. That's probably around $50 million in new ITCs added to the mechanism. As we contemplated in our original filing, a portion of those credits are intended to cover the revenue requirement for those batteries as a rate mitigation measure. Then, under the settlement, which is a notable change from our original application, the mechanism would no longer have a cap on the amount of credits that Idaho Power could use in any particular year, for the current cap of $25 million of additional ADITCs per year would be removed. This is to accommodate the battery storage revenue requirement and also to help provide stability to earnings as we continue our elevated CapEx and work through the regulatory cycle to recover on that CapEx, all while feeling the effects of higher depreciation and financing costs, and the regulatory lag introduced by the historic test year. We view the ADITC mechanism component as a particularly constructive outcome from the settlement. The settlement also has a rate design element to it, where the residential service charge will increase from $5- $15 per month over 2 years, and the small general service charge will increase from $5- $25 per month on January 1. This change helps with the more timely and equitable recovery of our fixed costs. The settlement went to the commission earlier this week during a scheduled decision meeting to reset the case schedule. The next steps in the process include testimony from the parties in the middle of this month, with the opportunity to reply if necessary. Additionally, the commission scheduled customer and technical hearings for the last week of this month. We still expect the case will conclude by the end of this year, and new rates would be effective January 1 of 2024. Slide 11 shows our updated full-year earnings guidance and key operating metrics. As Amy noted, we expect Idaho Power's earnings this year to be in the range of $5.05-$5.15 per diluted share, with the assumption that Idaho Power will use up $10 million of additional investment tax credit amortization. That's down from our estimate of $15 million last quarter. We expect results in the final quarter of the year to benefit from continuing customer growth, O&M, O&M expense management, and hopefully, a sustained moderation in power supply costs. On the other hand, as I alluded to earlier, we expect higher interest and depreciation expense to continue through the end of the year from our CapEx investments and plant going into service. We could also see potentially lower transmission wheeling-related revenues compared to the fourth quarter of last year when we, we saw the Western energy markets with some abnormal volatility. We continue to expect full-year O&M expense to be in the range of $385 million-$395 million, with much of the expected savings related to less scheduled plant maintenance compared to last year and our typical cost management efforts. We're on track with our lower O&M thus far this year. We expect this year's CapEx spending to be slightly higher than our initial expectations, so we've increased our estimate by $25 million to a range of $675 million-$725 million. And then looking past this year, we'll give a longer-term CapEx forecast update on the fourth quarter call in February. Our current CapEx budget for 2024 is trending higher than we anticipated in February this year, and we're expecting it to be in the range of $850 million-$950 million as of now, which is up from our earlier estimate of $800 million-$850 million. We think that theme of higher CapEx will continue in subsequent years as we address growth in our service area. We're currently estimating that our CapEx for 2025 through 2027 will land in the range of $2 billion-$2.5 billion over that three-year period, which is a pretty significant increase from what we included in our estimate last quarter, which was $1.5 billion-$1.7 billion for that three-year period. Currently, our estimates don't include the upcoming RFP results for 2026 and 2027, so any owned resources coming out of those RFPs would be incremental to the amount I mentioned. We'll continue to refine our plans and budgets during the fourth quarter and into early next year, and plan to provide an update on our Q4 earnings call, which is our usual cadence. Finally, given our most recent forecast of hydropower operating conditions, we've tightened our hydro range as we move further into the final quarter of the year. So that's a lot, and I'll stop there, and we're happy to address questions you might have. We are now ready to begin the question and answer session. 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, and 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. We do have a question in the queue. Are we ready to take our first question? Sure, we are. All right, great. Your first question comes from the line of Paul Zimbardo with Bank of America. Paul, please go ahead. Hi, Paul. Hi. Hi, good afternoon, team. At first, very well done on the settlement and, and nice to see in such a quick fashion as well. Did wanna probe into that a little bit, and I think, Brian, you mentioned related to the kind of the 9.1 level for amortization. Is that kinda what we should expect on an earned return basis, kinda as you execute on the high build cycle and more lag? Or are you able to use the sharing credits, or sorry, the ADITC to push you up towards that 9.6 sharing level? Just if you could help unpack kind of expectations there and how the mechanism works with lag. Yeah. So when you've got depreciation and interest expense caused by CapEx, it does in fact create some lag. The ADITC mechanism functions such that we can use the tax credits to get up to the 9.12% level. If we're above that, there's a bit of a deadband until you get to the sharing level at 9.6%. So we'll come out with guidance in February, but in a year like this one, where