Pinnacle West Capital Corporation (PNW) Q3 2026 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Pinnacle West Capital Corporation 2026 Third Quarter Earnings Conference Call. [Operator Instructions] It is now my pleasure to hand the floor over to your host, Amanda Ho. Ma'am, the floor is yours.

Thank you, Matthew. I would like to thank everyone for participating in this conference call and webcast to review our third quarter earnings, recent developments and operating performance. Our speakers today will be our Chairman, President and CEO, Ted Geisler; and our CFO, Andrew Cooper. Jacob Tetlow, COO; and Jose Esparza, SVP 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 website, 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 materially from expectations. Our third quarter 2026 Form 10-Q was filed this morning. Please refer to that document for forward-looking statements, cautionary language as well as the 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 website for the next 30 days. It will also be available by telephone through November 10, 2026. I will now turn the call over to Ted.

Thank you, Amanda, and thank you all for joining us today. We delivered strong third quarter financial results and reliably served customers through another challenging Arizona summer. Today, I'll discuss that performance, how we're serving growth while protecting customers, our resource plans and regulatory outlook. Andrew will then review our financial results and updated 2026 outlook. Before turning to our performance, our hearts are with the families and communities across Arizona facing recovery from this past week's floods. APS is contributing $250,000 to Navajo Nation and the Hopi Tribe for emergency assistance in the Four Corners area and assessing additional needs in Northern Arizona following this weekend's flash floods. We're also making $5 million in company-funded assistance available to customers facing financial hardship, whatever the cause. We're here to help our customers and communities through these difficult times. As I mentioned at the outset, our long-term planning and preparation was tested this summer, and it made a difference. We served customers through 12 record-setting peak demand days even as extreme heat and storms challenged our system. That performance reflects the work our employees do long before the hottest days arrive as well as their response when conditions are toughest. I'm incredibly proud of the way our team delivered strong operational excellence for customers through another record-breaking summer season. Palo Verde was a critical part of that performance. The plant achieved 100% capacity factor over the summer, delivering reliable carbon-free electricity for our customers and supporting the broader Desert Southwest grid. Turning to growth. Third quarter weather-normalized sales increased 9.5%, with commercial and industrial sales up 14.5% and residential sales up 4.5%. Arizona's economic strength and our service territory's appeal continue to attract investment. Amkor Technology is one example. In September, it announced the second phase of its advanced packaging and test campus in Peoria, increasing its planned investment from $7 billion to approximately $12 billion and supporting more than 3,500 Arizona jobs. Our recent TSMC agreement shows how we're serving this growth while protecting customers. Executed in October, our first direct pricing contract is a 25-year agreement that, subject to regulatory approval, will serve approximately 1.88 gigawatts of demand at full build-out across TSMC's chip manufacturing campus. Upfront capital contributions and credit support mechanisms align infrastructure and resource investments with TSMC's demand. Simply put, TSMC pays its own way. Residential customers will not subsidize this growth. The agreement provides a repeatable framework for other large customers, and we expect to file it with the commission for approval in the coming days. Our recently filed Integrated Resource Plan puts the scale of this growth into perspective. By 2041, we project our customers' annual energy requirements will more than double to approximately 80,600 gigawatt hours, with peak demand reaching 14.5 gigawatts, more than 5 gigawatts above today's level. Our preferred plan in the IRP identifies nearly 15 gigawatts of new resources and approximately 2.6 gigawatts of additional transmission capacity over the 15-year planning horizon. The IRP is a planning road map, not a decision about who will own each resource. We remain committed to our competitive all-source procurement process, and we will compete by leveraging our proven track record of delivering reliable generation projects on time and on budget. Our objective is a balanced mix of dependable generation and new transmission built to serve growth reliably and affordably. On the regulatory front, parties in our pending rate case have submitted closing briefs, and we await the Administrative Law Judge's recommended opinion and order. Based on the current schedule, we expect a final Commission decision before year-end. We seek an outcome that supports reliability investments, keeps affordability at the center and provides a timely, durable framework for future cost recovery. As we approach year-end, our priorities remain clear: deliver reliable, affordable service today, advance the dependable generation and transmission that Arizona will need tomorrow and achieve a constructive regulatory outcome that protects customer affordability while reducing regulatory lag. With the rate case decision and the TSMC agreement in hand, we look forward to updating our long-term financial outlook on our next earnings call. We see significant opportunity ahead, and we're determined to meet it with discipline and the long-term perspective for customers and shareholders alike. Thank you for your time today, and I'll now turn the call over to Andrew.

