Dominion Energy, Inc. (NYSE:D) Q3 2025 Earnings Call Transcript

Dominion Energy, Inc. (NYSE:D) Q3 2025 Earnings Call Transcript October 31, 2025

Dominion Energy, Inc. beats earnings expectations. Reported EPS is $1.06, expectations were $0.955.

Operator: Good morning, everyone. Welcome to the Dominion Energy Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. David McFarland, Vice President, Investor Relations and Treasurer. Please go ahead, sir.

David McFarland: Good morning, and thank you for joining Dominion Energy’s Third Quarter 2025 Earnings 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 report 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 other members of senior management. I will now turn the call over to Steven.

Steven Ridge: Thank you, David, and good morning, everyone. Since the conclusion of the business review last year, we’ve focused on 3 principal priorities first, consistent achievement of our financial commitments; second, continued on-time achievement of major construction milestones for the Coastal Virginia Offshore Wind project, and third, constructive achievement of regulatory outcomes that demonstrate our ability to work cooperatively with regulators and stakeholders to deliver results that benefit both customers and shareholders. As we successfully execute against these priorities, we empower our employees to provide the reliable, affordable and increasingly clean energy that powers our customers every day, and we position ourselves to deliver on the commitments we made to our investors at the conclusion of the business review.

We believe that continued execution against these commitments will deliver compelling value for our shareholders. I’ll address our financial results, and then Bob will address CVOW and regulatory progress. As shown on Slide 3, third quarter operating earnings were $1.06 per share, which includes $0.03 of RNG 45Z credits and $0.06 of worse than normal weather. Relative to third quarter 2024, positive factors for the quarter included $0.06 from regulated investment growth, $0.08 from increased sales, $0.05 from our DESC rate case settlement in 2024 and $0.03 from higher margins at Contracted Energy. Third quarter results also included worse weather, higher DD&A and higher financing costs. A summary of all drivers for earnings relative to the prior year period is included in Schedule 4 of the Earnings Release Kit.

Q&A Session

Third quarter GAAP results were $1.16 per share, A summary of all adjustments between operating and GAAP results is included in Schedule 2 of the Earnings Release Kit. Turning now to guidance. With 9 months of 2025 financial results reported, we’re narrowing our full year guidance range to $3.33 to $3.48 per share, inclusive of RNG 45Z earnings while preserving the original guidance midpoint of $3.40. On last quarter’s call, I highlighted sales and weather as noteworthy tailwinds through 6 months of the year. Over the last 4 months, we’ve seen weather reverse. And through 10 months of the year, now represents a small headwind of approximately $0.02. Continued strength from commercial and residential sales combined with other initiatives, gives us confidence in our ability to deliver full year results at or above the midpoint of our guidance, assuming normal weather for the last 2 months of the year.

We’ve provided year-over-year drivers for the fourth quarter in the appendix of today’s materials for your reference. Finally, we are reaffirming all other existing financial guidance. Turning to Slide 4. We’ve completed our 2025 financing plan. And as mentioned on prior calls, taking steps to further derisk future ATM equity. We remain focused on balance sheet conservatism, and there is no change to our previously communicated credit-related targets. Finally, we’ll provide a comprehensive capital investment forecast update through 2030 on our fourth quarter earnings call, which will take place in early 2026. We expect incremental opportunities to deploy regulated capital on behalf of our customers, with a timing bias towards the back end of the plan.

As always, we will look at incremental capital through the lenses of customer affordability, system reliability, balance sheet conservatism and our low-risk profile. In conclusion, I am highly confident in our ability to deliver on our financial plan. We’ve built our plan to be appropriately but also not unreasonably conservative to weather unforeseen challenges that may occur. And with that, I’ll turn the call over to Bob.

