Title

Presentation

IDACORP, Inc. misses on earnings expectations. Reported EPS is $2.12 EPS, expectations were $2.18.

Operator: Welcome to IDACORP’s Third Quarter 2024 Earnings Conference Call. Today’s call is being recorded, and our broadcast is live. A replay will be available later today, and for the next 12 months on the IDACORP website. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

Amy Shaw: Thank you. Good afternoon, everyone. We appreciate you joining our call. This morning, we issued and posted to IDACORP’s website our third quarter 2024 earnings release and the Form 10-Q. The slides we will reference during today’s call are available on IDACORP’s website. As noted on slide two, our discussion today includes forward-looking statements, including earnings guidance, spending forecast, regulatory plans and actions, financing plans, and estimates and assumptions that reflect our current views on what the future holds, all of which are subject to risks and uncertainties. These risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements.

Our cautionary note on forward-looking statements and various risk factors are included in more detail for your review in our filings with the Securities and Exchange Commission. As shown on slide three, we have Lisa Grow, IDACORP’s President and CEO; and Brian Buckham, IDACORP’s Senior Vice President, CFO, and Treasurer, presenting today. We also have other members of our management team available for a Q&A session following our prepared remarks. Slide four shows a summary of our financial results. IDACORP’s third quarter 2024 diluted earnings per share were $2.12 compared to $2.07 for last year’s third quarter. In the third quarter of this year, we recorded $2.5 million of additional tax credit amortization under the Idaho regulatory stipulation, but recorded no additional ADITC amortization during the same period last year.

Earnings per diluted share were $4.82 for the first nine months of this year, compared with $4.53 for the same period last year. Those results include additional tax credit amortization of $22.5 million through Q3 of 2024, compared to $7.5 million for the same period last year. Today, we updated certain key metrics and guidance for 2024. We increased the lower end of our previously-reported full-year 2024 earnings guidance to a range of $5.35 to $5.45 per diluted share. Our expectation of additional tax credit Idaho Power to use to support earnings also improved to a range of $25 million to $35 million. We’re pleased to see our strong operating performance reduce our full-year estimate on tax credit usage again this quarter, preserving credits for the future.

These estimates assume historically normal assume historically normal weather conditions and normal power supply expenses for the remainder of the year. Now I’ll turn the call over to Lisa.

Lisa Grow: Thanks, Amy, and thanks to everyone for joining us on Halloween. We have a treat for you today. I want to begin by acknowledging the incredible work our employees have done during a very hot and busy third quarter. According to the National Weather Service, 2024 was Boise’s second-hottest summer on record. When coupled with the robust customer growth in our service areas, the demand for energy continues to grow. We set a new record system peak of 3,793 megawatts on July 22, and we also hit new record monthly peaks in August and September. Our ability to maintain reliable service for our customers during the hot summer months is a testament to our innovative, resilient, and hard-working employees. Despite its challenges, the hot weather led to strong energy sales, which Brian will provide more color on during his remarks.

The hot-dry conditions led to an active wildfire season across the West, including in our service area. On the prevention side, as I mentioned during our last earnings call, we had our first public safety power shutoff event this summer, enacting the plans we’ve had in place for several years. A PSPS is one of our many wildfire mitigation efforts, and we continue to mature and implement our wildfire mitigation plan to help keep our communities and our systems safe. We’re still experiencing strong customer growth and economic expansion across Idaho power service area, as you can see on slide five. Our customer base has grown 2.6% since last year’s third quarter, including 2.9% for residential customers. We now serve more than 640,000 customers across Southern Idaho and Eastern Oregon.

Many of our commercial and industrial customer segments increased their usage compared to 2023, including year-to-date growth of 15% for manufacturing, 12% for food processing, 8% for sugar production, and 5% for dairy. We see sustained interest from large-load customers evaluating Idaho power service area. As we prepare for our 2025 IRP, the preliminary five-year forecast for our retail sales growth rate is 7.7% annually. That’s a notable increase from the already significant 5.5% growth rate we had in our 2023 IRP. This updated rate doesn’t include the load for two prospective energy-intensive projects for which we recently completed and delivered detailed construction and generation studies. We’re working with these prospective customers to determine whether they intend to move forward with construction at their facility.