Thank you, Ted, and thanks again to everyone for joining us today. This morning, we reported strong third quarter 2026 results, reflecting continued momentum across our business. I'll highlight the key drivers of our performance and discuss our updated outlook for the year. We delivered earnings of $3.49 per share in Q3, an increase of $0.10 year-over-year, driven by exceptional sales growth across all customer segments, continued customer expansion and favorable weather. These factors more than offset the impacts of ongoing investments in our system, including higher depreciation and amortization and both debt and equity financing costs associated with supporting long-term growth. Given our strong year-to-date performance, robust sales trends across our retail customer base and continued economic momentum in our service territory, we are raising our 2026 earnings guidance to $5.05 to $5.25 per share, up from our prior range of $4.55 to $4.75 per share. Sales and customer growth contributed approximately $0.35 per share of earnings growth during the quarter. Customer growth remained healthy at 1.8%, while demand trends continued to exceed expectations across all customer classes. Weather-normalized retail sales increased 9.5%, including 14.5% growth in commercial and industrial sales and 4.5% growth in residential sales. Importantly, this marks our second consecutive quarter of more than 9% weather-normalized retail sales growth, demonstrating the strength and sustainability of demand across our service territory. As a result, we are increasing our full year 2026 retail sales growth outlook to 8% to 10%, with 5% to 7% growth expected from large commercial and industrial customers. Weather also provided an additional benefit during the quarter, with each month experiencing more cooling degree days than the comparable period a year ago. As expected, depreciation and amortization expense increased as we continue placing significant capital investments into service. These investments are expanding system capacity, enhancing reliability and positioning us to meet growing customer demand. Interest expense also increased, reflecting financing activities that support our long-term infrastructure program. We continue to execute a disciplined financing strategy that balances capital investment needs, balance sheet strength and financial flexibility. In a significantly rising rate environment, we executed our financing plan efficiently in the third quarter. We raised $700 million of senior unsecured notes, including a $100 million reopening of our 2035 notes, which allowed us to maximize the execution of the financing transaction. We also priced approximately $235 million during the quarter under our ATM program, bringing year-to-date to nearly $920 million. We have priced the majority of our expected 2026 and 2027 equity need while maintaining a balanced, constructive capital structure. We will continue to look for opportunities to utilize the ATM program to stay proactive about our future needs. Looking ahead, the demand outlook for our business continues to grow. Based on the increased load forecast included in our recently filed integrated resource plan, we are raising our long-term sales growth outlook through 2030 from 5% to 7% to 8% to 10%, with large C&I customers contributing 7% to 9%. This reflects the substantial economic development occurring across our service territory. In addition, we continue to expect steady population growth during the same period, supporting annual customer growth of 1.5% to 2.5%. We are reaffirming all other aspects of our guidance and look forward to completing our pending rate case by year-end. With strong customer growth, increasing demand and significant investment opportunities ahead, we remain well positioned to deliver safe, reliable service while creating long-term value for our customers and shareholders. This concludes our prepared remarks. I will now turn the call back over to the operator for questions.

[Operator Instructions] Our first question is coming from Julien Dumoulin-Smith from Jefferies.

