Pinnacle West Capital Corporation (NYSE:PNW) Q3 2023 Earnings Call Transcript

Pinnacle West Capital Corporation (NYSE:PNW) Q3 2023 Earnings Call Transcript November 2, 2023

Pinnacle West Capital Corporation beats earnings expectations. Reported EPS is $3.5, expectations were $3.33.

Operator: Good day, everyone. And welcome to the Pinnacle West Capital Corporation 2023 Third Quarter Earnings Conference Call [Operator Instructions]. It is now my pleasure to turn the floor over to your host, Amanda Ho. Ma’am, the floor is yours.

Amanda Ho: Thank you, Matthew. I would like to thank everyone for participating in this conference call and webcast to review our third quarter 2023 earnings, recent developments and operating performance. Our speakers today will be our Chairman and CEO, Jeff Guldner; and our CFO, Andrew Cooper. Ted Geisler, APS’ President; Jacob Tetlow, Executive Vice President of Operations; and Jose Esparza, Senior Vice President of Public Policy, are also here with us. First, I need to cover a few details with you. The slides that we will be using are available on our Investor Relations, along with our earnings release and related information. Today’s comments and our slides contain forward-looking statements based on current expectations, and actual results may differ rely from expectations.

A vibrant skyline illuminated by the lights of the electric utility company.

Our third quarter 2023 Form 10-Q was filed this morning. Please refer to that document for forward-looking statements, cautionary language as well as Risk Factors and MD&A sections, which identify risks and uncertainties that could cause actual results to differ materially from those contained in our disclosures. A replay of this call will be available shortly on our Web site for the next 30 days. It will also be available by telephone through November 9, 2023, and I will now turn the call over to Jeff.

Jeff Guldner: Great. Thanks, Amanda, and thank you all for joining us today. We continue to execute well on our operations performance and financial management. As part of my operations update, I’ll share with you our success in managing through a record breaking summer in the valley and reliably serving our customers when they needed us the most. I’ll also provide an update on our pending rate case and other regulatory filings. As Andrew will explain our earnings expectations for the year on track to meet our guidance range that we recently updated in the second quarter. First, I want to recognize our operations and field teams for doing an exceptional job maintaining reliable service for our customers this summer. July was just one day short of an entire month of 110-plus degrees and August did not provide much repreve.

We ended the summer with 55 days of 110-plus degrees and 36 days of overnight lows above 90 degrees. During this period, our generation fleet performed extremely well and was available when our customers critically needed the power. Our careful long term planning for resource adequacy, combined with equipment maintenance programs and innovative customer demand side programs proved beneficial throughout the summer. APS set five new peak demand records during the month of July, ultimately reaching 8,162 megawatts on July 15. That figure’s over 500 megawatts higher than our last peak demand that was set in August of 2020. Our baseload and fast-ramping assets, including Four Corners, [Indiscernible] and Palo Verde all performed well. Our nonnuclear generation fleet’s equivalent availability factor, which is the percentage of time that a generation units available and ready to perform when called upon was 93.4% from June through September.

In addition, we were extremely pleased to have our Agave solar facilities and our AZ Sun batteries online and available to serve customers. Finally, Palo Verde generating station’s capacity factor for the same time frame was 99%. With the successful completion of the summer run, Palo Verde Unit 1 has entered its planned refueling outage on October 7th. Not only were our generation plants there when we needed them our customers were as well. Customers participating in APS’ Cool Rewards program helped create grid capacity while earning bill credits for voluntarily reducing their energy use. A community of more than 58,000 customers and about 80,000 of smart thermostats created a virtual power plant to save energy during the peak hours of the summer.

This year, participating customers conserved a record 135 megawatts of power, the equivalent of a peaking unit. APS’ Cool Rewards is the cornerstone of our virtual power plant, which is rapidly approaching 200 megawatts in participation and will be an important part of our long term resource planning strategy. We’ll continue to expand this resource and these important partnerships with our customers as we continue our journey to 100% clean and carbon-free electricity by 2050. Long term planning has been key to providing reliable service. In fact, we just filed our Integrated Resource Plan or IRP with the Arizona Corporation Commission yesterday, outlining our resource needs for the next 15 years. We’re expecting strong customer and demand growth during this period and have outlined the resources necessary to maintain affordable and reliable service for our customers.

