Pinnacle West (PNW) Q4 2025 Earnings Transcript

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DATE

Wednesday, February 25, 2026 at 11 a.m. ET

CALL PARTICIPANTS

• Chairman, President, and Chief Executive Officer — Ted Geisler
• Executive Vice President and Chief Financial Officer — Andrew Cooper

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TAKEAWAYS

• Q4 Earnings Per Share (EPS) -- $0.13 compared to a $0.06 loss in the prior year, driven by O&M efficiencies and robust sales growth, partially offset by unfavorable weather and increased financing and pension expenses.
• Full-Year EPS -- $5.05, down from $5.24, reflecting a $0.71 negative impact from weather, with underlying business growth offsetting additional headwinds.
• Weather-Normalized Sales Growth -- 6.8% in Q4 and 5% for the year, with 2% residential and 7.5% commercial and industrial segments, attributed to economic expansion in the service territory.
• Customer Growth -- 2.4%, reaching the upper end of the company's guidance range, and marking a historically high level of new meter installations.
• 2026 EPS Guidance -- Reaffirmed at $4.55 to $4.75, with no adjustments announced on the call.
• 2026 Weather-Normalized Sales Growth Guidance -- Maintained at 4%-6%, with extra high load factor commercial and industrial customers projected to contribute 3%-5%.
• Long-Term Sales Growth Guidance -- Reiterated at 5%-7% annually through 2030 based on committed projects and observed economic drivers.
• Operational Execution -- Achieved a 3.3% decline in O&M per megawatt-hour year over year, with further reductions planned for 2026.
• Rate Base Growth Guidance -- Sustained at 7%-9% through 2028, with ongoing capital investments in reliability and grid expansion.
• Palo Verde Nuclear Plant -- Operated at 100% summertime capacity factor, received a 2025 INPO Excellence Award for operational performance.
• Record System Peak -- APS recorded a system peak of 8,648 megawatts, an increase of more than 400 megawatts over the previous year.
• Capital Program and Financing -- 2026 equity needs "largely de-risked" with nearly $500 million already priced, and revolving borrowing capacity expanded by $550 million through credit facility extension to 2031.
• Holdco Debt -- Year-end 2025 level at 17%, within the targeted mid-teens range; intended to remain modest in 2026.
• Customer Satisfaction -- First quartile nationally for residential overall satisfaction and for utility digital experience; second quartile for business customers measured by Escalon.
• Large Load Customer Growth -- Ongoing TSMC expansions, with "900 additional acres recently acquired for future expansion," and a third fab under construction and fourth in early development.
• Infrastructure Delivery -- Over 400 megawatts of APS-owned resources brought online ahead of schedule, including new gas units at Sundance, Agave battery storage, and Ironwood Solar.
• Regulatory Developments -- Rate case is ongoing, with staff and intervener testimony expected next month and hearings in May; management expressed openness to settlement but currently focuses on the traditional process.
• Integrated Resource Plan (IRP) -- Updated 15-year IRP filing expected by midyear, providing further clarity on required generation and transmission to serve committed and forecasted customer growth.
• DSM Program Adjustments -- Residential demand-side management (DSM) program size reduced following commission review, aligning resources with greatest customer need and program effectiveness.

SUMMARY

Pinnacle West Capital Corporation (NYSE:PNW) reported a year-over-year decrease in full-year EPS primarily due to unfavorable weather impacts offset by business growth and cost discipline. The call highlighted significant customer and load growth, emphasizing the acceleration of large industrial customers, notably within the semiconductor sector, and their effect on long-term sales projections. Management provided details on capital deployment, rate base expansion, and the status of regulatory proceedings including explicit timelines for upcoming filings and hearings. The 2026 equity financing needs were described as "largely de-risked," with additional balance sheet flexibility obtained through expanded credit facilities. No material changes to sales or earnings guidance were introduced during the call, and management stressed ongoing action on cost efficiency, infrastructure investments, and strategic planning via the upcoming integrated resource plan.

• Management described recent regulatory precedent in Arizona—specifically, the adoption of a formula rate for a peer utility—as "generally constructive," while emphasizing differences in risk profile, historical rate cases, and growth characteristics compared to APS.
• Pinnacle West executives stated that the transition to a formula rate could support "a more linear trajectory" for earnings and rate base disclosures once current jurisdictional decisions are finalized.
• The uncommitted large load queue remains incremental to current financial plans, and negotiations via the subscription model are ongoing, with potential for contract filings within the year.
• Residential rates were noted as remaining below the national average, supported by focused affordability and rate modernization initiatives targeting fair allocation from high-load customers.
• Customer financing, federal grants, and alternative non-traditional funding sources were identified as avenues under consideration for future transmission and grid investments beyond the base plan.
• Discontinuation of certain legacy DSM programs generated cost savings for customers and impacted both O&M and gross margin, as those cost recoveries offset each other in reported financials.