Excellent. Nicely done, especially on that sales outlook. Never a second guess you guys. With that said, though, I mean, as you think about all these customer-backed projects coming into the plan, I wanted to get ahead a little bit on the cash flow metrics here and think about a little bit what is the defining or limiting factor here? Is it FFO to debt? Or is it the equity capital structure at the utility itself that will be the driving factor for incremental new equity issuance? Just -- we've clearly seen this as a trend, and you all clearly seem to be articulating more on this front. But just as we get ready for some of these projects to be coming into the plan, I know none of it is necessarily awarded here, but how would you think about this?

Julien, thanks for the question. Yes. Certainly, the most important thing is that we'll be able to provide updates on financing after we complete the rate case along with the update to our capital plan. So that will all kind of happen in sync. I think we do look at both metrics. Both are important and both kind of move in unison. And if you think about what are going to be the drivers of our external financing needs, there are 2 key ones that will change between kind of our regular way and going forward. One is that with the formula rate, we're going to have improved cash flow, improved FFO, which helps with our credit metrics. It helps push down our dividend payout ratio. It really puts us in a better position, both through the catch-up of the under-earning and then the ongoing improved cash recovery. So that's going to be an important part of supporting both the equity cap structure of the utilities, supporting our credit metrics. And then certainly, as Ted talked about, the direct pricing contract model is going to be providing upfront cash, which will help to defray those external financing needs. Both metrics are important. We tend to want to keep our equity cap structure above 50%. We like the 52%-plus range that we're in, in this rate case. We don't want to fall too far behind that. Ultimately, the way we've designed things like our DPC structure and the way we think about the formula rate, both also do support our credit metrics as well.

And then if I can ask maybe the follow-up related question. As you think about transposing rate base, given the comments you just made about equity into earnings growth, how do you think about dilution, right? Obviously, there could be some holdco dynamics here, but how do you think about the translation factor? Because clearly, especially given -- and in light of the elevated sales growth and the subscription programs here, it seems like it's a double-digit rate base growth program potentially.

Yes. So certainly, over time and through those mechanisms I talked about, there should be a better convergence between rate base growth and earnings growth, certainly as we look to earn closer to our authorized return. And we're engaging in accretive projects. We're doing things that, especially with the FRAM, will put us in a position to have more contemporary return and close that gap. And then the direct pricing contract structure also improves the ratemaking at the same time. So all of it kind of drives in the direction of better convergence between rate base growth and earnings growth.

Right. Absolutely. And certainly, it seems like your outlook is going to be based off of '27, which is inclusive of some of the step-up in FRAM to begin with, if I recall right.

You are correct. [indiscernible] Yes.

Your next question is coming from Shar Pourreza from Wells Fargo.

Just let me -- just a quick follow-up and maybe I can fine-tune Julien's question in a second. So just historically, there's been around 200 basis points of lag. So if you look at the 5% to 7% EPS, 7% to 9% rate base, there's a couple of hundred basis points there. Just given the 8% to 10% sales growth, do you envision that would narrow? And what would be sort of the structural lag we should be thinking about as you're thinking about the 200 basis points?

Yes. Sure, it's Andrew. Yes. No. So for sure, I mean, the management goal continues to be to earn within 50 basis points of our authorized return by the time we've kind of caught up on lag, and that remains the goal. That will happen through the mechanism of the formula rate, and that will be something that happens over time. Direct pricing contracts will also contribute to the narrowing of that gap. Sales growth is the exact type of trend that we've talked about in the past that creates tailwinds there to get us closer to the 50 basis points, gets us within the 50 basis points and ultimately potentially creates the opportunity over time to return funds to customers once you figure in nuclear production tax credits and things like that. So it's definitely one of the drivers. A big part of that mix over the long term is the large C&I customers. There's certainly a smaller ultimate impact for every percentage of growth there. But it's definitely a contributor and a tailwind to be able to achieve our management goal.

