Welcome to 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. 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 on the IDACORP 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 2, 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 3, 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 4 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 to $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 5, we've had 2.3% customer growth since last year's third quarter. This growth is in line with the trends we've seen for several years now and is readily apparent throughout our service area. There are a number of tower cranes visible near our headquarters in downtown Boise, throughout the Treasure Valley area to be exact, and construction is booming. You can see on the slide that Moody's GDP growth forecast is also positive. 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 6. 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. 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 filed in 12 years. Our case focuses 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 in 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 want to 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 preconstruction 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 procurement and we've included Slide 8 to summarize our status. For the RFPs for 2023 to 2025, we've installed 120 megawatts of the 293 megawatts of the company-owned storage that resulted from those RFPs. Evaluations continue on the RFPs we issued to meet approximately 350 megawatts of peak capacity needs in 2026 and 2027, which we estimated could be met by up to 1100 megawatts 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 projects 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 towards 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 many 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 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.

Thanks Lisa. Hi everybody. Let's start on Slide 9, which has a 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 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 US, 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 in 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 expense 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 report any additional amortization of accumulated deferred investment tax credits in the third quarter 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 recorded $7.5 million of additional ADITCs. 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 as we already accounted for it. Combined with nominal impacts from other IDACORP subsidiaries, we saw a $1.1 million decrease in net income over last year's third quarter. However, for the year-to-date, we saw a $13 million increase in net income over the first nine months of last year. Our ratios have moved closer to the company's target debt-to-equity ratio compared to where we were at year-end. As I've mentioned before, our goal is to maintain our current stable credit ratings as well as a capital structure nearer to 50% or 51% equity all in the face of our CapEx plans over the coming years. We still plan 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. Our September debt issuance enhanced our cash position for the near term and our rate settlement, if approved, would help with cash flows, increasing 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 1st, we received approval from the Idaho Commission to collect a $200 million increase in power supply costs from customers. These are for higher power and gas costs over the past year with collections from June 1 of this year through May of 2025. That rate change has helped improve cash flows from operations, as has the moderation in power supply cost volatility as the year progressed. Again, the rate changes from the Idaho rate case settlement, assuming it's approved, would also benefit cash flows. Looking back at September, IDACORP's Board of Directors approved a roughly 5% increase in the quarterly cash dividend on IDACORP's common stock from $0.79 to $0.83 per share. They've approved a 177% increase in the quarterly dividend 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 regarding 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 in 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 due to regulatory lag, not capital disallowances, but instead delayed collection resulting 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 our 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 is no stay provision in the settlement, so it can accommodate upcoming requests. 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, which is 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. The settlement also has 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, as 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, where the residential service charge will increase from $5 to $15 per month over two years. The small general service charge will increase from $5 to $25 per month on January 1. This change helps with a more timely and actionable 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, 2024. Slide 11 shows our updated full-year earnings guidance and key operating metrics. As Amy noted, we expect IDACORP's earnings this year to be in the range of $5.05 to $5.15 per diluted share, with the assumption that Idaho Power will use up to $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 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 expenses to continue through the end of the year from our CapEx investments and plan going into service. We could also see potentially lower transmission wheeling-related revenues compared to the fourth quarter of last year when we saw some abnormal volatility in the Western energy markets. We continue to expect full-year O&M expense to be in the range of $385 million to $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 to $725 million. Looking past this year, we'll give a longer-term CapEx forecast update on the fourth quarter call in February. But 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 to $950 million as of now, which is up from our earlier estimate of $800 million to $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 to $2.5 billion over that three-year period, which is a significant increase from what we included in our estimate last quarter, which was $1.5 billion to $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 amounts 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. We're happy to address questions you might have.

We are now ready to begin the question-and-answer session. And we do have a question in the queue. Are you ready to take our first question?

Sure.

Great. Your first question comes from the line of Paul Zimbardo with Bank of America. Paul, please go ahead.

Hi, Paul.

Hi, good afternoon, team. It's very well done on the settlement and nice to see in such a quick fashion as well. Did want to 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 kind of what we should expect on an earned return basis as you execute on the high build cycle and more lag? Or are you able to use the sharing credits or sort of 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?

Yes. So when you've got depreciation and interest expense cost from 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 dead band 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 come out next year with guidance that includes the use of ADITCs that 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 what I thought. I just want to be clear on it. And just going to the IRP for one second. I know you kind of characterized some of these higher kickers in the past just given how fast the backdrop has been evolving. Would you anticipate a need for an acceleration of the next IRP? And just kind of how current is the latest IRP if you get the question?

Well certainly, you can recall that we delayed the submission from June to September, really for that very reason, to make sure we have the most current information given how quickly things are changing. I will also say that it never really seems like we ever stop planning—it seems like we're in constant analysis for one issue or another. So I don't see that the cycle in 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, if 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 comes into play, it will change the way we're looking at our resource future.

Okay. Yeah. I did notice that one. Great. And then the last one, kind of big picture point together, assuming rate cases approved and settled, do you have any plans to, kind of, finally move towards a longer-term EPS CAGR?

Yeah. 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 base CAGR in there when we had our CapEx forecast put out. And we looked to that rate base 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 our 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 we'll 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 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 the year-end GAAP book equity, and that's another way to look at forecasting growth in the company's EPS.

Okay. Yes. All very good. Again, thank you for your time. Well done across the board.

Thanks, Paul.

Thanks, Paul.

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 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 that is higher than expected. Brian, do you want to take some of those details?