We anticipate that a variety of resource types will be important in serving this period of robust customer growth and look forward to partnering with customers, developers and stakeholders on bringing these technologies online. While the IRP does not specify ownership, we are committed to continuing our competitive all-source RFP process, which will yield a blend of PPA and ownership projects. The IRP includes a variety of scenarios but our preferred scenario identifies a diverse blend of technologies to secure a reliable grid while maintaining a strong focus on customer affordability. And this scenario also achieves our clean energy goals of 65% carbon free by 2030. With the extreme weather that we experienced each summer remains as important as ever to continue assisting our communities through our heat release support programs, APS partners with local community organizations to aid the state’s most vulnerable populations.

This support includes a collaboration with the foundation for senior living, offering emergency repair/replacement of AC systems during the hot summer months; the Salvation Army’s network of 18 cooling and hydration stations across Arizona; an emergency shelter and homeless prevention program in partnership with St. Vincent de Paul; and a new partnership with Salary 211 and Lyft to provide eligible Arizonans with free rides to cooling shelters. These are just a few examples of our efforts to collaborate for the benefit of our customers and communities, and I’m pleased to share that APS was recently recognized with the innovative Corporate Philanthropy Award by the Phoenix Business Journal for these partnerships and programs aimed at providing heat relief to vulnerable individuals and customers.

I’m also happy to share that we’ve completed our labor negotiations with our local IBEW and have a newly ratified agreement in effect. We worked hard to build a collaborative relationship with our labor union employees. And I’m grateful that we’ve been able to reach an agreement that allows us to continue to serve our customers and retain top talent. Finally, our customer care center was ranked as the top care center amongst our peers so far through the third quarter of this year as rated by our customers in the J.D. Power electric customer satisfaction study. And overall, our customer satisfaction is rated by customers through J.D. Power remains strong. I’m extremely proud of our employees, our progress so far and look forward to closing out the year strong.

Turning to our rate case. After 24 days of hearings, we wrapped up on October 3rd, and the parties are now in the briefing period, initial briefs are due November 6th with replied reach due November 21st. We expect the administrative law judge to issue her recommended opinion in order later this year, possibly early next year, with it being placed on an open meeting agenda shortly thereafter. We look forward to completing our rate case in a constructive manner while securing the cost recovery that’s necessary to enable continued growth of our electric grid and to support Arizona’s growing economy. As we look to wrap up 2023, our focus and priorities remain on executing our mission of providing clean, reliable and affordable service to our customers.

I want to thank you all for your time today, and I’ll turn it over to Andrew.

Andrew Cooper: Thank you, Jeff, and thanks again to everyone for joining us. Earlier today, we released our third quarter 2023 financial results. I will review those results, which were positively impacted by weather, and provide additional detail on the various drivers for the quarter. We earned $3.50 per share this quarter, an increase of $0.62 compared to the third quarter last year. As Jeff mentioned, we experienced record breaking summer heat. So weather was by far the large driver for the higher year-over-year results. In fact, the number of residential cooling degree days, which is a utilities measure of the effects of weather, increased more than 28% over the same period a year ago and were 32% higher than historical 10 year averages.

Residential coin degree days for the month of July were the highest of any year since data tracking began in 1974, and August recorded the second highest cooling degree days for the month behind only August of 2020. This resulted in a $0.38 benefit from weather versus third quarter last year, which itself was slightly warmer than normal. Favorable surcharge income through both our LFCR and the new surcharge related to the 2019 rate case appeal outcome, income tax items and other net were also positive drivers, partially offset by higher interest, higher depreciation and amortization and lower pension and OPEB nonservice credits. Our income tax benefit is largely due to the timing of certain tax items being recognized through the effective tax rate.

Q3 income taxes were also favorably impacted by the investment tax credit amortization from our Arizona Sun battery facilities and production tax credits from our Agave solar facilities. Turning to customer growth in the third quarter. It came in at 2%, which is right at the midpoint of our 1.5% to 2.5% guidance range. Arizona remains an attractive destination for population migration and for economic development. APS was honored in the September issue of Site Selection Magazine as one of the top utilities in economic development based on corporate end user project investments and affiliated job creation. Our weather normalized sales growth was flat in the third quarter compared to last year. For the quarter, residential sales were down 1.9% on lower weather normalized customer usage, but our strong C&I sales growth continued coming in at 2.2% for the quarter and is now at 2.8% through three quarters year-to-date.