INDUSTRY GLOSSARY

• INPO Excellence Award: Recognition from the Institute of Nuclear Power Operations for industry-best nuclear plant safety, reliability, and operational performance.
• O&M per megawatt-hour: Operating and maintenance expenses divided by total megawatt-hours generated or delivered, reflecting efficiency of operations.
• DSM (Demand-Side Management): Utility-led initiatives to manage customer electricity consumption patterns, improve efficiency, or reduce demand during peak periods.
• IRP (Integrated Resource Plan): A long-term utility planning document analyzing expected load growth and identifying generation and transmission assets needed to reliably meet forecasted demand.
• Rate base CAGR: Compound annual growth rate of the utility's net investment in assets approved by regulators for customer rate recovery.
• Holdco debt: Parent or holding company-level debt, typically distinct from operating subsidiary indebtedness.
• Subscription model: A customer-driven approach for contracting and allocating new infrastructure in response to specific, large-scale customer commitments.

Full Conference Call Transcript

Ted Geisler: Thank you, Amanda, and thank you all for joining us today. In 2025, our team demonstrated strong results and made significant progress on our strategic objectives. We served record levels of demand with top quartile reliability, provided customers with top quartile customer experience, and managed our grid expansion plans with discipline. Although we made solid progress in 2025, our efforts are ongoing. We remain committed to executing our strategy. Looking ahead to 2026, we will continue this approach with a particular focus on processing our rate case, executing our grid expansion plans, keeping rates affordable for customers, and finalizing commercial opportunities with new large customers. Turning to operations, I want to recognize the safety execution by our team.

Safety remains our most important priority, and I am proud of our team’s relentless focus on providing safe, reliable service, particularly through the third hottest summer on record. In 2025, APS set a new system peak of 8,648 megawatts on August 7, more than 400 megawatts higher than the prior year. Our generating fleet performed exceptionally well, and Palo Verde operated at 100% summertime capacity factor. Palo Verde remains the largest producing nuclear plant in the United States and recently received a 2025 INPO Excellence Award for achieving the highest levels of safety, reliability, and operational performance. This level of consistency underscores the strength of our team’s operational excellence.

Customer experience remains a key focus, and in 2025, we made meaningful progress toward achieving industry-leading satisfaction. For example, we developed and deployed an AI-powered high bill analyzer to help customers better understand their billing and energy usage and efficiently address ways they can save on their energy bill. These improvements are resonating. We ended the year in top quartile nationally among our peers for residential overall customer satisfaction and in the second quartile for business customers as measured by Escalon. We also ranked in the first quartile nationally in J.D. Power’s utility digital experience study. Our customer base is also becoming increasingly diverse.

Reflecting Arizona’s evolving economy, growth among commercial and industrial customers, including chip manufacturing and data centers, continues to drive strong economic activity across the state. These large load customers continue to accelerate their ramp schedules, as evidenced by our long-term sales growth of 5% to 7% through 2030. The U.S. Department of Commerce and Taiwan recently announced agreements expected to spur at least $250,000,000,000 of additional semiconductor investment in the United States. In Arizona, TSMC continues to expand their footprint, with a second fab moving to full production in 2027, a third fab under construction already, a fourth fab and advanced packaging facility in early development, and 900 additional acres recently acquired for future expansion and growth.

We look forward to working with TSMC and the broader chip manufacturing sector as we expand grid infrastructure to support their rapid growth. At the same time, residential growth remains strong across our service territory. For the second consecutive year, we installed more than 34,000 new meters, the highest level in 20 years. We are ready to meet demand growth, and our strong execution is showing results. We finished over 400 megawatts of APS-owned resources ahead of schedule, including new gas units at Sundance, the Agave battery storage facility, and Ironwood Solar. The Red Hawk gas expansion remains on track for completion in 2028, with ongoing preparations to support additional gas capacity of up to 2 gigawatts commencing in 2030.

In parallel, we are closely monitoring progress of Transwestern Southwest Desert pipeline expansion, which has recently been upsized from 42 to 48 inches due to strong regional demand. These investments are critical to supporting Arizona’s economic and population growth while maintaining strong grid reliability for our customers. Turning to regulatory matters, our rate case remains on track. Staff and intervener testimony is expected next month, with hearings scheduled to begin in May. We value our ongoing collaboration with the commission and stakeholders and continue to work together to support Arizona’s growth, reduce regulatory lag, and ensure appropriate cost allocation so that growth pays for growth.

In closing, 2025 was a strong year of execution by our team, meeting rising demand, investing for our customers, and positioning the company for long-term value creation. Our priorities for the year ahead remain clear: executing our mission to deliver safe, reliable, and affordable service to our customers, invest in baseload generation and transmission to serve growth, and achieve a constructive regulatory outcome that protects customer affordability while reducing regulatory lag. With that, I will turn it over to Andrew to discuss our financial results and outlook going forward.

