Idacorp Inc Q2 FY2021 Earnings Call

Welcome to IDACORP's Second Quarter 2021 Earnings Conference Call. Today's call is being recorded, and our webcast is live. A complete replay will be available later today and for the next 12 months on the IDACORP website. I will now turn the call over to Justin Forsberg, Director of Investor Relations and Treasury.

Thank you, Paul, and good afternoon, everybody. This morning, we issued and posted to IDACORP's website our second quarter 2021 earnings release and Form 10-Q. The slides that accompany today's call are also available on our website. We'll refer to those slides by number throughout the call today. As noted on Slide 2, our discussion includes forward-looking statements, including earnings guidance and spending forecasts, which reflect our current views on what the future holds but are subject to several risks and uncertainties, including those related to any potential further impacts of COVID-19. This cautionary note is also included in more detail for your review in our filings with the Securities and Exchange Commission. These risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements. As shown on Slide 3, on today's call, we have Lisa Grow, IDACORP's President and Chief Executive Officer; and Steve Keen, IDACORP's Senior Vice President and Chief Financial Officer. We also have other company representatives available for a Q&A session after Lisa and Steve provide updates. Slide 4 shows our quarterly financial results. IDACORP's 2021 second quarter earnings per diluted share were $1.38, an increase of $0.19 per share from last year's second quarter. Earnings per diluted share over the first 6 months of 2021 were $2.27, which were $0.33 above the same period last year. Both the second quarter and year-to-date earnings are the highest in the history of the company. Today, we also increased our full year 2021 IDACORP earnings guidance estimate to be in the range of $4.70 to $4.90 per diluted share, with our expectation that Idaho Power will not need to utilize in 2021 any of the additional tax credits that are available to support earnings under its Idaho regulatory settlement stipulation. These are our estimates as of today, and they assume normal weather conditions over the last 6 months of the year and assume a continued return to more normal economic conditions over the balance of 2021. I will now turn the call over to Lisa.