Robert Blue: Thank you, Steve, and good morning, everyone. I’ll begin with safety on Slide 5. Through September, our OSHA recordable rate was 0.28%, continuing the positive trend from the last 3 years. Continuing to reduce workplace injuries is one way we can honor the memory of our colleague, Ryan Barwick, who we lost in an accident earlier this year. We must continue to focus relentlessly on improving our safety performance. Now I’ll turn to updates around the execution of our growth plan. I’ll start with the Coastal Virginia Offshore Wind project. Slide 6 highlights what makes CVOW such an important and unique generation resource. The project is now 2/3 complete, and just a few months away from delivering much-needed electricity to our customers.

Slide 7 shows our major equipment progress. We successfully completed 100% of monopile installation 1 month prior to the conclusion of the piling season. very pleased with this tremendous milestone for the project. We’ve installed 63 transition pieces to date with all 176 transition pieces now fabricated. Turbine fabrication remains on schedule. Earlier this week, we installed the second offshore substation jacket and will place the accompanying topside shortly. The third and final offshore substation is nearly complete and will be installed in the first quarter of next year. Turning to timing on Slide 10. We now expect first turbine installation to occur late next month and continue to expect first power to be delivered to our customers in late first quarter of next year, approximately 5 months from now.

As a reminder, we’ll be energizing strings of turbines throughout 2026. No change to our current expectation of project completion by the end of ’26. But given delays with Charybdis, we have significantly reduced the schedules weather and vessel maintenance contingency, which could push a few of the final turbines into early 2027. We’ll continue to refine and update this assumption as we observe actual turbine installation cadence similar to what occurred with monopiles, which went more quickly than expected. Project costs now stands at $11.2 billion, which includes unused contingency of $206 million, down about $15 million from last quarter. Excluding tariff impacts, costs for project components have remained in line with the prior update.

The updated cost this quarter reflect the accelerated recognition of steel tariffs through the end of 2026, whereas we were previously recognizing all tariff costs on a quarter-by-quarter basis. Through September, the project has invested approximately $8.2 billion. The remaining project costs attributable to Dominion are expected to be approximately $1.5 billion. On Slide 11, we’ve continued to provide an update to our potential tariff exposure across discrete tariff categories and illustrative duration. We’re showing the impact of country-specific tariffs through project construction at the end of 2026. Please note that changes to tariff policy could impact these estimates. Unfixed costs include project management costs, fuel for vessels and changes to tariffs and network upgrades, if any.

Estimated network upgrade costs assigned by PJM to CVOW in the most recent decision point came down modestly. We expect this inaugural process to conclude by year-end and do not expect a material change to network upgrade costs. We’ll then execute and submit our generator interconnection agreement at PJM and FERC under the very standard finalization protocol, as is in place for all new generating sources. We expect the process to conclude in March, which will be the final step to First Power. As a result of this project cost increase, we recorded a modest charge this quarter, about $50 million after tax included on Schedule 2 for costs not expected to be recovered from customers in accordance with the cost sharing settlement with Virginia regulators, and our 50% cost sharing partnership agreement with Stonepeak.

These cost and risk-sharing arrangements continue to work as intended to protect customers and shareholders. Further on costs, we’ll file with our quarterly status report and our 2026 CVOW rider filing with the State Corporation Commission today. As shown on Slide 12, the project’s LCOE has been updated to $84 up from last quarter, driven primarily by lower forecasted rec prices. Keep in mind that REC sales are credited against the levelized cost of energy as value delivered to customers and the value of REC will change year-to-year based on market dynamics at the time. However, importantly, the LCOE compares favorably to other generation resources and is well below the statutory amount. It’s also in line with the LCOE range provided at the time of the original filing in November 2021.

The project is now forecasted to represent an average residential customer monthly bill credit of $0.63 over the life of the project. Under the rider proposal filed today, we’re forecasting a revenue requirement for the 2026 rate year, which begins in September ’26 of $665 million. This customer beneficial real-time cash recovery provides important financial support for this regulated investment during construction. If approved, the rider proposal filed today would result in residential customers seeing a decline in their monthly bill in September, as the project begins to generate electricity in early 2026. Progress on CVOW continues to go very well, and there’s every reason for our customers and policymakers to be excited by the timely delivery of much-needed low-cost electricity from this critical generating resource.