Andrew Cooper: Thanks, Ted, and thanks again to everyone for joining us today. Earlier this morning, we released our fourth quarter and full-year 2025 financial results. I will walk through our performance for the period, highlight the key drivers, then review our 2026 financial guidance which we initially provided on our third quarter call. Starting with the fourth quarter, we earned $0.13 per share compared with a $0.06 loss in 2024. Fourth quarter results reflect the continued vitality of our service territory, our strong operational execution, and sustained cost management. Key drivers included favorable O&M versus last year, as well as continued robust sales growth. These positives were partially offset by milder-than-normal weather, higher financing costs, and pension and OPEB expenses.

For the full year, we delivered earnings of $5.05 per share, landing in the upper half of our updated guidance range. While this compares to $5.24 per share in 2024, the year-over-year decline was primarily weather-driven, a $0.71 year-over-year drag. The prior year benefited from an extremely hot summer that extended into the fall, whereas 2025 experienced, on average, closer to normal weather. Additional headwinds included financing costs, higher pension and OPEB expense, depreciation and amortization, and O&M. Importantly, these headwinds were largely offset by strong underlying growth in our business. In the fourth quarter, we experienced 6.8% weather-normalized sales growth, driving full-year weather-normalized sales growth of 5%.

This included 2% residential growth and 7.5% commercial and industrial growth for the year, reflecting continued economic expansion across our service territory. In addition, customer growth remains a durable multiyear trend. In 2025, total customer growth was 2.4%, at the high end of our guidance range, as new businesses and new residents continue to decide to call Arizona home. This consistent, diversified customer and load growth provides a strong foundation for our long-term outlook. Looking ahead, we are reiterating all aspects of 2026 guidance provided on our third quarter 2025 call, including our annual earnings range of $4.55 to $4.75 per share.

Our weather-normalized sales growth guidance for 2026 remains unchanged at 4% to 6%, with extra high load factor C&I customers expected to contribute 3% to 5% of that growth. Our longer term sales growth guidance also remains unchanged at 5% to 7% through 2030, recognizing the robust growth in our service territory. We continue to be laser focused on cost efficiencies and our goal of declining O&M per megawatt-hour. In 2025, we successfully achieved a 3.3% year-over-year decrease and expect to further reduce our O&M per megawatt-hour in 2026. Cost management is a priority, and we will continue to strive for operational excellence and efficiency through our lean culture and initiatives. We are also reaffirming our capital and financing plans.

Our capital program remains firmly focused on reliability, grid resiliency, and meeting the growing needs of our customers. Consistent with that strategy, our rate base growth guidance remains unchanged at 7% to 9% through 2028. From a financing standpoint, we continue to execute a disciplined, balanced approach aligned with our balance sheet targets. Our capital spending is supported by a thoughtful mix of debt and equity. Importantly, our 2026 equity needs are largely de-risked with nearly $500 million already priced. We have also diligently focused on expanding our liquidity to ensure we can most effectively take advantage of financing opportunities throughout the year as our capital investment program continues to grow.

To that end, we recently closed on the extension of our core credit facilities to 2031 and an expansion of revolving borrowing capacity by $550 million. In closing, we delivered solid results in 2025 underpinned by strong execution and durable growth. We are excited about the opportunities ahead in 2026 and confident in our ability to execute our financial and operational plan with discipline. We look forward to progressing through our rate case with continued engagement with all stakeholders to support safe, reliable, and affordable service for our customers. This concludes our prepared remarks. I will now turn the call 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 Nick Campanella from Barclays. Your line is live.

Fei She: Hi. Good morning, team. This is Fei for Nick today. Thanks for the update and taking our questions. Just really wanted to touch on the capacity growth, if I can, here. Can you just update us on the latest thinking on the IRP planning, including timing this year? And generally, how should we think about the incremental transmission and gas generation opportunities, I guess, compared to what you disclosed here on Slide 21?

Ted Geisler: Yeah. Hi, Fei. Thanks for joining us. Midyear, we will expect to file an updated 15-year integrated resource plan. So that will be a snapshot of our most recent thinking in terms of load and demand forecast and the resource plan to be able to meet that. Of course, the near term in the action plan window, it will be a bit more specific with respect to technology resources and locations. And then when you get beyond that sort of near-term five-year window, then it is more directional in nature.

But the key is it will continue to show the robust, strong growth over the long term and the amount of generation and transmission needed to be able to serve this growth. Of course, our capital plan right now only goes out through 2028, and so a lot of the growth to support TSMC’s build-out, as well as data center ramping, goes beyond that period, and the resource plan should be able to indicate the amount of generation still needed to be able to serve even what we have already committed to.