Thank you, Justin, and thanks to everyone for joining us on today's call. I'd like to begin my remarks by highlighting the continued robust customer growth we are experiencing across Idaho Power service area. You'll see on Slide 5 that the growth remained strong in the second quarter, increasing 2.9% since June 2020. The influx of businesses and residential customers continues to benefit our company, while we believe the reliable, affordable, clean energy we provide remains one of the drivers for attracting new customers to Idaho. It has been remarkable to see this trend not only sustain but accelerate over the past several years. We are also seeing a return-to-normal operations for many of our commercial and industrial customers as our service area rebounds from the impact of the COVID-19 pandemic. As of the end of June, unemployment in our service area was 3.5% compared with 6% in June 2020 and the current mark of 5.9% nationally. Total employment in our service area has increased 6% over the past 12 months. Moody's forecasted GDP calls for very strong economic growth of 7.6% in 2021 and 6.9% in 2022. As we speak, like many employers in our area, Idaho Power is in the midst of the return-to-workplace process for many of our office employees. I'm happy to see more people at our offices and thrilled that safely bringing our employees back reflects a significant step forward to our new normal that is taking place across our service area. Idaho Power service area continues to experience significant interest from commercial and industrial projects in food processing, manufacturing, and distribution. Multiple developers, both local and national, are moving forward with the construction of commercial-sized facilities to better accommodate the speed to market of prospective projects. Idaho Power has also been actively working with Gervan Mining, which announced in early July, it will proceed with final construction of its Idaho Cobalt operations mine in Central Idaho. And just this past week, Lamb Weston announced a $415 million investment in the planned construction of a new french fries processing line at its existing facility in American Falls with expected capacity to produce more than 350 million pounds of frozen french fries and other potato products annually by mid-2023. This expansion is expected to add approximately 130 jobs. In addition to serving more customers than ever, we've experienced very hot, dry weather during the second quarter with our service area experiencing several very high-temperature days in late June and July. Slide 6 shows the recent outlook of precipitation and weather from the National Oceanic and Atmospheric Administration. Current weather projections for August through October show a 50% to 60% chance of above-normal temperatures and a 33% to 50% chance of below-normal precipitation in Idaho Power service area. If the warm and dry weather continues, we expect to see continued strong sales during the third quarter, particularly for residential and irrigation customers. At the same time, dry conditions and overall lower reservoir storage levels have decreased our forecasted hydro generation for the remainder of the year, which Steve will address later on. But it continues to appear that irrigators in most parts of our service area should have enough water to get them through the current growing season. The combination of customer growth and hot, dry conditions has created high demand for energy across our regions, as noted on Slide 7. Idaho Power hit a new all-time peak load of 3,751 megawatts on June 30, and we have exceeded the previous 2017 peak demand of 3,422 megawatts, more than 60 separate hours on 12 different days so far this summer. I'd like to thank the wonderful employees throughout our company who are helping us continue to meet this record demand. The recent heatwave has once again demonstrated the skill and dedication of our employees and the resilience of both our employees and our system. I'd also like to acknowledge our customers for helping us lighten the load during hours of peak usage in the late afternoons and evenings when we also ran demand response programs to help reduce loads. While we've been able to maintain reliable power for our customers during these extreme conditions, we also acknowledge the need for continued planning and preparation to meet the growing demand. The Jackpot Solar 120-megawatt project in Southern Idaho is scheduled to come online by the end of next year. Our company also recently issued a request for proposals to add another 80 megawatts of a capacity resource to meet peak energy needs by summer 2023. Separately, early modeling in the 2021 Integrated Resource Plan suggests that, subject to the timing of coal unit exits, additional capacity may be needed in future years. The recent spike in energy use and prices also emphasizes the importance of the Boardman to Hemingway transmission line, or B2H, which we plan to bring online as soon as 2026. B2H will allow Idaho Power to import up to 500 megawatts, which will help meet customers' peak summer demand and increased reliability for our system as well as the region. Record heatwaves don't last forever, but we believe periods of higher demand in the summer months are here to stay. Of note on B2H this month, all co-participants entered into an agreement acknowledging that Bonneville Power Administration does not intend to participate in the construction of the project or to be a co-owner in whole or in part of the project, and the EPA intends to sell its interest in the project to either Idaho Power or a third party. Idaho Power continues to evaluate its options regarding BPA's interest. I have a couple of notable Idaho regulatory updates to share. The first is a recent filing Idaho Power made to accelerate the recovery of depreciation expenses at the Jim Bridger coal-fired plant, which is noted on Slide 8. Our Idaho rates currently reflect a recovery timeline through 2034, but preliminary analysis indicates the potential exit of all 4 units at the plant sooner than the current timeline. If our filing with the Idaho Commission is approved as filed, rates would increase $30.8 million in December of this year. This would result in a near-term rate increase for our customers, but our study shows the potential for customer savings in the long term. Exiting the Jim Bridger plant early also aligns with our goal to provide 100% clean energy by 2045. Secondly, as seen on Slide 9, the Idaho Commission recently approved Idaho Power's request to defer incremental costs associated with our enhanced wildfire mitigation plan. This positive regulatory outcome will allow us to defer associated incremental costs to be included in a future rate proceeding. Our company is working hard to strengthen our grid and keep our customers safe during wildfire events. On our last earnings call, I stated Idaho Power did not plan to file a general rate case in Idaho or Oregon in the next 12 months. That remains true today. Steady customer growth, constructive regulatory outcomes, effective cost management, and economic conditions all play significant roles as we look at the need and timing of a future general rate case. I'll close my prepared remarks by reiterating my thanks to our employees for their hard work, meeting the increased demand for reliable energy as our service area grows, particularly during the heatwave. I also commend them for their resilience over the past 17 months as we navigate the challenges of the pandemic together. With that, I will turn the call over to Steve for an overview of our financial performance.

