Welcome to IDACORP's Fourth Quarter and Year-End 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.

Thank you. Good afternoon everyone. We appreciate you joining our call. This morning, we issued and posted to IDACORP's Website our fourth quarter and year-end 2023 earnings release and our Form 10-K. The slides that accompany today's call are also available on IDACORP's Website. During the call, we'll refer to the slides by number. 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. 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. This cautionary note is included in more detail for your review in our filings with the Securities and Exchange Commission. As shown on slide three, Lisa Grow, IDACORP's President and Chief Executive Officer; and Brian Buckham, IDACORP's Senior Vice President, Chief Financial Officer, and Treasurer will be presenting today. 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 full-year financial results. IDACORP's 2023 diluted earnings per share were $5.14 compared with $5.11 last year. Both 2023 revenues and earnings are IDACORP's highest in the history of the company, and 2023 was the 16th consecutive year of growth in earnings per share, which is something to celebrate. Today, we initiated our full-year 2024 IDACORP earnings guidance estimate in the range of $5.25 to $5.45 diluted earnings per share, which includes our expectation that Idaho Power will utilize approximately $35 million to $60 million of additional tax credits that are available to support earnings at the 9.12% return on equity level in the Idaho jurisdiction under its Idaho general rate case settlement stipulation. These estimates assume historically normal weather conditions throughout the year, and normal power supply expenses. Also, it is important to note that approximately $25 million of our expected usage of additional tax credit relates to amortization of incremental tax credit generated from Idaho Power's investment in 2023 battery storage projects, which you may recall we removed from the revenue requirement as part of our 2023 general rate case proceeding in Idaho. Now, I'll turn the call over to Lisa.

Thank you, Amy, and thanks to everyone for joining us on today's call. I want to begin my remarks by highlighting Amy's comment on IDACORP completing our 16th year of earnings growth, as shown on slide five. Idaho Power also didn't use any accumulated deferred investment tax credits in 2023, preserving the full balance of credit in the Idaho regulatory stipulation for future earnings support. I want to thank our entire team for all the efforts that have contributed to this success. As we turn to 2024, we remain focused on keeping our employees safe, building for the future to keep pace with growing customer demand, keeping prices affordable, working toward our clean energy goal, and seeking innovative ways to serve our customers. Our ability to deliver strong results while meeting the challenges of growth in the ever-shifting energy industry is a testament to our culture and Idaho Power's hardworking employees. Many of the topics I will touch on today will continue to drive our efforts and business strategies throughout 2024, and beyond. Turning to slide six, you'll see that strong growth continues across Idaho Power's service area. Our customer base grew 2.4% in 2023. And we now serve more than 630,000 customers. With that growth earlier this year, we also set a new winter peak load of 2,719 megawatts, an increase of over 4% from our prior winter peak in 2022. Moody's most recent GDP calculations for our region remain robust, forecasting growth of 3.6% in 2024 and 3.7% in 2025. We believe the reliable, affordable energy Idaho Power provides continues to be a driver for growth across our service area. And our local economy continues to outperform national trends. Idaho Power projects annual peak load growth of 3.7% from 2024 to 2028, based on our 2023 Integrated Resource Plan. This growth includes several new and expanding large-load customers, including Meta and Micron. Both of their sites are under construction, and both are participating in our Clean Energy Your Way program, which received commission approval last year, and is garnering interest from other large customers, including the city of Boise. The Micron site helped push Idaho to number five in a recent Site Selector Magazine ranking as states with the highest dollar value mega projects breaking ground across the country. Overall, economic development continues at a rapid pace, particularly in the manufacturing space. In 2023, we brought online The Stow Company in Nampa, and True West Beef in Jerome. We also continue to have a robust pipeline of potential large commercial and industrial customers, including data centers inquiring about service. With so many finding our service area increasingly attractive, there is likely some upside in our load forecast that we haven't accounted for at this point. And we are considering what additional infrastructure would be needed to serve this potential load. Even with this growth, we continue to provide strong reliability for our customers. In 2023, we had our second-best year for reliability with fewer customer outages, which resulted in less O&M costs related to outages.

