Pinnacle West Capital Corporation (NYSE:PNW) Q2 2025 Earnings Call Transcript

Pinnacle West Capital Corporation (NYSE:PNW) Q2 2025 Earnings Call Transcript August 6, 2025

Pinnacle West Capital Corporation reports earnings inline with expectations. Reported EPS is $1.58 EPS, expectations were $1.58.

Operator: Good day, everyone, and welcome to the Pinnacle West Capital Corporation 2025 Second 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 second 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, is 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 second quarter 2025 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 website for the next 30 days. It will also be available by telephone through August 13, 2025. I will now turn the call over to Ted.

Theodore N. Geisler: Thank you, Amanda, and thank you all for joining us today. Our second quarter financial results are in line with our annual guidance. Before Andrew discusses the details of these results, I’ll provide a few updates on recent operational and regulatory developments. As we progress through the summer season, I’m very proud to share our team continues to excel in delivering reliable service to our customers. For the third consecutive year, we set a new peak energy demand record. Our customers reached a new peak on July 9 at more than 8,500 megawatts when Phoenix reached 118 degrees, more than a 300-megawatt increase from last year’s peak. And we may surpass this again tomorrow as temperatures are expected to reach at least 118 again.

We take our responsibility to reliably and affordably serve our customers seriously through robust planning, resource procurement efforts and a dedicated team. I want to recognize our planners, engineers, operators, field teams, everyone that makes up the APS workforce for doing an exceptional job making sure our customers continue to experience reliable service through our summer season. Setting a new peak does not come as a surprise since our state continues experiencing growing customer demand, steady population growth and economic diversity. The Arizona Commerce Authority just reported a record-breaking year in fiscal 2025 with a projected 24,000 jobs created in the state and businesses committed to investing over $31 billion in Arizona communities.

For the second year in a row, Arizona earned the top spot by Site Selection Magazine for attracting business investment in the Mountain region. Additionally, CNBC recently ranked Arizona in the top 3 states for infrastructure, which takes into account how states are delivering on customer power and data demands. We’re working diligently with our customers and community leaders to develop the new infrastructure needed to power our state’s growth. In fact, TSMC announced earlier this month that it plans to accelerate production time lines for some planned facilities by several quarters, and we’re developing accelerated construction schedules now to meet their needs. Our all-of-the-above approach to resource planning is ensuring that we deliver reliable service to our customers every day and in the moments when it matters most, like this week.

The cornerstone of our balanced energy portfolio is the Palo Verde Generating Station, which celebrated its 40th anniversary this year. We continue to invest in Palo Verde for the long term. Although we have already secured 20-year license extensions to continue operating into the 2040s, we’re taking steps now to prepare for subsequent license renewals into the 2060s. In addition, we recently contracted to exercise a buyout option of 94 megawatts previously contracted under sale leaseback. This will allow us to continue providing reliable and low-cost baseload energy to our customers for decades to come. In addition to nuclear, natural gas continues to be an important part of our diverse resource portfolio. We are already developing 675 megawatts of additional natural gas generation to support reliability.

Earlier today, we announced a project with Transwestern Pipeline Company to support the Desert Southwest pipeline expansion. The new pipeline will help maintain year-round regional energy reliability by expanding transport capacity of natural gas from the Permian Basin to Arizona, enabling new gas generation infrastructure to be built in support of our customers into the next decade and beyond. This new pipeline was a critical milestone for our team to secure before proceeding further with procuring new gas generation needed to support Arizona’s reliability and growth. We expect the pipeline project to be in service by 2030, and we will be coordinating the development of new gas-fired generation to be in service coincident with this timing.