Thank you, Lisa. Let's now move to Slide 10, where you'll see our second quarter 2021 financial results as compared to the same period in 2020. Overall, we have experienced a very solid first half of the year, with strong customer growth, positive impacts from transmission services, and higher revenues resulting from the heat wave that affected much of the Western U.S. Because of these factors, IDACORP's second quarter net income was substantially higher than last year. On the table of quarter-over-quarter changes, you'll see our continuing customer growth added $3.9 million to operating income. Also, increased usage per customer drove operating income higher by $22.9 million. Cooling degree days were nearly double last year's second quarter, and the hot and dry conditions led to significantly higher usage across all customer classes. Irrigation and residential per customer usage increased 25% and 10%, respectively. A return to more normal economic conditions combined with the hot weather also drove a respective 12% and 8% increase in usage per customer in the commercial and industrial classes. Continuing down the table, the higher usage for residential and small general service customers was partially offset by $5.1 million lower revenues from the PCA, or the FCA mechanism. The FCA mechanism has tempered the effect of the higher usage for these customer classes and could do so again in the third quarter if customer usage continues strong. Next, you'll see a decrease in operating income of $6.8 million that relates to the change in the per megawatt hour revenue, net of power supply costs and power cost adjustment impacts quarter-to-quarter. The primary driver of this decrease relates to the amount of net power supply expenses that were not deferred to Idaho Power's power cost adjustment mechanisms. Recall that Idaho customers generally bear 95% of power supply cost fluctuations, and those costs were higher as the heatwave impacted wholesale energy prices at a time of increased energy usage by our customers. The heatwave also affected transmission wheeling-related revenues, which increased operating income by $3.9 million. Wheeling volumes increased as utilities work to serve high demand by moving energy across our system throughout the quarter. In addition, wheeling customers paid 10% more for Idaho Power's open access transmission tariff rate that increased last October to reflect higher transmission costs. Next on the table, other operating and maintenance expenses increased by $5.3 million. This was primarily due to last year's temporary deferral of certain maintenance projects at Idaho Power's jointly-owned thermal generation plant as well as higher accruals of performance-based incentives. We continue to see decreases in employee travel and training costs related to COVID-19, while our allowance for bad debt remains above historic levels and it's taking longer to collect. Our net COVID-19 recovery deferral impact, however, continues to remain nominal. Finally, our higher pretax earnings led to an increase in income tax expense of $4.2 million this quarter. The changes collectively resulted in a net increase to Idaho Power's net income of $9.6 million, or $0.19 per share. IDACORP and Idaho Power continue to maintain strong balance sheets, including investment-grade credit ratings and sound liquidity, which enable us to fund ongoing capital expenditures and distribute dividends to shareholders. IDACORP's operating cash flows, along with our liquidity positions as of the end of June 2021, are included on Slide 11. Cash flows from operations were about $39 million higher than the first 6 months of last year. The increase was mostly related to working capital fluctuations and the timing of net collections of regulatory assets and liabilities. The liquidity available under IDACORP's and Idaho Power's credit facilities is shown on the middle of Slide 11. At this time, we still do not anticipate raising any equity capital in 2021. Our combined liquidity, along with expected regulatory support from our annual adjustment mechanisms, is a substantial backstop to our expected capital and operating needs. Slide 12 shows our raised full year earnings guidance and our current key financial and operating metrics estimates. We now expect IDACORP's 2021 earnings to be in the range of $4.70 to $4.90 per diluted share. This guidance assumes normal weather and operating conditions for the second half of the year and assumes economic impacts from the pandemic will continue to normalize. Our guidance still assumes Idaho Power will use no additional tax credits in 2021. While we do not currently expect to record sharing of excess revenues with Idaho customers this year, the upper end of our range approaches that level, and the final jurisdictional allocation can adjust on that through year-end. Recall that above a 10% return on equity in the Idaho jurisdiction, Idaho customers would receive 80% of any excess earnings. Our expected full year O&M expense guidance remains in the range of $345 million to $355 million. It's fair to say this goal to keep O&M relatively flat for the ninth straight year is being challenged by the amount of customer and load growth we are experiencing. We also reaffirm our CapEx forecast for this year in the range of $320 million to $330 million, excuse me. Our expectation of hydropower generation has decreased somewhat given the weather conditions least represented and is now expected to be in the tightened range of 5 million to 6 million-megawatt hours. With that, Lisa and I and others on the call will be happy to answer your questions.

Your first question comes from Chris Ellinghaus with Siebert Williams.

I got a million questions where there's a lot of exciting stuff here. First of all, should is it time to get worried at all about next year's reservoir levels considering sort of the outlook for precipitation and the expectation that there might be another La Nina developing for the fall? So can you just sort of give us your thoughts on that and where reservoir levels are today?

Yes, certainly, I can start. Chris, this is Lisa. One of the things I was taught very early in my career is that no amount of worry actually puts any water in the reservoir. So it's not so much that we worry about it, but we certainly planned for the worst-case scenarios. And so we are being careful about how we're using the water. I would remind you we have some weather modification techniques that we utilize to maximize what we can get from each storm that comes through. Additionally, La Nina can often produce good snowpack for us. Generally, it tends to be more beneficial than not, although last year was also a La Nina, so there's not really a consistent trend. It continues to be variable. We definitely know how to operate in those conditions. This does mean we rely more on the market, and the diversity of our portfolio allows us to access other energy sources during drought conditions. Adam, is there anything you would add from an operations perspective?

No. I think you covered it. It's a little bit too early to tell, but we are focused on it, and we in fact have some meetings over the next month or so to make sure we keep an eye on it.