Got it. And then just lastly, I mean, obviously, you guys highlighted you'll get the GRC order by year-end. I just want to confirm this, I think I know the answer anyway. But just depending on when the GRC order comes and let's say, it's earlier part of December, is a special call kind of out of the question right now? Because obviously, post the GRC, this will be a massive update. So is there an opportunity to do a special call and update the plan in December? Or is it still the focus is a February update when you report year-end?

Yes, Shar, at this time, our focus is to utilize the Q4 call in February. We'll evaluate that based on timing of the final rate case decision. But at this point, I think it's safe to count on that Q4 call and anticipate a decision at some point mid-December for the rate case.

Your next question is coming from Richard Sunderland from Truist Securities.

I wanted to start with this IRP update. Can you speak a little bit more to the high-level plans for the in-service dates on that 15 gigs of generation and 2.6 gigs of transmission you spoke to in the script?

Yes, happy to, Richard. I appreciate the question. As you said, the plan outlines 15 gigawatts of resources needed. Importantly, that 15 gigawatts is measured on what is going to be necessary to serve purely what demand has been committed to. And so we did increase that committed demand from prior values. It's now 5.8 gigawatts, which is 1.3 gigawatts higher than before. But that does not include any prospective view on incremental or new data centers or incremental and new extra-large manufacturing beyond what we've already committed. So keep that in mind, the 15 gigawatts is purely for whatever has been committed or contracted that equals that now 5.8 gigawatt committed bucket. Out of that, about half is in development. We've got about 4.5 gigawatts of resources to be in service by 2028 and about 2.8 gigawatts additional of thermal generation, all of those projects we've spoken about before, the Redhawk expansion, Cholla conversion, Saguaro and Desert Sun, each, respectively, having their first phases in development. And of those values, about 40% is APS-owned. Keep in mind then that the other half remains to be procured. Saguaro and Desert Sun each have expansion capabilities. We're also procuring turbine reservations now for future projects as well as identifying future development sites. And then we'll continue to run our RFP process to look for incremental opportunities beyond that. That's all on the generation side. On the transmission side, we outlined that the IRP alone is driving 2.6 gigawatts of new incremental transmission above and beyond what's in the 10-year plan. This transmission is needed just to be able to support the connection of new generation resources. That, coupled with what's in the 10-year plan goes through 2035. It's a pretty meaningful amount of transmission just to be able to keep up with reliability, resiliency and connect the new generation resources, and we'll continue to evaluate those needs as we finalize transmission studies. And then lastly, just to reiterate, as we evaluate additional large manufacturing or data center customers that we may contract with in the future, we would then add those on top of this resource plan, both the demand as well as the resources commensurate to serve that demand in incremental form. But we're taking a conservative view and only adding those once they're contracted.

Got it. Understood. That was very comprehensive. And maybe to follow up a little bit more on the thermal side. It sounds like efforts underway on additional turbines. Could you pair that with kind of your anchor shipper status on the new gas pipeline? Basically, what's committed now on your end on that pipe in terms of these laid out resources? Is that all tied to committed customers as well? And how does the sort of gas supply side square with all these puts and takes today?

Yes, sure. The Desert Southwest pipeline is certainly a critical infrastructure project to be able to fuel some of the incremental thermal generation that will be in service in the 2030s. The generation that we've already announced will take service from that pipe. But there's certainly additional capacity that we've contracted from the pipe to be able to support generation beyond the projects that we've announced. So we'll continue to work with the developer on ensuring that pipeline maintains course, and we'll continue to look at the best fit projects to be able to develop to serve our customers beyond those that we've already announced to take advantage of that pipe. Given the solar irradiance we have in Arizona, we still believe that a balanced portfolio is the right mix for our customers. That blend of incremental natural gas, utility-scale solar, coupled with battery storage, that's what we continue to find in our model as being the best reliability solution at the lowest cost. And so it really will continue to be an all-of-the-above approach. But because we've had so much utility-scale solar and battery storage developed in recent years, we now are balancing that out with incremental gas. And then as we look to the future, it will likely be a blend of both.

Our next question is coming from David Arcaro from Morgan Stanley.

