Ladies and gentlemen, welcome to the Dominion Energy First Quarter Earnings Conference Call. I would now like to turn the call over to David McFarland, Vice President, Investor Relations and Treasurer.

Good morning, and thank you for joining today's call. Earnings materials, including today's prepared remarks contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management's estimates and expectations. This morning, we will discuss some measures of our company's performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures, which we can calculate, are contained in the earnings release kit. I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit. Joining today's call are Bob Blue, Chair, President and Chief Executive Officer; Steven Ridge, Executive Vice President and Chief Financial Officer; and Diane Leopold, Executive Vice President and Chief Operating Officer. I will now turn the call over to Steven.

Thank you, David, and good morning, everyone. Our first quarter 2024 operating earnings, as shown on Slide 3, were $0.55 per share, which included $0.06 of headwind from worse-than-normal weather in our utility service areas. Offsets to weather included modest interest savings driven by an earlier-than-budgeted close of the East Ohio Gas Company sale as well as O&M timing. Relative to last year, positive factors for the quarter were higher sales, regulated investment growth and better weather. Recall that we experienced a $0.10 weather headwind in the first quarter last year. So by comparison, a $0.06 weather headwind this quarter is actually a positive year-over-year driver. Other factors include higher interest expense and the revenue reduction at Dominion Energy Virginia related to moving certain riders to base rates. A summary of all drivers for earnings relative to the prior year period is included in Schedule 4 of the earnings release kit. First quarter GAAP results were $0.78 per share, which includes the net benefit from discontinued operations, primarily associated with the sale of gas distribution operations, unrealized noncash net gains on nuclear decommissioning trust funds, and the unrealized noncash mark-to-market impact of economic hedging activities. A summary of all adjustments between operating and reported results is included in Schedule 2 of the earnings release kit. Turning to guidance on Page 4. We are affirming all of the financial guidance we provided at our March 1 Investor Meeting. As such, we continue to expect 2024 operating earnings per share to be between $2.62 and $2.87 with a midpoint of $2.75. As discussed with the March investor meeting, we're no longer providing quarterly earnings guidance. We are, however, replicating in the appendix of today's materials, the expected cadence of earnings across 2024, including anticipated year-over-year drivers by quarter. There haven't been any changes to that guidance from the investor meeting. We continue to expect 2025 operating earnings per share to be between $3.25 and $3.54, inclusive of the impact of RNG 45Z credits with a midpoint of $3.40. We also continue to forecast an operating earnings annual growth rate range of 5% to 7% through 2029, up to a midpoint of $3.30, which excludes the impact of the RNG 45Z credits. As a reminder, authorizing legislation applies to produce RNG volumes in 2025, 2026 and 2027, but sunsets thereafter. For the avoidance of doubt, no changes to any of the other financial guidance we provided on March 1, including credit, dividend and financing guidance. Turning now to a status update on our business review initiatives as shown on Slide 5. During the review, we announced transactions that represent approximately $21 billion of debt reduction. With the closings of the Cove Point and East Ohio gas sales and completion of the DEV fuel securitization, we've now achieved 53% of the targeted debt reduction, representing over $11 billion. With regard to the remaining 47%, we're working methodically towards timely closings for the sales of Questar Gas, Wexpro and Public Service of North Carolina as well as the noncontrolling equity financing for the Coastal Virginia offshore wind project. In all cases, no changes to our original timing expectations. We look forward to continuing to work with involved parties and expect regulatory proceedings to conclude and transaction closings to occur during 2024. For a little more color, in Utah, parties to the merger proceeding agreed to a comprehensive settlement in late March, which was followed by an evidentiary hearing in front of the commission on April 11. In Wyoming, a commission hearing is currently scheduled for May 23. And in North Carolina, a commission hearing is currently scheduled for June 11. As it relates to our announced offshore wind partnership, the transaction requires approvals from the Virginia State Corporation Commission and North Carolina Utilities Commission as well as certain consents from the BOEM and other regulatory agencies. All regulatory filings have now been submitted and procedural schedules have been published in both Virginia and North Carolina. We are excited to have a well-capitalized and experienced financing partner on terms that significantly derisk the project for Dominion Energy customers and shareholders. On credit, the business review resulted in significant quantitative and qualitative improvement to our credit profile. Recent comments by the rating agencies with whom we maintain frequent engagement highlighted the credit positive nature of the business review results. As a result of the review, we have strengthened the company's credit position with an existing consolidated rating categories at each of our three rating agencies. Turning to financing on Slide 6. No changes to the financing plans that we shared at the investor meeting. Specific to 2024, we have normal course long-term debt issuance at DEV in the plan for later this year. We expect to issue between $600 million and $800 million of common equity during 2024, including $200 million through our DRIP program and between $400 million and $600 million via ATM. We view this level of steady common equity issuance as prudent, EPS accretive and in the context of our sizable growth capital spending program, appropriate to keep our consolidated credit metrics within the guidelines for our strong credit ratings category. Our plan includes the ongoing utilization of hybrid securities in our capital structure. We have $700 million of junior subordinated notes that will mature in August. And as a reminder, we expect to issue between $700 million and $1.5 billion of hybrids this year. We expect to structure any new hybrids to qualify for 50% equity treatment from the credit rating agencies. In conclusion, I'll reiterate that I'm highly confident in our ability to deliver on our financial plan. The post review guidance has been built to be appropriately but also not unreasonably conservative to weather unforeseen challenges that may come our way. With that, I'll turn the call over to Bob.