But then above and beyond that, we are still negotiating to be able to serve incremental data center demand from our subscription queue, which we talked about last quarter. That is not in the capital plan, and to the extent that we are able to secure an agreement for incremental load to be able to serve a portion of that queue, that would be resources that would need to be built above and beyond what we have talked about. And then in addition to that, any further expansion for TSMC would also need to be considered and would drive further generation or transmission expansion beyond what we have shown in the three-year window within the current capital forecast.

Fei She: Great. That is super clear. Thanks for that. And the holdco debt percentage of total debt, can you discuss the cadence to reach that mid-teens level target and where your 2025 year-end metric landed?

Andrew Cooper: Sure, Fei. It is Andrew. Yeah. We are committed to keeping our holdco debt at a judicious level and that mid-teens level. I believe if you calculated it at year end, it was at 17%, so kind of within the range that we are targeting. And as you look at the financing plan for 2026, the holdco debt levels are intended to be quite modest and stay within that bandwidth.

Fei She: Great. Thanks for all the update. I will leave it there. Thanks.

Operator: Thank you. Your next question is coming from Shahriar Pourreza from Wells Fargo. Your line is live.

Alex (for Shahriar Pourreza): Hey, good morning, everyone. It is actually Alex on for Shar. Thanks for taking our questions. So just on the future sales growth of the 5% to 7% annually over the next five years, can you just remind us how sticky that number is over the long term? And also, what are you assuming in your forecast? Is that just sort of the minimum take agreements you have in your large load contracts? So if you were to sort of take it this way, you know, if customers sort of ramp faster and take more power on over time, would that be accretive, an opportunity to that 5% to 7% forecast? Thanks.

Ted Geisler: Yeah, Alex. I think the way to think about that is that load forecast is based on existing demand that we have certainty in being developed or already in service within the service territory that we expect to grow, as well as projects that are already in development or under construction. Therefore, there is upside to the extent that there is anything incremental added to that from either our uncommitted queue, further TSMC expansion, or other projects that have not been announced yet. But the growth forecast that we have outlined is really based on projects that we have a high degree of confidence and certainty in developing, and we track that very closely.

Andrew Cooper: And just to add to that, Alex, the cadence of that committed queue that we have got in our sales forecast goes through into the 2030s. So while we have given you the 5% to 7% through 2030, the full build-out of that existing capacity does have a runway beyond that. And we should also keep in mind that ramp and the cadence now and 2030 is borne out of kind of our experience with these customers over the last several years and represents a pretty educated view of what that ramp looks like over the next several years.

Alex (for Shahriar Pourreza): Got it. That is helpful. Thank you. And just on the EPS and the rate base CAGR you have out there. So as you sort of just look out to 2027 and beyond, how should we be thinking about the delta between the two? Is sort of the 200 points the right figure? Or could you see those two converge over time just given the amount of opportunities you are seeing? Thanks.

Andrew Cooper: Yes, Alex. For sure, as we get out through the rate case, I think we will be looking at both the capital plan itself and what makes the financing plan and, therefore, what our EPS trajectory looks like. And so if you think about the rate base CAGR that is going through 2028 right now, and we roll that forward in the third quarter call, really just beginning to see the impact of some of the projects that are in our long-lead kind of execution window. You heard Ted talk about Red Hawk on the call. It is a good example. A lot of the transmission projects in our strategic transmission plan also represent that.

And so as we continue to consider how to provide more transparency for longer around the capital plan and what that means for the rate base CAGR, that will then trickle through the rate case and around a formula rate that allows us more prompt recovery, to give you more detail on what that means for financing and ultimately for the trajectory of our EPS. But, ultimately, our goal remains to create a more linear trajectory there borne out of the formula rate.

Alex (for Shahriar Pourreza): Great. Leave it there. Thank you.

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

Julien Dumoulin-Smith: Hey. Good morning, team. Nicely done. Thank you for the time. Appreciate it. Good morning, team. Just wanted to talk quickly implications from the UNS case of late, especially the formula rate decision being set. Any thoughts, reactions on your front in terms of read-throughs? Any two or three critical points that you would flag here as a read to APS? Again, I know it is delicate; it is a comment here, but I want to make sure we are all aligned on the same reads here, if you can comment, both on the concept of formula as well as the fair value piece.

Ted Geisler: Yeah. Of course, Julien. No. Fair question. Look, I think the headline from our read was it was generally constructive. But there are material differences between the situation for the UNS gas case and then APS. I will just step through a few points on how we think about it. First, they got about 86% of their original revenue requirement ask, which results in over a 14% rate increase. That is pretty healthy. They got a formula rate with a post-test year plan. The commission rightfully recognized that through all the good work at the workshops last year, there is no need for a pilot. So it is a secure formula rate for perpetuity.