In addition to generation, we continue to make progress on our transmission investments and are on track to complete multiple transmission and substation projects for our growing customer base. With the tremendous growth and critical need to build out the grid, we have increased our investment in transmission infrastructure and expect this to continue being a strong component of our capital plan well into the future. We are evaluating additional opportunities to build FERC jurisdictional transmission for the benefit of our customers and look forward to providing additional information on this in the future. As Arizona continues to grow at unprecedented levels, reliable service for our customers is our top priority, which has led us to update our clean energy goal from 0 carbon to carbon neutral by 2050.

We’re also transitioning away from interim targets to better reflect our near-term focus of reliability and affordability for our customers and instead, we’ll report interim progress in our resource plans going forward. We will rely on the integrated resource planning process to forecast the right energy mix and our all-source RFP process to support reliability through best fit, least cost resources, including dispatchable resources such as natural gas plus solar and storage. Turning to our regulatory updates. We filed a rate case on June 13. Key components of the filing include a 10.7% return on equity, 1% return on the fair value increment, 52.4% equity layer and 12 months of post-test year plan. We requested an increase of annual revenue of $580 million with rates to be in effect in the back half of 2026.

Since our filing, a procedural schedule has been issued, which shows a hearing in May and a final open meeting vote in October of 2026. The rate case supports investments in our energy infrastructure to ensure that all customers continue to receive the reliability they count on and increased resiliency under all weather conditions. We’re focused on investments to protect the grid from extreme weather and have invested in programs such as vegetation management, predictive maintenance and wildfire early detection and mitigation tools. On a related note, H.B. 2201, the state’s wildfire mitigation bill received bipartisan support from the Arizona legislature and was recently signed into law by Governor Hobbs. The bill requires Arizona utilities to submit comprehensive wildfire mitigation plans to the Arizona Department of Forestry and Fire Management for approval and mitigates wildfire liability risk by defining standards for the wildfire mitigation in Arizona with reference to those plans.

Lastly, we’re laser-focused on reducing regulatory lag, controlling costs and keeping rates as low as possible for our customers. We’ve proposed a formula rate adjustment mechanism to improve timely recovery of prudent and necessary costs while smoothing out customer bill impacts. In addition, we’re proposing adjustments to our existing rate design to ensure new large customers will pay their full cost of service without shifting costs to other customers. We’re focused on building out the grid to serve growth, ensuring reliability for our customers at the lowest cost possible and executing on our regulatory priorities. We look forward to delivering on our commitment to customers for safe, reliable and affordable service, especially through the summer season, while also delivering on our commitments to shareholders as well.

With that, I’ll turn the call over to Andrew.

Andrew D. Cooper: Thank you, Ted, and thanks again to everyone for joining us today. This morning, we released our second quarter 2025 financial results. I will review those results and provide some additional details on key drivers for the quarter. We earned $1.58 per share in the second quarter, a decrease of $0.18 compared to the second quarter of 2024. Weather, O&M, share issuance and pension and OPEB nonservice credits were the primary negative drivers for the quarter-over-quarter comparison, along with income taxes and D&A. These were partially offset by sales growth and transmission revenue and a gain from an El Dorado equity investment. While weather was beneficial for the quarter as compared to normal weather, it was less than half the weather benefit we experienced in the second quarter last year.

As a reminder, June 2024 was the hottest June on record, contributing much of the quarter-over- quarter drag. Our sales growth was strong for the quarter, contributing $0.08 of benefit year-over-year as our weather-normalized sales increased 5.2% compared to the second quarter last year, solidly within our guidance range of 4% to 6% and with significant contributions from both residential and C&I customer classes. C&I once again has shown robust sales growth at 8% for the quarter with the continued ramping of diverse data center and large manufacturing customers in our service territory. We experienced 2.4% customer growth in the second quarter, and Arizona’s economic backdrop remains strong. We continue to see strong in-migration and population growth with Phoenix ranking in the top 3 among the 50 hottest new home markets for 2025 according to Zonda, a national housing market data firm.

