IDA - NYSE

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 Web site. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

Thank you. Good afternoon everyone. We appreciate you joining our call. This morning, we issued and posted to IDACORP's Web site 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 Web site. 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, 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 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 drive 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 Micro 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 enquiring 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. Turning to slide seven, the Idaho Commission approved the settlement agreement in our Idaho general rate case in December. The settlement, which resulted in new rates effective on January 1 of this year, resulted in an overall rate increase of $54.7 million or an average of 4.25% for Idaho customers. This was a positive outcome for our company and our customers, and underscores our constructive regulatory environment. It helps us recover some of the significant infrastructure investments we've made to serve our growing customer base since our last general rate case in 2011. This outcome also benefits our cash flows as we continue to develop additional infrastructure, and maintain the reliability of our system. As noted on slide eight, Idaho Power filed its Oregon general rate case, in December, 2023. And that case will be processed throughout much of 2024. We ask for a total annual rate increase of $10.7 million in Oregon. We expect to make additional rate filings as we experience significant growth in our service area. For example, earlier this week, we provided notice to the Idaho Commission of our intent to file a general rate case or a limited issue rate proceeding as soon as June 1 of this year. We're still working to determine what type of case we might file, which will include conversations with Idaho Staff, and other key stakeholders. We continue to plan for and add new resources that will meet our growing demand. Turning to Slide 9, in 2023, Idaho Power installed a total of 131 megawatts of energy storage capacity, the first utility-scale batteries in Idaho. The table on Slide 9 doesn't account for an additional 11 megawatts of batteries installed at several distribution substations in 2023. These systems are already helping to maintain reliability and affordability during period of high use. 100-megawatt Franklin Solar project, in southern Idaho, is scheduled to come online in 2024, and will include an additional 60 megawatts of company-owned battery storage. These resources will be instrumental as we move away from coal-fired generation, and integrate additional intermittent renewable energy resources. As highlighted on slide 10, we published our 2023 integrated resource plan in September. The plan shows Idaho Power expects to be completely out of coal-fired generation by 2030. We're planning to convert our remaining coal-fired units to natural gas, which will reduce the carbon emissions of those units by about half and help keep our system reliable and affordable. We expect two of those units to be ready by this summer. Evaluations on RFPs for 2026 and 2027 resource needs are ongoing. You may recall Idaho Power has self-bills included in that process. At this point, the separate evaluation team has a short list of projects and they've initiated contract negotiations with the shortlist bidders. We expect to execute contracts in the coming months. As shown on slide 11, 2023 was a big year for our high voltage transmission project, especially Boardman-to-Hemingway. We obtained certificates of public convenience and necessity for B2H in Oregon and Idaho. We also finalized an agreement with the Bonneville Power Administration and PacifiCorp that transfers BPA share of B2H to Idaho Power. We expect to break ground this year and finish the project no earlier than 2026. Idaho Power and PacifiCorp are also working together on the 1000 mile Gateway West transmission line, which will help both companies meet rising customer demand and improve reliability. We're currently discussing with PacifiCorp the timing of construction for the segments most important to Idaho Power and the specific ownership allocation of those segments. In addition, we continue to look at other transmission projects that will be key to supplying reliable, affordable, clean energy in the future. As I close my remarks, I want to reiterate my thanks to our employees and the leadership team for all the great work they did to drive our success in 2023. As I reflect on the year, it's incredible how much we accomplished. The challenges of growth, rising costs, and the increasing demand for clean energy, while maintaining safety, reliability, and affordability are real. But it's clear to me we have the right team in place to thrive in this fast-moving energy landscape. With that, I'll hand the presentation over to Brian for an overview of financial results and outlook. Brian.