If either were to take that step, these projects would represent another significant increase in industrial load on our system, likely increasing the 7.7% rate. Additionally, our customer pipeline includes a robust mix of datacenters, manufacturing, food processing, distribution, warehousing, and cold storage projects. We’ve also experienced an uptick of biodigester projects, partnering with our local dairy customers, and we’re engaged with several proposed large-scale residential developments intended to serve growing workforce needs in Southern Idaho. As our service area grows and energy demand increases, we’re working to secure additional resources to meet current and future needs. Turning to slide six, as part of our RFP process, we have selected several wind, solar, and battery projects, along with several power purchase arrangements to meet projected low deficit through 2027.

Notably, we’re under contract to purchase and own a 300 megawatt wind generation facility which would become Idaho Power’s first company-owned wind project. Brian will touch on how these additional projects have impacted our CapEx plans in a bit. As we look beyond 2027, we’ve initiated an all-source RFP for resource needs in 2028 and 2029. Along with our important transmission project, new dispatchable resources will be part of the solution as we work hard to find a balance of least cost least risk resources to serve our customers. Turning to slide seven, I’ll address our regulatory cases in Idaho and Oregon. The Oregon Commission approved our general rate case settlement in September, resulting in an overall base revenue increase of $6.7 million or around 12% for Oregon customers, effective October 15.

This was our first general rate case in Oregon since 2011, driven primarily by the significant infrastructure investments we’ve made since then to serve our customers safely and reliably. In Idaho, we’ve requested an increase of $99 million or 7.3% through a limited scope case we filed in late-May to focus on recovering period-end infrastructure investments through 2024, as well as our increased labor expenses. We’re making our way through that proceeding, and expect the case to go to hearing in December. We have requested new rates to be effective on January 1, pending approval from the Idaho Commission. I’ll close with a look at hydropower conditions. As we head into winter, our outlook remains good. We’re hopeful this winter’s snow pack will further bolster hydro conditions as we head into 2025.

And if you look out our windows from our offices, there’s some nice snow at the top of those mountains. As I mentioned last quarter, our multiyear efforts to refurbish our hydro fleet were critical this summer. Those resources were key in helping us serve and balance loads during the hot, high-demand summer months. As you can see, we have work to do to continue to provide our customers with safe, reliable, affordable, and increasingly clean electricity in these exciting times. And we’re up to the challenge. With that, I’ll turn the time over to Brian.

Brian Buckham: Thanks, Lisa. I have a relatively lengthy update, so I apologize for those of you getting ready to trick or treat. But I’d say today isn’t your average conference call. We want to give you a more comprehensive update. And then, we also look forward to following up with you in discussions during the upcoming EEI financial conference. So, I’m going to start on slide eight, our reconciliation of the third quarter’s results. IDACORP’s net income increased $8.3 million for the third quarter of this year versus last year. That was due to higher net income at Idaho Power from this year’s increase in Idaho base rates, and from customer growth of 2.6% over the past 12 months. Higher usage per retail customer, particularly from residential and irrigation customers also benefited the quarter.

Total other O&M expenses increased $20.3 million in the third quarter, as in part from $4 million of increased pension-related expenses and $6 million of increased wildfire mitigation and related insurance expenses during the quarter. Those costs were partially offset by increases in retail revenues because they were included in the last Idaho rate case for recovery through base rates. Inflationary pressures on labor-related costs also contributed to the increase in other O&M expenses. Depreciation expense increased $5.6 million for the quarter. We expected that increase from the system investments we’ve made to meet growing customer needs and to maintain system reliability. Other net changes in operating revenues and expenses increased operating income by $3.3 million.

That was mostly due to a decrease in net power supply expenses that weren’t deferred for future recovery in rates due to power cost adjustment mechanisms. And on a net basis, non-operating expenses decreased $2.4 million in the third quarter from a combination of increased AFUDC from the higher construction work and progress balance and increased interest income from higher interest rates on cash. And those increases were partially offset mine increase and interest expense on long-term debt, as you might expect. The increase in income tax expense shown in the table was mostly the result of higher income before income taxes, partially offset by an increase in additional ADITC amortization compared to last year’s third quarter. Turning to slide nine, cash flow from operations improved substantially from last year, it’s close to a net $300 million comparative increase.

The June 2023 power cost rate change and the revenue benefit of the January 2024 rate changes from the Idaho general rate case, and a notable moderation in power supply cost, all combined to help with the significant improvement in cash flows. Okay, with that, I want to spend the rest of my time on some important updates that we have. As Lisa noted, our 2025 IRP’s preliminary five-year forecast for annual retail sales growth rate is 7.7%, which is obviously substantial. And I’m going to reiterate the point that the 7.7% doesn’t include loads from the two potential energy-intensive customers that Lisa mentioned. Nor does it include any sort of estimated sign-on rate for the remaining several gigawatts of prospective customers that are in our pipeline.