Thanks, Steven, and good morning. I'll begin my remarks by highlighting our safety performance. As shown on Slide 7, our employee OSHA injury recordable rate for the first three months of the year was 0.32, a significant improvement relative to an already strong historical performance. I commend my colleagues for their consistent focus on employee safety, which is our first core value. On March 1, we announced the results of our comprehensive business review. We thank all those who were able to participate and provide feedback following the event. Please note that those meeting materials, including the webcast replay, continue to be available on our website, and we encourage all to review thoroughly. Throughout the review, I met extensively and directly with many of our shareholders to better understand their perspectives on our company's fundamental opportunities and challenges as well as changes they wanted to see affected as a result of the review. Since the conclusion of the review, I've continued that deliberate campaign of investor engagement, and I'd like to share what I believe represents by and large, the consensus among those shareholders. First, we delivered a truly comprehensive result. This was not a partway review. Instead, we fully addressed head-on, the challenges that our company has faced in the past. Second, recognition that we've taken significant steps to enhance transparency, and that we have developed a financial plan that is more durable and more appropriately conservative than in the past. Third, acknowledgment of material changes to my compensation structure, full details of which are now available in our proxy statement and our governance more generally, that demonstrate a strong commitment to shareholder alignment. And finally, and perhaps most importantly, a clear expectation that the company must be 100% committed to executing and delivering on the operational and financial guidance we have provided. On that last point, we are unwavering. Let me repeat what I have said before. I am accountable for, and my entire leadership team has embraced our commitment to execute and deliver. I am very excited for the next chapter of our company. With that, let me provide a few updates on the execution of our plan. Turning to offshore wind, I'd like to start with a few remarks related to inaccurate news releases circulating yesterday regarding the status of our project. There has been no delay ordered. Our construction schedule has not been altered. We expect to begin monopile installation between May 6 and May 8. On April 29, a motion was filed in the U.S. District Court for the D.C. circuit, requesting a preliminary injunction in connection with a complaint filed related to the administrative process for certain permits and approvals received. The judge has not ruled on the preliminary injunction motion and in fact, has issued no orders other than the following schedule. We'll file a status report tomorrow regarding the various mitigation plans being finalized with BOEM and other agencies prior to beginning monopile installation and provide the estimated date for such installation work to begin. We and the government will file our brief in response to the plaintiff's motion on Monday. Plaintiffs have until May 9 to file any reply. The biological opinion was thorough and complied with all legal requirements, which is true of all other permitting actions for this project. Similar arguments to those made by the plaintiffs in this case have been rejected by courts when raised with respect to other projects. Most recently, by the U.S. Court of Appeals for the first circuit just last week and the challenge brought against the permit for Vineyard Wind. We believe this lawsuit has no merit and we expect the court to deny the plaintiff's request for a preliminary injunction. Let me just reiterate. The project is proceeding on time and on budget, consistent with the timelines and estimates previously provided. As shown on Slide 8, last month, the project received its 11th and final federal permit. Our materials and equipment were on track and making excellent progress. We've received 36 monopiles from our supplier, EEW at the Portsmouth Marine Terminal representing 20% of the total. We expect deliveries to continue steadily in the coming weeks. These monopiles will begin to be installed next week. DEME will use their heavy lift crane vessel, Orion, which is currently at the Portsmouth Marine Terminal in Virginia. Recall that we've scheduled monopile installation across two seasons, 2024 and 2025, which allows us to better mitigate any potential delays or disruptions without impacting final schedule. The first of three offshore substation topside structures have been completed and delivered to CSWind/SEMco to be outfitted. The first six transition pieces have been loaded and are on their way to Virginia and expected to arrive in late May. All 161 miles of onshore underground cable has been manufactured, and over one-third of the 600 miles of offshore cable has