Let me pivot to discuss Charybdis, our American Made Jones Act-compliant wind turbine installation vessel which has been a challenge. I’m extremely disappointed that Charybdis has again not met expectations. I recognize the importance of executing consistently against any commitment, and we failed to deliver regarding Charybdis. We built Charybdis to derisk our installation process. We continue to believe that it will represent a strategic advantage, providing enhanced schedule certainty, which ultimately translates into cost certainty. The vessel successfully completed sea trials received sign-offs and arrived in Portsmouth, Virginia in September. Upon arrival, Siemens Gamesa successfully completed all necessary modifications for turbine handling and installation.

Simultaneously punch list items were identified that require remediation prior to the vessel being cleared to begin turbine load-out and installation. While all major systems are operating well, there are a variety of quality assurance level items that require addressing and those tasks are currently underway to ensure that the vessel can commence work as quickly as it is safely able to do so. It’s become clear that while the ship’s design and construction methods are consistent with global best practices, we didn’t properly account in our timing estimate for the risk inherent in being the first Jones Act-compliant wind turbine installation vessel to be built and regulated in the United States. The vessel is expected to be cleared to load and install turbines in November.

As a reminder, unlike monopile installations, there are no time of year or time of day restrictions on installing turbines. Finally, any modest delay beyond November won’t impact first power timing in late first quarter of 2026. One final note on Charybdis. Project costs continue to be approximately $715 million. Moving now to data centers on Slide 14. We continue to see robust demand from data centers. We now have approximately 47 gigawatts in various stages of contracting as of September 2025, which compares to around 40 gigawatts as of December 2024, an increase of 7 gigawatts or 17%. As a reminder, these contracts are broken into substation engineering letters of authorization, construction letters of authorization and electrical service agreements.

As customers move from the first to the last, the cost commitment and obligation by the customer increase. We’re currently studying over 28 gigawatts of data center demand within the substation engineering letters of authorization stage, which means the customer has requested the company to begin the necessary engineering review for new infrastructure required for service. This compares to approximately 26 gigawatts as of December 2024 and represents a roughly 7% increase. There are also now about 9 gigawatts of data center demand that have executed construction letters of authorization which are contracts that enable construction of the required distribution and substation electric infrastructure to begin. This compares to just over 5 gigawatts in December 2024 and represents an approximately 73% increase.

Should a customer in this stage, elect to discontinue a project, they’re obligated to reimburse the company for its investment to date. Finally, we now have nearly 10 gigawatts in electric service agreements or ESA, representing contracts for electric service between Dominion Energy and a customer. This has increased by nearly a gigawatt or 12% since December 2024 as well. By signing an ESA, the customer is committing to consume a certain level of electricity annually often with ramp schedules where the contracted usage grows over time. We welcome these customers to our system and recognize the vital contribution data centers make to national state and community success. We’re developing resources across distribution, transmission and generation to ensure we meet this critical need on a timely basis, while also taking active steps to safeguard all of our customers from the risk of paying more than their fair share for reliable and affordable electric service.

Data center demand should and can be a win-win for our state, our customers and our company. Turning to Slide 15, let me share a few additional business updates. First, on the biannual review proceeding and the proposed large load tariff, post-hearing briefs were filed last week. We anticipate a final order by the end of November. Next, on the transmission side. We submitted project proposals in the latest PJM open window process that closed in August. This year’s reliability open window represents the largest proposed investment by Dominion Energy since PJM began its open window process. While final project selections by PJM won’t be made until Q1 2026, there is a robust need for new transmission across the region, and we expect this open window to reflect that.

Recall that in last year’s open window, Dominion was awarded around 100 projects totaling nearly $3 billion. On the generation front, we’ve announced a number of updates in recent weeks. SCC hearings for the Chesterfield Energy Reliability Center, an approximately 1 gigawatt natural gas-fired electric generating facility concluded in September, and post-hearing briefs were filed this week in line with previous testimony. We expect an order in December. On October 15, we filed our next set of utility scale solar and storage projects with the SEC, representing about $2.9 billion of new investment. The filing included approximately 845 megawatts of utility scale solar and 155 megawatts of storage projects, which will further derisk our growth program.