Due to the weaker weather normalized residential sales, we are adjusting our sales growth guidance for the year to 1% to 3% while keeping our long term sales growth guidance at 4.5% to 6.5%. Turning to O&M. This quarter came in slightly lower than last year. However, we continue to see pressures in O&M, both from inflation as well as increases in costs incurred to serve the significant growth in our service territory. We continue to look for opportunities to reduce risk and find efficiencies that keep our costs low and maintain customer rate affordability. We raised our O&M guidance last quarter and are reaffirming it now while continuing to target O&M permit what hour declines over the long term. Interest expense remains a drag on earnings as the Federal Reserve continues to combat inflation through higher rates, and they have signaled that higher rates will likely persist.

This is expected to impact future debt financings and refinancings. With that said, I will note we only have a single fixed rate maturity of $250 million in 2024 and we will continue to closely monitor our financing needs. Recently, our Board approved a 1.7% increase in our quarterly dividend. We are proud to continue our track record of steady dividend growth and are confident in our intention to grow back into our 65% to 75% dividend payout ratio target over the long term. Turning to CapEx. We have raised our guidance for 2023 from $1.67 billion to $1.8 billion. This increase is due to distribution investments needed to serve our growing service territory and generation investments to support the reliability of our fleet. This higher CapEx level also includes increases in transmission spend as we continue to make key investments in our FERC jurisdictional high voltage system.

We now expect 2023 transmission capital within our regulated footprint at a spend level nearly 50% higher than last year. Finally, I’d like to reiterate the impact weather has had on our financial outlook for the year. Taking both the mild spring weather of the second quarter and extremely hot summer weather of the third quarter into consideration, we continue to guide to our $4.10 to $4.30 per share earnings guidance range for the year. With our rate case hearings concluded, we look forward to continuing to execute on our strategy as we await the issuance of the recommended opinion order and the final decision. This concludes our prepared remarks. I will now turn the call back over to the operator for questions.

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Q&A Session

Operator: [Operator Instructions]. Your first question is coming from Shar Pourreza from Guggenheim Partners.

Shar Pourreza: So Jeff, the TransCanyon win under the DOE program, and obviously, it’s a large line, it’s 114 miles, Utah to Nevada. Can you just talk about any timing, scale, next steps and sort of how to think about opportunities like that relative to the current CapEx guidance? And there’s obviously other needs in the region. So curious, are you seeing more announcements like this.

Jeff Guldner: I think that was one of three announcements that was made by the DOE, and there’s another one that’s in the region here that we’re not out with. But that one — this line, as you know, is a joint project that we’ve been working on for a while with Berkshire Hathaway. This DOE announcement is essentially a derisking opportunity. So it’s certainly positive for the project, but that project is still quite a ways out. It is core to our business and that it’s transmission. But given that this is at an unregulated affiliate at TransCanyon, it would be more project financed. And so it is a little different than the core transmission at the utility that we’re talking about, which is, again, where we tend to look mostly at the investment opportunities, but certainly something that we want to continue to look at. But it is a ways out.

Shar Pourreza: And then obviously, just quickly the jump in the CapEx is notable, and you raised it somewhat obviously at the tail end of the year. Could we see similar increases to ’24 and ’25 CapEx and future updates, or was this year’s increase a one-off? You’re still kind of projecting similar rate base right now in the ’25 time frame. So I guess how do we think about the cadence.

Andrew Cooper: Yes, so we did raise CapEx for the year by $130 million. And this was really looking at the needs for the year, independent of any potential rate case outcome and how generation could be addressed under a tracker. There were needs around the existing fleet, and we identified those. On the distribution side, we continue to see customer growth and frankly, some of the equipment that we need to acquire to serve that growth costing more in the current environment. I’d say the area that really — we’re not going to be able to provide an update on CapEx out past this year until after we get through the rate case. But I’d say the one trend that I think is critical to highlight, when you think about where the real transmission opportunities begin for us, it’s within our regulated footprint.

And so that additional $55 million that we’re spending on our FERC transmission assets this year, I think is reflective of a trend that we’ve seen over the last few years of continuing to lean in there. There’s a massive need in the transmission system, we have a formula rate and a competitive ROE. And so that’s an area where we’re going to expect to continue to lean in, regardless of rate case outcome and need around CapEx going forward. But the need here was discrete to identify needs in 2023, and we’ll be able to provide an update for ’24 and beyond when we come out of the rate case.

Operator: Your next question is coming from Nicholas Campanella from Barclays.