Thanks, Lisa. Hi, everyone. We appreciate you tuning in for today's call. I'll start on slide 12, which is a reconciliation of our 2023 results compared to 2022. Just as a broad overview before I get into more detail. In 2023, we saw continued strong customer growth, and we benefited from our ongoing commitment to operating efficiently with our O&M expenses coming in basically flat compared to 2022. We also had the benefit of a June 2022 rate change related to Bridger for a full year and lower income tax expense. Those positives were partially offset by reductions in usage from mild weather and higher depreciation and financing costs from our record level of CapEx. Getting into more granular detail, customer growth of 2.4% increased operating income by $15.7 million. Our residential customer growth rate remained strong at 2.6% for the year, and this is a continuation of steady growth we've seen, and the trend points to continued strong customer and load growth in our service area. We wouldn't be in the Idaho Power earnings call if we didn't talk about the weather. Usage per customer decreased operating income by about $31 million in 2023 compared to the prior year. More moderate temperatures and greater precipitation resulted in irrigation customers using less energy to operate their pumps. And it caused residential and commercial customers to use less energy per customer for cooling and heating during the year. The impact of the decrease in sales volumes per customer was partially offset by a $15 million increase from the fixed cost adjustment decoupling mechanism for our residential and small commercial customers. Remember, the decoupling mechanism doesn't apply to irrigation customers. So, we saw a negative weather-related impact to irrigation sales without an attendant FCA revenue offset in 2023, just like we saw in 2022. The change in retail revenues per megawatt hour, net of associated power supply costs and power cost adjustment mechanisms increased operating income by $11 million in 2023 compared with 2022. That increase was primarily due to the June 2022 Bridger-related rate increase for our Idaho customers. Other O&M expenses were almost equivalent in the last two years. Inflationary pressures on labor-related costs were mostly offset by our continued efforts to operate efficiently, really part of our culture, and from lower expenses from scheduled cyclical plant maintenance projects, and the timing of regulatory deferrals and credits received related to a jointly funded infrastructure project. Depreciation expense increased $25.3 million, which I'll admit initially sounds significant. However, the magnitude on a year-over-year comparison basis is due partially to an increase in plant and service and partially to the impact of the Bridger Order I mentioned earlier. The latter is actually the larger of the two reasons. Non-operating expense decreased $4.7 million in 2023 compared with 2022. Allowance for funds used during construction increased as the average construction work in balance, and progress balance was higher throughout 2023. Also interest and investment income increased due to higher interest rates and higher average cash and cash equivalents balances. These increases were partially offset by higher interest expense on long-term debt. Wrapping up the table, the $11 million decrease in income tax expense was primarily due to plant-related tax adjustments.

Thank you. We are now ready to begin the question-and-answer session for attendees who have joined on the Q&A line. And your first question comes from the line of Alex Mortimer with Mizuho Securities. Alex, your line is open.

Hi, Alex.

Hi. Good afternoon, team. So, I know you're still waiting for the RFP process to finalize for the '26-'27 timeframe. But could you quantify what that opportunity could potentially look like from a CapEx perspective, as well as when/how we might get that update?

Hi, Alex. Yes, this is Adam. It's a bit challenging with these RFPs due to the confidentiality involved. Currently, there is a shortlist, and Idaho Power submitted three benchmark bids. One was for a wind project of 600 megawatts, while the other two were battery projects of 150 megawatts and 100 megawatts. We won’t know if Idaho Power will win those bids for a couple of months. We're aiming to execute agreements around March-April, but that's the general overview. The success of the bids is still to be determined.

And Alex, this is Brian, just to add to that. Remember the original need that we had at the time we started the RFP processes was 350 megawatt capacity satisfied by as much as 1,100 megawatts of variable energy. So, that can change from time to time as our operating needs change, but that was the original magnitude of the RFP.

And your next comes from the line of Paul Zimbardo with Bank of America. Paul, your line is open.

Hi, Paul.

Hi, Paul.

Hey, it's actually Julien on for Paul. How you guys doing?

Hi, Julien.

Hi, Julien.

Just wanted to go back to that rate-based question super quick if you don't mind, can you talk briefly about maybe the discrepancy from the last update just in terms of like the net puts and takes beyond just the CapEx increase if you don't mind, would that be okay?

Yes, that's fine. Go ahead, Brian.