we suggested that we may be using additional ADITCs, it would look like we would be trending towards that lower end because of the use of ADITCs. So if we, if we come out next year with guidance that includes the use of any A- ADITCs, it means we're targeting that 9.12% level. Remember, that 9.12% level moves with year-end book equity from a modeling perspective, so you have to look at that when trying to estimate year-end results. Yes. Okay. No, that's, that's what I thought. Just want to be clear on it. And just going to the IRP for one second, and I know you kind of characterized them as tire kickers in the past. Just given how fast the backdrop's been evolving, like, would you anticipate a need for an acceleration of the next IRP? And just kinda how current is the latest IRP, if you get the question? Well, certainly, you recall that we delayed the submission from June to September, really for that very reason, is to make sure we had the most current information, given how quickly things are changing. I will also say that it never really seems like we ever stop. So- ... planning, where it seems like we're in constant analysis for, you know, one issue or another. So I don't see that the cycle that of which we submit to the PUC would change, but ongoing analysis of needs that come up in between IRPs, we certainly do that, frequently. Adam, anything you would add to that? No, I agree. I mean, in the past, when we would file these, they would kind of be good for a couple of years. Now, the way growth is looking and the way our resource needs are looking, we are updating it honestly, monthly. It feels like sometimes even weekly, depending on what we're seeing in the market. So, the other thing that's in IRP that you might have noticed is we had kind of a large load scenario, where we added what might happen from a load and resource perspective if certain loads came to fruition. And so I think that's something to look at, too. As we start to see these loads, come about, we're going to need to make some changes. We've also had a fair amount of inquiries on the data center side of things that, as you know, these are pretty large loads, and if any one of them come into play, it'll change the way we're looking at our resource future. Okay. Yes, I did notice that one. Great. And then the last one, in a big picture, pulling it together, assuming rate case is approved as settled, do you have any plans to kind of finally move towards a longer-term EPS CAGR? You know, that's a question we get frequently, and it's one that we look at. We certainly haven't really felt like we were able to do that. But Brian, any color you would add? Yeah, I'd say one thing to look at is when we published in February, we had a rate-based CAGR in there when we had our CapEx forecast put out. And we looked to that rate-based CAGR and really executing in the regulatory arena on that as an avenue towards looking at what the prospects are for the future of the company. So we would rely on that more so than a long-term EPS forecast. What we're tasked with doing is going through the regulatory cycle and really getting fair results out of that. So for now, we'll execute on our CapEx plans and work to get that into rates. As we've talked about in the past, we're probably headed into a series of cases or a series of cases with certain types of mechanisms, whether they be trackers or otherwise. The doors are open for those types of things at this point, to at least have conversations. And as we do, we'll start to look more like a, a normal utility in the rate cycle and really execute on that. And for the interim, we do still have the mechanism out there that points to year-end GAAP book equity, and that's another way to look at forecasting growth in the company's EPS. Okay. Yes. No, all very good. And again, thank you for the time, and well done across the board. Thank you. Your next question comes from the line of Chris Ellinghaus with Siebert Williams Shank. Chris, go ahead. Hey, everybody. How are you? Good. Hi, Chris. Hi, Chris. The, the increase in the guidance, does that tell us that your third quarter was above expectations, and in what kind of ways? Actually, it was a little lower than planned. It's been a series of other things for the full year to date, is higher than expected. Brian, do you want to hit some of those details? Yeah, I can touch on that. I mean, as we look at the third quarter, if you saw your irrigation loads, they didn't really come in where they typically would. And if you compare them to last year's third quarter, last year's third quarter was also low. So from a sales perspective to that customer class, it wasn't a strong year. We were bolstered by a few other things like customer growth. The Bridger rate change from a year-to-date perspective has been beneficial, and we saw transmission wheeling. O&M is in a good spot. I think you can see that we're lower year-to-date on O&M than we were last year, and that was one of the things we mentioned a while back that we'd really be focused on this year. So that has been materializing for us. But the uplift in the guidance, some of those factors just outweighed, you know, the lower sales to industrial customers. We did have some positive results on the tax side as well. One thing to note, though, is that our results for this year do have $7.5 million of ADITCs, so from a comparable year-over-year basis, didn't have the-- don't have comparability there. So if you take an average fourth quarter, just as an example, it does get you sort of into the range that we have out there, right now. Okay. The IRP has, you know, a very significant resource requirement in the preferred portfolio. Can you give us any insights or, you know, what your philosophy is today in terms of thinking about owned versus procured resources out of that preferred portfolio? Yes, great