In addition, according to recent U.S. census population estimates, multiple cities within our service territory have seen tremendous growth over the past 5 years with Buckeye, Goodyear, Surprise and Coolidge all exceeding 15% population growth. This customer growth included a surge in new home builds and new meter sets. In fact, meter sets through the first half of the year are on a similar pace to last year, which was the highest number of new meters in over a decade. Also of note, in Phoenix, inflation and unemployment both remain below national averages. This provides us confidence in our current long-term sales growth guidance of 4% to 6% through 2027. We continue to monitor overall economic trends, both locally and nationally, and we’ll take them into consideration for future updates.

O&M was higher this quarter. And year-to-date, while our O&M costs were higher compared to last year, this is largely due to the timing of the planned major outage at our Four Corners plant. Our cost-saving measures and lean culture remain a central tenet of our operations, and we continue to anticipate balanced spend aligned with our O&M guidance in the second half of the year. We’re also maintaining our goal of declining O&M per megawatt hour while our customer footprint continues to grow. We are focused on executing our capital investment program and financing strategy. Our long-term plans remain intact with the passage of the One Big Beautiful Bill Act. We have already begun construction on our Agave and Ironwood projects, where we anticipate tax credit benefits and these key reliability resources are on track to be in service by 2026.

Turning to our financing plan. We issued $800 million in bonds in the second quarter to pay off our 2025 maturities and support our funding strategy. We continue to be deliberate in our financing plan to support a balanced capital structure and balance sheet strength and find advantageous financing opportunities. We are reiterating all other aspects of guidance and given the strong execution of our plan through the first half of this year, we expect that we will end the year in the top half of our full year EPS range of $4.40 to $4.60 per share. As always, we are closely monitoring sales growth and weather as we move through the summer. We look forward to continuing to execute our strategy throughout the rest of 2025. This concludes our prepared remarks.

I will now turn the call back over to the operator for questions.

Q&A Session

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

Julien Patrick Dumoulin-Smith: Nicely done this quarter. So — just if you can elaborate a little bit about today’s announcement with ET here in the pipe. I mean, can you talk about the opportunity to scale beyond just this RFP here for ’28 through ’30? I mean, obviously, you’ve got 2 gigawatts and change there. But the ability to potentially tap into some of the 16 gigawatts of uncommitted queue, I mean it’s a big commitment with ET here. I mean is that really aligning with your participation in just the 2 gigawatts? Or is it more than that in terms of your own generation opportunity that you see?

Theodore N. Geisler: Yes, Julien, I appreciate the question. A couple of pieces there. This pipe was a critical strategic commitment for us to create a long- term reliable supply of natural gas that was sort of foundational for us to be able to then build the generation and transmission needed to be able to power the state’s growth well into the future. And so this is a really important milestone, and we’ve been working on it hard and waiting to secure it before being able to officially sort of roll forward and bring clarity on additional transmission and generation projects. Look, it’s a big pipeline project, 42-inch design capacity, 1.5 Bcf per day, and APS is the anchor shipper. So we’ve contracted a volume that we believe supports substantial reliability and growth for many years to come.

And we’ve contracted for the ability to procure even more from the pipe as needed as we both serve committed queue and begin to eat away at that uncommitted queue. I think with respect to the RFP, what you’ve seen from us is we’ve got just about annual RFPs. And so the one that was put out here for 2,000 megawatts, that was targeting a very narrow window of time and really wanting to accomplish 2 things: one, be able to secure a renewal of existing gas resources that are tolls or PPAs so that we can ensure that capacity for the long term and then marry it up with long-term commitments of new data center growth. But then two, to be able to start to solicit the market for new gas generation. And the pipeline will be a key element to that. We believe APS is well positioned to have strong ownership opportunities with new gas generation.

And the total results from this RFP and procurement efforts alongside it could easily exceed 2 gigawatts, but we’ll look to be able to provide more clarity on that as we get later into the year.