Also on October 15, we filed our 2025 Virginia Integrated Resource Plan, which presented several possible generation build portfolios with additional resource capacity across both renewable and dispatchable generation technologies in response to continued robust load growth in our service territory. The IRP update demonstrates a continuation of our focus on an all-of-the-above approach to ensuring reliability, affordability and increasingly clean generation. On customer affordability, as shown on Slide 16, our current residential electric rates at DEV and DESC are 9% and 11% below the U.S. average, respectively. And based on the build plans proposed in both states latest IRPs, both will maintain customer bill growth rates through the forecast periods below current electricity inflation levels.

In conclusion, we’ve summarized key highlights from today’s call on Slide 17. We realize how important it is to meet the commitments we provided at the conclusion of the business review. We are 100% execution focused. We will deliver for our customers, our employees and our shareholders. With that, we’re ready to take your questions.

Operator: Thank you, Mr. Blue. Ladies and gentlemen, the floor is now open for your questions. [Operator Instructions] We’ll go first this morning, Shar Pourreza of Wells Fargo.

Shahriar Pourreza: Hey guys, good morning. Thank you. Appreciate it. It’s good to be back. So Bob, just on the elections, I mean, there seems — any source you’re looking at. There’s obviously a strong possibility the gubernatorial process may flip parties. Governor Youngkin has obviously been really supportive of CVOW, the biannual process. I guess, how do we price in any risk on the construct should we see this flip? I mean are we going to wake up one day and the Trump administration now blocks this project, just given the lack of connection with the Republican governor. Have you spoken to Spanberger? Just any thoughts around the political backdrop would be great.

Robert Blue: Yes, Shar, thanks a lot for that question. Let’s start with the fact that every statewide candidate running regardless of party supports CVOW and that’s consistent with the bipartisan support that this project has gotten at every level, federal, state, local government, including congressional leadership. And if you think about it, there are really good reasons for that. It’s the fastest way to get 2.6 gigawatts on the grid that’s going to serve AI and technology companies, defense security installations. It’s critical to important infrastructure upgrades at the Oceana Naval Air Station. And if you stop it now, it causes energy inflation. So it’s not surprising that we’re seeing bipartisan support at all levels of government and we expect that to continue after the election.

Shahriar Pourreza: Got it. Okay. Perfect. And then just lastly on Charybdis.Can you just give us a little bit of a sense, if you can, on just the nature of the punchlist for the project? And when do you kind of expect the quality assurance items that you obviously highlighted to be completed, which are underway?

Robert Blue: Yes. Let me — that’s a great question. Let me give you a little context walk you through where we are. As you know, this is the first Jones Act-compliant wind turbine installation vessel to be built in the U.S. and subject to U.S. regulatory oversight. It’s a big ship. It’s 472 feet long. It’s 184 feet wide, weighs 27,000 tons. It’s got some complex systems on it. It’s got a 2,200-ton capacity crane. It’s got a jacking system that’s capable of creating a 40-meter air gap under the hall when the ship is jacked up. And those systems, the crane, the jacking system, the dynamic positioning system, they are all operating very well. So earlier this month, local regulators when it arrived in Portsmith conducted a standard new to zone inspection.

And that identified 2 primary areas of concern. The first was the material condition of certain components, primarily within the ships electrical systems. And then second, the need for documentation that confirmed that the systems we built has built met U.S.-approved codes and standards. So that created this punch list of about 200 items that have to be addressed before we can begin loading turbines. So let me talk a little bit about what we’re doing. Ships divided into 63 zones, our crews, including qualified marine electricians are doing detailed surveys, and they’re either documenting or immediately mitigating discrepancy. So to date, we’ve done over 4,000 inspections across 69 electrical systems including 1,400 cable inspections. We’ve got 200 people working around the clock of that original 200 punch list items, we’ve closed out about 120.

