Logo of jester cap with thought bubble.

Image source: The Motley Fool.

DATE

Monday, May 4, 2026 at 12 p.m. ET

CALL PARTICIPANTS

  • Chairman, President, and Chief Executive Officer — Theodore N. Geisler
  • Executive Vice President and Chief Financial Officer — Andrew D. Cooper

Need a quote from a Motley Fool analyst? Email [email protected]

TAKEAWAYS

  • EPS -- $0.27 per share, up from a loss of $0.04 per share, driven by higher transmission revenue, strong sales, favorable weather, and decreased O&M, partially offset by higher interest expense, lower Eldorado contribution, and increased depreciation.
  • Transmission Revenue Benefit -- $0.16 per share, stemming from ongoing transmission system investment to serve a growing customer base with continued upside expected in line with guidance.
  • Weather Benefit -- $0.13 per share, as March set a record for heat with nine days at or above 100°F, resulting in elevated residential and commercial cooling demand.
  • Customer Growth -- 2.2%, at the high end of annual guidance, supported by infrastructure expansion in Arizona's accelerating manufacturing and semiconductor sector.
  • Weather-Normalized Sales Growth -- 9.4% with commercial and industrial up 14.6% and residential segment up 1.8%; adjusted Q1 sales growth was 7.4% excluding a prior-year one-time item.
  • Annual Sales Guidance -- Reaffirmed at 4%-6% for 2026 despite current quarter performance above the upper end of this range.
  • Long-Term Sales Growth Outlook -- Maintained at 5%-7% through 2030, underpinned by 4.5 gigawatts of committed customer load and significant uncommitted demand in the pipeline.
  • Operating & Maintenance Expense -- Decreased due to lower planned outage costs and reductions in energy efficiency program expenditures.
  • Capital Structure & Equity Funding -- All 2026 equity funding needs met; $850 million of priced equity is available for future issuance, including $350 million secured in the first quarter.
  • Credit Ratings -- Unchanged with stable outlooks from all three agencies, reflecting positive dialogue and an emphasis on maintaining strong financial metrics during regulatory proceedings.
  • Transmission CapEx Trajectory -- Capital spending on transmission has quadrupled over five years, supporting the increase in transmission-related earnings through scalable, formula-based recovery.
  • Rate Case Status -- On track, with multiple testimony rounds completed and a hearing scheduled for May 18, targeting reduced regulatory lag and improved investment recovery.
  • Infrastructure Projects -- Construction has begun at Red Hawk (eight turbines, 400 megawatts gas capacity), with Desert Sun advancing through development and equipment procurement.
  • Resource Procurement -- All-source RFP bids for projects starting 2029-2031 are under review, with final awards expected this year.
  • Industrial Contract Model -- Subscription model negotiations are active and progressing, with the first tranche sized at 1.0-1.2 gigawatts based on current capacity and targeted for Commission filing in 2026.
  • Uncommitted Demand Queue -- Nearly 20 gigawatts of uncommitted large-customer demand, reflecting substantial interest and future growth opportunities.
  • Customer Satisfaction -- APS placed in the first or second quartile in the Escalent relationship model and achieved first quartile status nationally with J.D. Power, earning the highest awareness score for customer programs.
  • Formula Rate Recovery -- Transmission revenues are annually trued up, largely decoupled from weather, enabling timely recovery and steady rates for both retail and wholesale customers.

SUMMARY

Pinnacle West Capital Corporation (PNW 0.87%) reported a return to profitability, highlighting transmission and weather as key earnings contributors. Management confirmed that all equity needs for the year are satisfied, and a robust equity cushion is positioned for future capital requirements. The positive regulatory dialogue maintained current credit ratings with a stable outlook, and the rate case is progressing in line with the schedule, aimed at supporting ongoing investment recovery. Major capital projects are proceeding, including Red Hawk and Desert Sun, while the company actively manages a large, growing pipeline of industrial customer demand and related infrastructure expansion efforts. The subscription contract model is gaining market acceptance, with counterparties negotiating terms tied to incremental capacity additions. Customer satisfaction scores were noted among the best in the country, reinforcing the company's customer-focused operational approach.