Nicholas Campanella: So I just wanted to ask on pension. Could you just give us a sense on how that’s performing versus targeted returns year-to-date? And just appreciating that recapture of pension is only partial because of the way that the test year in the rate case is structured. Should we be thinking about a continued benefit or headwind into ’24 here, anything that you could quantify would be helpful as we think the ’24?

Andrew Cooper: So I guess just from the outset, I would say that we’re really committed to a liability driven strategy and I’ve said it many times before. We’re primarily fixed income invested about 80% of our portfolio. And it’s meant to match up the asset and liabilities so that our funded status remains strong, because from an investor value proposition perspective, I think over the long term, having to mitigate through the strategy they need to go out to the market and raise external capital to fund the pension, that is what we do not want to do. And so we’re focused on funded status for that reason. Fixed income returns have continued to be challenged this year. When it comes to 2024, we’re not really in a position today to give an update because we do only revalue the assets and liabilities at the end of the year.

And so as you’ll recall from prior years, we look at actuarial gains and losses relative to the expected return at year end as they’re material, and we measure that through what is known as a corridor test, which is the most common accounting approach among utilities to addressing actuarial gains and losses. And at that point, if it’s material, we would amortize any gain or loss over the life of the plants, which is in the 10 to 12 year range. So too early to look out at 2024. You alluded to the pension expense that was crystallized at the end of ’22 based on market returns last year. And there, we have advocated through the stages of this rate case, including the hearing and we will continue to do so through to the open meeting to ensure that we get appropriate recovery there, consistent with our prior rate case, which in a split test year.

As you noted, it doesn’t necessarily get us recovery on the whole amount, but would average out to give us half of the recovery on that 22 year end impact. So we’ll continue to advocate for that and certainly be able to give you an update when we revalue everything at year end on any impacts from ’23 returns. The one thing I would remind you of is that higher interest rates, while they may impact the value of our bond portfolio have a meaningfully positive impact on service costs, which helps us from an O&M perspective. And you see that in the year-over-year O&M numbers this year. And of course, potentially lead to a higher expected return next year given where yields are. So we look at all the puts and takes around higher interest rates and discount rates at year end and can give you an update at that point.

Nicholas Campanella: And I guess just the IRP, obviously, some big opportunities here, and you’re not making any assumptions on ownership at this point. But can you just give us a flavor of is this spending that could potentially be incorporated in the next five year roll forward, or is it more further looking than that?

Andrew Cooper: What I’d say is that you’ve got our current CapEx forecast for the next three years. We’ll refresh ’24 and ’25 after the case. As the rate case is done, we have better clarity on the SRB mechanism, which we continue to advocate for in this case. The IRP is agnostic. As you said, we’ve got projects in various stages of development in our pipeline and bringing those projects forward will be dependent upon ensuring reliability and diverse group of developers, including ourselves but also whether or not there’s contemporaneous returns. Because of the lumpiness of that CapEx, we want to make sure that we’re going to lean into it that there’s an ability to recover that investment in a timely way.

Operator: Your next question is coming from Julian Dumoulin-Smith from Bank of America.

Julian Dumoulin-Smith: Actually, let me just pick up where Nick left off there on IRP here real quickly. Just obviously, the new data centers growth is pretty impressive here. I just wanted to get a sense of just how firm are some of these industrial manufacturing and data center, data points that you guys are showing here. I mean, obviously, your things are large, or subject to some movements and delays. But how firm in time line is that, are these numbers here in front of us? I’ll leave it open then to you guys.

Jeff Guldner: We’ve got pretty significant growth, obviously happening here in, I’d say, a few different sectors. One is the industrial load from TSMC and there’s some other kind of high load factor factory load that is coming up. And a lot of that is really being driven by land availability. So you look at some of the big parcels of land that can hold these facilities. And as some of these companies compete, if it’s not company A, company B is going to come in and take that land. And so some of that industrial load growth, I think, is going to continue and we continue to see pretty significant upside from the TSMCs and the supply chain that, that brings because that brings Linde and sort of gas manufacturers and other things.

Data centers, I think, are absolutely happening, they’re a little bit harder to figure out exactly where the megawatts are going. So I think that you can look in the region and say there’s a certain amount of megawatts that are here, how that gets allocated between individual customers gets challenging for some of our planning folks, but it’s more of a question of where it’s going to go and how do we build the transmission distribution system out to that, match it on the generation side. But this is an attractive market for data centers. So we see that as a pretty significant growth opportunity. Coop, you want to comment on just how it’s spoke through on the IRP?