So it’s important to know not all those items are created equal. Some punchless items are a little more complex and will take longer to resolve. But the progress has been really good. And so based on the pace of work the commitment of the team we’ve got there, highly confident that we’ll work our way through all the punch list items and be ready to start operating in November.

Operator: We’ll go next now to Nick Campanella at Barclays.

Nicholas Campanella: One follow-up on the ship, just after you get this punch list done, I just wanted to confirm, there’s no other approvals needed across offshore wind supply chain, the boat or with federal government that would allow you to install turbines that’s just really getting past this punch list?

Robert Blue: Yes, once we get through the punch list, we’re ready to go.

Nicholas Campanella: Great. Can I just ask about the capital plan comments then? I know you’re going to be updating things in the fourth quarter. I think you talked a little bit about the bias of that capital plan update being more back-end weighted, if I heard you correctly. But on the funding, you did derisk equity for ’26 and ’27 here. What’s the balance sheet capacity to kind of absorb higher CapEx at this point? And should we still expect equity in ’26 and ’27 on the next pro forma plan?

Steven Ridge: Nick, it’s Steve. I’ll take that. Yes, we talked a little bit about the update we’ll provide on the fourth quarter call in probably February of ’26. And I fully expect at that time, we’re going to see upward revisions to our capital plan across distribution, transmission and generation that effectively reflect what we filed in the IRP, which is some significant increases in the amount of generation. One example is the South Carolina CCGT that we’re now authorized and seeking approval to build with our partners, Santee Cooper. None of that capital, for instance, was included in the most recent capital update. And we’ve identified opportunity for additional generation in Virginia, and much of that’s not been included.

So we’ve talked about transmission and the opportunity with the PJM open window. So there’s — we’re in a fortunate position to have a lot of really high-quality opportunities to deploy regulated capital to the benefit of our customers. which will provide sort of a full update next — early next year. With regard to our balance sheet, I’m really pleased with where our balance sheet is. When we came out of the business review, we talked about being at 15% FFO to debt starting in 2025, that’s still where we’re tracking. That’s about 100 basis point cushion relative to our downgrade threshold at Moody’s 200 basis points at S&P. We mentioned the time Moody’s is going to be slightly lower than that 15% just given the methodology they deploy relative to sort of our more simplified metric for FFO to debt.

But we’re in a very good position, and we’ve taken steps, as you noted, to do a lot of derisking for our planned ATM. When we update the capital plan come early next year, we’ll, at the same time, give you an updated perspective on our financing needs. We’ve been very effective at deploying ATM and hybrid equity, very cost competitive. And we’ll look at all the tools available to us. As we’ve always said, we’ll look at all the available tools available to us to source capital from the most attractive source. And so I don’t want to get out in front of that, but you can assume we’re going to finance the growth of our business in a way that maintains that balance sheet conservatism. But in so doing, it should also provide for value to our shareholders.

Operator: We’ll go next now to Steve Fleishman of Wolfe Research.

Steven Fleishman: Yes. Just one other question on the Charybdis. Just want to confirm there’s nothing related to the government shutdown or any political stuff that’s affecting the timing, it’s just this punch list?

Robert Blue: That’s it, Steve. There is nothing related to the government shutdown or anything else.

Steven Fleishman: And then once we start seeing turbines come in. Can you give us a sense of like cadence there? My recollection is maybe the first set a little slower, but then it gets into a cadence. So can you maybe talk a little bit about what we should be looking for on turbine cadence?

Robert Blue: I think exactly what you just described. We’re going to — if you think about monopiles, for example, we, at the beginning, we’re a little bit slower and then got into a rhythm. So we’ll update the installation cadence as we go along. But you should expect that the first few are going to be slower, and then we’ll pick up the pace as we move through. But we’ll be able to give regular updates on how we’re doing on turbine installation cadence.

Steven Fleishman: And then off topic, when we get these PJM open window wins or not, like how should we think about how much of that might already be in your plan or additive? Is it all additive? How should we think about that?