  • APS’s forthcoming Integrated Resource Plan (IRP) will provide updated sales growth analysis based exclusively on contracted load, with any additional industrial demand remaining as potential upside.
  • The company sees its current capital plan supported by large-load customer contracts, with a strategy to utilize a mix of up-front customer funding and retained earnings to reduce reliance on external capital.
  • Pinnacle West confirmed that the repeal of the renewable energy standard will not reduce current clean energy investments, as current market-driven demand already exceeds previous regulatory targets.
  • Existing large-load tariff mechanisms will require growth-driven customers to directly finance incremental grid needs, either via updated tariff pricing or special subscription contracts under Commission review.
  • The utility continues to analyze the potential conversion of the retired Cholla coal facility to gas, with timing aligned to upcoming resource planning cycles and rising local demand.

INDUSTRY GLOSSARY

  • Integrated Resource Plan (IRP): A comprehensive utility plan that forecasts future electricity load and sources of generation to reliably and affordably meet customer needs over a defined planning horizon, incorporating regulatory, economic, and operational assumptions.
  • Subscription Model: Special contract structure in which industrial customers commit to up-front funding or accelerated capital participation to secure incremental grid capacity, with distinct rates and regulatory approval separate from standard tariffs.
  • Extra-High Load Factor (XHLF) Tariff: A rate structure designed for customers with consistently large, predictable electricity usage, ensuring those loads fund the infrastructure needed for their service.

Full Conference Call Transcript

Theodore N. Geisler: Thank you, Amanda, and thank you all for joining us today. We are off to a solid start in 2026, delivering first quarter earnings that support the financial guidance we provided in February. Before Andrew reviews the quarter in more detail, I will highlight several operational, customer, and regulatory developments that underscore the momentum across our business. Arizona’s diverse economy continues to expand at a strong and sustained pace, reinforcing the state’s position as a national leader in semiconductor and advanced manufacturing. We are proud to support TSMC’s accelerated expansion in Arizona and are working closely with the company on the infrastructure needed to power their growth.

With its second fab complete, TSMC expects to begin volume production of 3-nanometer chips in the second half of next year. Construction is underway on the company’s third fabrication facility, and TSMC has also begun construction on its fourth fab and first advanced packaging facility, with those facilities expected to come online by 2029. Importantly, the momentum extends well beyond TSMC. Activity across the semiconductor supply chain continues to intensify throughout the region, with key suppliers rapidly establishing and expanding their local footprints to support accelerated production timelines. United Integrated Services Corp, Sunlit Chemicals, and Mournstera have all purchased land in North Phoenix.

At the same time, engineering firms, clean room specialists, electromechanical integrators, and equipment suppliers are increasing staffing levels and scaling operations across the Valley. These investments demonstrate strong confidence in Arizona’s economy and reinforce the sustained growth we are seeing across our service territory. Turning to operations. Our focus remains on delivering top-tier reliability, strengthening grid resilience, and investing in the infrastructure and technology needed to serve our customers safely and efficiently. Across the company, we are using automation and advanced analytics to improve decision making and execution.

For example, we are applying machine learning tools to better anticipate equipment performance, prioritize asset maintenance, identify outage restoration more accurately, and strengthen situational awareness during periods of elevated wildfire or weather risk. These capabilities are helping our teams act faster, target investments more effectively, and continue improving reliability for our customers. We continue making solid progress on our generation and transmission investment plans. Construction is now underway at our Red Hawk expansion project, which will add eight combustion turbines and approximately 400 megawatts of reliable natural gas capacity to the system. We are also advancing the Desert Sun project, where we have secured major equipment reservations and continued to progress through early development activities, including siting and permitting.

On resource procurement, we recently received proposals in response to the all-source RFP issued later last year, which targeted new resources beginning service between 2029 and 2031. We are evaluating those bids now and working with counterparties to determine the best-fit projects for our system and customers. We expect to make final awards later this year. As we plan for long-term growth, we are also focused on near-term summer preparedness. Palo Verde Unit 2 is in the final days of its planned refueling outage and expected to return to service soon. With all three units operating, Palo Verde will continue providing round-the-clock reliable and affordable energy to help meet our summer demand.