been produced. Scheduled for the manufacturing of our turbines remains on track. It's worth noting that even though we won't begin turbine installation until 2025 per our schedule, DEME recently finished supporting an installation campaign for Moray West, a project off the coast of Scotland that has now successfully installed the same Siemens Gamesa wind turbine model that CVOW will use. The lessons learned from that project will benefit our project installation in the future. Moving onshore. Construction activities remain on track, including civil work, horizontal directional drills, and the boards where the export cables come ashore. On regulatory, last November, we made our 2023 rider filing, representing $486 million of annual revenue. The hearing is scheduled for later this month, and we expect the final order by August. Turning to Slide 9. As reflected in our standard status report filed with the SEC yesterday, we've updated the project's expected LCOE to be $73 per megawatt-hour, down modestly relative to our last update. The drivers for the lower LCOE include about $1.5 related to an updated REC price forecast, which produces a larger project benefit for customers, as well as other factors. There have been no changes to the capital cost, capacity factor, or interest rates. We've again provided sensitivities to show how the average lifetime cost to our customers is affected by these key assumptions. We remain well below the legislative prudency cap on this metric, and I would point out well below the PPA prices being considered in other parts of the country. Project to date, we've invested approximately $3.5 billion and remain on target to spend approximately $6 billion by year-end 2024. 93% of project costs are now fixed. We'll gradually increase that percentage over the remainder of the project construction timeline. I'm very pleased that per the filing, current unused contingency of $284 million is equal to the original contingency filed in November 2021, despite being some 30 months further along with the project. Slightly lower contingency relative to our prior update is not unexpected, and changes of this kind are considered normal as we move further towards project completion. The current contingency level continues to benchmark competitively as a percentage of total budgeted costs when compared to other large infrastructure projects we've studied and ones that we've completed in the past. We've been very clear with our team and with our suppliers and partners the delivery of an on-budget project is the expectation. Lastly, the project is currently 28% complete and we've highlighted remaining project major milestones on Slide 10. Let me now provide a few updates on Charybdis, as shown on Slide 11. The vessel is currently 85% complete, up from 82% as of our last update. Last month, we announced that Charybdis was successfully launched from land to water, marking a major milestone in the vessel's construction. To achieve this milestone, welding of the ship's hull and commissioning of the vessel's four legs and related jacking system were successfully completed. I encourage you to access the short video of this successful launch included in today's materials. There's no change to the expected delivery timeframe of late 2024 or early 2025, which will be marked by the successful completion of sea trials. There's also no change to the vessel's expected availability to support the current CVOW construction schedule. In April, we agreed to terminate a charter agreement under which Charybdis would have serviced a third party until returning to CVOW in the second half of 2025 to begin turbine installation. As a result of the mutually agreed termination, CVOW currently has exclusive access to the vessel in 2025, and we're exploring options to further derisk the project's timeline by potentially accelerating its deployment to CVOW. The termination does not have a meaningful impact on our financial plan, earnings, cash or credit, and there's no change to our financial guidance as a result. Finally, there is no change to the project's current estimated cost of $625 million. Charybdis is vital, not only to CVOW, but also to the growth of the offshore wind industry along the U.S. East Coast, and is key to the continued development of a domestic supply chain by providing a homegrown solution for the installation of offshore wind turbines. We continue to see strong interest and use of the vessel after the CVOW project is complete. Turning to Slide 13, let me address affordability as well as provide a few regulatory updates. At DEV, current rates are approximately 14% below the national average. Yesterday, we made several filings related to fuel and transmission riders that would result in a net bill reduction for a typical residential customer of roughly 3%. At DESC, our recently approved fuel cost settlement related filings reduced customer bills by over $13 a month. Current residential rates are now approximately 18% below the national average. And in March, we initiated