Steven Ridge: Steve, I’d say we’ve made a reasonably conservative assumptions in our forward capital plan with regard to wins across PJM open window as well as opportunities to deploy capital that don’t go through that PJM wind with sort of organic maintenance capital and growth capital within our — and what we’ve seen historically and more recently is upside to what we’ve assumed I can’t tell you sort of specifically what that will look like. But I’d say there’s about — we run rate in our forward projection $2.5 or so billion a year for electric transmission, that’s up pretty significantly from what it was just 4 or 5 years ago. To the extent we continue to see opportunities, there could be continued upside to that.

Steven Fleishman: Yes. And then last quick one. Just the IRP was interesting on the nuclear, where it looked like at least for now, you actually delayed the SMR new nuclear by 5 years. Could you just like talk to what is driving that?

Robert Blue: Yes, Steve. I mean, it’s a variety of circumstances. We’re taking a look at financing and technology. We’re also taking a look at how it fits within everything else that we’re projecting to construct. So I mean, we’re talking about pretty far out in the first place and now a little farther out with the update. I wouldn’t read too much into that.

Operator: We’ll go next now to Paul Zimbardo with Jefferies.

Paul Zimbardo: To follow up on CVOW a little bit. To the extent that some of those final turbines do slip into the following year, are there any supply chain, labor or other kind of constraints to be mindful of? And is there any way to think about what a financial impact of that could be?

Robert Blue: There are no supply chain or other issues. And as to financial impact, we’re talking about a small number of turbines. So it’s not a meaningful financial impact.

Steven Ridge: I would just add, as you might suspect, years ago, when we put this plan together, which had us completing all the turbines at the end of 2026, which is actually where we still intend to do. We obviously gave ourselves a little bit of latitude as it relates to what the ultimate timing would be. And in fact, I think we’re very pleased that. Here we are some years after that original time line was produced and we’re effectively on target for these dates. And so we’ve made accommodations in advance that gave us some cushion to the extent that anything caused us to go anywhere beyond that end of ’26 time frame. So I think we’re very well buttoned up on that, quite frankly, with regard to suppliers and vendors and so forth.

And as Bob mentioned, I think in the prepared remarks, I think one thing that’s really important for our stakeholders to recognize is, we’ll be energizing these turbines throughout 2026 and deploying that rate base effectively and beginning to collect depreciation and in our revenue requirement throughout the time period that we’re installing through 2026. So the actual impact of a couple of turbines slipping into 2027 is pretty de minimis all things considered, which makes it a little bit different, I think, from something that’s a bit more chunky by doing it on a stream, we’ve effectively dechunkified that revenue stream. And so I think that acts as a fairly significant de-risker or mitigant to the type of risk you might see from standard power plant where you can’t collect anything until everything is ready to go.

This is 176 individual power plants that we’ll be able to collect on in real time through 2026 as we deploy strings of turbines.

Paul Zimbardo: I like that phrase, dechunkified. One other I had just you called out that you’ve had some weather and other headwinds year-to-date, but you still expect to be midpoint or better. Could you just go through what some of the — those are kind of the positive offsets looks like sales are coming in stronger. If you go through that, it would be helpful.

Steven Ridge: Sure, Paul. Yes, I’m really pleased with 2025 financial performance year-to-date. We’ve had — we are now in a weather deficit, a $0.02 weather deficit. And really, the biggest driver of that has been sales across 2 primary sources. One is faster and more ramping on our data center customers. That’s been pretty consistent through the year. And then over the summer, we saw increased usage per customer on our residential class, which was something we’re trying to understand better, but it was a departure from what we’ve seen in the past. So the 2 of those combined have been a tailwind, as I’ve mentioned in the past, that’s been the most positive driver that gives us that confidence. And we’ve seen some true-ups on our riders, which allow us as we deploy capital to the extent we deploy it faster. We get some true-ups there. That’s been a little bit of a help as well. But primarily, it’s been sales.

Operator: We’ll go next now to Carly Davenport with Goldman Sachs.