I was wondering just on the topic of the IRP, could you maybe lay out kind of how you would stage the RFPs as you go about just continuing along the process to nail down the megawatts and projects and the split of utility-owned versus non?

Yes. We're generally in annual RFP mode. It doesn't perfectly follow a calendar year. But right now, we're continuing to evaluate project proposals for the 2030, 2031 time period. We went out for solicitation of projects that would supply greater than a gigawatt of supply. We'll evaluate those results. And as soon as that result analysis concludes, then we'll reissue a new RFP. So it will generally be an RFP about every year going forward just to continue to test the market, identify resource opportunities. And then any development projects that we identify through our own pipeline, we'll compete in that process to ensure its competitiveness as we go forward and commit to those projects in order to be able to serve growth. So that's generally how we see it playing out.

Okay. Got it. And would you not include the projects in your CapEx plan until you were to potentially win them through those RFP conclusions?

Well, the way we think about it is when we are confident that those projects are competitive, whether it be because we've had enough visibility into the market prices or because the RFP is concluded, at that point, then we'll embed it in the capital forecast. And so for example, we've said that Cholla conversion, Desert Sun and Saguaro, we have confidence in their competitiveness. And so any of the capital associated with those projects that happens to fall within the current guidance window would be included. If we think that there's any question in the project's competitiveness, we would not include it in the capital forecast until we're confident in its ability to compete and be developed. Of course, any resources associated with a DPC contract are being contracted with that customer. And once that commitment is made, then they would be included in the capital forecast as well.

Okay. Got it. Yes, that makes sense. And I guess curious on the transmission side of things as well. Are there milestones that would be needed from your end to ensure that they're needed and kind of approved from the regulatory side before considering the transmission CapEx additions in your own forecast?

Well, we do file a 10-year transmission plan with the Corporation Commission for visibility and awareness, and there's transmission workshops to walk through each of those projects. But those projects are FERC regulated, clearly demonstrate significant reliability and resiliency need in order to maintain resource adequacy within our service territory. And then because there is no excess available capacity on the transmission system in our service territory today, any new generation that we connect requires incremental transmission to be able to incorporate that new capacity into the grid in a reliable manner. So we're very confident that any project we identify has already been through the study process to demonstrate its prudency and need and therefore, comfortable that when we put it in our plan, it's necessary from a reliability standpoint. And therefore, we're counting on its need and ability to be developed.

Our next question is coming from Nicholas Campanella from Barclays.

Congrats on the DPC framework, definitely a milestone. Obviously, this seems to be for the manufacturing customer base with TSMC. Can you talk about it just being more replicated for data centers or other manufacturing customers? And then just like what is your line of sight to convert more of this 20 gigawatts of uncommitted into the committed bucket now that you have this DPC out there, can you kind of start replicating this? Is this something that is more of like a long term or something we could see in the context of what's coming in the fourth quarter?

Yes. Thanks, Nick. The DPC was designed to be replicated. It's a standard agreement that we believe balances the right approach of protecting our existing customers from any cost shifts or reliability impacts while also securing the agreement necessary to ensure that we can build out the necessary infrastructure to reliably serve these extra-large customers. So we do believe it's the right approach, and we do believe that it can be replicated. As a reminder, the DPCs generally include credit support, both cash CWIP and deferred revenue prepayments, collateral provisions, both liquid and nonliquid termination provisions, direct assignment cost provisions to protect existing customers from cost shifts as well as, of course, minimum energy and demand thresholds. All of that, we believe, is necessary to ensure that we are responsibly serving this new growth, and we believe that it can be replicated. With respect to being able to serve more from the 20-gigawatt queue, we do have other negotiations ongoing with customers that are in the queue. It's way too early to tell whether those will transpire into a DPC or not, but we are having those discussions. But importantly, outside of the extra-large customers in the queue, we continue to see incredibly robust, what I call organic non-data center growth in the service territory. And a meaningful part of that increase of our committed queue that now increased to the 5.8 gigawatts is from non-data center customers that are just driving and fueling the economy here in Arizona. So we're trying to take great care in ensuring that we continue to build out the grid and preserve capacity necessary to serve that amount of growth. The residential growth, the small- to medium-sized business growth, the continued manufacturing growth within the service territory. We've made a commitment to Arizona that we will support in a timely manner, building out the grid to serve that sort of business-as-usual societal needs from the non-data center customers, and we want to make sure that we preserve capacity to do that. As we continue to get greater visibility into the incremental generation and transmission projects that we can build, then we will evaluate what the ongoing non-data center demand is, what the capacity timing is of those new incremental projects and have dialogue with the queue customers to identify best fit projects for that new capacity.