We are prepared to serve our customers safely, reliably, and affordably during the months ahead when they depend on us the most. We continue to strengthen our customer-centric culture with employees focused on delivering reliable service, minimizing outages, and providing a seamless experience across phone, field, and digital channels. In the first quarter, APS delivered strong results in the Escalent customer relationship model, ranking in the first or second quartile across all core KPIs. APS also ranked in the first quartile through J.D. Power and was highlighted nationally as a top performer in customer awareness and participation in products and services, earning the highest awareness score in the country for available customer programs. Lastly, our rate case remains on track.

We have completed multiple rounds of written testimony, and the hearing is scheduled to begin on May 18. We look forward to working with the Commission and intervenors in a timely and constructive manner. In summary, we are executing our plan, delivering operational excellence to our customers, investing in grid expansion to serve Arizona’s rapid growth, and improving investment recovery to reduce regulatory lag while ensuring affordability for customers. With that, I will turn the call over to Andrew.

Andrew D. Cooper: Thank you, Ted, and thanks again to everyone for joining us today. This morning, we reported our first quarter 2026 financial results. I will review those results and provide additional details on sales and financial guidance. For 2026, we reported earnings of $0.27 per share compared to a loss of $0.04 per share for 2025. Higher transmission revenue, favorable weather, higher sales and usage, and lower O&M were the primary benefits this quarter. These positives were slightly offset by increased financing costs, a smaller contribution from our Eldorado investment than last year, and higher depreciation and amortization. Transmission revenues contributed 16¢ of benefit this quarter. This reflects our continued focus on heightened transmission investments to support our growing customer base.

Expect a strong benefit in this area throughout the year, in line with our annual guidance. Weather also provided a meaningful benefit this quarter, primarily driven by the warm weather we experienced later in the quarter. Although we saw less heating load in January and February due to a mild winter, according to the National Weather Service, March was the hottest on record, with nine days at or above 100 degrees. The resulting impact was a benefit of 13¢ attributable to weather in the first quarter due to an increase in residential and commercial cooling degree days.

We continue to see a consistent ongoing influx of customers into our region, as customer growth for the quarter was again strong at 2.2%, near the high end of our annual customer growth guidance. Our weather-normalized sales growth was 9.4% for the quarter, driven by strong C&I growth of 14.6% and residential growth of 1.8%. We had a one-time adjustment to sales growth during last year’s first quarter, and if we take that into consideration, we would still have experienced strong weather-normalized sales growth at 7.4% during Q1 of this year. We are not changing our annual sales growth guidance of 4% to 6% at this point, but it is a strong start to the year.

This trend of customer and sales growth reinforces our need for investments in our system to ensure reliable service for our customers. On the expense side, O&M saw a significant decrease in the first quarter compared to last year. This was mostly driven by lower planned outage expenses and a reduction to Commission-required energy efficiency programs. We continue to have a strong focus on cost management, and we are maintaining our goal of declining O&M per megawatt-hour. Interest expense was higher this quarter compared to the first quarter of last year, driven by higher debt balances from issuances. Our year-over-year benefit from our Eldorado investment was smaller, driving a slight drag.

Finally, our depreciation and amortization expense for the quarter increased slightly as the placement of additional plant in service was partially offset by the retirement of Cholla. Turning to the balance sheet. We recently had positive conversations with all three credit rating agencies, resulting in the maintenance of our current ratings and stable outlooks. We are focused on sustaining solid ratings and metrics to the benefit of our customers as we continue to work with the Commission and stakeholders on reducing regulatory lag through our pending rate case. Our guidance for financing remains unchanged. We are pleased to announce that all of our equity funding needs for 2026 have been completed, and we are opportunistically working towards future year needs.

We now have nearly $850 million of priced equity available to us for future issuance under equity forwards, including more than $350 million priced during the first quarter. We continue to utilize a mix of debt and equity sources to maintain our balanced capital structure. We are reaffirming all other aspects of our financial guidance and look forward to reliably serving our customers as we continue executing our strategy throughout the year. This concludes our prepared remarks. I will now turn the call back over to the operator for questions.

Operator: Certainly. Everyone, at this time we will be conducting a question-and-answer session. If you have any questions or comments, please press 1 on your phone at this time. We do ask that while posing your question, please pick up your handset if you are listening on speakerphone to provide optimum sound quality. Once again, if you have any questions or comments, please press 1 on your phone. Your first question is coming from Shahriar Perruza from Wells Fargo. Your line is live.