Andrew Cooper: So year-to-date, we’re seeing our C&I sales growth in the 2.8% range year-to-date through September, which is as we’ve gone through the year, we’ve had to monitor the ramp rate and it goes back to what Jeff was saying in that when you’re thinking about these customers, you may have an anchor tenant and then they’re building out their box from there. And so watching those ramp rates and understanding them with some of these earlier customers that are coming through will help inform our long term view. But that 4.5% to 6.5% growth rate that we’re expecting through ’25 is based on the data centers we know we’re ramping up, it’s based on TSMC and its supply chain. TSMC has made recent announcements that reaffirm their 2020 commitment to being up and running. And so that’s the planning forecast that we’re working under in the near term and then the continued attractiveness of the service territory over the longer term from an IRP perspective.

Julian Dumoulin-Smith: And then I know we’ve spoken to times about earned returns here, and that’s difficult in some respects to get ahead of in the context of the case. But any further points that you would make in terms of items that would stand out in terms of puts and takes against your ability to earn your authorized levels here? I mean, obviously, we’ve sort of seen a number of points, but obviously, Nick mentioned pension a second ago. But what other points would you flag here as you think about the puts and takes and the ability to see improvement here, especially those in your control?

Andrew Cooper: We do have a historical test year and so we’re working with a number of costs that go back to the ’21, ’22 period. And so if you think about O&M, there, we need to continue to manage costs, exercise our lean muscle, because those costs do go back to a time when I think people still use the word transitory to talk about inflation. So O&M is one of those pension. We’ve done what we said we were going to do throughout the case is once we knew the numbers, we’d go back in and advocate in favor of addressing those. And then interest expense is really the third one, and that’s partially within our control and partially not. Strategically, within this case, we were okay with areas of WACC other than ROE being lower to keep the overall revenue requirement down.

So having a low interest expense and a slightly lower equity capital structure was really all in the name of ensuring that we could focus on ROE and the importance of a market competitive ROE to our ability to attract capital to the state. So on the interest expense side, we’re really doing all the things that are within our control to finance opportunistically. If you think about it, we went in earlier this year to — with the banks to expand our revolver capacity, so that we could be in the CP market more often to give us flexibility and not lock in long term rates because we have to, but be able to choose market environments that are conducive to doing it. On interest expense, I would also say that we’re — the advocacy in the rate case is important because ultimately, ensuring that our credit rating stabilizes at an appropriate level, means that on a relative basis to our peers, achieving competitive credit spreads will help to mitigate rates as well.

And there, we’ve taken whatever measures we can to clear out 2024 maturities. We actually refinance one of our pieces of 2024 maturity debt back a couple of years ago at very competitive yield. And we only have one fixed rate maturity next year that needs to be reset at current rates. So I think those are really the three areas. The key advocacy we’re doing is around ways to reduce regulatory lag coming out of this case. The SRB is certainly one mechanism we could do it. We’re leaning into our FERC return assets that have a formula rate. And after this case, we will continue to identify and push for ways to reduce regulatory lag in the state overall.

Operator: Your next question is coming from Paul Patterson from Glenrock Associates.

Paul Patterson: I wanted to go over just the sales growth and the changes we’ve seen since the beginning of the year in 2023. Could you just elaborate a little bit more like why it’s not met your expectations for 2023? And I know that you guys are reiterating the long term weather normalized sales growth. But maybe just review why you don’t think what’s happening this year is going to impact longer term?

Andrew Cooper: So if you think about the course of the year and the trajectory that our sales growth has been. We’ve known really even going back 12 to 18 months that we’ve been moving into an environment where our sales growth is going to be driven by extra high load factor, large C&I customers. And we had very robust residential growth during the years around COVID as we had the work from home trend. And what we’ve seen quarter upon quarter is that trend tends to reverse out. We still have 2% customer growth coming into the service territory but the contribution from residential sales between energy efficiency, continued rooftop solar penetration and then some of the normalization of trends around residential usage, we’ve seen a decline, that decline has caused more of a deceleration than we expected.

And that’s frankly also relative to trying to gauge and continuously forecast EV penetration, which helps to offset some of that. So from a residential perspective, it may have been more pronounced over the last few quarters. But ultimately, it’s moving from a trend perspective in the direction that we’ve anticipated. But again, this quarter, I think continue to emphasize a trend and it’s probably been a little bit more pronounced. Early in the year, we did reforecast our high load factor customers, and that was really primarily based on the delay that Taiwan Semiconductor announced in the ability to start up the facility. They’ve committed to and they’ve reiterated recently a 2025 startup, and that is the basis of the long term plan. The continued ramp of the data centers we’re seeing from one data center to another could be slower or faster than we expected.