And then I was just curious on the long-term sales forecast increase to 8% to 10%. Obviously, that lines up with the resources that you've announced you're building to today, 7% to 9% large C&I. Could you talk to the composition of that? And I know for TSMC specifically, does this include kind of their total expansion? Could there be more beyond that just based on what's been announced? Is there any way to understand that?

Yes, Nick, one of the aspects of our load growth that we're so excited about is the diversity. In fact, if you look at the division of that load growth, it's actually more manufacturing than it is data centers and a wide variety of manufacturing, certainly advanced manufacturing such as chip manufacturing, but others as well. For example, we recently had Kimberly-Clark announce a large manufacturing center down in Yuma, Arizona, and we've got others throughout the service territory. We also have incredibly robust growth still coming from residential, which is our largest category of growth. And then, of course, you've got data centers and the advanced manufacturing, including TSMC. The 1.88 gigawatts of committed service represented in our DPC contract with TSMC is included in the IRP and is reflected in the 5.8 gigawatts of committed demand. So that is in there. We'll continue to work with TSMC on any future plans they have and any service they may need beyond that.

Our next question is coming from Paul Patterson from Glenrock Associates.

A lot of my questions have been answered. I just wanted to sort of on the long-term sales growth, which is a significant increase. It sounds like that's a little bit of a tailwind on rate lag. But I'm wondering, does -- do you see it having any significant impact on affordability in terms of the rate impact having that much more volume? Or will that be offset by something?

Yes, Paul, we certainly believe that these new extra-large customers that are contributing to a meaningful part of that new load growth will have an affordability benefit to existing customers. When I think about the cost drivers of continuing to deliver reliable service to our customers, there continues to be an increase in fixed cost to be able to provide that service. You think about just the incremental increases in cybersecurity investments, wildfire protection investments, IT systems. These are all necessary investments just to reliably serve our customers regardless of volume. And so when we add these extra-large customers, they're helping reduce what otherwise would have been higher costs that would be borne by residential customers, and they're benefiting those customers. Now it's difficult to quantify because you'd have to take a more detailed perspective view on the usage and volume of each, but we know that a significant amount of that 5.8 gigawatts of committed demand is from these extra-large customers and their volume will provide an affordability benefit. On top of that, though, I just want to demonstrate that we're not counting on that to help ensure we protect affordability for customers. We're taking our own action as well. We're going on about 3 years of relatively flat O&M during an inflationary environment. The commission recently passed on a 1% decrease due to their rightsizing of the DSM plan. And they also passed on about a $14-a-month decrease in November due to passing on savings from our Green Power Partners program back to customers. And then if you think about our rate CAGR just simply over the last 7 years, it's been well below inflation while we've been serving record growth. So I think our customers will see affordability benefit from the higher volume, but we also are doing everything we can to take management action to protect affordability as well.

Our next question is coming from Travis Miller from Morningstar.

I appreciate all the details to answer most of my questions, but a couple of quick follow-ups here. On the transmission side, how do you anticipate the costs allocated between the large load customers of that subscription program and then traditional retail FERC rates?