Yeah. I can touch on that. I mean as we look at the third quarter, if you saw your irrigation load, 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 bridge 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 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 ADITC. So from a comparable year-over-year basis, we didn'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 a very significant resource requirement in the preferred portfolio. Can you give us any insights or what your philosophy is today in terms of thinking about owned versus procured resources out of that preferred portfolio?

Yeah. Great question. There are certainly a number of things that drive our selection of our preferred portfolio, obviously risk, least cost, and certainly we look to own some of that. I'm not sure we expect to own all of it. So that's why we view competitive bidding as required by our regulators. 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. We let that process really sort out once we've decided what our preferred portfolio looks like. Anything that you would add, Adam?

Yes, Chris, this is Adam. One of the things you've seen over the last three years from 2023 to 2025, we've had about 443 megawatts 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. As you look at the '26 RFPs, 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 to keep in mind is, it's not just resource growth that you're seeing in IRP, our transmission is a big part of that too. You probably note the Gateway West moved forward from really the 2035-ish timeframe to the 2029 timeframe for one of the segments, which is a pretty notable investment. And then you have segments nine and ten also, midway through that decade. We also have a project called Southwest Intertie that was in our IRP 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 the batteries and the solar and the wind that could come to fruition, but also the transmission which is one of our goals to be a major 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, and I mentioned this in my remarks earlier. When you look at the 2026-2027 timeframe, we don't have any owned resources from the RFP shown in that new updated capital stack that we have in the 10-Q and that's the $2.5 billion to $2.7 billion number. So there's a lot of CapEx there 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 again, Brian just reminded me too that what I just mentioned, Chris, does not include the conversion of coal to breaker units one through four and coal units one through two as well. So you'll see those in IRP too, and also have growth benefits there.

That was my next question. Relative to the Q4 rate base number of 11-plus percent that you guys quoted us, Brian, you just sort of added to the near-term CapEx outlook and put out the IRP. Should we be expecting or is it reasonable to expect that your updated rate base growth when you come out with your updated CapEx is going to 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 have 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. Good afternoon. Just a follow-up on the rate base CAGR or the CapEx in 2025 through 2027. If you now on average for those three years of $2.25 billion versus the prior $1.6 billion, I mean, that's a 40% increase. So I suspect just by the easy math there seems like there's quite a bit of upside to that 11% rate base CAGR. And then I'm curious what is the incremental CapEx for?

Yes. 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, and a number of other projects. One is, as you saw on 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 and 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 look out for three 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 pull up dramatically including from some of the items that I mentioned.

And 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 sort of on Micron. It was nice to see that press release a couple of weeks ago, I guess clearly broke ground. Are they still on schedule in relation to what your forecast is in the IRP? Within 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?

Yes, it certainly could. And we're hopeful that it does, Chris. And 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 you have anything, Adam?

Yes, this is Adam. I guess a couple of things on that. One is a lot of jobs, I think, 17,000 indirect jobs, and 2,000 jobs related to the specific facility, $15 billion. If you go out there, the project is absolutely massive, and they're doing a ton of work right now. Frankly, we have a team dedicated to them because we're doing a ton of work to support it. They’ve always said their production was going to start up in 2025 and will ramp up over time. 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 the site excavation has already begun. I think that project had some starts and stops over the last year, but that seems to be moving forward according to your plan in the IRP?

Yes.

Yes. And maybe you noticed that they recently had a social media post that just indicated in October that they are ramping up construction kind of full bore now. So they took a little bit of a 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 our 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 if you are running up against any deadlines of further delays in this project with what type of capacity that can be brought into your service territory to serve your customers included in the IRP?

Yes. This is Adam. We hope 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 received and you have to get those from both the Department of Energy in Oregon and the BLM. We've seen a little bit of delays in terms of their review of those items. We're meeting with them weekly trying to get that to move ahead. We've been pushing for this June 2026 deadline to have it 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 more of the November timeframe based on some of these changes. At the end of the day, we have a 2026 RFP and a 2027 RFP that we're evaluating and that we feel like that push from June to November is a possibility that we will increase what we need in 2026 and 2027. The other thing that's beneficial is the conversion of volume is right around that same timeframe. So that will give us some help in terms of needed capacity there.

Okay. Got it. Great. Thank you very much.

Thanks, Brian.

Thanks, Brian.

Your next question comes from the line of Ross Fowler with UBS. Ross, go ahead.

Hello Ross.

Hey Ross.

Hi. Afternoon. So I just wanted to poke at this, 2025 to 2027 CapEx increasing a little bit more. Just on the base plan increase, and then if you have a lot of success in the RFP process and you get a lot of owned generation in the plan out there, how do I think about the balance sheet? And how do I think about funding that CapEx increase?

Do you take 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 RFP wins. If they were BTA, for example, sometimes the payments are lump sum near the back end or have smaller milestones along the way. If they're self-builds, we're funding it along the way. So that's going to 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. What we're looking to do is keep our debt equity ratio down to about 50%. We want to keep it in that zone, maybe 51% equity. So we're just going to have to blend that and equity going forward to stay in that range. 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 RFPs and those ones come in and then sort of implying that financing plan as the CapEx comes by is that right?

Yeah. As I mentioned, we expect to have those awards out of the first part of next year. So we'll be talking more about that.

Okay. Thank you very much.

Yeah. Thanks, Ross.

Thank you.

All right. It looks like that is all the questions that we have in our queue. So 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. We always look forward to that. I hope you all have a great weekend. Thank you.

That concludes today's conference. Thank you again for your participation.