Yes, I could talk about what's driving that changed CapEx forecast. One is changes in assumptions around some of our transmission. So, we've been working with our partners in terms of ownership and allocation, and timing around the transmission project, and also, as Lisa mentioned, looking at other potential transmission opportunities that might be out there for us. So, that's how some of the change in the forecast from 2022 to 2023. B2H is in there certainly, and that moved around a little bit. Battery storage is in there for '24 and '25. But again, no incremental upside from any of the RFPs in our CapEx forecast. Really it's some of them have had increases in prices from projects, as you've seen across the board pretty much all over. We've seen acceleration in project like Gateway West, that's a piece of that of driving CapEx, as I mentioned, other transmission projects as well. So, really no one really large driver in there, it's really price increases. Some project scope changes, and then additional projects that are in the pipeline for us.

Right, it sounds like a bunch of different things moving around. But to that end, when you think about 2026 here, can you comment a little bit about like what the puts and takes are, just because it seems like you ratcheted up CapEx and then rate base was maybe even slightly down, if you will. Just making sure I'm hearing you right, it's like a little bit of a push out.

Yes, Julien, that's a great point. On the rate base side, things have changed. One of the main factors that caused the rate base to slide was the overall increase in CapEx, as you saw from the CapEx slide. However, some elements, like certain projects, shifted in this scenario. For example, Boardman to Hemingway has been pushed out a bit. Additionally, projects like Gateway West have a CapEx component but do not appear in the rate base forecast because they are not considered plant and service. Therefore, we are only including plant and service in our calculations. You can see some of this information in the quick line we provided, which outlines when certain plants might close and become eligible for the rate base. So, the answer to your question about the rate base is that it's simply a matter of shifting project timelines, rather than eliminating any projects.

Right. It sounds like really this is a question of just when it's coming into the forecast, or what have you. But then ultimately, if you can, just going back to what's not included and timelines for when you get that resolution here. I mean, and ultimately what that forecast is looking, seems like a lot of these forecasts are kind of changing real-time. Do you want to comment a little bit on what that ultimately could look like for '27-'28, especially considering that some of the rate base could have been pushed out from '26 in that period, right? How much of a spiky uptick could you see in CapEx and rate base in that timeframe specifically, or is it going to get smoothed out here potentially with the RFP pushed out a little bit?

This is Brian again. So, part of the answer to that depends on how we pay for the projects, right? Some of these projects could have milestone payments, some of them could pay at the end. So, there's CapEx associated with that that could impact the CapEx slide that we put out today. The rate base slide though, a lot of those projects would actually come into the window in that '26, '27, '28 timeline. So, there could be a little bit of lumpiness in some of those years depending on when we go into regulators and try to incorporate those into rates.

Wonderful. All right, guys, excellent. And then, just, if you don't mind just real quickly if I can follow up on one more item here. How do you think about solidifying clearance for a single-issue rate proceeding versus kind of a general rate case here, if you will? Or what do you need to do?

Yes, so we're looking at that right now. And this is Lisa. We've stayed out for over a decade, so this last rate case was quite large, a lot of work went into sending that in and working through all of the discovery requests and just how big that rate case was. So, this rate case will be a lot simpler. So, we're working with the staff and other stakeholders to gauge their interest and see if we can make it a more simplified case that would be really focused on the investments that we're making, and perhaps labor increases. So, we're exploring that now, and we'll decide as we talk to those stakeholders.

Excellent. Thank you, guys, for the time.

Thanks, Julien.

Thank you.

Hey, Shar.

Hi, it's actually Jamieson Ward on for Shar. How are you guys doing?

All the handshakes here.

Hey. Well, Julien just asked most of the question I was going to ask on the rate case, so that was my second one. I'll ask the second part that is a little separate from that. And then, a primary one on the ADITC, and the battery projects announced going forward. But just to follow on Julien's question there, how do we factor in Hells Canyon and timing knowing that that's now expected to be a 2025 event right now? I thought that was reiterated in the slide, the licensing was expected to occur in '25. So, if the case is filed in June, what impact, if there is an impact, would Hells Canyon play just knowing that, in prior conversations we've had, that was going to be, at least at one point, a deciding factor of when a case would be filed. Does this play into that?

So, the case we would file this year wouldn't include Hells Canyon, but you're right.

No, I realize, yes.

It may need that in the future rate cases when we do get the license, that very well could trigger perhaps a single-issue rate proceeding. Or it may be included in another general rate case. We'll have to wait to see what's going on in that year before we make that decision.