Yes, Travis. So first of all, all of it is rate based within the FERC rate base, but the cost allocation will depend on the driver. It's difficult to detail out because it just simply depends on what the need of that incremental transmission is. Some of this is simply needed to be able to replace aging infrastructure and improve resiliency. Some of it is to increase capacity on the transmission system just given the broader service territory growth. And then some of it is due to adding new generation. The transmission that is specific to a customer premise, that's governed by the tariff rate formula and will require customer payments and contribution as well as, of course, any benefit from that transmission to the broader system ends up contributing to the broader rate base. So it really is a mix of all of those drivers. But bottom line is similar to assigning generation investments to the growth driving it. We're ensuring that these large customers pay their appropriate share of the transmission costs that they're causing as well.

Okay. Got it. Another one, the 50 basis points, the pathway to that 50 basis points, what are you thinking in terms of timing? Or what's your goal in terms of timing on that lag?

Sure, Travis, it's Andrew. We know that it's going to take some time to catch up effectively from lag, just given we're still working under a historical test year that goes back to the middle of 2021. We expect rates to be in effect from the rate case through '27. Based on the time line that we've proposed for the formula, we would make our first formula filing in May of 2027 with those rates going into effect towards the end of 2027. That is effectively the first opportunity for us to begin to meaningfully catch up at that point. We're bringing it forward from a '24 test year to a '26 test year. And then by that second formula filing in May of 2028, that will be the first opportunity to be in a full cadence of formula rate filings on an annual basis. So we would expect that once that '28 filing is processed, that you'd now be in a position to earn significantly closer to your authorized return. And that -- those rates would go into effect at the end of '28. You're not going to get a lot of impact of them in '28, given December is when we contemplate rates going into effect under the formula rate. So really 2029 becomes the run rate as we move forward and have the ongoing benefit from the formula rate we expect coming out of this rate case.

Okay. Perfect. Got it. And then one other real quick one. Election results, any chance that, that would delay the GRC decision timing? Or has it in the past?

Yes. No, we don't anticipate any connection there. At this point for the rate case, we're first waiting on the Administrative Law Judge to complete his recommended opinion and order, which we expect here in the coming weeks. And then the Commission has been pretty focused on wanting to ensure that this case wraps up this year. So we'd expect that to still occur in December regardless of election timing of results.

Your next question is coming from Sophie Karp from KeyBanc.

I heard you talk about this aspect of DPC that is prepaid revenue in a way. Could you talk a little bit more about that? And maybe is it possible to begin to quantify how much of the capital need can be covered by that feature?

Yes. Sophie, we can speak generally to it. It's all part of the broader credit support that we seek to ensure that these new large projects and the infrastructure associated with it can be supported by incremental credit support in order to preserve the company's financial health as we serve these large infrastructure investments. And so that credit support is a blend of cash CWIP as well as deferred revenue prepayments. We work that out with each counterparty depending on the profile of the investment spend, the timing of that and the magnitude. So it's a general framework, but it's going to be unique in terms of the sort of timing and cadence of that cash based on the infrastructure requirements, the volume of that infrastructure and what's needed to ensure that the credit profile of the company remains whole during that infrastructure build.

Got it. Got it. And then on the IRP, I guess, have you guys given any thought to nuclear upgrades? Some of your peers out east nonregulated are doing quite a bit of those. Is that an option for you?

Yes. Sophie, we've looked at any opportunities at Palo Verde, but all of the meaningful upgrades have already been done at Palo Verde. We've already replaced all the steam turbine generators, for example. So I think really any opportunity remaining would not be very measurable. Instead, we're really more focused on investing in the plant for the long term, ensuring that we can reliably support its subsequent license renewal and then also investing in digital modifications. But incremental upgrade opportunities, we don't believe exist in any meaningful form at this point.

Our next question is coming from Anthony Crowdell from Mizuho.

Nicely done. Just -- I had just one question. Just quickly on -- I think you raised your '26 guidance midpoint by $0.50. The Q3 year-over-year was just up about $0.10. I mean, how much of the raise was like weather-driven versus sales growth? And how much of that carries into '27?