Julien Patrick Dumoulin-Smith: Got it. Understood. And then maybe can you speak a little bit to the transmission opportunity here? I mean, look, clearly accelerating here from, call it, the $350 million level to double that to $700 million by ’27. But to your point, you’re kind of insinuating that ’29 procurement here, you have procurement needs in 2030. What’s the scale of the opportunity on transmission and then to marry that up with what you just talked a second ago on generation. And ultimately, when do you guys provide a reveal of longer-term CapEx because almost everything we’re talking about here is beyond the scope of what you guys technically or officially disclosed today in the medium term.

Theodore N. Geisler: Yes, Julien, that’s correct in the sense that commensurate with the continued growing generation portfolio, we also expect a continued growing transmission portfolio. And transmission is key for really 3 reasons. One, as we build new generation, we’re going to need to invest in new transmission to connect that with customer demand. Two, we’ve got a substantial need within the service territory to continue to expand the capacity and resiliency of the existing system, which is part of what’s driven the capital program for transmission to more than double here in the recent period. But then three, on top of that higher run rate going forward, we expect that there will be an opportunity for large regional transmission investments to give us access to the marketplace even outside of the Phoenix Metropolitan area, both access to the market for low-cost energy, but also access to additional generation that may continue to provide a balanced energy supply into Phoenix.

And those will be lumpy over time as most large new transmission projects are, but we view that as above and beyond the current run rate necessary just to support reliability and resiliency. And as we roll forward capital, the next iteration of that likely on our Q3 call, then we’ll see opportunities to continue to lean into transmission over time.

Andrew D. Cooper: Just — Julien, it’s Andrew. To put a little bit around the numbers where we are today, the run rate of transmission, just the local area projects, the core blocking and tackling is in that $300 million to $400 million range. And that is a major step up from the $150 million to $200 million we were doing in that space less than 5 years ago. And then as you think forward, the numbers we’ve disclosed ’25 — 2025 to 2027, those are the beginnings of some of the strategic transmission projects that we outlined in our strategic transmission plan last year which was a pretty substantial plan over a decade. And if you think about even the run rate of that plan, to Ted’s point, it is lumpy. But as we — ’25 to ’27 is only the beginnings of those projects, to your point, that become operational in the latter part of the decade.

As we roll things forward, you’ll see more detail on those projects, and then you’ll start to see some of the projects that are in the strategic transmission plan that we’re still evaluating and how those may play out. And those are the longer lead time lumpier projects that Ted was referring to.

Julien Patrick Dumoulin-Smith: Right. So it seems like in the transmission investment potential is accelerating into the end of the decade as you kind of reach more of the COD on the long-distance projects?

Andrew D. Cooper: That’s correct.

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

Nicholas Joseph Campanella: So I think everyone understands that you’re in the middle of a rate case. Now we have to go through ’26. There’s going to be additional lag while we wait for those new rates. Can you just kind of talk about how you expect that lag to evolve ’26, ’27 and then ’28 as we get through the GRC as well as the formula rate plan?

Theodore N. Geisler: Yes, Nick, I think the easiest way to think about that is, obviously, 2026 is key to being able to conclude this rate case. And with better visibility now with the procedural schedule, we expect that to be in the latter part of the year. And importantly, while we look forward to resolving that case, it’s still based on the 2024 test year. So day 1 of new rates in effect still means meaningful regulatory lag, which is why we believe the commission is so focused on wanting to address that for all utilities through the formula rate mechanisms and formula rate policy. And so once the case concludes the end of ’26, then based on the proposed plan of administration, the first ability to file a formula rate adjustment based on updated costs would be then in 2027.

And so we would expect for that filing to occur by July 31, 2027, based on the proposed plan of administration with the new formula rate adjustment in effect by September 1, that will certainly give some relief and update on regulatory lag. And then 2028 has the potential to be the first full year of those updated costs with then, of course, an annual adjustment going thereafter. So that’s how we think about it. But obviously, we’ve got to agree on that with the commission and go through the stakeholder process through this upcoming case first.