And they have an ROE similar to their current. That said, we do disagree with the notion that you should have an ROE reduced at all as a result of the formula rate, and we will continue to make that argument. But they still got a fairly healthy ROE consistent with what they have had before plus the formula rate. But you have to recognize some of the differences. It is a gas utility in an area that does not experience near as much growth as what we are seeing, 16 years since the last rate case filing, so a little bit difficult to make the argument that regulatory lag is impacting our ability to fund growth like we see.

They certainly have a different risk profile, and the formula rate schedule was a little different than what we are proposing or would expect to work with the commission on securing. But what was proposed worked for UNS. They agreed to it, and maybe that works for their service territory. So, again, I think the headline is generally constructive. It secures the first formula rate within the state and shows the direction that the state is heading, which is great. But there are some differences between our service territories that we will continue to advocate for.

Julien Dumoulin-Smith: Yep. Absolutely. Thank you for that. Appreciate it. And then just if I can keep going here, in as much as you guys have this interesting 20 gigawatts of uncommitted load, the 4.5 of committed, relative to the 25 system peak. So just incredible backdrop. With that said, can you comment and reconcile a little bit against the IRP? I know it is coming midyear. I get that we are trying to jump ahead of that a little bit. But just trying to, like, decompose, especially the 4.5 committed, against what is already in the forecast or even beyond the core forecast. But what would be incremental in that IRP?

You know, again, it is all kind of coming back to an eventual roll forward of your plan as well as, like, what is truly incremental to the plan relative to the current years that you have disclosed. Just trying to zero in. It seems like a material update here.

Ted Geisler: Yeah. Appreciate the question, Julien. The way I would characterize it is the IRP will consider known and committed customer demand. So it will reflect, with a longer range forecast, what we expect the 4.5 gigawatts of committed load to materialize into over the 15-year period, as well as our, I will call it, organic load growth that is above and beyond that 4.5 gigawatts of committed high load factor demand. It will also include our latest thinking in terms of TSMC and the related chip manufacturing schedule for both timing and potential expansion. It will not include any portion of the uncommitted queue that is in negotiation or yet to be contracted.

So that will all still remain incremental demand above and beyond what we show in the IRP. So I guess just summing it up, the IRP will give us the best line of sight for how the 4.5 gigawatts of high load factor demand will materialize over the 15-year period, plus our view on the organic load growth such as residential, etc. And then anything that we contract from the uncommitted queue, which we are actively working on, will be incremental to that even above and beyond what we show in the IRP.

Julien Dumoulin-Smith: Right. Absolutely. And then just to close the loop on that, I mean, where are you in terms of what is in the committed versus uncommitted? I imagine the bulk of the committed is TSMC, but can you break that down a little bit? And maybe even comment a little bit of where you stand on kind of translating further of the uncommitted into the committed bucket. Like, any potential that moves from one bucket into the other prior to that IRP even?

Ted Geisler: Yeah. I would say the majority of that committed is still a healthy amount of high load factor customers that are data centers or related that we have committed to over the past couple years and are actively in build-out or ramping. TSMC is certainly a material portion of that. But the 4.5 gigawatts does not include any potential expansion of TSMC, and we will continue to work with them on their plans for any acceleration or expansion. So that would be above and beyond the 4.5 gigawatts. But as we said in the last quarter, we did bring forward an opportunity to the uncommitted queue to evaluate through our subscription model. Those negotiations are ongoing.

To the extent that is finalized ahead of the IRP, it may be included, but there is a likelihood that it would be incremental to the IRP. We would aim to be able to file an agreement with our commission for any successful negotiations of that subscription model this year.

Julien Dumoulin-Smith: Yeah. No. Good reminders, and thank you. Alright. I will leave it there. Thanks again. All the best. Alright. Speak to you soon.

Ted Geisler: Thank you.

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

Paul Patterson: Hey. Good morning.

Ted Geisler: Morning, Paul.

Paul Patterson: So just I know, you know, we have got staff and intervener testimony coming up here, but I am wondering, given all the discussions sort of happening there in Arizona and what have you, is there were there any thoughts about maybe, and given the fact that we have gotten out the ROE from the formula stuff from UNS, what are your any thoughts about maybe potentially a settlement on the case? I mean, I know, as I said, we have staff coming up and interveners, but just want any thoughts about that. Has there been any thought about that or discussion with that?

Ted Geisler: Yeah, Paul. Appreciate the question. I would say at this point, we are focused on processing the case in the traditional manner. We always remain open to settlements, and the company actually has a long track record of successful settlements in this jurisdiction. But this case has some unique aspects to it. One is making sure that we align on the mechanics of implementing the formula rate. And two is the importance of getting the rate design changes agreed to for the new high load factor tariff. And those would be well served in the traditional hearing process.