That’s driving year-to-date, as I mentioned, 2.8% sales growth in the C&I segment. And so for the year, we’re looking at 1% to 3% overall, down from the 2% to 4% that we talked about last quarter. That is fundamentally driven by some of the deceleration on the residential side. But over the long term, much of that sales growth is driven by the large C&I segment. And we continue to see the inflows of these larger customers, both the data centers and some of the advanced manufacturing and we feel confident that it can change from quarter-to-quarter a little bit who’s ramping, who’s not. As Jeff said, from a land use perspective, there’s attractive parcels and we know who all is talking about taking them. So we feel good about it and the continued attractiveness of Arizona for those businesses coming in.

Paul Patterson: Just on the residential. You also mentioned during the prepared remarks about the virtual — the success in your virtual power — I forget the name, but the virtual power plant participation and what have you. Are you seeing — I mean do you think there might be a price elasticity issue that’s developing? I mean, is the success there in that, what do you think — is there any tie-in with that, I guess, is what I’m wondering in terms of what’s happened on the weakness in the residential area and perhaps the interest in being part of this savings program that you discussed earlier?

Jeff Guldner: Paul, the core rewards program, which is that virtual power plant program, I don’t think that’s having an effect on the residential growth. Those are really an opportunity for us to call on those customers a number of times a year. On a lot of them, you actually precool the home before you call the event and then the customer can opt out without any penalty. And so we do see a little — if you call it, multiple days in a row, there’s a little erosion that happens as you get further into the events, but I don’t think that’s having an effect on the sales.

Paul Patterson: I didn’t mean that, that program itself was the problem. What I was suggesting was that the interest in that program or the participation in that program, which seems to be pretty strong. So does that might be a signal of — they’re trying to save money, right, that’s part of the — I understood. So I was just wondering if that was — if there were somewhat related in that way, if you follow me as opposed to it being the driver of lower residential consumption. Am I making any sense?

Andrew Cooper: I think I would differentiate that program from the trend that you’re suggesting may be happening. And we’re definitely looking at usage patterns overall. If you think about the trajectory of our quarter, we had a month and half of extremely intense weather. And as we started to move into cooler weather, there was inevitably going to be customers looking at their bills, thinking about the opportunity to conserve in September. And I think as we saw the quarter go on, we saw residential usage per customer trail off. And I do think part of it reflects some bounce back effect from what was a very intense summer. So we’re understanding those patterns and customer reactions both from a bill sensitivity perspective and just overall conservation.

But I think those are probably anomalous to this particular quarter. There tends to be a psychology around when do I turn off my AC for the year. And people this year might have done it earlier, just in response to knowing that they were running it so intensely during the summer. But on the flip side, we actually saw price per megawatt hour go up for the quarter, which suggests that when we’re in that intense period of heat, customers became more insensitive to our time use rates. And so normally, when you have higher megawatt hour sales you’re seeing it at a lower price because it’s more of the off-peak hours. And so I think from month to month, you’re seeing different customer behaviors and we try to understand those as best we can. But overall, for the quarter, I think, we’re just continuing to see the same trend of residential customers slowing down, continued energy efficiency and distributed generation and this reversal out.

If you go back year-over-year, quarter-over-quarter for the last 24 months, you’ve been seeing those COVID work from home numbers continue to reverse out as people return to normal usage patterns.

Operator: Your next question is coming from Michael Lonegan from Evercore.

Michael Lonegan: So following up on an earlier question on Julian’s rate case question. Obviously, there’s some dependence on the outcome here. But coming out of it, given some delayed recovery on growing nominal O&M, higher interest expense, pension expense like you alluded to and assuming the SRB recovery mechanism is not granted, obviously, like given what happened in Tucson Electric case, you obviously may have some meaningful regulatory lag. You talked about some mitigation measures. But just wondering what your expectations are on when you may have to file your next rate case and just the frequency of that in general, especially without a recovery mechanism like SRB.