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, wouldn't be in 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 equivalence 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. As Lisa mentioned, we ultimately didn't record any additional amortization of accumulated deferred investment tax credits as of the end of 2023, preserving the full-year-end 2023 balance of around $86 million for future years. While we predicted to use additional ADITCs throughout the year, our year-end results ultimately eliminated our need to use them to achieve a 9.4% return on year-end equity in Idaho by a small margin. Beginning in 2024, the ADITC mechanism supports Idaho earnings at a 9.12% level. Our CapEx on a cash basis was over $600 million in 2023, an Idaho Power record, and it was an increase of more than 40% over 2022. On an accrual basis, it was $734 million. If you look at the projects that entailed, it's our standard system reliability work, plant upgrades, and work on our transmission system and our battery storage projects to meet customer growth. On slide 13, we've included our updated five-year forecast of CapEx. You'll see our current plan for 2024 to 2028 has a 21% increase in CapEx compared to the 2023 to 2027 forecast we had at this time last year, amounting to $700 million of additional CapEx in this updated five-year forecast. We have a healthy mix of capital projects that make up our spending plan. We have no one particular project making up a majority of the expected spend. Our update includes refreshed cost assumptions from our major capital projects, but it's worth pointing out this update still doesn't include any projects related to the pending RFPs for 2026 and 2027 energy and capacity resources, or if we end up with new large loads that are in the pipeline that drive further infrastructure needs. We are only including what we believe is known and executable as of today, so there is the potential for increases. We hope to have some clarity around the RFPs later in the first quarter, though we're still a ways out on any final decisions in the RFPs. Slide 14 is our estimate of the conversion of our CapEx spent into rate-based eligible assets at the end of each of the next five years as we place the assets into service. Last year at this time our estimated five-year rate-based CAGR was 11.1% based on rate-based eligible assets at the end of 2022 in addition through 2027. So, as we roll forward our CapEx forecast for our next five-year outlook with rate base from our 2023 general rate case as the starting point, our rate base CAGR for 2024 through 2028 is 10.8%, again with about $700 million of higher CapEx in the current five-year forecast compared to our five-year forecast this time last year. In terms of financing that CapEx, as I've mentioned before, our goal is still to maintain our current credit ratings as well as the capital structure near 50% or 51% equity. To do that, we're still planning to blend that in equity issuances. We don't have any sizable debt maturities to address in the next few years, which helps on the debt side and with our credit ratings. We also haven't drawn down any of the funds from our November 2023 forward equity offering today, though it's intended to satisfy our equity needs in 2024. As a matter of good housekeeping, we could put in place an ATM later this year as we look to satisfy future equity needs, keep that debt equity ratio in a good spot. We're also focused on affordability for customers through this capital cycle. We start with rates well below the national average, and then combining that with the denominator expanding due to customer growth, a regulatory philosophy where growth pays for growth, and the fact that the average life of the assets we're placing into service is relatively long, and we have the formula to maintain affordability for our customers. I think the relatively small single-digit percentage size of our general rate case I asked in Idaho last year, despite having not filed a general rate case in over a decade, is indicative of our ability to maintain low customer rates while our CapEx and rate-based forecast is elevated. Turning to slide 15, cash flows from operations decreased compared to 2022. As we discussed during the second quarter earnings call last year, we received approval from the Idaho Commission to collect $200 million increase in power supply costs from customers for higher power and gas costs, with collection from June of 2023 through May of 2025. We expect that rate change along with the increased collection that began in January 1 from the Idaho general rate case settlement to help support cash flows from operations. As Lisa mentioned, in late December, the IPUC issued an order approving the settlement stipulation for Idaho general rate case. We've included a summary of the settlement on slide seven. The settlement provides for an increase to annual retail revenues of about $55 million, effective as of January 1 of this year. That's net of the transfers of cost recovery to base rates, including $168 million from current PCA rates most notably. The settlement increased an ROE of 9.6%, which sets our overall rate of return at 7.247% in Idaho. And last December, we filed a general rate case in Oregon, targeting a rate increase on October 15 of this year. As outlined on slide eight, the filing requested an annual rate increase of $10.7 million. The filing requested a 10.4% authorized rate of return on equity, and a $189 million Oregon-Jurisdiction retail rate base. Idaho Power proposed capital structure of 49% debt and 51% equity in that case. Slide 16 shows our updated full-year earnings guidance and key operating metrics. We expect IDACORP's diluted earnings per share this year to be in the range of $5.25 to $5.45, with the assumption that Idaho Power will use between $35 million and $60 million of additional investment tax credit amortization to realize the 9.12% return on year-end equity in Idaho. As we contemplated in our Idaho general rate case filing, around $25 million of the additional investment tax credit amortization we expect to use this year relates to covering the revenue requirement for our investment in 2023 battery storage projects. Other items causing the expected additional investment tax credit amortization usage this year are higher depreciation and interest expense from the CapEx increase, as well as higher book equity expected at year-end 2024, offset by the reduction from a 9.4% to a 9.12% ROE floor. And the guidance assumes normal weather throughout 2024, and normal power supply expenses. We expect full-year O&M expense to be in the range of $440 million to $450 million. While this looks and sounds like a notable increase over our 2023 spending, it's important to note that about $40 million of that expected expense relates to amortization of pension and wildfire mitigation plan regulatory assets, which was approved for recovery in the general rate case settlement. So, excluding the new amortizations that are now collected through retail rates, our O&M expense in 2024 could be relatively comparable to our O&M expense in 2023. We anticipate spending between $925 million and $975 million of CapEx for 2024. As the five-year forecast showed, we expect to see a continuation of these CapEx numbers in subsequent years as we address growth in our service area. Finally, given our most updated forecast of hydropower operating conditions, we currently expect hydropower generation to be within the range of 5.5 million megawatt-hours to 7.5 million megawatt-hours for the year. Although we have solid carryover from the prior year, snowpack thus far has been below normal, but storms have been rolling through lately, so we're hoping for a benefit from those storms. With that, we're happy to address questions you might have.