We demonstrated successfully the ability to achieve a constructive outcome in the last rate case through the hearing process, and so we think that is a viable path for us to once again achieve a constructive outcome. So at this point, we are focused on the traditional format. We always remain open to settlement, but that is not something I would count on for this case.

Paul Patterson: Okay. Fair enough. And then just finally, there was a nuke conference yesterday, or hearing, what have you, at the commission, and I was not able to listen to a lot of it, frankly. But it sounded like there is a lot of kind of excitement for, you know, in the context of utilities, in terms of this resource, and, you know, I was just wondering if that you guys, you know, with any thoughts about what the, if there is anything in the near term that we might see on that? Or just any thoughts on that?

Ted Geisler: Yeah, Paul. I mean, we are fortunate that the broader community, policymakers, and community leaders remain very supportive for nuclear. Obviously, that is important to us given the fact that we operate the largest producing nuclear plant in the country today. But there is also a lot of interest in whether there is an opportunity for new nuclear in Arizona going forward.

We have been very clear with stakeholders and our customers that while we remain constructively supportive of new nuclear for our country and potentially Arizona in the future, that is not something that you would expect in the near term, but it is something that we want to pay close attention to and work collaboratively with stakeholders to identify what those opportunities could look like over the medium and long term for our state. And so that is a big part of what the workshop was about yesterday, and we really appreciate the commission taking time to learn and explore what these opportunities could be. It is great dialogue.

But we have been very clear that there is a lot of capital required, you need constructive policy, and, importantly, you need the supply chain and the trades to be able to have the capacity to be able to build out these projects. So we are actively involved in the industry. We are actively involved in the state in supporting what new nuclear could look like in the future, but we view that as more of a medium and long-term opportunity.

Paul Patterson: Awesome. Thanks so much, guys.

Ted Geisler: Thanks, Paul.

Operator: Thank you. Your next question is coming from Stephen D’Ambrisi from RBC Capital Markets. Your line is live.

Stephen D’Ambrisi: Hey, Ted and Andrew. Thanks for taking my question. A quick one. On Slide 20 on the sales growth, I mean, I think the first bullet says it all, nine consecutive quarters of growth exceeding the guidance range. And just obviously, 4Q looks like it is accelerating. Maybe there is some, you know, art versus science of weather normalization in a weak weather quarter. But can you just talk a little bit what the sales growth trend looks like versus kind of the 4% to 6% 2026 sales growth that you have given in the long-term guidance as well?

Andrew Cooper: Sure, Steve. It is Andrew. We have continued to see very diversified and very consistent sales growth. For the year, residential came in at really the top end of where we have ever forecasted because that 4% to 6% that we have forecasted for last year and we forecast for this year represents largely the ramp-up of our extra high load customers. So to see that level of residential growth driven by nearly 2.5% customer growth remains strong. What we expect in 2026 is kind of a reversion to the normal dynamics where the ramp-up of the extra high load factor customers is the dominant part of the sales mix.

But one of the tailwinds that we have seen that we will just have to continue to monitor in 2026, distributed generation produced pretty small offsets to residential sales. That is right. I think that is what drove it to the upside and kind of continued to drive that tailwind into Q4 of last year. And so we will just have to continue to monitor as those reductions in applications we are seeing for new rooftop installations translate potentially into support for our residential sales growth numbers. But in the near term, 2026 is driven by the known customers in that queue that we see ramping and see coming online, including, as the fabs of TSMC continue to move ahead.

And then over the longer term, through 2030, that step up is really related to, again, those known customers and where we expect them to be in their ramps. And, having worked with the data centers for a long time, I think our forecasting has gained a good balance of understanding where these customers are, what the intent of their facilities are, how that drives those ramp rates year to year. But, fundamentally, the runway that we have with these customers combined with the semiconductor space and then the residential growth gives us pretty strong confidence in those numbers through the end of the decade.

Stephen D’Ambrisi: Okay. That is helpful. And just, I do not know if you do, do you have a sensitivity or rule of thumb on, like, the extent, I know you are guiding back down to the normal average for resi customer growth, but to the extent it is back at the top end and outperforms by 50 basis points or 100 basis points, like, what that means for, like, an EPS sensitivity?

Andrew Cooper: Yes. On a gross margin basis, we typically say that 1% of residential growth is somewhere north of $25 million, whereas 1% related to extra high load factor could be more in the $5 million to $10 million range. So that is kind of the distinction of, of course, all of it gives us operating leverage as we continue to focus on reducing our costs across the system. But that is the rule of thumb that we think about in terms of residential hours just being more clustered around the peak and the ex-HLF, of course, delivering 90-plus percent load factors across peak and off-peak hours.

Stephen D’Ambrisi: Okay. Very helpful. Thanks very much, guys. Appreciate it.

Ted Geisler: Thank you.