So, looking out over the next few years on load additions, there’s still potential upside on that rate of load growth. That customer growth inevitably results in additional CapEx. So, in February of this year, we increased our five-year capital forecast by 21% from our February 2023 five-year CapEx estimates. And we mentioned there was some upside potential in that. And that February increase resulted from a lot of different things like project cost updates and the time to get new resources, but it didn’t include results from our 2026 and 2027 RFPs. So, we’ve largely made our way through those RFPs, and we’ve updated CapEx estimates for our projects from 2024 through 2028. And the updated CapEx estimates are on slide 10. I think you’ll agree they’re substantial.

So, these updates include two particularly sizable projects, so 200 megawatts of company-owned batteries for 2026 and the 300-megawatt owned wind project in Wyoming that Lisa mentioned. And combined in terms of dollars for those two projects and some interconnection infrastructure for them, that’s a ways over $1 billion of incremental CapEx through 2028, including our estimate of AFUDC for just those two projects. The payment timing and construction windows move around, so we’ll plan to update this slide again in February and add in 2029. That’s our usual cadence for CapEx updates. We’re providing this update today because of the magnitude of the increase. All in our total CapEx increase from our February estimate this year to our current estimate is about 46%, which is $1.8 billion in incremental capital.

We’re not necessarily done yet. As Lisa noted, we have RFPs outstanding for resources in 2028 and beyond. They’re all resource RFPs, and Idaho Power has submitted its proposed company-owned projects into the process. Any potential wins from those RFPs are not yet in our CapEx forecast and we’re several months out from knowing even the short list in that process. Also excluded as of now are the incremental capacity and energy resources we may need to serve either of the two large industrial customers that Lisa and I mentioned. I think it’s important to remember that we’re building to serve our growing customers. It’s not optional work. As a vertically integrated utility, it’s our obligation to serve existing and new customers reliably, and that’s why we’re building this infrastructure.

IDACORP is a different company than it was even a couple of years ago, and I’ll say it’s an exciting place to be. It isn’t enough to build the needed infrastructure. We’re also charged with converting that CapEx into rate-based through the regulatory process to keep the utility financially healthy. Our estimated rate-based CAGR was 10.8% in our last refresh in February, and that was based on our prior CapEx estimates. On slide 11, you can see our updated rate-based CAGR forecast of 16.9% with the latest CapEx forecast, based on our estimated in-service dates and assuming timely inclusion of the new CapEx in rates. If you look at the chart, we’re effectively expecting to double our net rate base in a five-year period from where it was when we filed our 2023 Idaho general rate case.

I’m not sure we’ve seen that organically in our industry before, at least not in the last few decades, although, we did look back, and Idaho Power did it in the late 1950s with the construction of two portions of the Hells Canyon Complex. So, there is at least precedent for that doubling. One common question we’ve received is, how can we keep rates affordable for customers with that level of CapEx and rate-based growth? And on affordability, we’re in a good position with our regulatory and service area formula. We start with low rates of around 20% to 30% below the national average. Related to that, Idaho’s growth pays for growth regulatory approach will also help accommodate the additional rate base. New large load customers pay up front for certain infrastructure that directly serves them, like a transmission inter-tie or a dedicated substation.

After that, those new large load customers are required to pay through their special contract a load ratio share of incremental system resources that come out of our generation and construction studies. This is under the base premise that the infrastructure development we undertake for our large new customers shouldn’t harm our existing customers. With our growth, we’re also fortunate to have an expanding denominator of customers, including new and expanding industrial customers with individual special contracts based on the cost to serve them to absorb rate increases. Also, much of what we’re constructing are long-lived assets, which reduces the magnitude of recovery of depreciation and rates. And I’ll say last, I’ll mention our culture of keeping operations efficient and a track record of continuing to manage O&M expenses also helps with rates.

Ultimately, with each of those aspects of our service area and regulatory framework, our expectation is that we’ll be in front of our regulator frequently, but with reasonable rate requests for our existing customers, with the new and expanding larger special contract customers providing cash flows for much of the infrastructure we’ll construct for them. Our customers, our owners, our cost of capital, and economic development in our service area all benefit from this thoughtful regulatory framework. A continued thoughtful and constructive regulatory framework is an important aspect of our value proposition and important to our attracting capital that helps us and our service area prosper. Another area I want to cover is the financing plan for our CapEx. Like we’ve said before, we’ll need growth capital, and it’s going to be a blend of debt and equity.