Thank you. We are now ready to begin the question-and-answer session for attendees who have joined on the Q&A line. [Operator Instructions] 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 [directionally] (ph) 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 little bit difficult with these RFPs because so much of it is confidential. Right now, there is a shortlist, and Idaho Power did put in three benchmark bids. One was for a wind project, one was for -- and two really were for battery project. The wind was 600 megawatts. The two battery projects were 150 megawatts and 100 megawatts. In terms of whether Idaho Power will win those bids or not, we won't know here for a couple months. And hoping to execute agreements March-April timeframe, but just want to let you know that's the general size. Whether they'll be successful or not is 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.

Okay, understood. And then, can you discuss potential timing and scale of future equity issuances, maybe in the '25-'26 timeframe, given it seems like '24 has been covered with the earlier announcement?

Yes, Alex, this is Brian. So, you're right, the 2023 forward issuance we did, back in November, was intended to finance 2024's equity need. And actually maybe even a little of 2025, given that we upsized the offering. So, some of the variables we've got to look at in terms of what 2025 entails is cash flow, what we get in terms of tax credits, where our power supply costs go, things like that, that's going to impact the equity need. We do expect cash flow to improve in 2024 and in 2025, compared to what we saw in 2023. And that's going to help reduce the need. Our regulatory approach in 2024 that we're looking to, how that turns out could also impact what our equity needs look like. So, if we can reduce some of our regulatory lag we can reduce some of our equity needs. The RFPs Adam just mentioned though, if we're successful in the RFPs we will likely finance a portion of that with equity, potentially in 2025. So, we're looking to keep that debt equity at 50% or 51% equity as I mentioned. So, we will take equity to fund our growth. But as of now, all of those variables are still in play on the equity side. So, for now, what I will say is we do plan to put up an ATM at some point this year if our equity needs to come up, but we would be funding equity needs in 2025 at that point. No near-term equity needs certainly given our prior forward. But with the ATM also looking at a potential forward component, like we did in our follow-on offering last year, just to be ready in the market, if need be, on the equity side.

Understood. Thanks so much, and congrats on a great year.

Thank you.

Thanks, Alex.

And your next comes from the line of Paul

Hi, Paul.

Hi, Paul.

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

Hi, Julien.

Hi, Julien.

Good.

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, but Julien, on the -- yes, that's a great point. So, on the rate base side, things have moved. So, one of the biggest things that caused the rate base slide to change was we have higher CapEx overall, as you saw from the CapEx slide. But on rate base, some of the things with like [indiscernible] moved in this scenario. Boardman to Hemingway shifted out a little bit. And then, when you have projects, like Gateway West, while they have a CapEx element, they don't show up in the rate base forecast because they wouldn't be plant and service. So, we're only including plant and service. So, you can see some of that in the [quick line] (ph). And so, we added that [quick line] (ph) to show a little bit more about when plant might be closing and going in to be eligible rate base. So, really the answer to your question on the rate base side, it's just a shifting of projects timing-wise, not the elimination of 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 of 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 zip code 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 are -- 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 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 our -- 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.

And your next question comes from the line of Shahriar Pourreza with Guggenheim Partners. Shahriar, your line is open.

Hey, Shar.

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, it --

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 et cetera, but more just from a practical standpoint. What might be realistic to assume is going to be something safe to model, safe 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, it's not -- we can't hold them back as well.

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.

Absolutely. Got it. Thank you very much. That's all I have. Thanks for taking our questions. Thanks.

Thank you.

Okay.

And our next question comes from the line of Brian Russo with Sidoti. Brian, your line is open.

Hi, Brian.

Hi. Good afternoon. Hey, 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? 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?

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 was the other? Sorry, Brian. What was the other part of your question?

Oh, yes, for true-up. But I guess if you're going to use a 2024 test year, then it's basically current rate base would be reflected in rates.

Yes, Brian. This is Brian. So, we don't have that put together yet in terms of what the actual number we would submit to regulators would be. The true-up component is relatively small at this point. But the amount of additional rate base that we plan to cover -- plan that we put into service during 2024 that is rate-based eligible is very significant. So, when we have that number, we'll be able to share that.