an electric general rate case representing the first filing in the past four years during which time we've invested $1.6 billion in our system to the benefit of our customers. We expect new rates based on a typical procedural schedule to be effective in September. Being very focused on affordability allows us to ensure customers are getting compelling value, coupled with high reliability. Turning to Slide 14 and the growth outlook in Virginia, let me share a few thoughts on, first, our customers' needs; second, what's being done to support them; and third, the impact to our long-term financial plan. First, customers' needs. We're ramping into the very substantial and growing multi-decade utility investment required to address resiliency and decarbonization public policy goals, plus the very robust demand growth we're observing in real-time across our system. DEV's weather-normal year-over-year sales growth rate through March was 4.8%, precisely in line with our full year 2024 growth rate expectation of 4.5% to 5.5%, driven by economic growth, electrification, and accelerating data center expansion. The data center industry has grown substantially in Northern Virginia in recent years. In aggregate, we've connected 94 data centers with over 4 gigawatts of capacity over the last approximately 5 years. We expect to connect an additional 15 data centers in 2024. Northern Virginia leads the world in data center markets. In recent years, this growth has accelerated in orders of magnitude, driven by the number of data centers requesting to be connected to our system; the size of each facility; and the acceleration of each facility's ramp schedule to reach full capacity. For some context, historically, a single data center typically had a demand of 30 megawatts or greater. However, we're now receiving individual requests for demand of 60 to 90 megawatts or greater, and it hasn't stopped there. We get regular requests to support larger data center campuses that include multiple buildings and require total capacity ranging from 300 megawatts to as many as several gigawatts. Last month, PJM released its capacity auction planning parameters. The results align with our analysis of load growth and the need for requisite dispatchable supply resources included in our 2023 IRP. This independent modeling also validates the need to expediently progress the recurring local and PJM regional transmission planning and expansion process and our decision to expedite numerous projects over the last two years. Second, what are we doing today? We will take the steps necessary to ensure our system remains resilient and reliable. We had already accelerated plans for new 500 kV transmission lines and other infrastructure in Northern Virginia, and that remains on track. We've been awarded over 150 electric transmission projects totaling $2.5 billion during the PJM open window last December. We're working expeditiously with PJM, the SCC, local officials, and other stakeholders to fast track these along with several other critical projects. We're committed to pursuing solutions that support our customers and the continued growth of the region. This includes assessing dispatchable generation needs, especially during winter and on-site backup fuel storage. Finally, what's the impact to our financial plan? Our capital plan is driven by demand, reliability, and customer needs. When we consider this demand growth, we think about the full value chain: transmission, distribution, and generation infrastructure investment that has and will continue to drive utility rate base growth. We believe there may be opportunities for incremental regulated capital investment toward the back end of our plan and beyond. As I've said before, we will look at incremental capital through the lenses of customer affordability, system reliability, balance sheet conservatism, and our low-risk profile. Our IRPs take a longer-term view. The 2023 IRP factored in significant load growth and investment in generation and transmission over the next 15 years to meet that load growth while keeping the cumulative average growth in customer bill below 3%. The most recent PJM load projections, along with our work to optimize the best ways to meet this load, will be factored into our planning for this year's IRP. The 2024 IRP will be submitted to the SEC and NCUC in October 2024. We will continue to provide updates as things develop. We remain focused on our core responsibility of safely providing reliable energy to our customers. With that, let me summarize our remarks on Slide 15. Our safety performance this quarter was outstanding, but there's more work to do to drive injuries to zero. We affirmed all financial guidance. Our offshore wind project is on time and on budget. We continue to make the necessary investments to provide the reliable, affordable, and increasingly clean energy that powers our customers every day, and we are 100% focused on execution. We know we must deliver and we will. With that, we're ready to take your questions.