We intend to keep our capital ratio around 50% equity and debt, and that’s a really important metric for us. We have a strong balance sheet now, and we intend to keep it that way through this cycle. Turning to slide 12, the amount of external financing we estimate we need for 2025 through 2028 is about $1.3 billion in equity and about $2 billion in debt. And this is just the amount for the next four years, and we plan to update it when we build 2029 into the forecast for our February call. We’ve already financed our needs for 2024. And at this point, we expect to see a step down in the run rate of our external capital needs further out when cash flow from including CapEx and rate base helps. Lots of factors influence how much external financing we’ll need and when and even the blend of debt and equity in any given year or overall.

And it’s a litany of things. I’ll call out a few like project and service dates, capital spend, the timing of regulatory recovery and the resulting cash flows, payment timing on major projects, maintaining our debt equity ratio and our credit metrics, and capital market conditions, so, quite a few different factors. Because of all those factors, I wouldn’t assume our debt or equity issuance amounts are consistent each year or that they’re necessarily proportionate in any given year. As I noted before, our operating cash flow this year has improved substantially over a low cash flow year last year, and we expect a cash flow increase will help lower our financing needs going forward. In terms of the nature of our financing, we have lots of tools available in the toolbox.

For equity, we have an ATM program on file already, and that’s our preferred method for raising equity given the cost and efficiency. We could potentially use the current and subsequent ATM programs to fund a considerable amount of our equity needs over the next four years. Historically, we’ve been conservative and simple in our financing approaches, and we’ve had good reception in the capital markets. Simplicity in maintaining a solid and understandable balance sheet has been beneficial to the company. We’ve seen hybrids and mandatory convertibles and other instruments be more in vogue in our industry. That’s not necessarily off the table, though it’s not our first choice. We don’t have any holding company debt, and it’s not our preference to take that route either.

So, again, it’s not necessarily off the table. We’ll focus on the right financing at the right time. Next up, as we continue our infrastructure build out, our cadence on regulatory proceedings will be more frequent than you’ve seen in the last decade. You’ve seen the impact of regulatory lag in our results this year, which we expected. The 2023 general rate case in Idaho was a traditional case with a historic or arguably hybrid test year, which created that regulatory lag. So, in our 2024 Idaho case filed at the end of May, we focused on requesting a period end rate base. The idea was to alleviate some of the regulatory lag that results from a historic test year methodology. Going forward with continued high levels of CapEx, we still anticipate filing rate cases on a frequent basis.

These could take the form of general rate cases, limited scope cases, multi-year approaches, one-off recoveries of major projects, different types of avenues, all in an effort to match the timing of our collection through rates more closely with when assets are in service and serving our customers. So, what does all this mean for potential earnings growth? We think our estimated rate-based growth rate is an opportunity for the current future shareowners and bondholders who are supporting our growth, those who are providing growth capital for our business. If you start with our rate-based growth as the baseline for estimating potential future earnings, there’s an aspect of structural lag to remove, but it’s typically relatively small and consistent because we’re thoughtful spenders and we’ve kept our business model core and simple.

Another factor is regulatory lag, which can change from year-to-year, but typically works out over time. The dilution from equity issuances to fund the growth is the other item to consider in the equation. Taking all of those factors into account, we’d expect to see what we believe will be among the leading earnings growth and earnings quality profiles in the industry. It’s not necessarily linear growth, of course, particularly as we build infrastructure ahead of the time revenues from use of that infrastructure comes in the door. But the infrastructure that we’re building for our current and future customers represents a considerable amount of earning force power. So, to summarize all of this, we have a level of customer growth ahead of us that creates an infrastructure need that would both excite and challenge even the nerdiest of electrical engineers.

This growth represents a tremendous opportunity for our company, for our owners, and for our service area and its economy. We’re also focused on affordability for our customers and have what we believe to be a formula to keep rates affordable. And we’ll of course need, as we’ve mentioned before, accretive growth capital. That’s not necessarily imminently, but it will be in combination with our plan for regulatory actions that increase cash flow, support our balance sheet, and help reduce those financing needs over time. Our plan, as you might expect, is to remain focused on maintaining our record of consistent is to remain focused on maintaining our record of consistent execution in this scenario of rapid growth and infrastructure development, and in what we expect to be a continued constructive regulatory environment.