Lisa? Chris, let me add one thing. It's been a while since we've talked about these issues. But if you go back a few years, we've had multiple times that we've had several years in a row that we had drought-like conditions. And one good thing is the Brownlee Reservoir sort of hits a bottom, and that bottom might move slightly. But the level we're at right now, I think, is nearing the point. It kind of doesn't go below that even in bad years. Now that doesn’t mean that's an optimum thing because it would much rather have a lot more water, but it doesn't go down to 0 or at least hasn't in what we've seen.

Okay. Lisa, can you talk about what you were saying on the commercial and industrial recovery, where do you feel like you are compared to normal? And what did this quarter look like versus last year from what you can interpret the COVID situation?

Well, as I mentioned in the remarks, we really are seeing a return to normal levels. And then some of the new business is starting to show up as well. So there have been some maintenance cycles that have happened during the last year that felt a little bit out of cycle from their normal timing, but I think they might have been taking advantage of what was going on in the world to do some maintenance in a time that was slightly different than normal. So I would say it's getting really close to normal levels. And as we mentioned, lots of planned increases as well. So we're very excited about that return because also, that means people are getting back to work, and we're very optimistic.

Okay. I just want to make sure I'm clear on this. You said a couple of times that the revised guidance is assuming normal for the second half of the year. So you haven't included any consideration for what appears to be a pretty hot and dry July so far?

Chris, I would say that we don’t include those in our baseline. Our midpoint is not something we disclose within our range, but we do consider them as we look upwards. As I've mentioned, the third quarter and July seem quite promising, and the entire quarter plays a significant role in our annual results. The idea is present; it’s not fixed, and I’d describe it as a range. We did mention towards the end that we're beginning to share some insights, but that doesn’t mean we’ll stop at any point. I believe this is a reasonable range. We've drafted the outlook, and by mid-July, much of it is coming together. As you noted, the heat has continued.

Okay. When does the sort of the unofficial end of the irrigation season really hit for you?

It generally is late August, September, depending on the crops that are planted. So I would say it's generally into September, early September.

Yes. That's one area, Chris, where I think we don't know sometimes if we just got irrigation earlier or how much of it is going to be an absolute up. So that is one of the question marks that kind of you wait until you get to the end of August and you kind of know what really happened, how much of that was all up and how much was just sooner.

Right. Lisa, you mentioned this cobalt mine. Can you give us some details on what kind of load does that look like?

I'm going to have Adam Richins answer that. He's been more directly involved with that. Adam, do you want to take that one?

You bet. Chris, one of the things I think you noticed that gets a little bit touchy with our customers in talking about the load, tend to be a bit confidential for them. So I can't get into that. Right now, they're focused on a mid-2022 in-service date. And I'll just tell you, I've been up there. I've looked at the mine, and it's moving in terms of construction. So that's what they've said publicly. And in terms of the load, you can't get into that, but we're pretty excited about what it will bring to our service territory.

Will you be able to later talk about the load or maybe what the scale of the mine is?

Yes, it all depends on whether they're willing to go out with that information publicly. A lot of these folks consider it competitive information if others are looking at what their load is, then they can determine how much they're buying and some of those types of things. So it really depends on the customer. I would love to share more, but they have to let us know kind of when it's okay for us to do so.

Okay. And Lisa, you sort of were talking about depending on the coal retirements and obviously, had some new peak loads and whatnot. Can you give us your general thoughts on new resources? Obviously, IRP details are somewhat fluid, but can you sort of talk about what your vision is? And would you imagine participating in any kind of material new resources?

It's a great question. So as you mentioned, the IRP is really the process we go through to identify our future resources. But we do have an RFP out there on the street for 80 megawatts that we didn't have previously in the plan. It really came up from the analysis we did on looking at whether or not we could take the second unit of Valmy out earlier. And when we refreshed all the variables, it demonstrated that we were going to need something sooner. And something that was a capacity resource, not just energy. And so we're looking forward to getting the results back there. And then we are looking at all kinds of resources. And again, that analysis that goes into the RFP, or excuse me, the IRP is really critical. So that's where we can test sort of the technologies against one another on their performance and costs. So I am very optimistic. I think there's a lot of exciting opportunities out there. And I'll let the IRP run its course, and we'll have more information available at that point. That should be out by the end of this year.

Your next question is from Ryan Greenwald with Bank of America.

Maybe first, can you guys just talk a bit about any shift in dynamics amid the latest scarcity concerns when it comes to the planned early acceleration of Jim Bridger? So in terms of any initial conversations with stakeholders and any change in mindset there?