Analyst: Good morning, everyone. It is actually Alex on for Shar. Thanks for taking our questions. So just on the long-term sales growth, that 5% to 7% you have out there through 2030, you are obviously seeing a lot of growth in your service territory and in the pipeline as well. You saw 7% growth just this past quarter. Can you talk a little bit about how sticky this outlook is? Can we see this trend continue going forward? Is there anything that you see that could potentially allow you to revisit this outlook as opportunities continue to materialize?

And then just pivoting, on the EPS and the rate base CAGR, as we look out, say, 2029 and beyond, any updated views on how we should be thinking about the delta between the two? Is that 200 basis points the right figure, or could you see those two converge over time given all the opportunities and growth that you are seeing?

Andrew D. Cooper: Good morning. As you noted, we did have sales growth this quarter that, even adjusting for the adjustment from the first quarter of last year, was almost 7.5%. That was driven by the continued ramp-up of our extra-high load factor customers, and we have a number of them that are all in different stages of their ramp. Last year, we were able to increase our long-term sales growth guidance through 2030 up to that 5% to 7%. What you saw in the first quarter here looked more like the top end of our range for the long term, relative to what we expect for this year, which is 4% to 6%.

You are seeing long-term trends begin to manifest around the diversity of customers we have. We are about to get rolling on Fab 2 at TSMC, as Ted mentioned, and we continue to see sustained customer additions to our service territory, which for the quarter were in the top half of our customer growth range. Fundamentally, that long-term runway around the diverse sales growth in the service territory is something we see continuing. We will continue to revisit because that sales growth rate is driven by the customers that are committed today—the roughly 4.5 gigawatts of customers that we have committed to.

There is a large backlog of customers in our queue, and as we continue to work the capital plan and the ability to serve those customers, we will look for opportunities to invest and see sales growth beyond our base plan. For now, we feel comfortable with the 5% to 7% long term and the 4% to 6% for this year. Regarding EPS versus rate base CAGR and the roughly 200 basis point delta, we will have to revisit all of this at the conclusion of the rate case.

Our capital investment opportunity will be informed by the ability to narrow regulatory lag, which in and of itself will help narrow that gap between what we spend and how it drops to the bottom line, as well as some potential for bilateral contracting opportunities with some of our large-load customers. Our expectation is to continue to push those customers to support some of the upfront funding, which will allow us over the course of the contract to front-end load some of the funding and reduce the need for external funding. As we continue to have better and more predictable cash flow conversion, it gives us an opportunity to fund more from retained earnings.

We will continue to look at that while also looking at the capital opportunity to reinvest in the system.

Operator: Your next question is coming from Julien Dumoulin-Smith from Jefferies. Your line is live.

Julien Patrick Dumoulin-Smith: Hey, team. Good morning. Nicely done. What a way to start the year. Maybe just to kick things off from a timing perspective: what could we see on the August 3 IRP filing, and how do you think about that refresh cycle? What kind of clues could we get to kick off the summer ahead of any broader post–rate case update? And related to timing, what are the gating items for this subscription model contract effort you are trying to get off the ground? When could contracts be signed—is that something we could see this summer? Do you think about that materializing?

Theodore N. Geisler: Appreciate the question. The IRP will be a meaningful update. The team is finalizing the analysis and the report now, and we will work with stakeholders on engaging in different review components ahead of the official filing later this summer. The IRP analysis will include our latest long-term thinking in terms of sales growth within the service territory across all three sectors: residential, small to medium-sized business, and industrial growth. Importantly, it will include all of the extra-high load factor growth that we have committed to, but it will not include anything that we have not contracted for yet, which will remain as upside.

We have done a lot of work over the past six to twelve months to analyze over the next ten to fifteen years how residential growth trends with distributed generation and energy efficiency, how the long-term ramp rates will play out for the committed 4.5 gigawatts of extra-high load factor growth, and the resources needed to support that. Within the near-term action plan window of the IRP, it will show some specific projects that have already been announced. Beyond that, it will show buckets of generation and transmission needed.

As we carry forward the capital plan—either at the conclusion of this rate case or into the beginning of next year—that capital plan should support the resource and transmission needs outlined in the IRP based on the committed growth included in the analysis. On the subscription model, we continue to be in active negotiations with counterparties on various projects. It is too early to tell how those may conclude, but as soon as they do, we would expect to be filing agreements with the Commission, and we are still on track to get those filed this year.