Okay, that's the answer. Yes, no, I realized there would be stuff, but I guess I was trying to get a sense of whether you would hold off for a certain amount of time after or if it would trigger a quicker case than you otherwise would have expected to file just, again, because you haven't filed in so long. And now that pace is picking up, just trying to get a sense of the cadence as the model rate increases going forward?

Just to add on to that, one thing I will mention is there's a possibility that we would look to file something in advance of the actual date of receipt of the license. To the extent, we have any visibility to that, we may file earlier than the license date. You saw this on the Langley Gulch plant when we put it into service. We did have a filing in advance, and our rate change actually happened very near to the time that the plant went into service. Given the magnitude of the Hells Canyon license, we may look to do something similar to that in the future as well. We will be in front of the regulator, we expect, relatively frequently. So, this could be something that goes into a GRC if the timing works out. If not, it could be a single-issue case. And remember, we did take Hells Canyon to the regulator earlier since it had been such a long project, and got a prudency determination through 2015 on expenditures we've made on that project, just because it's been out there for so long and we have so much AFUDC on that project. We've also been collecting AFUDC on it, which has been helpful from a rate perspective as we do take that in to incorporate it into customer rates.

Perfect. Thank you. Yes. And your comments there are consistent with my recollection and my notes from what you mentioned earlier. So, I appreciate the additional color, and thank you for that. As we think about the amount of ADITC amortizations, or additional ADITC amortizations, I should say, going forward, of course, you have the additional $25 billion amount with battery project. The level that it supports, of course, has come down to 9.12%, being 95% to the 9.6% authorized. How should we think going forward of kind of an expected amount? And I'm saying this with a full realization and understanding that you do not provide multi-year guidance or long-term EPS CAGR, etc., but more just from a practical standpoint. What might be realistic to assume is going to be something safe to model for the next few years as you're continuing to invest at the pace, the clip that you are, and depending on the timing of rate cases.

Sure. Yes, James, this is Brian. So, a few things you have to look at in terms of how many credits we'll use. I'll give you this answer first. You have to look at it separately each year. There's not a specific number that we would say is going to be used every year. There is an upper limit, right? First of all, there's an upper limit to credits. Right now, as of the end of the year, we had $86 million in the mechanism. We do expect to add some more to that from the 2023 batteries as they go into service and are paid for. In terms of future additions to the mechanism, that takes regulatory action. We'd actually have to go into the regulator and ask for additional ITCs to be put into the mechanism, whether they're current balance sheet credits or credits that come off of renewable projects and batteries we install in the future. Depending on what that balance is, the number is going to depend on a lot. One thing that's a big factor is equity, for example. When equity is issued, it increases book equity. And as that is incorporated into our financial statements, that could use additional credit to catch up to that higher book equity. Now, that moves EPS as well, of course. And then, we have to look at financial headwinds every year. For example, in 2024, we've talked about higher depreciation and interest expense. So, to the extent we have to absorb that, tax credits would be used to absorb some of the financing costs associated with our growth. Beyond that, I would say on the credit side, it's going to depend on the size of the bucket in any given year as to what we're going to be using. So, you can't just take a straight-line look at tax credits. As we go to the regulator and we increase our cash collection, for example, we would expect our rate-based earnings power to eliminate the need for as many credits. So, over time, we would expect the need to rely on credits to earn close to our authorized rate of return would go away. But that's something that fortunately these credits in the interim do provide us with earnings support.

I think it's also worth noting that the way the mechanism works, we don't have discretion to decide how many to use. Whatever the number is, that amount is used. So, we can't hold them back either.

Got it, got it. That's helpful. Okay, that all makes sense. And I appreciate all the detail there. It sounds like we should continue using the year-end book equity iterative calculation that I think we all use to sort of figure out each year what the need will be. It sounds like that's still the go-forward practice.

That's correct. Remember that the number can change. So, remember in this particular case, the number fell to 9.12. If the ROE were to go up in subsequent cases, that number would be expected to also move with it.

Hi, good afternoon. So, just to follow up on either limited issue or general rate case, if you filed by June, is it fair to say that you'd have new rates effective in January of 2025?

So, we'll start with, yes, we would file in June with the expectation that they would go into effect January 1. We would be using a 2024 test year.