Nicholas Joseph Campanella: Okay. That’s helpful. And then I guess just to follow up on the last question. Just to be very clear, the Southwest pipeline, you have 2 gigs of committed in the queue right now. And just this pipeline unlocks how much capacity that you could actually serve into the early 2030s, if you could just simplistically frame it.

Theodore N. Geisler: Yes. So to be clear, we’ve got close to 4.5 gigawatts of committed extra high load factor customer demand, and that’s a blend of largely data centers as well as large manufacturing like TSMC. That’s the committed amount that we are actively working on committed projects under contract, putting steel on the ground to serve. In addition to that, we’re now approaching just under 20 gigawatts of uncommitted queue that is expressed serious interest in new projects within our system, and we’re working with that queue on being able to identify new resources to be able to serve them. The pipeline was a critical first step in us then gaining clarity on the ability to reliably commit and serve to that uncommitted queue.

Now that we’ve got that in place, we’re going to continue working and finalize new generation projects that will be able to be allocated to that uncommitted queue and then the transmission associated with that. So I think this pipeline was the first key step. It will certainly be used to help ensure long-term reliability for our committed customers. But a big part of that pipeline, given the magnitude is going to really be used to allow us to start to commit to projects in the uncommitted queue. And I think we’ll get more visibility on that later in the year and into next as we announce generation projects and transmission projects to support those uncommitted customers.

Nicholas Joseph Campanella: Okay. That’s great. And just one last one, if I could. Just the El Dorado gain, just was that expected in guidance when you set guidance? Or is that kind of incremental through this year? And otherwise, would you still be at the midpoint?

Andrew D. Cooper: Sure, Nick. It’s Andrew. Just by way of background, El Dorado is our nonutility nonregulated business. It is some legacy investments that were to invest in energy infrastructure and in some community projects over the years. And SAI became profitable over the last year. It’s an electric switchgear company actually serves the data center market, among others. And so we’ve had to recognize some gains related to the increased profitability in that investment. It’s something that we monitor quarter-to-quarter because it’s a minority investment under an equity investment method of accounting, it’s not something that is part of core business. It’s not something that we plan for when we budget. And so while it’s been nice to see some tailwinds from it this year, which have contributed to — among many other factors have contributed to our ability to have confidence in the upper end of our range.

It’s not something that is really part of that core that we’re focused on for the long term. And you’ve seen us last year, we exited our Bright Canyon business as a way to really emphasize the core. And while SAI has been profitable and a good story this year, it’s not something that we’re certainly as focused on as the core infrastructure investments.

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

Paul Patterson: So a lot of stuff has been covered, but I just have one really sort of technical question. On the solar — on your slides, the solar power plant performance, it looks like for the 6 months and 3 months, it’s — the performance is down, I guess, from 36% to 26%. Can you just tell me what that is?

Theodore N. Geisler: Yes, Paul, I think that’s really referring to peak value or peak demand. And really, that’s just reflecting that the more solar you install, the less capacity is there to be able to serve peak demand. So that’s well within our resource planning assumptions and consistent with what we would expect.

Paul Patterson: So it’s like a curtailment thing?

Theodore N. Geisler: No, it’s not curtailment. It’s just a factor of total capacity installed and the amount of that, that’s actually serving peak energy demand. But the solar facilities that we have and our utility scale facilities, they’re performing well and performing as expected.

Paul Patterson: Okay. So it’s — okay, I got you. I think I get what you’re saying. So I guess it’s the way it’s sort of laid out here.

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

Travis Miller: A lot of questions and thoughts here on the generation and transmission side. I was wondering on the distribution side, as you hit some of these peak demand and continue to see some of this growth, is there upside opportunity in terms of capital investment or other O&M savings, et cetera, at the distribution level?