Yes, I'm not sure. I mean we've been certainly, again, talking with the IRP and other stakeholders about what that might look like. And certainly, we talk with our partner over at PacifiCorp. Recall they're the majority owner, operator of that plant. So I don't think there's been anything that I could say is a change of how we've been thinking about it in the past. So maybe I'm not fully understanding the question you're asking.

Yes, Ryan, if you consider the two plants that we have already transitioned, the end-of-life costs and related factors seemed distant at the outset. However, as we progress, we need to address the complete situation and find a solution for each plant. Regarding the Bridger decision, as Lisa mentioned, we have the latest insights on timing, and there's continuous effort on the upcoming steps. The process of distributing costs over time and collecting them from the customers benefiting from the plant's use remains unchanged, and this situation largely drives the filing.

Got it. So it sounds like at this point, you guys are trying to proceed with the earlier acceleration, not too concerned about a slowdown?

Not too much. I pointed out that the beauty of this is how both Valmy decisions and Boardman were presented, allowing for flexibility. They function as a living plan once implemented. You start with a plan, there's plan A, which then evolves. The process allows for ongoing oversight and continuous updates. So, starting with this process is beneficial, and you won't reach a point where you have a perfect forecast for the future. Our focus is more on a mechanism that can adapt to these situations.

I think it's important to mention that regarding the Valmy agreement, the final depreciation date actually occurred after we would complete our operations there. Therefore, if we needed to adjust the operation date, it wouldn't affect the depreciation schedule. We still have some flexibility in that area.

Understood. And then maybe lastly, with respect to the BPA intention to sell their stake, any more color you guys can provide there around timeline and how this could play out in coming months in terms of your potential ownership?

Well, we're still working with our partners on that. So there isn't a lot more that we can say, but they are active conversations, and we continue to work through it.

Your next question is from Brian Russo with Sidoti.

I have a question that may seem a bit odd, but is there a possibility where it gets excessively hot and dry, causing demand to surpass your generation capacity? In those low hydro conditions, would you be forced to purchase high-priced power, which contributed to the negative margin variance on the PCA?

I think we need to be careful with terminology, but when we experience high power levels and need to manage those, it becomes a balancing act. We often refer to it as balancing, especially when we're conserving water for later in the year. The market may provide opportunities to purchase power at a better price, allowing us to reserve some of our resources for future use. Operators are continuously working to manage this situation, although it can lead to increased costs. Historically, we've faced years with very high power costs. In one instance, we offered to spread those costs over several years but ultimately had to collect them in a single year, which raised expenses. Our costs are somewhat influenced by the market, and we strive to manage that as best as we can. The hydro resources are beneficial since they offer us more flexibility at times, and we would prefer to have more of that. We began this year with a fairly typical amount of carryover, slightly below average going into summer because we used some in the spring, but it was close enough. Even with a good year, there can be days when we need to purchase from the market.

And Adam, do you want to add any color? Because we have a relatively new group of leaders in operations, and they were really creative looking out and seeing some of this coming and moving quickly to adapt.

Thank you for the question. It’s an important one. In June, we faced a rare event in our service area, with a significant occurrence in the Northwest that was even less common. As Steve pointed out, while the conditions for carryover were decent, we had one of the driest springs in recent memory. However, we managed to navigate through it successfully. The system performed well. Our operational team is trained for these situations and is well-prepared. We did need to purchase additional energy from the market, but we have processes in place to proactively manage these situations and sometimes hedge those purchases as well. We also bought some transmission on the market that we might not have previously. Ultimately, this is part of our routine operations. While it adds some pressure to our system, it has been performing well, and we are satisfied with the outcomes.

Right. Got it. So the $6.8 million of negative net income driver related to power supply costs. That implies you're already in the 95%-5% sharing, correct?

The 95%-5% arrangement applies to all power supply costs, regardless of whether they are lower or higher than usual. When costs are lower, 95% of the savings are returned to customers, and we retain 5%. Conversely, when costs are higher, we keep 5%. This primarily pertains to Idaho. The customer absorbs the costs, and we take the remaining 5%. Previously, this was a 90%-10% split, which has now been adjusted to 95%-5%. This arrangement is based on the most recent rate case, and the 95%-5% distribution works off the figures established in that last general rate case.

Okay. Got it. And then the IRP filing, I think you got an extension to December, but I think the target month was in September of 2021 to file. Is that still the goal? Or is it going to be pushed back, do you think, towards the end of the year?