We'll take our first question today from Shar Pourreza at Guggenheim Partners.

Maybe I can start with a two-part question on data centers. Bob, I know you made prior comments in media around self-generation and self-supply. What are you seeing within the pipeline you just discussed as it relates to these two items, which can obviously mitigate some of the load growth you highlight? And secondly, how are you sort of thinking about rate design and tariff changes to make sure Virginia customers benefit or at least are held harmless on things like interconnection costs?

Yes, Shar, both really good questions. I may take them a little bit in reverse order. We've worked with data centers for many years, and we have very strong relationships with them. As you know, Loudoun County is home to the largest data center market in the world. And we have had an opportunity to work with our data center customers for 15 or more years. So with those relationships, we're certainly looking into alternative rate designs and discussing potential structures with them. Obviously, anything that we would do there would need to be approved by the SCC. So nothing specific to offer, but we certainly continue conversations with these customers that we've worked with so well for so long. As behind-the-meter solutions or some sort of self-supply, I suppose there could be some specific situations where that might make sense for some customers. But we think, given their need for reliability and affordability, the majority of those solutions are going to want to access the broader network of system resources that are in front of the meter. And I think it's really important to keep in mind, regardless of the source of generation, substantial transmission investment, which we've noted before. So fundamentally, given our long history with data center customers, we're quite confident in our ability to find solutions that work for them, for other customers and for our shareholders.

Got it. Perfect. And then maybe just touch on resource adequacy for a second and kind of your plans as it relates to the upcoming capacity auction. Are you electing the FRR, which is due by the 17th of this month? And more importantly, just elaborate a bit more on the IRP update and incremental generation spend. Could this kind of be accretive to the plan?

Yes. Again, I'll take the second part first. So as to potential incremental capital, as we said in our prepared remarks, toward the end of the plan, we could certainly see some additional capacity. We described the way data centers are ramping in faster than they have before that their requests are bigger than they've been before. We don't forecast demand based on engineering assessments. We do that based on signed contracts. And then in the later years, customer intelligence, we're pretty confident in our ability to do that. So there may be potentially some upside there as we go out. As I said in our prepared remarks, our investments are going to be driven by policy and customer needs. We'll be very thoughtful about our balance sheet and our business risk profile as we make additional investment decisions. Fundamentally, it's just a very exciting time for the industry, particularly for us, given our experience with data centers. As to PJM as I expect you know, Shar, from 2007 to 2022, we participated in the PJM capacity market through the reliability pricing model. In 2021, we announced we were going to elect FRR because that made the most sense for our customers. Now with PJM's most recent capacity market reforms and assumptions, it makes sense for us to return to the capacity auction starting with the '25, '26 auction. It returns us to the way we did business for many years. It doesn't change guidance. It doesn't change the way we operate our system or the way we think about the world. In fact, all the auction planning parameters released by PJM in April are quite consistent with our view. We're going to see substantial load growth driven by electrification, data centers for the foreseeable future.