Jeff Guldner: Michael, that’s really the key issue around the SRB is that given that and frankly, given the growth that we’ve been talking about through most of this call, if there’s not a mechanism that’s in there to help us contemporary to recover that, the post test year plant that we have in process right now only gets you so far. And so the kind of the point around having an SRB is that if you don’t do that, you’re going to drive more frequent rate case filings. The specifics around that, we won’t know until we see the outcome of this rate case. So it’s too early to tiny down with kind of exactly what that timing would look like. But it completely comes back to the point that if you have an SRB mechanism in place that helps us track some of the capital and derisk some of the projects that are needed to reliably serve load then we’re able to do that without having to come back in as frequently on the rate case.

And so Tucson didn’t get it, that’s a little bit more of a unique story, I think, in the circumstances there. So we’re continuing to advocate for it in this case. There’s a lot of positive dialog towards the end of the hearing around that, but we won’t know that until we get through the rate case process.

Operator: Your next question is coming from Anthony Crowdell from Mizuho.

Anthony Crowdell: Just I guess quickly, if I could hit on like cadence of the year, very strong third quarter, type of drivers you could give us going into fourth quarter? And maybe is there an ability where you would maybe flex O&M within the year?

Andrew Cooper: So you saw for this quarter that O&M was relatively flat. And I think that, that was very specific to some offsets from employee benefit expense that you could see detailed in the 10-Q. But foundationally, we’ve seen the same trends around O&M throughout the year, which is some of the lagging impacts of inflation, particularly around areas like wages and then increased O&M needs around our generation fleet, both nuclear and non-nuclear. We saw those from early in the year as we prepared to get into the summer and then we saw those after the summer where we needed to continue to spend time around the fleet. So the O&M numbers that we gave last quarter, that $915 million to $935 million that upped O&M level we continue to remain on track to.

While we always look for opportunities to pull forward O&M from a future year, in this case, we took the anticipated weather benefit, we took the new surcharge revenue that was coming in and we look to the opportunities we have within the year to derisk our system, ensure plant reliability and address some of the wage issues that ensure we could maintain a competitive workforce. So what you’re seeing from that 15 to 35 range that’s remaining on track, the ability to derisk future years is probably a little bit more constrained given the needs of this year in particular. But certainly, as we see those opportunities, whether — even the smallest things, we’re encouraging people to look to do that work this year, if they can.

Anthony Crowdell: And just one follow-up. I believe, Jeff, you were answering — I think it was Mike but my brain is a little squishy right now from the day. Just on the SRB, talked about having conversations and the uniqueness to what happened to Tucson. But just, one is any update you can give us on maybe the conversations you’re having? And two, how do you think the SRB would — how do you tie that into with one of the commissioners opening up a docket to minimize regulatory lag? You would think that the SRB would fit there and kind of already answer the question to minimize regulatory lag, I’ll leave it open ended there.

Jeff Guldner: Anthony, it’s certainly consistent with the dock and on regulatory lag. Obviously, that hasn’t really started or is going to take a while to work through that docket. So we’re, again, making the advocacy here in the case. It came in later in the process with Tucson than it did with us. So we were able to have more conversation at the hearings on it. And so if you listen to some of the hearings, I think there was, again, more dialog about folks trying to understand what does this do. We have now the briefing process and so this is being briefed out and so you’ll be able to see it in the briefs. And then you’ve got — so you’ve got really two more steps. So the judge is going to have to take the briefs and the advocacy that she heard at the hearing and conclude what is her recommendation based on that.

And then the next opportunity is with the commission. And so the judge’s recommended opinion is a recommended opinion. And so regardless of where that comes out, you will likely see continued advocacy through the open meeting as we present these cases, because just like you said, if they are — and I think they are looking at how can I reduce regulatory lag, because it helps to reduce the number of rate cases that you have to come in with. And so as we tie those together, whether it’s in the briefing stage right now or ultimately at the open meeting, those are exactly the arguments that we’re trying to make. And again, the importance to us is that in PPA — if you PPA, all the projects we need for reliability, you have less control from a project execution standpoint, and so a little bit more risk in getting those projects in.

And so you want to make sure that there’s that appropriate balance of self build versus PPAs. And it’s really hard to self build this stuff if you’re then picking up regulatory lag and it will drive quicker rate case filings. And so I think all those items are going to come out in the continued conversation, but we’re still a ways from getting that through but it’s probably early next year or later this year before we’ll see that.

Anthony Crowdell: And just lastly, what is the cost to mitigate a rate case. Have you guys put an estimate or a range around mitigating a rate case?