Our goal has been around November. And right now, we're on track to meet that.

Okay. And then also the e-megawatt RFP, is that a purchase power agreement-type scenario? Or is that something you would consider self-building?

We're aiming to do a bit of both. We would love to build and own something, but we also want to ensure that there is a response to the RFP. So we are open to various possibilities.

Okay. And then lastly, can you remind us what BPA's percentage stake is in the B2H?

I believe it was 24%.

Okay. So 24% of, I guess, that $1.1 billion kind of cost you guys disclosed?

Your next question is from Ashar Khan Verition.

So I just wanted to, I guess, there are a couple of things happening, if I may mention, right, to what people are talking about. But the higher load and the higher warm weather is generally positive for earnings. Is that fair to assume?

I'd say that, yes.

Generally.

We've had a strong July. As you mentioned, we still need to consider August and somewhat September, but August is a crucial month, correct? That month isn't yet factored into your forecast. However, you indicated that if you exceed the upper end of your range in the 490s, you would be included in the sharing mechanism, if I understood correctly.

Yes. We're not stating that 490 is the fixed number. We're simply informing everyone that it is not significantly beyond where the allocator currently stands. It remains stable, but it can fluctuate slightly. However, it is currently above that upper range.

Understood. Understood. I totally understood it, but it's not at 490 right now. That's my main point. I guess I just wanted to clarify that, right?

You're correct. It's above that.

I just wanted clarification on that. Also, do you have any updates on the relicensing issue? Do you still see it as a 2023 event?

Well, it's an ongoing process. At this point, we believe that, that still is possible, but there's the goblet of things we've got to go through to get there, but that's our best guess today.

Okay. I'm trying to understand the recent growth in the service territory. If you refer to your annual report, you'll notice that our return on equity has slightly decreased. We typically earn around 9.6% to 9.4%, and based on last year’s report, it seems our total stock book value shows a low of 9.3%. From your perspective, what do you consider the ideal return on equity? Should it be 9.3%, 9.4%, or 9.5%? Where should we set our expectations for future planning with this higher growth? I’d like to hear your thoughts on this.

So, you'd say it ideal, I mean, they do move. There's years that we have better support, say, out of our subsidiaries. Our Oregon property has no mechanism around it, the way Idaho does. So it has variability. And so the reality is there are some years we don't get as high as others. But the goal is to maximize, yes.

To maximize, yes.

Yes, we are focused on maximizing our efforts. We've frequently discussed the considerations around whether to file or not, and the impact of ongoing growth. The pandemic introduced uncertainties, and it was hard to gauge where we stood, but it seems that growth remains strong. We're committed to keeping pace and ensuring we address future demands. Some of the years in question were affected by circumstances we didn't foresee, including the pandemic, which certainly wasn't on my radar five years ago. Despite the fluctuations, I believe we are in a solid position, and our narrative continues to progress positively. Growth is our immediate focus, and as Lisa mentioned, we have outlined some of our increasing needs and capital expenditure growth in our shareholder updates, which highlight a different narrative that is evolving. We are still on that path.

Okay. If I can ask one last question. Looking at it on a consolidated basis, the book value is increasing by $2. If you apply a lower end return on equity of 9, that amounts to around $18 million. Dividing that by 50 million shares suggests that we should grow by about $0.30 annually, but we haven't achieved that. I'm trying to understand the correct way to assess the increase in book value since that's a consolidated figure. What would be a reasonable estimate for IDACORP's increase in book value? Is it $1.50, or what should we consider as the right number?

Yes, we haven't released that information yet, Ashar. That's why we have been sharing a chart for several years that shows year-over-year changes. With that chart, you can analyze the years when we've reached sharing limits, allowing you to estimate potential support levels and determine where sharing might exceed those limits. People often use that for their estimates.

I wanted to check in again to see if I could improve my model's accuracy. Thank you for the great results. As a reminder, when do you usually announce your dividend policy? I seem to have lost track. In the past, it was released in August. Is that still the timing, or has it been postponed to the fall?

For the last few years, we have typically announced our dividend changes in September. I believe we shared that this would be our approach. Normally, we provide some guidance about what to expect for the following year, but we did not actually make the announcement until after September.

That concludes the question-and-answer session for today. Miss Grow, I will turn the conference back to you.

Thank you again to all of you for your continued interest in IDACORP. We certainly look forward to the possibility of meeting with you in person later this year, and I continue to wish you all good health, and have a great evening. Thank you very much.

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