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. That's what we believe with so many other things being settled in the -- in this last rate case, we feel like it's really a matter of in this time where we're growing so fast, we just simply can't stay out another decade when we're spending roughly a billion dollars a year. So, we will be in more frequently.

Yes. And Brian, you've seen us control our own and keep it relatively flat. You saw it 2010 -- '22 to 2023. We're pushing to do it again for 2024. The one area where we just aren't able to do that, of course, is in labor. So, that's an area that's very difficult to absorb, particularly as we have to keep people here and employed in order to meet these growth demands. So, we look at that one as an area where if we're looking at limited scope labor or something, we would look to include in the mix in addition to the infrastructure investment.

Yes, this is Adam. I think in addition to that, just with the growth we're seeing in batteries, you've got to maintain all this, the new systems that are out there. So, that's part of the 1M increases we're seeing as well.

And then, I would also add we have some regulatory deferral mechanisms for things like the wildfire mitigation plan that allows us to make those investments now and defer the recovery list until later. So, that helps for other rising costs that are going up.

Okay, great. And you mentioned earlier inquiries for data centers. Could you just add more context behind that? And when you might need additional generation capacity, which I assume would have to be some base load or gas-fired generation, maybe along with renewables and then tie that into maybe when we can expect the next IRP?

Yes, so it is a time right now where it is the amount of megawatts that are sort of kicking the tires. It used to be that three to five megawatts was big. These are showing up at hundreds or more. So, it's an ongoing process that it feels like we're just in a perpetual IRP analysis. So, Adam, you want to give a little more color?

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.

Thanks, Brian.

Thank you.

And your next question comes from the line of Bill Appicelli with UBS. Bill, your line is now open.

Hi, Bill.

Hey, Bill.

Hi, good afternoon. Thanks for taking my question. A lot of stuff has already been asked and answered, but just to clarify on the ADITC balance. So, Brian, I think you said you ended the year at 86 million. And then, we should add to that, I guess, the full amount from the batteries, right? Is that 50 million? I know you referenced to 25, but the total value of the batteries in terms of what it adds to the ADITC balance, is that 50 million or what is that? So, then you sort of add to that and then we back off what you assumed to utilize this year, right? And then we'll have what you assumed to utilize this year, right? And then we'll have the residual balance for moving forward. Is that the way to think about it?

You're correct, Bill. So, we had 45 million originally authorized by the regulators. We had planned to use some of that in 2023, but did not. So, we had the $45 million balance. And then, we're authorized to add to that all of the credits that are generated from the batteries that we installed in 2023. We don't get the credits until they are installed and paid for. And so, we have some outstanding payments on some of the batteries right now. The 86 million is the bulk of it. That's the total amount, 45 plus the amount we added. We expect another 15 million to 20 million to be added to that from portions of the batteries that were 2023 batteries, but are not yet on the books for purposes of the mechanism, so, ending closer to around 100 million of tax credits eligible in the mechanism for 2024.

Okay. All right. And then, you'll back off whatever you end up consuming in that range for this year, right?

Correct.

Okay. And then, in this rate filing that you're going to make, should we assume that you would go back and ask for additional credits?

I mean, we may. That is one thing we could do because we are installing batteries in 2024, and they will also generate ITCs. We think it's an efficient mechanism for both our customers and our shareholders to use the ADITC mechanism for those credits. So, it's possible that we would make a similar ask to incorporate those into the mechanism in even a limited scope case in front of the TUC.

Okay, all right. That's helpful. And then, just going back a little bit to the questions around the CapEx, you guys have talked about, and Brian sort of asked about this a little bit, and you talked about it regarding the data center, but the potential for additional capital is related to higher load growth. Is that more back-end loaded potentially to the extent that there are additional CapEx revisions from higher load growth, excluding the RFPs, but just strictly from the load growth? That would be sort of on the back end of this CapEx forecast, or is there a potential for some of that to be feathered in sooner? How should we think about that?

I think it's safe to say it's probably towards the end of the time period we're talking about, just given how quickly you could actually build something once you've negotiated a contract with such a large load.

Okay. And then, Brian, you had mentioned about when you think about the financing and what's the right metric to look at? You mentioned the 50% to 51% equity. I mean, you -- maybe you can share with us the FFO to debt number that maybe you ended the year, or you talked about the cash flow improvement. So, how should we think about under that metric if you have that handy?

So what I would tell you is we want to be more towards the 15% to 18% FFO to debt number. We ended up the year below that, and probably through this CapEx cycle, might be closer to that 13% to 15% range where we've been recently.

Okay. Okay, all right. That's helpful. All right, I'll leave it there. Thank you very much.

Okay. Thank you.

Thanks, Bill.

Thank you. And there's a final opportunity here. [Operator Instructions] 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.