question. You know, we have certainly. You know, there's a number of things that drive our selection of our preferred portfolio. Obviously, it leads risk, leads cost, and it certainly, we look to own some of that. I'm not sure we expect to own all of it. So that's why we do competitive bidding and as required by our regulators, and so we try to compete in those, and we've been successful with some of them, and some of them, we have not been the winner of those. So we let that process really sort it out once we've decided what our preferred portfolio looks like. Anything that you would add? Yeah. Yeah, Chris- Adam. This is Adam. You know, one of the things you've seen over the last three years, from 2023- 2025. We've got about 443 MW of energy storage projects that have come into play. We've competed for each of those, and at the end of the day, we have been successful for 293 of those megawatts. If you look at the 2026 RFP, we have three benchmark bids that we put into that. That hopefully we'll find out if we were successful there over the next couple of months. So our goal absolutely is to compete where we can with these RFPs. I think another thing, though, to keep in mind is it's not just resource growth that you're seeing in the IRP. Our transmission is a big part of that, too, and you probably noticed the Gateway West move forward from really the 2035-ish time frame to the 2029 time frame for one of the segments, which is a pretty notable investment. And then you have segments at 9 and 10 also midway through that decade. You also have a project called Southwest Intertie that was in our IRP. That's a transmission project that we're also evaluating and looking to see if there's opportunities for us there. So I think when you look in terms of our growth, you look not only at you know the batteries and the solar and the wind that could come to fruition, but also the transmission, which one of our goals is to be a major you know player in the transmission game. We're well situated, sitting in the middle of the market, and feel like this is a good opportunity for us as we move forward. One thing I'll add, Chris, I mentioned this in my, in my remarks, earlier. When you look at the 2026-2027 time frame, we don't have any, owned resources from the RFPs shown in that new updated capital, stack that we have in the 10-Q, and that's the $2.5 billion-$2.7 billion number. So there's a lot of CapEx there. It's diversified across the board as to what that CapEx is comprised of, but any incremental additions from winning those RFPs would add to that CapEx out in the future. And then- Again, Brian just reminded me, too, that what I just mentioned, Chris, does not include the conversions of coal to Bridger units one through four, and Valmy units one through two. as well. So you'll see those in the IRP, too, and also have some growth benefits there. That was my next question. Relative to the, you know, Q4 rate base number of 11%+ that you guys quoted us, you know, Brian, you just sort of added to the near-term CapEx outlook, and you put out the IRP. Should we be expecting or, or is it reasonable to expect that your updated rate base growth when you come out with your updated CapEx is, is gonna be on the higher side? If you look at it from a CAGR perspective, what we put out in February had lower numbers in it. They also had some additions, more on the front end than the back end. So a lot of what we're talking about will add additional incremental spend in 2026 and 2027, and then we'll be tacking on 2028. We'll do that in February. Some of the ultimate CAGR on that will depend on what the numbers are in 2028, but there is a good possibility that that CAGR could actually be larger when we update our numbers in February. We're going through the capital budgeting process as we speak. Okay, that's great. All right. Thank you so much. Appreciate it. All right. Thank you. Thanks, Chris. Your next question comes from the line of Brian Russo with Sidoti & Company. Brian, go ahead. Hi, Brian. Yeah, hi. Hi, good afternoon. Hey, just to follow up on the rate base CAGR or the CapEx in 2025 through 2027. If you're now, you know, on average for those three years of $2.25 billion versus the prior of $1.6 billion, I mean, that's a 40% increase. So I suspect, just by the easy math there, there seems like there's quite a bit of upside to that 11% rate base CAGR. And then I'm curious- Yeah. Yeah, what's the incremental CapEx for? Yeah, I think you're right. I think you're right on that growth rate, and the CapEx comes from a number of different areas. So it's things like the batteries, transmission construction, some gas plant work, a number of other projects. One is, as you saw in the IRP, potentially accelerating Gateway West into the near-term window. That's an adder to that. There may be other transmission projects that get built into that. So really, it's a pretty diverse mix of projects that add that up. Some of it is actually from price increases, project scope changes that we have for projects that were originally contemplated, and then a lot of that is also from additional projects. When we do our capital budgeting, we usually have a pretty good lookout for 3 years. So we're updating that and now bringing in some of the further years out. So years four and five in our window are starting to fill up dramatically, including from that, some of the items that I mentioned. That's, that's a great list. This is Adam. I think also, you have to keep in mind that the 21 IRP did not include some of the large loads that we're seeing now. So everything that Brian mentioned is just really to be put in place to serve those loads and others. So the growth has been significant from a large load standpoint. Okay, great. And then just touch on Micron. You know, it was nice to see that press release a couple of weeks ago, I guess, you