Theodore N. Geisler: Yes, Travis, I appreciate the question. Absolutely. Distribution is directly tied to growth. And as we continue to experience strong growth, that puts pressure on continued investments in the distribution system. So I think what you see today is a growing level of distribution investments commensurate with the customer growth we have. And if you look at the quarterly values of customer growth, we’ve got the highest level of customer additions this past quarter that we’ve had in the last 2 years. And the growing distribution category is reflective of keeping up with that growth. In addition, within distribution, we have resiliency investments because we continuously invest back into the existing distribution system to ensure we’re achieving our target of top quartile reliability for all our customers.

And that includes new technology to create greater visibility and automation on the distribution grid in addition to replacing old circuits, adding redundancy and then building new circuits and transformers to keep up with growth. So that’s an important part of our capital program, and we believe we’ll continue to see growth into the future as we continue to support a growing customer region. The last thing I’d say is from a peak demand standpoint or customer count standpoint, while we may be a midsized utility, we actually have the fifth largest service territory from a square mile standpoint of our peers. And that means it’s a big distribution system. And so there’s a lot of investment opportunity just to ensure we’re maintaining reliable service to our customers over the long term.

Travis Miller: Okay. That’s great. And then real quick on the rate case, anything in your initial conversations or putting together the request that you think will be more contentious or less contentious with all the stuff that you’ve got in there?

Theodore N. Geisler: I think the case was filed as expected. But importantly, this case includes 2 elements that are, I’ll call it, unique and above and beyond what you would expect from a standard rate case filing. So the 3 key components for the case is the standard component, which is simply seeking recovery to make up for the revenue deficiency. The second component, though, is to provide a proposal consistent with the commission’s policy statement for transitioning to a formula rate plan going forward. And we filed our case consistent with the outcome of the workshops that were held last year and with a design that incorporated a lot of feedback from stakeholders along the way. So it’d be unfair to say everyone agrees with the details of that plan, but it does incorporate a lot of the feedback that was considered last year, and we look forward to working with stakeholders and the commission on finalizing the details of that.

The third component, importantly, is on the minds of many, and that is a proposal for adjusting rate design to ensure that our new large customer additions are paying their fair share of the infrastructure required and preventing a cost shift to other customer classes. And that’s an important element of this case that’s particularly important now given the sizable additions of customers and infrastructure to support that new growth. And I know that’s top of mind for many utilities across the country, and we believe it’s paramount to ensure affordability for our existing customer base going forward. So those are the 3 elements. I wouldn’t say there’s any aspect of that, that stands out as overly contentious, but there are 2 key components that are above and beyond what you would normally expect in just a standard rate case filing.

Travis Miller: Sure, yes. Okay. And then could the commission break those out such that they would might approve parts of any of those 3?

Theodore N. Geisler: Well, I suppose anything is possible. I don’t know if that would be the most efficient way, though, to process this case. And we fully expect to have a standard hearing process, and it probably makes sense then while you have an administrative law judge and all the stakeholders weighing in through a formal hearing to ensure that everyone has the opportunity to produce evidence and testimony to debate and support all 3 of those elements. So we believe that’s likely how the commission is thinking about it, and that’s certainly the way we believe is the most efficient way to process this filing.

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

Sophie Ksenia Karp: A lot of growth happening in your territory, some of which you’re highlighting through volume growth as well as customer growth, et cetera. At what point do you think your kind of rate base CAGR begins to inflect to the upside? And how do you think about the timing of maybe quantifying it for investors given the rate case and all the other moving parts that you have?

Andrew D. Cooper: Sophie, it’s Andrew. Yes, I think a lot of the key things that Ted highlighted earlier on are critical to think about the long runway that we have from both a customer growth perspective and a CapEx perspective. And that is the sort of new area where we’re looking at some of these larger generation investments that we could make, and that’s — we talked about the pipeline kind of unlocking the opportunity to begin to look at those. And then as we think about accessing new resources from afar, some of these transmission projects that are above and beyond the run rate that we’ve been talking about. And because there are larger projects, we’ve started to give more information in our disclosure around the quip aspect of some of these longer lead time projects that may not show up in rate base in such a narrow window that we show, which right now is ’25 to ’27.