So, to finally wrap up, I’ll cover slide 13, which looks more near-term and shows our updated full-year earnings guidance and key operating metrics. After a generally on-plan start to the year in the first quarter, we saw notable improvement in our results in second and third quarters. From that, as Amy noted, we updated our expectation of IDACORP’s earnings this year, and also our ADITC usage expectations that you can see on the slide. We also tightened our hydro range we move into the final quarter of the year. With that, we’re happy to address questions. Again, thanks for listening on our lengthy Halloween update. We have a lot going on here at IDACORP. It’s certainly been busy, but also a tremendous amount of fun. One might even call it a treat.

Operator: We are now ready to begin the question-and-answer session. [Operator Instructions] Your first question comes from Alex Mortimer with Mizuho. Please go ahead.

Lisa Grow: Hi, Alex.

Alex Mortimer: Hi, good afternoon, team.

Brian Buckham: Good afternoon.

Alex Mortimer: So, just given the updated and I understand there are some puts and takes given pending regulatory outcomes. But generally, do you expect to be earning maybe around your support level in the coming years? And then maybe tied into that, any thoughts on how we should view the trajectory of tax credit usage?

Brian Buckham: Yes, Alex, this is Brian. So, if you mean the base level, do you mean by the base level the ADITC earnings level?

Alex Mortimer: Yes, correct.

Brian Buckham: Yes, to there, we do expect there to be an element of regulatory lag going forward. But again, that regulatory lag should be relatively consistent year-by-year. So, the amount of depreciation and interest expense that we would incur even if we had a period-end rate base will cause some lag mostly likely in our earnings, that customer growth alone may not be adequate to cover. So, from that basis, yes, it is possible that in the coming years we could be earning at that base level that was set for the ADITC mechanism. Over time though, we would expect the inclusion of rate base in rates to eliminate the need to rely on the mechanism over time. And that’s’ where the incremental significant earnings horsepower comes from.

Alex Mortimer: Understood.

Brian Buckham: What was the second aspect of your question, Alex?

Alex Mortimer: And then just the trajectory of tax credit usage, but it sounds like that’s also been answered, I guess, just turning —

Brian Buckham: So, we do have a tax credit appetite, Alex. And so, we will be using some of those credits for purposes of our returns, but we would expect there to be carry-over balances. The amount in the mechanism right now is about $105 million, plus or minus, and we have an expectation, as you saw in our guidance, to use $25 million to $35 million of that this year.

Alex Mortimer: Understood. And then, I guess you’re continuing to add generation, but also continuing to raise your low-growth expectations. So, how do you think about the scale maybe of your future generation needs above and beyond the current plan? And then maybe also how to view the split between dispatchable and intermittent resources, going forward, just given the load profile of some of your customers, particularly the larger ones coming on to the system?

Lisa Grow: Hi, Alex, this is Lisa. So, I think it’s important to add into the substantial amount of transmission that we’re adding to system as well, so it’s not only generation assets that will help us meet the demand. But having said that, Adam, what would you add on there?

Adam Richins: Yes, the transmission — Alex, this is Adam. Of course, we’re going to add a fair amount of wind, solar, and batteries. We’re also converting our current coal fleet to gas, both at Valmy, and at Bridger. In addition to that, Lisa mentioned that the SWIP project is a project we’re looking at. Gateway West is a project on the transmission side that we’d need to move forward to culminate some of this growth, and then, of course, B2H in 2027. In terms of dispatchable resources, as we go out for these RFPs, they’re all resource RFPs, but our models are starting to show more and more the need for dispatchable resources, particularly in the winter time. And so, you will see us in this IRP really start to focus in on that, and see if that’s needed for the timeframe of ’29 through ’31.

Alex Mortimer: Great, thank you so much. I’ll leave it there and congrats on a great quarter.

Adam Richins: Thanks, Alex.

Lisa Grow: Thank you.

Operator: Your next question comes from the line of Ross Fowler with Bank of America. Please go ahead.