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

Ryan Levine: Good morning. Any color you could share around the pace of the large load commitments in the uncommitted bucket that you are considering to be ready for? I mean, do you think this should all come together, a lot of these large customers, around the same time, or kind of how do you manage the cadence of potential movement from the uncommitted to the committed bucket?

Ted Geisler: Yeah, Ryan, the way we are treating that is as we identify infrastructure and projects to be able to offer to that uncommitted queue at a volume that is worthy of gaining their interest, so call it a gigawatt or more roughly, then we will offer that to the uncommitted queue, generate or gauge interest based on the location and the timing of that infrastructure and ultimately work with counterparties on the best fit for that infrastructure opportunity and negotiate an agreement.

We made our first offer through the subscription model in the latter part of last year, and as a result, we are actively in discussions right now with those counterparties that are interested with the intent to try to finalize an agreement and file it with the commission this year. And then in parallel to that, we are working on a pipeline of generation and transmission infrastructure projects that would create incremental capacity that could then go back and be offered to that uncommitted queue. So we would expect that to be on somewhat of a repeatable basis going forward.

Again, as mentioned before, I think when Julien was asking the question, all of that for uncommitted demand would be incremental to the current plan. We wait until we have a secured contract with a definitive project before we add it to the plan, both from a capital and rate base standpoint. And then the load growth associated with those uncommitted projects would also be incremental to the plan. So we are actively working on that now. But, importantly, want to make sure that we identify the infrastructure capacity first and do this prudently. And then secondly, it will be important in parallel to work with our commission on modernizing the rates to ensure that growth pays for growth.

Ryan Levine: Great. And then is the company looking to finance some of the transmission build-out with the DOE energy dominance financing as we have seen with some of your peers around the country? And how are you thinking about the transmission funding source?

Andrew Cooper: Yes, Ryan, it is Andrew. We will look at all sources for the CapEx plan. In particular, we are interested in looking at sources of capital that are outside the traditional. I think it starts with our customers and ensuring that as part of this growth-pays-for-growth conception that they are putting capital to work given the size of some of their balance sheets and the urgency with which they want to come online. So, looking at customer financing, certainly looking at any financing alternatives out there. And so we will continue to evaluate grants and other opportunities that come out of the federal government as well as we go along.

But, fundamentally, the financing plan you see is our base plan today, which really allows us to rely on traditional funding sources. But certainly, as we look at some of these large projects and more on a temporal basis, looking at doing a bunch of large stuff at once, we will look at all kinds of alternatives to take it off balance sheet during construction. I think it really starts with ensuring that we are aligned with our customers and, through the subscription model, to the extent that we can get capital upfront from our customers to buy down their price over time, that helps us as well from a balance sheet perspective.

Ryan Levine: Thank you.

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

Anthony Crowdell: Hey, good morning, Andrew. I am sure you are missing New York City with the snow we just got. Just two quick questions. One is, where did you end the year on an FFO-to-debt basis? And will you be at 14% to 16% throughout the entire forecast period? And I have one follow-up.

Andrew Cooper: Yeah. So, you know, Moody’s is really the limiting, given their downgrade threshold is 14%. So we really focus there. And we were north of 14%. We will not get their official calculations until Q1, but if you do it on the basis as we understand it, we are high 14s from a Moody’s perspective. So feel good about that. Our aspirational goal is to ensure that we are always maintaining 100 basis points of cushion. If you look at the regulatory lag that we are going to continue to go through in 2026, I think it really points to why the dialogue we are having in the rate case is so important.

The FFO to debt, the further you get away from any rate relief, it starts to come under some pressure. And so, while we know that the rating agencies do not take a short-term perspective, and we have maintained pretty consistent dialogue with them about the improvements that we are seeing and the potential for cost recovery, particularly through the formula, if you look at our running trajectory in 2026 versus 2025, that is all regulatory-lag related, and that should translate into the top line. On an FFO-to-debt numerator perspective as well.

Ultimately, I think our goal is to grow that numerator, and that will go a long way to shore up the credit metrics and allow us to deliver that 14% to 16% for the long term with sufficient cushion within that range.

Anthony Crowdell: Great. And then I think, Ted, it was to earlier one of the earlier on transparency. You hope to get earnings, I believe, once the formula rate plan is in effect. You started talking about maybe more linear or more linearity with the earnings. Is it you hope with the formula rate plan, once it gets passed and enacted, that we get a more linear trajectory of earnings, a longer trajectory of earnings, or both?

Ted Geisler: Yeah, Anthony. I think we fully recognize that a more standard disclosure would be able to match earnings, rate base, and capital plan out to that five-year mark. And so we would like to be able to give longer visibility and also include within that a more consistent linear trajectory. But given the current construct within our jurisdiction, of the lumpy nature of these rate cases, that has just been challenging to do while maintaining precision with that forecast. And so we will take the opportunity once this case is processed to be able to step back and reflect on the best set of disclosures we can develop and release.