And then what would be the test year and then like to true-up? How much CapEx from your last rate case would you capture in this for rates in 2025 to reduce any lag?

Yes, Brian. We don't have the actual number that we would submit to regulators finalized yet. The true-up component is relatively small at this moment. However, the additional rate base that we plan to cover and put into service during 2024, which is eligible for rate base, is very significant. Once we have that number, we will be able to share it.

Yes, understood. And it seems like if you kind of back out the amortization of the expense in your 2024 guidance, is it fair to say that, that this case will again really be capital driven and not really operating expense driven?

Yes, that's correct. With many other things settled in the last rate case, we believe it's really a matter of our rapid growth. We simply can't wait another decade while spending roughly a billion dollars a year. Therefore, we will be engaging more frequently.

Yes. And Brian, you've seen us manage our operating and maintenance expenses and keep them relatively stable. You noticed this from 2022 to 2023. We're striving to achieve the same for 2024. The one area where we are struggling is labor. It's quite challenging to manage this, especially as we need to retain our workforce to meet growth demands. We view this as a sector where, if we consider limited scope labor or similar options, we would look to incorporate that along with our infrastructure investments.

Yes, this is Adam. Maybe just to add to that, when we track large load requests, we consider a large load of megawatts or more. This year, in 2023, we had more requests and inquiries on our system than ever in the history of the company. We used to get, as Lisa mentioned, one, two, three, four megawatts. These requests are now in the hundreds to even thousands. Now, whether they will actually come to our service territory is an open question, and obviously those discussions are confidential. But if we did see a significant amount of these entities decide to come here, you could see us having to move forward with, for example, a gas plant sooner than what our IRP showed. Just as a reminder, in our IRP, we now look at large load scenarios. And so, as we move forward with future IRPs, we'll do the same. And what that could show is the need for gaps may increase even as early as the 2030, 2029 timeframe. But, again, it all depends on what loads come to fruition and whether these companies decide to site in Idaho or somewhere else.

Okay. And then, maybe just a more detailed update on B2H. You mentioned it shifted a little bit, yet you're still expecting to break ground this year. I mean, what's the likelihood that it's the earliest 2026? Is that still realistic and on track?

Yes, so you've been following us for quite a while. So, this has been quite the process to get to where we are. So, we're feeling good about getting to the finish line with permits. Right now, there have been some delays in getting the notice to proceed. It's mostly due to just the responsiveness of the agencies. But I will have Adam give you a little more color on it. But I feel like we're getting to the end. I think it won't be any sooner than 2026 for sure.

Yes, you hit on most of it. The issue we've run into is just a little bit of delays related to the notice to proceed from the Oregon Department of Energy and from the BLM. We still do plan to start construction this year, hopefully in the first half of this year if possible. And our end date is still 2026, given what we're seeing. So, as long as we can work with agencies, get some of these final notices to proceed, we have some right-of-way work to also do. And then, we're doing some micro-siting and some amendments on that front. If it all comes together, yes, construction would start in 2024 and it would end before the end of the year in 2026.

Okay, great. And lastly, just given new rates, and I suppose it might be tiered rates during the peak demand season along with the ADITCs, which are partly due to the battery storage revenue being transferred there, anything we should be aware of in terms of the quarterly dispersion of your margins or earnings as it relates to your full-year guidance?

Brian, not from my perspective, I mean, one of the things we've done in the past is we've used ADITCs. We have made an estimate early in the year of the full-year ADITC usage amount. And then, we record that pro rata over the year, not based on anticipated sales each quarter. So, you'd expect us to do that again this year with the ADITCs. But otherwise, yes, there were some minor changes in the case to tiering, but I wouldn't expect it to have a dramatic impact on seasonality. We should still have seasonality that's similar to what we've seen in the past, driven more heavily by weather than by any changes to rates.

Okay, thank you very much.

Thank you.

Thanks, Brian.

Thank you. And there's a final opportunity here. And we'll pause for just a few moments to see if any questions come into our queue. All right, it looks like there are no further questions. So, this does conclude the question-and-answer session for today. Ms. Grow, I will turn the conference back over to you.

Thank you. Thanks to everyone for joining us this afternoon and for your continued interest in IDACORP. I hope you all enjoy President's Weekend and have a great evening. Thank you.

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