Carly Davenport: Maybe just on the data center update, just any color that you’re able to share on the sort of timing to in-service for the 9.8 gigawatts of load that’s now under ESA and just how to think about that cadence looking forward?

Robert Blue: Yes. Carly, it’s our data center load just continues to grow and the demand continues to grow, which is something considering that we’ve connected 450 data centers already and we’ve got more than 25% of our sales going to data centers in Virginia. So we’re not seeing any decrease. We’re actually seeing the opposite and that’s the whole PJM DOM zone is seeing quite a bit of new capacity requests. And they continue to choose us because we’ve got really good fundamentals. We’ve got great connectivity to global fiber networks. We’ve got a very business-friendly environment in Virginia. We’ve got the largest data center workforce in the U.S. and then we’ve got reliable and affordable electricity, thanks to us. So we’ve gotten 370 delivery point requests since 2020, which is over 58 gigawatts of capacity, 17 gigawatts of that just in 2025.

That’s across our service territory and also the co-ops that we serve from a transmission point of view. So we’ve now communicated a firm dates for over 100 delivery point requests, which represents over 25 gigawatts of capacity in the DOM zone. And those energization dates stretch through 2031. So sort of match up with everything that we’ve been saying already. So typically, from the time of a delivery point request until we’ve got a customer hooked with the meters about 4 to 7 years and then they ramp in over time from the date. So we’ve got sales growth off that 10 gigawatts of ESAs as they ramp in the current 4 gigs of meter demand just continues to increase steadily just off those ESAs over the coming years.

Carly Davenport: Great. That’s really helpful. And then maybe just a clarification question on Slide 11. To the extent that costs through the end of ’26 on CVOW do trend above that $11.3 billion level and recognize what you’re outlining here is not materially at that level. Are you still assuming that Stonepeak will continue to contribute incremental capital there? And if so, just what is your sort of confidence level there?

Steven Ridge: Yes. So under the agreement we have with Stonepeak capital between $11.3 billion and $11.8 billion is shared about 2/3 at Dominion and 1/3 with Stonepeak that agreement without getting into too many details, provides incentives for them effectively to do that, to fund that. So that’s what we’ve assumed. And as you mentioned, it’s only a very small amount. I think in rounding terms, it’s even less than the $400 million that we’re over through 12/31/26 on Slide 11.

Operator: We’ll go next now to Jeremy Tonet at JPMorgan.

Jeremy Tonet: Happy Halloween.

Robert Blue: Thank you, Jeremy.

Jeremy Tonet: Just one last one, if I could, on CVOW here and recognize a lot of progress and a lot of fronts here. But just wanted to turn to the inter-array cable fabrication not as much progress on that side quarter-over-quarter. I’m just wondering if you could touch on that a little bit the drivers.

Robert Blue: It’s not necessarily a linear production, Jeremy, but we are totally on track on inter-array cable manufacturing and installation. So I would read nothing into if you’re sort of doing the math on how much per month or quarter, anything like that, we are right on track.

Jeremy Tonet: Got it. And I just want to come back to the question on nuclear, if I could. And granted, as you said it pretty far off at this point. But we have seen the federal government kind of step up with new efforts to support development here. And just wondering if there’s anything out there that you would be looking for that you think could materially, I guess, change views on the potential for nuclear’s role going forward?

Robert Blue: Well, I mean, our view is we’re in the most in Virginia, at least the most nuclear-friendly state in the country. And the policies port here is very strong, the public and policymaker support, whether it’s the nuclear Navy or the big parts of the supply chain or the reactors that we’ve been operating safely here in Virginia since the ’70s. But I think as we’ve described before, as we think about new nuclear cost overrun risk being borne by our customers and our shareholders is a concern. First-of-a-kind costs being borne by our customers as a concern, and the balance sheet that we’ve worked very hard to get in shape and our business risk profile can’t change. So there are ways to work through that, that’s the MOU that we entered into with Amazon.