Ross Fowler: Afternoon, guys. Happy Halloween. So, maybe just let me pull on a couple threads here that you talked about on the earnings call. So, the affordability one, right, let’s talk through that a little bit, right, your rate base growth CAGR grew 17%, you’re sort of doubling your rate base from where you were before. And you talked, Brian, about how you shouldn’t think about a doubling of bills or rates because there’s a lot of things that mitigate that back against that, right, so you have the depreciation that brings that in over time. Of course, you have all the industrials paying for what they’re using on the grid. And that’s really maybe the piece I want to explore, because that volume growth of that industrial load seems very high, right, for your service territory.

So, what does that actually walk the residential billing increase back to in sort of a broad scope, is that within the scope of inflation, is it mid-single digits, is it higher than that, like, what are you guys seeing as you put this plan through the regulatory process around those bill increases and that rate pressure for customers?

Brian Buckham: Yes, Ross, great question. There’s a lot that goes into that. And, at the end of the day, what we’re required to show and from the commission as we get approval of special contracts for these large industrial customers is the so-called no-harm analysis. And in doing that, that’s making sure that the infrastructure serving these new large industrial customers is being charged to those customers either in advance or over time in their rates, and so, by doing that no-harm analysis, you do end up with a lot of the incremental cost of resources being allocated towards those large industrial customers, and covered by their revenue requirement. And so, I don’t have exact numbers for you, but residential rates that track more along the rate of inflation, and the industrial rates coming up for those special contract customers on a cost-conserved basis would generally be considerably higher than what you would see for a residential customer, certainly not — [multiple speakers] residential and industrial.

Ross Fowler: Yes, I got you, Brian. So, if I thought about that in maybe another way, if I thought about the large CapEx program here, and I sort of try to figure out what was serving those industrial customers, I could take that aside and say, “Okay, I know where that is going from a rate perspective,” and then the rest is sort of just residential and commercial, and I could think about that as the actual kind of rate pressure — rate-based math I would think of, absent volume growth in that dynamic, if that makes sense?

Brian Buckham: That’s a fair way to do that, Ross. I will say that as you look across what the CapEx increases were, a lot of the CapEx is to serve existing customers as well on a reliable basis. It will be spread over a larger denominator. But we’re making upgrades in other system resources, like the distribution system, for example, hardening up the system that benefit all customers. And some of our transmission investment, for example, benefits all customers, and so that that element of it as well will be allocated across the full customer base. But a very significant portion will be allocated to the customers that are causing the increase. One other thing I would mention is that, for some of these customers, we have to build out, say, a substation specific to them or transmission inter-tied specific to them. Those costs don’t get allocated across the system to any other customers, those dedicated specifically and paid upfront by the large industrial customer.

Ross Fowler: Yes, that makes complete sense. And then, as I think about — you said you’d have to sort of — I guess given the scale of the CapEx program, what do you — you mentioned this a little bit in the call, but what is the tenure of rate cases from here, should I think about being in front of the regulator every year as you — a pretty significant capital program goes through or how are we thinking about that in terms of future rate case filing?

Lisa Grow: Yes, I think that’s a reasonable assumption just given we’re trying to reduce the regulatory lag as we go through just record amounts of capital expenditures. So, yes, I think that would be a reasonable assumption.

Brian Buckham: One thing I would add, Ross, is we could do different arrangements. We could do, for example, a multiyear arrangement with the commission, that’s not what’s sitting in front of them right now. But because of the frequent need to be front of the regulator and get rate changes to incorporate all of this CapEx converted to rate base, I mean it will serving these customers. So, we do have to have a relatively frequent cadence. So, we could be there on an annual basis or a mechanism that perhaps requires us to not be in every single year.

Ross Fowler: No, that makes sense, Brian. And then, I can’t wait to get away to go trick or treating without the earnings growth guidance question. I mean you kind of triangulated a little bit for us on the call, but is there any thought process as to where you might win or you might get more specific on that?

Brian Buckham: No, not at this point, Ross, we’re just looking to execute well on our various projects. We have a lot going on and it’s incumbent on management to get in and make sure we’re converting that into rate-based while it serves our customers. And that methodology that I talked about, starting with rate-based growth and using equity dilution to help come up with a rough estimate is our best approach at this point.

Ross Fowler: Okay, perfect. Thank you.

Brian Buckham: Thank you.

Lisa Grow: Thank you.

Operator: Your next question comes from the line of Bill Appicelli with UBS Securities. Please go ahead.

Lisa Grow: Hi, Bill.

Brian Buckham: Hi Bill.

