Dominion Energy - Q1 2024

Executive Summary

• Q1 2024 operating earnings were $0.55 per share, with GAAP EPS of $0.78; management flagged a $0.06 weather headwind, partially offset by interest savings from the earlier close of the East Ohio Gas sale.
• Guidance affirmed: FY 2024 operating EPS $2.62–$2.87 and FY 2025 $3.25–$3.54; dividend, credit and financing guidance also reaffirmed.
• Coastal Virginia Offshore Wind (CVOW) remained on time and on budget; updated LCOE to $73/MWh, project ~28% complete, 36 monopiles received (as of the call) and contingency of $284 million intact.
• Demand backdrop strengthened: Dominion Energy Virginia (DEV) weather-normal sales growth of 4.8% YTD and accelerating data center pipeline (expect ~15 connections in 2024), positioning long-term rate base growth.
• Consensus estimates from S&P Global were unavailable at time of retrieval; comparisons to Street estimates cannot be provided (S&P Global data access limit) [GetEstimates error].

What Went Well and What Went Wrong

What Went Well

• Affirmed full-year operating EPS guidance for 2024 ($2.62–$2.87) and 2025 ($3.25–$3.54), and reiterated dividend and credit guidance: “no changes to any of the other financial guidance”.
• CVOW execution: “The project is proceeding on time and on budget,” with updated LCOE $73/MWh, 93% costs fixed, contingency of $284 million maintained; “We believe this lawsuit has no merit” regarding attempts to delay construction.
• Virginia segment strength: DEV operating earnings rose to $424 million from $386 million (+$38 million YoY), with favorable drivers including rider equity return and weather vs last year.

Quote: “We affirmed all financial guidance… and we are 100% focused on execution. We know we must deliver and we will.” — Robert Blue.

What Went Wrong

• Weather headwind of $0.06 impacted operating EPS; higher interest expense also weighed on results.
• Corporate & Other operating earnings fell to $(143) million from $(73) million YoY (−$70 million), reflecting higher net interest expense and other items.
• Q1 operating revenue declined YoY to $3.63B from $3.88B; GAAP EPS declined to $0.78 from $1.15 due to adjustments and discontinued operations mix.

Transcript

Operator (participant)

Ladies and gentlemen, welcome to the Dominion Energy First Quarter Earnings Conference Call. At this time, each of your lines is in a listen-only mode, and at the conclusion of today's presentation, we will open the floor for questions. Instructions will be given for the procedure to follow if you would like to ask a question. I would now like to turn the call over to David McFarland, Vice President, Investor Relations and Treasurer.

David McFarland (VP of 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.

Steven Ridge (EVP and CFO)

Thank you, David, and good morning, everyone. Our first quarter 2024 operating earnings, as shown on slide three, were $0.55 per share, which included $0.06 of weather 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 non-cash net gains on nuclear decommissioning trust funds, and the unrealized non-cash 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 four. We are affirming all of the financial guidance we provided at our March 1st 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 at 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%-7% through 2029, off a midpoint of $3.30, which excludes the impact of the RNG 45Z credits.

As a reminder, authorizing legislation applies to produced 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 1st, including credit, dividend, and financing guidance. Turning now to a status update on our business review initiatives, as shown on slide five. 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 non-controlling 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 11th. In Wyoming, a commission hearing is currently scheduled for May 23rd, and in North Carolina, a commission hearing is currently scheduled for June 11th.

As 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 de-risk 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 within existing consolidated rating categories at each of our three rating agencies.

Turning to financing on slide six, 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.

Bob Blue (Chair, President and CEO)