Anthony, the increase in our guidance was fundamentally driven by the higher-than-forecasted sales growth across customer classes. I mean, it's just been substantial, seeing residential sales growth, including new customers coming to the service territory plus increased usage and then the faster-than-forecasted ramp of some of our large C&I, that's been the primary driver. There's some modest weather benefit in there as well, and that has been pretty consistent throughout the year. It hasn't been like one big peaky weather event. We've had Q1, Q2, Q3, we've had weather uplift. Now the guidance update does take into effect what we know for October, which was more mild. But this has been fundamentally a story of sales growth, and we've used some of that to offset some O&M risk out in the future. When you talk about the sustainability of it, I think you see that we've continued that 8% to 10% sales growth out past 2026 as well. And there, there's a slight change in mix. You noticed that for '26, large C&I is driving a significant percentage of it. I mean, we've got double-digit teens large C&I growth, but residential growth was above average this year. And we think part of that was customer behavior-driven. We had a March in Phoenix where we had 9 days above 100 degrees, and that drove earlier than typical cooling by our customers, and it would appear that they just never shut it off. And so assuming that we revert to more normal residential usage trends next year, when we pair that with the ramp that we see for both our manufacturing and large C&I customers, it's that sustained continuous 8% to 10%, but just a slightly different mix than we see this year.

Our next question is coming from Steve D'Ambrisi from RBC Capital Markets.

Steve, are you there? If you are, we can't hear you. Stephen D’Ambrisi: Can you hear me? Sorry about that.

Yes. Stephen D’Ambrisi: Not sure what happened. I think my headset cut out. Apparently, it's my first conference call. Just 2 quick ones. Wondering how we can think about scaling this IRP opportunity beyond the existing plan and then just any incremental committed load coming into a future IRP? Just for the first part, does the 2 to 3:1 kind of multiplier that you're seeing of new resources to committed load, does that hold as you continue to add new committed load? And then I think you had mentioned 40% of projects within the window are APS-owned. Does that mix shift over time as you have an increased penetration of DPC agreements? Or is it more stable?

Yes. I appreciate the question, Steve. I sort of think about the incremental opportunities in 2 buckets. One is we continue to just see robust non-data center growth within the service territory. That's part of what led to the increase in guidance. Of course, it's at a pretty high level of sales growth that we updated, yet that's sustained and defended by all the new projects and growth we see coming in. So certainly, there always is upside potential there from the current level, but it really is quite elevated, and we think it's durable for the medium to long term. But the more obvious opportunity is that we have not included any prospective view on any incremental data centers or new large manufacturers that may be contracted in the future. We would not include those in that load growth forecast until we have certainty that we are committed to serve them, and we have a contract. And so when you think about the 20-plus gigawatt queue, anything coming from that queue over the 15-year horizon that the IRP covers would be above and beyond the current IRP and you would need incremental generation and transmission to serve each one of those projects. Getting to your next question regarding the ownership, we've always said that we think moving from our historical 10% to 15% incremental generation ownership to something closer to 50-50 was a more balanced approach, and we believe in our ability to easily compete at that ownership level. So the 40% is getting closer, but we still see there being upside potential for ownership, given our track record of being able to develop these projects on time, on budget and ensuring that they've got the reliability characteristics to meet that load. The last piece, Steve, I'll say is that there is no excess generation in our service territory. Any new meaningful customer growth that we take on requires new generation to be procured. It just has to be. And in addition to that, you're going to have to expand the transmission system to connect that new generation to our current network. So any new customer commitment we have or any organic sales growth above and beyond our current guidance level is going to require new generation and transmission to be able to serve it. That's part of why we're already working on development plans beyond the phases of Desert Sun and Saguaro that we've announced because we know we're going to need that capacity, not just to be able to serve the out-years in the IRP, but also to have a chance at serving incremental growth beyond what we've already committed.

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