Julien Patrick Dumoulin-Smith: Got it. Thank you. And if I can needle a bit: APS’s rebuttal moved several mechanics closer to what the UNF guys have on their gas template. How should we think about the cadence of that 200 basis points? Is a 50 basis point ROE gap by 2029 still the goal, or is there potential to move that forward?

Theodore N. Geisler: Yes. We still believe that our rebuttal position—and our ability to continue to manage regulatory lag going forward—is consistent with our position at this point. Management’s goal is to be able to consistently earn within that 50 basis points, given there is some element of structural lag that will continue to exist. The latest thinking on design elements for formula rate, as well as assuming a constructive outcome in the rate case revenue requirement, would allow us to do so by 2029 and going forward.

Operator: Your next question is coming from Richard Sunderland from Truist Securities. Your line is live.

Richard Sunderland: Good morning. Picking up on the subscription model commentary, can you frame whether interest has shifted at all relative to expectations three to six months ago? Any flavor you can give around those conversations would be helpful, given limited insight from the outside.

Theodore N. Geisler: The interest is still robust within the service territory. Our overall queue size remains elevated, hovering just under 20 gigawatts of uncommitted demand. How much of that is duplicative projects or interest versus projects ready to execute is to be determined, but the interest in viable projects for us to contract is meeting our original expectations. These contracts are complex. They involve details around investments and execution of both transmission and generation, ensuring that the rates are carefully calculated to make sure growth pays for growth, that the financing needs are met, and that both the utility is protecting its customers for reliability and affordability and the counterparty gets what they need in terms of timing and resource adequacy.

It takes time to work through these negotiations, but they are making progress. We are pleased with how the subscription model was received by the market. We are not at the point yet of filing them with the Commission, but it is trending in that direction.

Richard Sunderland: Switching gears, about a month ago the Governor’s energy task force delivered a report. There was a lot in there, including new nuclear. What do you have an eye to out of that report—anything to highlight on the nuclear front or more broadly?

Theodore N. Geisler: We appreciated working with the Governor, several agencies within the state, and other stakeholders to create awareness of the energy needs to power Arizona’s growth and how to think about those needs at a macro level. It was a robust set of discussions culminating in a directional report that identified several key factors. One, the state plans to invest in and support new gas infrastructure to power growth reliably, showing widespread support for the gas pipeline infrastructure needed. Two, the state will continue to benefit from a diverse set of resources, anchored by around-the-clock dispatchable generation while also benefiting from our robust solar irradiance.

And longer term, the state has always been a leader in reliable and affordable nuclear generation, and both the utilities and the state believe that is a technology worth paying attention to and being open to support in the future when it makes sense from an affordability and licensing/permitting standpoint. We have said before, specific to nuclear, that we are not in a position to put the utility balance sheet at risk. To the extent we have large customers interested in seeing new nuclear and willing to help support the financing, as the operator of the largest producing nuclear plant in the country, we would be very open to those discussions at that time.

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

Paul Patterson: Good morning. On the prepared remarks, you mentioned how much you have taken care of in terms of equity, but you also mentioned looking for additional opportunities. Could you elaborate a little on your thinking there?

Andrew D. Cooper: Sure. We have continued to try to de-risk the equity plan. We have a three-year equity plan through 2028. Admittedly, that is the base case plan without expectations that could come from the formula rate or bilateral subscription-type agreements; it is the base of what we need with the CapEx plan we have in place today. Through various equity forward transactions, we have accumulated almost $850 million of equity to put to work. Our stated need for this year is $650 million of equity, so we have nearly another $200 million that we have achieved through our ATM program to help meet future-year needs as well.

We will continue to look at the equity needs against the rate case and our cash flow situation. For the base needs—roughly $1.0 billion to $1.2 billion of new money from 2026 through 2028—we have already begun to eat into that number by several hundred million dollars. We are trying to de-risk and do so opportunistically as we go along.

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

Ryan Michael Levine: Good morning. In light of Commissioner Meyer’s testimony in D.C. recently, what is the thought process around converting retired coal to gas generation, and the potential for federal permitting reform to impact the company?