Thanks, Steven. Good morning. I'll begin my remarks by highlighting our safety performance. As shown on slide seven, our employee OSHA injury recordable rate for the first three months of the year was 0.32, a significant improvement relative to 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 part-way 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 to 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 29th, 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 plaintiffs' motion on Monday. Plaintiffs have until May 9th 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 in a challenge brought against the permit for Vineyard Wind. We believe this lawsuit has no merit, and we expect the court to deny the plaintiffs' 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 eight, last month, the project received its eleventh and final federal permit. On materials and equipment, we're 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 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 CS Wind Semco to be outfitted. 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 a third of the 600 miles of offshore cable has been produced. Schedule 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 bores 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 a final order by August. Turning to slide nine, as reflected in our standard status report filed with the SCC yesterday, we've updated the project's expected LCOE to be $73 per MWh, down modestly relative to our last update. The drivers for the lower LCOE included about $1.50 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 that 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 sole and exclusive access to the vessel in 2025, and we're exploring options to further de-risk 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's 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 and related filings reduced customer bills by over $13 a month. Current residential rates are now approximately 18% below the national average. 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%-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 GW of capacity over the last approximately five 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, one, the number of data centers requesting to be connected to our system, two, the size of each facility, and three, 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 or greater. However, we're now receiving individual requests for demand of 60-90 MW 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 MW 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 2 years. Second, what are we doing today? We will take the steps necessary to ensure our system remains resilient and reliable. We'd 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 SEC, 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-based 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 SCC 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.

Operator (participant)

At this time, we will open the floor for questions. If you would like to ask a question, please press the star key followed by the one on your touch tone phone now. If at any time you would like to remove yourself from the question queue, simply press star two. Again, to ask a question at this time, please press star and one on your telephone keypads now. We'll take our first question today from Shar Pourreza at Guggenheim Partners.

Shar Pourreza (Senior Managing Director of Energy/Power/Utilities)

Hey, guys. Good morning.

Bob Blue (Chair, President and CEO)

Morning, Shar.

Shar Pourreza (Senior Managing Director of Energy/Power/Utilities)

Morning. Maybe I can start with a two-part question on data centers. Bob, I know you've 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 held, you know, harmless on things like interconnection costs? Thanks.

Bob Blue (Chair, President and CEO)

Yeah, Shar, both really good questions. I may take them a little bit in reverse order. You know, 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 to 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, we think 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, you know, 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.

Shar Pourreza (Senior Managing Director of Energy/Power/Utilities)

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 seventeenth of this month? And more importantly, just elaborate a bit more on the IRP update and incremental generation spend. Could this kind of be accreted to the plan? Thanks, guys.

Bob Blue (Chair, President and CEO)

Yeah. 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. You know, 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 2025-2026 auction. Returns us to the way we did business for many years.

Doesn't change guidance, 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 and data centers for the foreseeable future.

Shar Pourreza (Senior Managing Director of Energy/Power/Utilities)

Got it. Thank you very much, super helpful. Congrats on the results, guys.

Bob Blue (Chair, President and CEO)

Thanks, Shar.

Operator (participant)

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

Nick Campanella (Senior Equity Research Analyst)

Hey, good morning, everyone. Thanks for taking my questions.

Bob Blue (Chair, President and CEO)

Morning, Nick.

Nick Campanella (Senior Equity Research Analyst)

Morning! Hey, I wanted to ask on South Carolina. I think, you know, HB 5118 has been kind of progressing through, and it's our understanding that can maybe kind of change, you know, 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?

Bob Blue (Chair, President and CEO)

Yeah, Nick, appreciate that question. You know, 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.

Nick Campanella (Senior Equity Research Analyst)

Hey, I appreciate that. And then I guess just on the ship to be certain, you kind of talked about de-risking the project timeline, and you seem ahead of schedule. Is that versus this, the ISD, the 2024 to early 2025? Or is that more relative to where it falls in your kind of 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 Virginia offshore wind.

Steven Ridge (EVP and CFO)

Hey, 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 reasonable, 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 in 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 2024, early 2025.

With the termination of the charter that we discussed in the call, that doesn't change the broader expectation for 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'll allow us, without that first charter, we won't need the time to reconfigure the vessel's outfitting between charters to accommodate our project's turbine size. So 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, to the vessel, to 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.

Nick Campanella (Senior Equity Research Analyst)

All right. All very clear. Thanks for the time.

Steven Ridge (EVP and CFO)

Thanks, Nick.

Operator (participant)

Steve Fleischman with Wolfe Research, please pose your question.

Steve Fleishman (Managing Director and Senior Analyst)

Yeah, thank you. Good morning.

Steven Ridge (EVP and CFO)

Good day. [crosstalk]

Steve Fleishman (Managing Director and Senior Analyst)

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?

Steven Ridge (EVP and CFO)

Yeah, we haven't issued any shares of the ATM yet, Steve. 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.