Bill Appicelli: Hi, good afternoon. Just a couple questions, maybe building on one of Ross’s last questions there on the earnings growth. So, I mean right you’re talking 17, nearly 17% rate-based growth and I guess, is this potentially moving higher when you include 29? I mean or is that do you think we sort of peaked out here at this level? I guess that’s one question. And then, I mean, yes, I mean, 1.3 billion, even if it’s not going to be ratable even sort of simplistically, that’s 5% or 6% of the market cap, right? So, I mean, you can sort of, to your point there, we’re back into a potential for double-digit earnings growth over time. But I mean, the second part of my question after the rate based part of it is how lumpy should we expect it to be? Is there going to be periods where the lag is worse than others and we’ll be catching up, so it’s not a linear growth, but it’s going to be more sawtooth, depending on the rate case outcomes and the cadence of cases?

Lisa Grow: Yes. Starting with your last question, I would say that that’s certainly a possibility. We really are thoughtful about what we ask for in each rate case. And we work through each one and that sort of indicates what we need to think about in the next case. And then, as far as the first part of your question, as we go beyond this forecast period, as we mentioned, there are additional loads and additional resources that are out there as potential. We’ll keep updating that forecast as we go through time and have more certainty on those.

Brian Buckham: Yes, and Bill, what I would add to that is on that rate-based growth percentage, so we would start with a higher base year on that, and that’ll certainly impact the percentage growth, but the number would still be, as we expect with 29 added still robust. And as Lisa mentioned, we’re not done. There may be more additions there that we’re not aware of as of yet and are waiting on the results of customers who have construction and generation studies that are in hand. What I would say on the lumpiness is if you look at the rate-based slide that we put out there, you can see that there’s a pretty significant amount of rate of CapEx that converts to rate base at least based on our current estimates in 2027. So just even looking at the rate-based forecast you’d expect there to be some lumpiness in our earnings.

And the regulatory lag part is difficult to estimate. You know, with projects that move around in terms of timing, that can create lumpiness in our results. But again, this is CapEx that’s being used to serve customers from a reliability perspective, not really optional. So, as we’re going into the regulatory arena, we have a lot of confidence in the capital we’re converting into rate base. But yes, certainly not linear. And you can see the quip — we put the quip conversion on that rate base growth forecast slide, so you could see what we’re — what we would expect to move in and out of rates based on project timing.

Bill Appicelli: Right, okay. And then, just to clarify on the RFP wins, the batteries and the wind, you’ll be constructing that yourself, so you will get the quip. It’s not a build-on-transfer kind of one-shot deal.

Brian Buckham: That’s correct. So, we’ll be making payments on those, and because we’ll be making payments, we’ll be earning AFUDC on those assets. There are circumstances where paying at the end of a project is our preference, but these will be projects that have milestone payments.

Bill Appicelli: Okay. And then, just lastly, on the credit metrics, can you just speak to the updated outlook there? I know you’ve been sort of tracking below the ultimate target, but given the pace of growth, I mean, do you feel like you’re still trending upwards on the FFO targets, or is this going to take you longer to get there now with this just another leg up of growth?

Brian Buckham: Well, a lot of that’s going to depend on the outcome of rate cases and whether or not we’re successful in removing some of the regulatory lag. A regulator that understands the importance of the financial health of the utility is important in that regard to make sure that our cash flow metrics stay in a good spot and our credit metrics are good. You look at our plan, we plan to issue equity, we do plan to file frequent rate cases for cash collection. So, getting cash sooner will help. We’ve certainly seen that this year with a dramatic improvement in cash flow. As we look ahead on Moody’s and S&P, there are circumstances where we sort of stay near our downgrade threshold where we are now. And it is possible it takes longer to get out. And that’s part of why we filed our case in the Idaho Commission to reduce some of that regulatory lag that puts pressure on those credit metrics.

Bill Appicelli: Okay. All right, great. Thank you so much.

Brian Buckham: Thank you.

Operator: Your next question comes from the line of Chris Ellinghaus with SWS. Please go ahead.

Chris Ellinghaus: Hey, everybody. How are you?

Brian Buckham: Hey, Chris.

Chris Ellinghaus: Congrats on the update. It’s pretty exciting. Brian, you gave us a number in your financing slide for dividends. It sort of suggests that you’re going to lag dividend growth based on sort of what I’m inferring on the earnings growth side. So, can you give us a little thought on what you’re thinking about dividend growth going forward.