Theodore N. Geisler: We continuously look at when it makes sense to revisit using some of our retired generation sites. At this point, the Cholla site is the only one that would fall into that category. Analysis was done back in 2015 on the need to retire that site as a coal facility, but ever since then we have continuously done analysis to determine when it makes sense for our customers to potentially convert it to gas, use the site for new gas generation, or even other technology in the future. That analysis is ongoing. As demand rises in our service territory, natural gas continues to be an affordable resource for us.

As the cost of new gas generation has increased recently due to supply chain demands, gas conversion continues to look even more affordable. If and when it makes sense for us to convert on behalf of our customers, we will make that clear, begin those investments, and put it in our plans for the future.

Ryan Michael Levine: Regarding potential federal permitting reform to impact the company, any color there?

Theodore N. Geisler: At this point, there is nothing specific we can directly tie to where reform could benefit us. We agree with Chair Myers that the broader need for streamlining federal permitting has never been more present than now, given the significant infrastructure needs to power growing markets within our country—Arizona among the top. Whether it be transmission siting or gas pipeline infrastructure, any help driving efficiencies and expediting federal permitting will allow us to implement infrastructure quicker and serve customer demand quicker. We support opportunities to look at those reforms, but it is too early to tell in terms of any specific opportunities that will benefit our infrastructure plans.

We are not counting on changes to reform to execute our plan and we remain on track with our infrastructure investment opportunities.

Ryan Michael Levine: On the ongoing study around converting to a gas plant, is there any timeline for when that study will conclude? Would that be concurrent with the subscription negotiations targeting the end of this year?

Theodore N. Geisler: The best opportunity to continue to look at that is as we conclude our analysis leading up to this IRP filing. That will include a wholesale look at our generation mix to serve growth, and as part of that, continued renewed analysis on any potential for gas conversion or new gas generation at the Cholla site.

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

Anthony Crowdell: Good morning, team. On Slide 18, you showed committed load and then the uncommitted load. Twenty gigawatts is uncommitted. What are the factors or timing for when we can maybe move that 20 gigawatts into the 4.5 gigawatts? Do you see a conversion through 2026 or timing of conversion?

Theodore N. Geisler: The subscription model offering we came out with last year and the negotiations currently underway with counterparties would reflect some elements of that 20 gigawatts potentially moving over to the committed customer bucket. That process is underway now. As we approach opportunities to file special rate agreements with our Commission, that is the opportunity to create more visibility into how much of that 20 gigawatts may shift over based on this initial subscription offering. As we continue to work forward in our plan for new transmission and generation infrastructure, that will give us visibility into what the next iteration of the subscription model could look like to offer back to that queue.

Our goal is to submit those contracts to the Commission for review this year, which is when we will have greater visibility. In addition, our IRP will provide our latest analysis on organic load growth—non–extra-high load factor growth inclusive of residential and small to medium-sized business—and likely provide visibility into what we are thinking beyond just the 20-gigawatt queue over the next ten to fifteen years.

Anthony Crowdell: For APS, I believe you have a large-load tariff that may reevaluate the cost to serve these large-load customers on some cadence. When you talk to potential large-load customers that may come onto your system, do they have comments or preferences? Are they agnostic to the different types of large-load tariff that exist—the APS offering versus other utilities?

Theodore N. Geisler: We have an existing extra-high load factor tariff, and as part of this rate case we have proposed updating that tariff to reflect the current supply-demand environment and ensure it is priced so that growth pays for growth. Generally, these large customers accept the responsibility of paying for the cost associated with serving their growth. Looking ahead, customers will have two options. The standard offering is to continue to take service from that XHLF tariff, recognizing it will be priced based on actual cost of service.

To the extent they want an accelerated offering through the subscription model—where they contribute to financing infrastructure or potentially help accelerate providing key equipment—we can enter into a special contract to be submitted to the Commission for review and approval. Either way, pricing—whether through tariff or subscription model—needs to pay for the entire cost of service. That is a commitment we have made to our Commission and our other customers.

Anthony Crowdell: Have they shown a bias for or against it, or are they agnostic?

Theodore N. Geisler: There is general support. We need to defend the pricing and ensure customers have visibility into it. As we engage with counterparties on incremental infrastructure needed to serve them—incremental transmission and incremental generation—these are truly new builds. There is no more capacity on the existing system to take advantage of, so it is all new construction. As a result, the price looks different than it did when you were taking benefit from legacy infrastructure already installed. It is important that we are transparent about what it takes to serve them. There is general acceptance that this is the reality of today’s operating environment and what it will take to reliably connect in the Phoenix market.