And our aim would be to be more consistent with our peers in that regard. So once we conclude the case, we will prepare a new set of disclosures and forecasts, and our goal would be to be able to provide that in a longer term and be able to achieve more linearity as a result of the more regular nature in which the formula will work.

Anthony Crowdell: Great. Thanks for taking my questions.

Ted Geisler: Thanks, Anthony.

Operator: Thank you. And once again, everyone, if you have any questions or comments, please press star then 1 on your phone. Your next question is coming from Chris Ellinghaus from Siebert Williams Shenk. Your line is live.

Chris Ellinghaus: Hey. Good morning, everybody. Just a follow-up. I was thinking the same thing about the disclosure and, you know, how formula rates will change that. But just to be clear, you know, is it just the formula rates being effective, or do you also need to have some greater clarity on, say, you know, what is in the committed queue as well as having some better sense of where TSMC is going with their next expansions to give you, you know, adequate data to do that sort of extension?

Ted Geisler: Yeah, Chris. The way we think about it is it really is almost entirely about the timing consistency of cost recovery. We have got a pretty good view of our committed demand, and it is robust. But due to the substantial regulatory lag in the jurisdiction, the ability to consistently, on a linear basis, translate that top-line growth into bottom-line growth is challenged by the lumpy nature of our rate case process. When you evolve to a formula rate, you have got more steady, gradual rate changes for our customers, and it also allows us to have a bit more of a predictable and consistent recovery method to be able to recover those costs.

And that is really the biggest change.

Chris Ellinghaus: Okay. Sure. Andrew, in terms of looking at particularly the res DSM component of O&M, how should we think about that going forward relative to where you are for 2026?

Andrew Cooper: Yeah. So I think the most important thing to keep in mind, Chris, is that those are regulatory programs that we recover through rates. And so they basically show up in both our gross margin number, and then they show up offsetting nearly dollar for dollar on the O&M side. At the end of last year, the commission determined to discontinue some of those regulatory programs, and so the size of the overall DSM program condensed. And so you have seen that condensing both on the gross margin side and on the O&M side.

And so, while there is a great overall story around our O&M cost management as a company, when you look at our waterfalls from 2025 to 2026, a considerable portion of that O&M-related benefit is tied directly to an offsetting decrease in revenue received on the gross margin side, that ResDSM/PSA/chemicals line item.

Chris Ellinghaus: Yeah. I understand that there is an offset, but what I am trying to figure out is, sort of given the cost pressures, particularly for residential, you know, sort of across the board, do you think that their appetite for those programs is permanently reduced, or do you think there could be some return to those programs given just sort of cost of living pressures for consumers?

Ted Geisler: Yeah. Chris, this is Ted. I guess the way I would look at it is I think the commission and staff really took a thoughtful approach to reviewing all the programs and saying which of those programs have the greatest positive impact for the customers that need them the most, and let us focus the funding on those programs while retiring the programs that are a bit legacy in nature, that have less effectiveness, and may not be worth the investment any longer. A lot of those programs have been in place for many years. They did a lot of good work. But they also started to reach a saturation point.

And so, really, the programs that are remaining are the ones that benefit the customers that need it the most and have the greatest impact. And I think this commission is focused on just continuously reviewing those programs to ensure that they are using the dollars wisely and they are maximizing impact for the investment made. The commission is also very focused on affordability. They recognize the need to allow utilities to recover costs as a result of inflation, as a result of the investments needed to secure a reliable grid due to growth, but in parallel, look for any opportunity possible to be able to reduce cost per customers.

And the right-sizing of the DSM plan resulted in a meaningful savings to all our customers. But just to echo what Andrew said, we need to do our part as well, which is why we are going on three years now of flat to declining O&M, declining O&M per kilowatt-hour. We continue to be focused on modernizing the rates in this rate case to ensure that the extra high load factor customers are paying their fair share of growth, which has a net benefit to residential customers. And we remain competitive from a rate standpoint where residential rates are below the national average, and do everything we can to be able to keep them affordable.

Chris Ellinghaus: That helps. Thanks, Ted. Lastly, the additional TSMC expansions, how much vision do you have into them at this point? And when do you have to have, you know, more perfect clarity on what that is going to look like for you?

Ted Geisler: TSMC is a very important customer, obviously, with substantial build-out ongoing. And so we are in active discussions with them on both the timing of the fabs that they have announced and committed to as well as any potential expansion that they may have. So when they are ready to solidify their plans, then we will be ready to align on what that means from a utility infrastructure standpoint.

Chris Ellinghaus: Okay. Great. Thanks. Appreciate the details.

Ted Geisler: Thanks, Chris.

Operator: 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.

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