Brian Buckham: Yes, Chris. So, what we did there is we looked at the dividend that we decided to pay in September and rolled that forward. So, I wouldn’t necessarily use that as a proxy of what we’re going to do for the next four years because that can change based on our cash flow at any given time. So, we made a decision with our Board in September to slow the rate of growth of the dividend down to reinvest that money in our business and when that starts to pay more in cash flow then we’ll have the flexibility to increase our dividend payout and over time over the long term get back towards that 60% to 70% payout ratio but again we’ve got in front of us what we think is a compelling growth story and we want to be able to capitalize on the dollars that we’re getting to reinvest in the business.

Chris Ellinghaus: So are you thinking dividend growth will sort of be lockstep sort of lumpiness with earnings?

Brian Buckham: Not necessarily. If you look at what we’ve done on our dividend growth since 2012, it has been relatively steady. We decided for now to slow the growth rate down. Once we’ve gone through the regulatory process and we have some of these projects in service and we’re receiving revenues from our customers for some of the investment, we can accelerate the growth in the dividend. I wouldn’t expect the dividend to track earnings necessarily every year. I would expect a more steady cadence in the increase in the dividend growth rate for the next few years.

Chris Ellinghaus: Okay, great. That’s helpful. Something that seemed a little odd to me, the ADITC recognition for the quarter versus your guidance for the year, maybe I don’t understand your process, but it would seem that as you move through the year, it’s sort of natural for your ADITC recognition to sort of decline as you have a better view of the full-year. So, in the third quarter you get a really good picture of the year at that point, but your guidance sort of implies a bigger recognition in the fourth quarter, and I don’t quite understand why that would be? Can you give us a little thought there?

Brian Buckham: So, right now, we have $22.5 million of ADITCs recorded. So, if we end up at the end of the year with, say, $25 million or $30 million of ADITCs used, we’d record another quarter of $2.5 to $5 million ADITCs. So, last year, if you’ll recall, we actually reversed them because our estimate for the year-end changed. This year we slowed the rate down because we will amortize off whatever we need in any given quarter to hit what we believe our year-end target will be. So, that’s why we recorded larger amounts in the first-half of the year compared to what we recorded in the third quarter. So, we would expect on that cadence to record a small amount in the fourth quarter if everything continued as we planned. With that strong operating performance during the year, the first quarter was not as strong for us. Second and third quarter were stronger, which a lot of that operating performance allowed us to reduce that credit need going into the end of the year.

Lisa Grow: I think it’s also worth noting that in our 2023 rate case that we didn’t put the battery in the revenue requirement and instead are recognizing those ADITCs to sort of make up the difference as we go through these as a rate case going forward. So, it’s a way to help keep rates low for the customers. So, that’s a little bit different than previous years.

Chris Ellinghaus: Right, thanks Lisa. Another thing that seems a little odd to me in the quarter, looks like irrigation sales were only up 3.4%. Given the weather conditions that you had, which seemed pretty extreme at least for agriculture purposes. Can you give us a little color there? It seems like a pretty small increase year-over-year.

Lisa Grow: Yes, so Chris, you have to think about what crops are in. They kind of had a late start given the cold spring, so we kind of saw disappointing results in that first part of the season. And then, once they start cutting hay and those crops that come off a little bit earlier, it naturally drops in Q3 anyway. So, overall it’s been a decent year for irrigation. It’s just sort of the cadence of when they use and how much they use.

Chris Ellinghaus: Okay. One last thing, these additional large load potential customers, do you have any sense of when you may know about them?

Lisa Grow: It’s really up to them. Adam, what would you say?

Adam Richins: Yes, hey, Chris. We deliver them their studies in October. The way these studies work, they generally provide kind of cost and timing information. We’re waiting for a response. I’d hate to predict exactly when, but probably hope in the next couple months to get a good feel for where they are headed.

Chris Ellinghaus: Okay, great. Thanks for the details. We’ll see you soon.

Lisa Grow: All right. We’ll see you soon.

Brian Buckham: Thanks, Chris.

Operator: [Operator Instructions] That concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

Lisa Grow: Thank you, and thanks again to everybody for joining us today especially given that it’s Halloween. I hope you have a great evening and go out with your trick-or-treaters. I hope there’s lots of chocolate in their little baskets that you’ll pretend you’re not taking away from them when they are sleeping. So, we look forward to seeing many of you at EEI. And again, thank you for your continued interest in IDACORP. Thank you.

Operator: This concludes today’s conference call. Thank you for your participation and you may now disconnect.