Jeff Guldner: I wouldn’t say — we don’t do like rate case expense. Some utilities file like rate case expense and put it in there. This is all embedded within the existing team, so the costs are essentially already embedded in the teams that we have. And when we come out of a rate case that just moves into other regulatory matters. So it’s not something that we’ve ever really focused on. Certainly, there’s paper and other things involved, but it’s not material.

Operator: Your next question is coming from Travis Miller from Morningstar.

Travis Miller: Trying to unpack this weather and then also related to earlier questions on O&M. I’m guessing and correct me if I’m wrong, that you’ve incurred some extra O&M just for the fact that you’ve had to operate the system at a higher level given the weather. What’s the resulting potential benefit in, say, 2024 or 2025, if you get back to normal weather, you move the earnings on the top line? But are there other impacts that would be a benefit from not having hot weather?

Andrew Cooper: No, it’s a good question, Travis. And certainly, there were some reliability related needs. A lot of them anticipated even before the summer where we were spending money to continue to ensure our fleet. We do all of our summer preparedness the same way every year. We project for the summer forecast. In fact, the peak load we reached was consistent with the types of forecast that we set in advance and we plan our own resources and the PPA and market based resources accordingly. So we’re spending money on O&M on the fleet even before the summer. And certainly coming out of the summer, the wear and tear, both the CapEx that I mentioned that we’ve increased this year as well as the O&M are related to that. You do see we released this quarter the outage schedule for next year.

So you do see across our gas fleet and hopefully as well as the normal Palo Verde refueling outage pretty robust outage schedule next year, including what will be the beginning of the last major outage at Four Corners during the asset’s life. So there is some [Indiscernible] related work to get us through the remainder of the decade next year. One of the things that we didn’t have this year, but we planned for is we didn’t have a very strong monsoon rain and wind season this year. So there’s some — a little bit of a mitigant there, we plan for that every year and didn’t have intense storms. But we did have very intense storms in the winter at the beginning of this year. So there’s puts and takes every year on how we plan and then how we deploy those O&M resources.

But foundationally, given the outages we have next year and the overall plan, I think if we had a normal weather year next year, it wouldn’t have a material impact on the overall O&M picture.

Travis Miller: And then just real quick on the 5% to 7%. I think you’ve said base year was normalized 2022. If you — and correct me if that’s wrong. But if you get through when you get through this rate case, do you foresee then adjusting that 5% to 7% to think about post rate case earnings number as the jump-off point?

Andrew Cooper: That’s something that will come out with after the rate case. I’ve mentioned it in this forum before that we said that 5% to 7% on a year that had been a financial reset. So our earnings were in decline in the year we said. So it certainly would be something that we’ll look at. Because ultimately, what we want that 5% to 7% to represent is an evergreen long term growth rate. And so being able to achieve that over the long term regardless of base here is the ultimate aspiration. So it will be something that we’ll look at after the case when we refresh the guidance.

Operator: Your next question is coming from Sophie Karp from KeyBanc.

Sophie Karp: I just — most of my questions have been answered, but I was curious if I could maybe get you to comment a little bit on the impact that the growth in data centers and other similar industrial users is going to have on the margins if that continues. So can you help us understand, I guess, if the impact of adding 1 gigawatt of load of data centers is equivalent to how many residential customers? And over time, how do you think that the rates of different customer classes are paying are going to evolve in areas or not?

Andrew Cooper: And so one of the things we’ve talked a lot about is that with our extra high load factor customers, given the hours that they’re running and you’re going to see a lower overall margin. We tend to give it in a percentage growth rule of thumb that if you have 1% of residential growth, it’s equivalent to $20 million to $25 million of margin. If you have 1% of high load factor growth, it’s more of the equivalent to $5 million to $10 million of margin. And so you do see a lower margin contribution, but an awful lot more megawatt hours. And so from that perspective, that’s why we’re so focused on our O&M continuing to be disciplined from a volumetric basis. We’re going to have higher O&M as we serve more customers.

But given these high load factor customers allow us to spread that O&M and frankly, they’re a single site versus residentially going out to more and more subdivisions that that growth becomes efficient growth for us despite the margin being lower overall. From a customer cost of service perspective, we ensure that customers and our rate design is meant to ensure a fair distribution of costs across our various customer classes, and that’s something that we look at each time we go in for a rate case and in short. But fundamentally, just from an overall perspective, blunting O&M with lots of megawatt hours in a single site is positive despite the lower margin.

Operator: Thank you. That completes our Q&A session. Ladies and gentlemen, this concludes today’s event. You may disconnect at this time, and have a wonderful day. Thank you for your participation.