Steve Fleishman (Managing Director and Senior Analyst)

Okay, great. And then, just going back to the kind of tie in with the data center and IRP and the like, Bob, you mentioned, you know, dispatchable generation and then potentially gas storage. Could you just give a little. It sounds like maybe you've got, like, a winter tightness that maybe you need to deal with, and just would you be investing in the storage? And, yeah, just how we should think about those needs.

Bob Blue (Chair, President and CEO)

Yeah, just, just to be clear, we're looking potentially at, you know, we got a couple big combined cycle plants, not too far away from each other, being able to have some gas LNG storage that is available to those two. That's the kind of thing that we're talking about.

Steve Fleishman (Managing Director and Senior Analyst)

Got it.

Bob Blue (Chair, President and CEO)

You know, more broadly, as we've discussed, we're building a lot of renewables, which all of our customers are looking for, but we need to make sure that we can operate the system reliably. That's why we've been talking about that storage I just described, as well as some combustion turbines at our Chesterfield site.

Steve Fleishman (Managing Director and Senior Analyst)

Okay, great. I will leave it there. Thank you.

Steven Ridge (EVP and CFO)

Thanks, Steve.

Operator (participant)

Our next question this morning will come from Jeremy Tonet at JP Morgan. I hope I said your name correctly, sir. Your line is open.

Jeremy Tonet (Research Analyst and Managing Director)

Hi, thanks. It's Jeremy Tonet from JP Morgan.

Bob Blue (Chair, President and CEO)

Good morning, Jeremy.

Steven Ridge (EVP and CFO)

Hey, Jeremy.

Bob Blue (Chair, President and CEO)

Good morning.

Steven Ridge (EVP and CFO)

You've got competition on this call, Jeremy.

Jeremy Tonet (Research Analyst and Managing Director)

Okay, I guess so. That's right. But you know, continuing, I guess, with the data center line of thought, if I could, and 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?

Diane Leopold (EVP and COO)

Hi, Jeremy, this is Diane. Really nothing new to report from what we said before. In February of 2023, we signed an MOU with NE Edge to work together on development of a data center on Millstone property, and they are continuing to work with the state agencies and legislators to gain approval 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 would be about a few hundred megawatts.

Steven Ridge (EVP and CFO)

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 Station, so.

Jeremy Tonet (Research Analyst and Managing Director)

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 costs of SMR development in the state. And just given how nuclear provides the 24/7, you know, base load 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, you know, really moving forward swiftly on SMR development, and just wondering, any high-level thoughts you might be able to share there?

Bob Blue (Chair, President and CEO)

Yeah, Jeremy, first, I think that legislation confirms a continued commitment in Virginia among policymakers in support of nuclear power. You know, 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. You know, 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 a ways to go yet.

Jeremy Tonet (Research Analyst and Managing Director)

That makes sense. Thank you for that.

Operator (participant)

Next, we will also hear from Bill Appicelli at UBS.

Bill Appicelli (Executive Director and Head of North America Power and Utilities Research)

Yeah. Hi, good morning.

Bob Blue (Chair, President and CEO)

Good morning, Bill. [crosstalk]

Bill Appicelli (Executive Director and Head of North America Power and Utilities Research)

Hi, 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?

Bob Blue (Chair, President and CEO)

Yeah, 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.

Bill Appicelli (Executive Director and Head of North America Power and Utilities Research)

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

Diane Leopold (EVP and COO)

So 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.

Bill Appicelli (Executive Director and Head of North America Power and Utilities Research)

Okay. That's helpful. Thank you. 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 know structure the contracts and their commitments in terms of you know having the load show up and so that you know you're structuring the cost profile appropriately to you know protect ratepayers?

Bob Blue (Chair, President and CEO)

Yeah, Bill, great question. Data centers are on a rate schedule that applies to all our large customers. And that's been that way for some time. And the State Corporation Commission would have to make any changes if we were talking about approve any changes, if we were talking about any changes to that, which not on the table at the moment. The sort of thinking about the way we structure contracts, they have contract minimum demands that they are obligated to achieve in order to cover the incremental cost of the infrastructure that we're building for them. And that has been in place for us for some time.

Bill Appicelli (Executive Director and Head of North America Power and Utilities Research)

Okay, great. Thank you very much.

Operator (participant)

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.