While prices are meaningfully different than years ago when there was excess grid capacity available, demand interest from our visibility has not changed at all.

Operator: Your next question is coming from Steve D’Ambrizi from RBC Capital. Your line is live.

Stephen D'Ambrisi: Thanks very much for taking my question, and congratulations on the strong start. Following up on questions about the subscription model, I believe the Phase 2 offering was initially sized at up to 1.2 gigawatts. What drove that sizing? Is it more reflective of the near-term opportunity within the 20 gigawatts, or is it a function of available capacity at Desert Sun or gas capacity? How should we think about the pace of potential incremental additions?

Theodore N. Geisler: You are correct that the initial sizing was driven by the infrastructure we had identified as being available for a subscription offering. That reflected the available generation and transmission we had visibility to in the timeframe the subscription counterparties were interested in—in large part from Desert Sun and the transmission to coincide with it. That will be a continuous evaluation. Think of it less as a fixed amount of capacity and more as a process: we evaluate how much of our organic load growth will require infrastructure for existing customers—residential and small to medium-sized business—and then how much incremental infrastructure we can build to offer above and beyond that to the subscription queue. We then contract for that availability.

When we went to the subscription queue, we started with that 1.0 to 1.2 gigawatt offering and continued conversations with counterparties on their interest—whether one counterparty or multiple. That also opens the door for other counterparties that may have access to key equipment to add additional capacity. The premise is: first, we create the opportunity to add incremental infrastructure above and beyond organic load requirements; then we offer that to the queue, engage in negotiations, finalize awarded capacity, and then repeat the process with new infrastructure opportunities we create for future availability.

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

Travis Miller: Hello, everyone. Thank you. Question on the transmission side: the revenue and earnings contribution for this quarter, and thinking about the year and future years—was there anything in the quarter that made this uniquely large, or is this the type of trajectory we should see again this year and then following along the upward-sloping line of transmission investment?

Andrew D. Cooper: As mentioned in the prepared remarks, our transmission investment has continued to increase to serve growing load. If you go back five years, we have doubled and then doubled again the amount we are spending annually in terms of transmission CapEx. For our system, that starts down at 69 kV, so it is a substantial amount of local-area infrastructure as well. What you are seeing—also reflected in last year’s results—is a continued step function upward in the results of the transmission investments we have been making.

It takes time for that investment to show through to the bottom line, and that is what you are beginning to see year over year as we engage in more and larger projects, and that will continue upward. It also shows the benefit of a formula rate—having gradual increases and contemporaneous recovery to reduce lag. It is also a rate that allows us to pass back wholesale revenue to our retail customers and has kept some transmission rate increases pretty stable over the years, producing the right results for customers as we continue to grow.

Travis Miller: On those transmission earnings, how weather sensitive are those? Or are those completely decoupled through the formula rate?

Andrew D. Cooper: It is trued up and intended to earn our return on those investments.

Theodore N. Geisler: Keep in mind it has a balancing account, and a meaningful amount of that transmission revenue is also paid by wholesale customers, which offsets the cost to retail customers. It has an annual true-up. The transmission driver is really more a reflection of our growing capital investments within the transmission system to support reliability and growth than it is weather or any other factor.

Andrew D. Cooper: What you are seeing right now is the impact of the rates we put into effect in the middle of last year, and there will be new rates that go into effect in 2026. The quarter is consistent with the full-year guidance we gave for the transmission segment.

Travis Miller: One high-level on the renewable energy standard repeal—any impact? Your thoughts on that process?

Theodore N. Geisler: No impact expected. The Commission took a logical approach: the utility is already exceeding the original goals set forth in that renewable energy standard, driven by general market interest and demand, as well as the amount of growth that has spurred significant investment in utility-scale solar and battery storage projects across the service territory to date. Having an outdated policy standard that we are already exceeding did not make much sense. From here, we view it to be market driven. On updates to the demand-side management energy efficiency standard, this was an opportunity for the Commission to review which programs have the greatest value and impact for customers and which have less.

We think they appropriately right-sized programs to focus on those with the greatest value while also passing on roughly a 1% rate decrease to all customers. It preserves the value of these programs while creating an affordability opportunity.

Operator: 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.