I think you pointed to the rate case is an important milestone given the formula rate that Ted just talked about, gives us the opportunity to look at all capital on an even playing field because you’ll have very consistent cost recovery across different asset types. And I think we’ll have better visibility into that — the cadence of the long-term CapEx spend really across the different parts of our business. And so we haven’t made any determinations around elongating that CapEx disclosure, but certainly expect to roll it forward in the ordinary course the way we would typically in the third quarter. And as we’ve developed these strategic transmission projects, continue to work, as Ted said, on the generation opportunities unlocked by the pipeline, we’ll be able to provide more information as we go forward.

Sophie Ksenia Karp: Got it. And then I don’t know if I missed it maybe in the prepared remarks part, but are you quantifying your kind of larger customers’ pipeline in terms of maybe load study requests or however else you may quantify it?

Theodore N. Geisler: Sophie, I think if I understood you right, have we quantified the potential customer commitments that are available through the uncommitted queue. Forgive me if I misunderstood your question, but we’ve got about 4.5 gigawatts of committed customers that fall into the category of we consider extra high load factor customers or significant large commercial customers. And that’s made up of largely data centers and large manufacturing. But in addition to that, we’ve got nearly 20 gigawatts of customer requests in an uncommitted queue. And the pipeline was a critical infrastructure commitment that we wanted to secure and get visibility to before we start to then get further on new generation or transmission build necessary to be able to then start to contract in that uncommitted queue.

Now that we’ve got the pipeline secured, I think we’ll be able to begin in earnest working with some of those customers and associating their needs with new generation or transmission projects.

Operator: Your next question is coming from Ryan Levine from Citi.

Ryan Michael Levine: One clarifying question. In relation to the anchor shipper relationship, what’s the risk for shareholders and rate payers if the uncommitted growth projects don’t materialize? Or is there any color around how to phrase the risk profile, recognizing that there’s a lot of growth potential? I’m just trying to understand the potential risk if some of that doesn’t materialize.

Theodore N. Geisler: Yes, Ryan, I think the easiest way to think about that is even if you had no uncommitted queue, this pipeline was still necessary to secure long-term reliability with the most affordable resources possible for our existing customers and the customers that we’ve already committed to serve. So while there’s upside for us to be able to procure even additional capacity on this pipeline, the pipeline was essential even just to serve our existing customer base and those that we’re currently building out to serve in the committed queue. And as a result, we believe that this pipeline is easily demonstrated as prudent and necessary to support reliability now and for the long term.

Ryan Michael Levine: And just a follow-up, are there contractual rights to be able to expand your capacity if needed and the growth materializes at prenegotiated tariff rates? Or is that subject to future negotiations?

Theodore N. Geisler: We’ve commercially secured the ability to flex up capacity procurement.

Operator: Your next question is coming from Paul Fremont from Ladenburg.

Paul Basch Michael Fremont: Congratulations on the quarter. Given the fact that you guys are currently in a rate case, when should we expect that you would give 2026 guidance?

Andrew D. Cooper: Paul, it’s Andrew. Typically, as you alluded to in a rate case, just given uncertainty over the timing of its conclusion, we wouldn’t normally provide earnings guidance. But as Ted mentioned in the prepared remarks, we now have the procedural schedule, and we expect rates — we expect a hearing in the fourth quarter. And as a result, you’re talking about next year being, for the most part, pretty much regular way. So we would expect to be in a position to provide earnings guidance for 2026 based on that procedural schedule. And we would typically provide earnings guidance on the third quarter call.

Operator: Thank you. That completes our Q&A session. Everyone, this concludes today’s event. You may disconnect at this time.