know, clearly broke ground. Are they still on schedule in relation to what your forecasts are in the IRP? And then your comment on Micron trying to attract suppliers, it seems like that could create a nice multiplier effect, which could probably increase your residential customer growth forecast? Yeah, it certainly could, and we're hopeful that it does, Chris. You know, as far as their schedules, certain parts have kind of continued to move around. They are exposed to the same sort of construction challenges that everyone is. At this point, though, as far as we know, things are on track. I don't know if we have anything more. Yeah, this is Adam. I guess a couple things on that. One is a lot of jobs, I think 17,000 indirect jobs, 2,000 jobs related to the specific facility, $15 billion. If you, if you go out there, the project is absolutely- Massive ... massive, and they're doing a ton of work right now. And frankly, we have a team dedicated to them because we're doing a ton of work to support it. So, they've always said their production was gonna start up in 2025 and will ramp up over time. And frankly, if you go out there, that's what it looks like they're doing. They're making a ton of progress, and we're just excited to be a part of it. Okay, and then Meta, it's my understanding that, you know, the site excavation has already begun. So I think, you know, that project had some starts and stops over the last year, but that seems to be moving forward, you know, according to your plan in the IRP? Yep. Yeah, and if you maybe noticed this, they recently had a social media post that just indicated in October that they are ramping up construction kind of full bore now. So, you know, they took a little bit of break for redesign in the facility, and now they look like they're going ahead pretty quickly. They've also entered into some of the solar contracts that we've mentioned, which just shows their commitment, I think, to this area. Okay, great. And then just, maybe lastly, the Boardman to Hemingway, I think you mentioned earlier that you looked to break ground or start construction in the first half of 2024. I think that's being pushed back from maybe a prior target by year-end 2023. And I'm just curious, you know, are you running up against any deadlines of further delays in this project, with you know, what type of capacity that can be brought into your service territory, you know, to serve your customers, included in the IRP? Yeah, this is Adam. We'd hoped, you're right, to break ground in October. At the end of the day, what we're seeing is a little bit of delays. We have the permits, but along the way, you have to get notice to proceed, and you have to get those from both the Department of Energy in Oregon and the BLM. And we've seen a little bit of delays in terms of their review of those items, and so we're meeting with them weekly, trying to get that to move ahead. We've been pushing for this June 2026 deadline to have this in service. Right now, that's optimistic for sure. We're working towards that goal. It is possible that it could be pushed out to the, you know, kind of more the November timeframe, based on some of these changes. At the end of the day, we have a 2026 RFP, 2027 RFP, that we're evaluating, and if we feel like that push from June to November is a possibility, then we will, you know, increase what we need in 2026, 2027. The other thing that's beneficial is the conversion of the B2H is right around that same time frame, so that'll give us some help in terms of, needed megawatts there. Okay, got it. Great. Thank you very much. Thanks, Brian. Thanks, Brian. Our next question comes from the line of Ross Fowler with UBS. Ross, go ahead. Hi, Ross. Yeah. Hey, Ross. Hi, afternoon. So I just, I just wanted to poke at this 25-27 CapEx increase a little bit more. Just on the base plan increase, and then if you have a lot of success in the RFP process and get a lot of owned generation in the plan out there, how do I, how do I think about the balance sheet? How do I think about funding that CapEx increase? Go ahead, Brian. Yeah. So some of that depends on the nature of the awards that we would receive if we were to get some of those RFPs in. If they were BTAs, for example, sometimes the payments are lump sum near the back end or have smaller milestones along the way. If they're self-billed, we're funding it along the way, so that's gonna impact the type of capital and timing of the capital that we'll need for those projects. And frankly, even just the larger CapEx that we have out there now, we're going to have to finance. And what we're looking to do is, you see that our debt equity ratio is down to about 50%. We want to keep it in that zone, maybe 51% equity. So we're just gonna have to blend debt and equity going forward to stay there, into that range. And, I think that's where we'll just have to keep credit ratings in check with some of those issuances. And then you'll give an update sort of around the RFPs when those ones come in, and then, you know, sort of blend that financing plan in as the CapEx comes by. Yeah. Yeah. Is that right? As I mentioned, we, we expect to have those awards out the first part of next year, so, we'll be talking more about that. Okay. Thank you very much. Thanks, Ross. Thanks. The final opportunity, please press star one to signal for a question, and we'll pause for just a moment. All right, it looks like that is all the questions that we have in our queue. At this point, I will hand the conference back to you, Ms. Grow. Thank you. Thanks to everyone for joining us this afternoon and for your continued interest in IDACORP. We'll be seeing many of you in Arizona coming up in the next week or so, so we always look forward to that. And I hope you all have a great weekend. Thank you. That concludes today's conference. Thank you again for your participation.