They’ve expressed some interest in helping finance an SMR at North Anna 3. We continue to work our way through that. But fundamentally, as we think about new nuclear, which could be very beneficial for the state, we need to think about first-of-a-kind cost, cost overrun risk and our business risk profile.

Jeremy Tonet: Got it. So it sounds like backstops on catastrophic risk and just cost overrun risk would be the key thing to pull forward, I guess, the time line at this point?

Robert Blue: They would be incredibly valuable, yes.

Jeremy Tonet: Got it. That’s very helpful. Last one, if I could. And then as we think about data center development here and clearly, there’s been a focus for you, you guys well ahead of others here. But equipment availability that stands right now, transformers, transmission, equipment, everything for CCGT. Just wondering how long the queues at this point? And how do you think about, I guess, winding that up with more data centers, just given how time on are on both sides at this point for demand?

Robert Blue: Well, if you think about the sort of time line on components for generation, our IRP that we just filed with the dates that we’ve got for new gen line up with what we expect time lines for the supply chain. And then more broadly, I think everyone is experiencing. There’s more demand for transformers and other equipment. I think we’re advantaged because of our size, because of the long relationships that we have with suppliers. We’ve been doing a lot of transmission work at this company for quite a while. And so I think that puts us in a good place as we try to connect the data center load that we’ve got. It’s a big lift, but we’re very much up to the task.

Jeremy Tonet: Got it. And just one last one, if I could. Speaking about time line, if anything for CVOW, if anything flips into ’27 here, do you think that there would — that would impact, I guess, the ’26 guide at this point? Or is that kind of just small at this point and wouldn’t really think of it as much of a headwind when it comes to the ’26 guide?

Steven Ridge: Jeremy, I feel very, very good about our financial plan. We’ve constructed it to be appropriately though not unreasonably conservative. So when things — if something like that were to occur, I feel very good about our ability to maintain our ability to hit the commitments we made to our investors at the conclusion of the business review.

Operator: We’ll go next now to Anthony Crowdell at Mizuho.

Anthony Crowdell: I want to ask — this is my last one 3 times. Just quickly, is there a cadence of generation needs that you guys look at in 2 to 3 years, whether it’s like a gig a year? Like how much generation will you be bringing on to the grid as we look out towards the back end of your plan?

Robert Blue: Well, I mean, the best way to look at it, Jeremy, is we outlined it in the IRP. So I’m not going to walk through sort of what comes on each year. But I will say we’ve got 2.6 gigawatts coming on in offshore wind by end of next year. Chesterfield Energy Reliability Center, which is in front of the commission right now. That’s a gig of natural gas peaking that would come on ’29 and then we’ve got a cadence roughly of a gig of solar a year. I mean between us and PPAs coming online plus we’ve got another, I guess, 0.5 gig-ish 500 megawatts of uprates on our existing gas fleet in Virginia. So it’s all in the IRP sort of by year, which is probably the best way to look at it.

Anthony Crowdell: Great. No, that’s perfect. And then just one follow-up. When Charybdis finally clears to, I guess, begin installation does the company issue a press release or an 8-K just how best can we track that?

Robert Blue: Well, we’ve noticed a lot of people track where Charybdis is on the web on one of these vessel finder sites. So you’ll see it. It won’t be at the dock anymore. It will be out at a turbine I would not anticipate us issuing an 8-K or a press release when it’s done because it’s another step in the project, a project that is going extremely well. We didn’t issue a press release when we started installing other components. We just moved through this efficiently and effectively as we’ve been doing throughout our offshore wind project.

Operator: And ladies and gentlemen, this will conclude our question-and-answer session for today. Mr. Blue, I’d like to turn the conference back to you, sir, for any closing comments.

Robert Blue: Thanks, everybody, for taking the time to join the call today. I hope you enjoy the rest of the day and your Halloween.

Operator: Thank you very much, Mr. Blue. Ladies and gentlemen, that will conclude today’s Dominion Energy Third Quarter Earnings Call. Again, thanks so much for joining us, everyone, and we wish you all a great day. Goodbye.