We will take our next question from the line of Nick Campanella at Barclays.

I wanted to ask on South Carolina. I think HB 5118 has been kind of progressing through, and it's our understanding that it can maybe kind of change a few things on the regulatory footprint there. Can you just kind of talk through if that affects your capital plans or your assumptions at all and how we should kind of think about that?

Yes. Nick, I appreciate that question. The legislature is scheduled to adjourn next week. In keeping with our standard practice, I'm not going to talk about pending legislation today. We'll know where everything lands next week. I can tell you what we're very focused on in South Carolina. First, a constructive outcome in our electric base rate case that's pending right now. As we mentioned in our opening remarks, we've invested $1.6 billion on behalf of our customers since the last case. Our rates in South Carolina are low. Our reliability is outstanding. So we think we're in a very good place with respect to that case. And then beyond that, we're very focused on continuing to serve our customers well, and getting closer to earning our authorized return in South Carolina. If you just sort of look big picture, South Carolina is a great state to do business. We want to be in a position to continue to invest in growth capital as the state grows. So that's what we're focused on, and we'll see how the legislature lands here in a week or so.

I appreciate that. And then I guess just on the ship, these ships to be certain, you talked about derisking the project timeline and you seem ahead of schedule. Is that versus the ISD, the '24 to early '25? Or is that more relative to where it falls in your current offshore wind construction schedule? And then maybe you can kind of remind us what's in the plan today for future contracting opportunities for that ship after you're done with the Virginia Offshore wind?

Nick, I'll take the second part first with regard to what we've assumed. So we've made some assumptions of the ability to contract the vessel to third parties at the conclusion of the work it does for CVOW, and we continue to see robust interest in that vessel, given sort of the unique nature of what it provides. So we feel like we've made reasonably conservative, not unduly conservative assumptions on that, and that's included in the guidance that we provided with regard to the Dominion Energy contracted energy segment at the Investor Day materials. With regard to the timeline and sort of what it all means, no change to the expectation that the vessel will complete its sea trials in late '24, early 2025. And with the termination of the charter that we discussed in the call, that doesn't change the broader expectation for the timeline for the project. What it does is it allows us to make sure that we can stay on track of that schedule. It gives us opportunities to begin installation when weather is most favorable. It will allow us, without that first charter, we won't need the time to reconfigure the vessels outfitting between charters to accommodate our project's turbine size. So if you think about the vessel availability as on track, consistent with how we've thought about it in the past. To the extent we're able to bring it forward, that's great for the vessel, for the project. But I wouldn't think of it as bringing the back end of the project in. It's just another way that we can mitigate what will be, I'm sure, things that happen along the way that we don't currently foresee, but we want to build as much cushion as we possibly can, and that's what this will accomplish for us.

We will take our next question from the line of Steve Fleishman with Wolfe Research.

Just one quick question. Do you have a number for kind of where you stand on the ATM for this year as of now? How many shares you've issued?

Yes. We haven't issued any shares of the ATM yet, Steven. And that's a function of during the business review, our ATM shelf registration expired, and so we actually didn't have the registration statement available to us. So we will be implementing that here very, very shortly, and then that will allow us to begin that program.

Okay. Great. Going back to the connection with the data center and IRP, Bob, you mentioned the concept of dispatchable generation and possibly gas storage. Can you provide some insights on whether there are winter conditions we need to address? Also, will you be investing in storage, and how should we consider these requirements?

Yes, to clarify, we are considering having two significant combined cycle plants located close to each other, which would utilize available gas LNG storage. This is part of our plan. Additionally, as we have previously mentioned, we are investing heavily in renewable energy, which our customers are increasingly demanding, but it is essential that we can maintain reliable system operations. This is the reason we've been discussing the storage mentioned earlier, along with the addition of some combustion turbines at our Chesterfield site.

Our next question this morning will come from Jeremy Tonet at JPMorgan.

It's Jeremy Tonet from JPMorgan. Continuing, I guess, with the data center line of thought, if I could. And I appreciate that this is a sensitive topic overall. But just any thoughts that you could provide with regards to the uncontracted Millstone capacity and that could possibly supply power to data centers? And how have conversations with stakeholders evolved there?

Jeremy, this is Diane. Really nothing new to report from what we said before in February of '23. We signed an MOU with NE Edge to work together on the development of a data center on Millstone property. And they are continuing to work with the state agencies and legislators to gain approvals to move that project forward. If the permits are granted, then we remain ready to support the project, and that would include providing land and a long-term PPA for power from a portion of Millstone, which will be about a few hundred megawatts.

And Jeremy, I would just note, and I think we disclosed this earlier, we've not made any assumptions in our financial plan associated with a co-located data center at the Millstone Power facility. So...

Got it. That's very helpful. And continuing with this line of thought, if I could. I believe there's legislation passed in Virginia to possibly recover some cost of SMR development in the state. And just given how it provides the 24/7 baseload that seems to match up well with data center needs. Just wondering any thoughts you see there on the potential over time? We see Ontario Power really moving forward swiftly on SMR development. And just wondering, any high-level thoughts you might be able to share there?

Yes, Jeremy, first. I think that legislation confirms a continued commitment in Virginia among policymakers in support of nuclear power. We operate four units in Virginia and have well for many years. The Navy has a substantial nuclear fleet. Many of those vessels ported in Virginia. And there are other parts of the nuclear industry that are all represented in Virginia. So I think it was a very positive sign that that legislation passed that continues to support nuclear power in Virginia. We included SMRs in our last IRP out toward the end of the plan. We continue to investigate the opportunity to be able to deploy SMRs on behalf of our customers. But I would add, just like with every other investment that we think about, we need to make sure that it's customer-friendly, that it fits within the parameters of our balance sheet and our business risk profile. So we're continuing to explore SMRs, as you point out, they are dispatchable and non-emitting, but we've got ways to go yet.

And next, we will also hear from Bill Appicelli at UBS.

Most of my questions have been answered, but just piling on the data center, just a couple of comments that you made there. You commented that the ramp times have been accelerating. Can you maybe just describe how that's playing out? Like, for example, the 15 that you're connecting this year, when would you expect them to be at full run rate?

Yes, Bill, I don't think we know specifically on those 15 how quickly they're going to be at full run rate. It really is just a matter of the amount of time that some of them that we've seen in the past would take to ramp fully into the capacity they ask for. They're expecting to ramp in quite a bit faster. But we don't have specifics regarding those 15 that we expect to connect this year.

Okay. I mean, is there, I guess, a historical precedent of how long it's taken on prior data centers?

This is Diane Leopold again. So typically, when they had capacity, they might ramp into that capacity over like a 4- to 5-year type of period. And now that same capacity that we're interconnecting could be closer to a 2- to 3-year period.

Okay. That's helpful. And then I guess just more broadly, again, on the same topic. Can you just share a little bit about the process of evaluation with the data center developers and how you structure the contracts and their commitments in terms of having the load show up and so that you're restructuring the cost profile appropriately to protect ratepayers?

Yes, Bill, great question. Our data centers are on the rate schedule that applies to all our large customers, and that has been established for some time. Any changes would need approval from the State Corporation Commission, but that is not currently being considered. Regarding how we structure contracts, there are minimum demands that they must meet to cover the additional costs of the infrastructure we are building for them, and this has been in place for a while.

Ladies and gentlemen, thank you. This does conclude this morning's conference call. You may disconnect your lines, and we hope that you enjoy the rest of your day.