Dominion Energy Aktie

Welcome to the Dominion Energy Third Quarter 2026 Earnings Conference Call. [Operator Instructions]

I would now like to turn the call over to David McFarland, Senior Vice President, Investor Relations, and Treasurer.

Good morning, and thank you for joining Dominion Energy's Third Quarter 2026 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.

Thank you, David, and good morning, everyone. We continue to be focused on 3 top priorities: first, consistent achievement of our financial commitments; second, continued 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 benefit both customers and shareholders. As we'll discuss today, we continue to demonstrate success against these priorities, extending our track record of high-quality and consistent execution. I'll cover financial results in my remarks. Bob will provide updates on the NextEra Energy combination, CVOW and other business items in his remarks.

Turning first to third quarter results, as shown on Slide 3. Third quarter operating earnings were $1.28 per share, including $0.05 from RNG 45Z credits and $0.05 from better-than-normal weather. Third quarter GAAP results were $1.30 per share. A summary of earnings drivers relative to the prior year period is included in Schedule 4 of the Earnings Release Kit, and a summary of all adjustments between operating and GAAP results is included in Schedule 2 of the Earnings Release Kit.

Turning now to guidance. Year-to-date operating EPS has benefited from better-than-budgeted sales, better-than-normal weather and higher-than-expected 45Z credit income, combined with strong overall financial and operational execution. Inclusive of conservatism for balance of year weather as well as potential opportunities to derisk future financial performance, we now expect full year results to be in the top half of our original guidance range. We've provided year-over-year drivers for the fourth quarter in the appendix of today's materials for your reference. Additionally, we are reaffirming all other existing financial guidance provided on our fourth quarter earnings call, including credit, dividend and long-term growth guidance.

Turning to financing on Slide 4. We made significant progress on our financing plan during the quarter, successfully executing several planned transactions while continuing to manage the balance sheet, consistent with our robust credit guidance. In September, the Virginia State Corporation Commission approved our fuel securitization financing petition, representing the balance of approximately $900 million, helping mitigate near-term fuel-related impacts on customer bills.

Turning briefly to sales. We're continuing to see strong sales in our service areas with LTM weather normal electric sales growth of 3.4% across DEV and DESC. In addition, all 10 of the DOM zone's summer peak demand days have occurred in 2026. And in August, DESC set a new all-time electric peak.

Turning to Slide 5. Since our last update, we continue to see robust and durable demand from our differentiated, high-quality, low-risk data center customers across multiple localities in Virginia. And we're bringing these customers onto our system in the right way: protecting existing customers from cost shifts while mitigating stranded cost risk by utilizing a large load framework approved by the Virginia State Corporation Commission in our most recent biennial review that ensures these customers continue to pay their fair share of the investments required to support their growth.

We now have over 54 gigawatts of data center capacity in various stages of contracting, including over 12 gigawatts of capacity contracted under electric service agreements. To put that in context, we've added over 6 gigawatts of contracts or 13% since the end of last year.

In conclusion, I'm 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.

Thank you, Steven. I'll begin with safety on Slide 6. Through September, our employee OSHA injury recordable rate was 0.41, which remains well below industry average. Safety is our first core value, and we're always focused on driving workplace injuries to 0.

Turning next to our announced combination with NextEra Energy. As we detailed in May, this transaction represents a truly transformational opportunity to bring together 2 world-class utilities with 238 years of collective industry experience to even better serve millions of regulated customers across 4 states. Looking ahead, we believe we can accomplish far more on behalf of our customers together than we can apart.

In mid-September, NextEra and Dominion announced an enhanced Virginia benefits package that puts customers first and positions the Commonwealth as a global energy leader. That proposal doubled the duration of residential bill credits, expanded energy bill assistance by $100 million, included a $100 million workforce development fund, committed to creating at least 1,000 new jobs in the Commonwealth, building a new shareholder-funded co-headquarters tower in Richmond and supporting Virginia companies through a $1 billion annual 5-year Virginia supplier program. Over the longer term, customers and communities will benefit from a stronger company with the scale and capabilities to buy, build, finance and operate critical energy infrastructure more efficiently, helping support reliability, affordability and economic growth.

In Virginia, we've received testimony from parties which we will address through rebuttal testimony due November 2. Evidentiary hearings begin on November 17, and the final order is due by January 11 of next year. Ultimately, the State Corporation Commission will decide the case based on the record presented to it and on the legal standard, whether adequate service to the public at just and reasonable rates will not be impaired or jeopardized by the proposed transaction.

Another way of thinking about this is whether the transaction will do no harm to customers. We're confident that we have met that standard. In fact, we've exceeded the standard by proposing significant benefits in terms of customer affordability, jobs in our service area and development of needed energy resources.

In South Carolina, we've received testimony from parties which we will address through rebuttal testimony due November 18. Hearings begin on December 8, with a final order by January 29, 2027. In North Carolina, hearings begin on February 23, 2027. The time lines for each of the proceedings are shown on Slide 7.

Required federal approvals have all been filed and continue to progress. We continue to expect the transaction to close in the second half of 2027. I could not be more excited about the combination of these 2 companies. We'll continue to share updates as we progress through the regulatory process.

Turning next to offshore wind on Slide 8. CVOW continues to make significant progress, with the project approximately 85% complete and the fabrication of all nacelles, towers and blades now complete. We've installed 44 turbines representing more than 640 megawatts of generating capacity, with the installation of the 45th turbine happening now. Installation continues to average approximately 2 days from jack up to jack down, consistent with our assumptions.

July and August turbine installation cadence was in line with expectations, while September and October were below due to a combination of weather and Charybdis maintenance activities, which were completed earlier this month. Importantly, these impacts were within the types of risks contemplated when we added scheduled contingency last quarter. While we utilized a portion of that contingency, our outlook has not changed. We continue to expect project completion by the end of 2027 and energization of the third and final offshore substation by year-end 2026.

From a cost perspective, our current budget remains $11.65 billion, including $123 million of unused contingency. We also continue to see strong customer value. The project's LCOE remains well below the statutory threshold, as well as the range contemplated in our original filing, and we estimate CVOW will generate approximately $5 billion of fuel savings for customers during its first 10 years of operation. Our overall view of the project remains unchanged. CVOW installation has been significantly derisked and continues to make progress against its schedule and cost objectives while delivering significant long-term customer value.

Now I'll turn to other business updates, as shown on Slide 10. In mid-October, we filed our Virginia Integrated Resource Plan update, which included several possible generation build portfolios designed to meet robust customer demand growth. Relative to last year's company preferred plan, we've added and accelerated 4 gigawatts of solar and 2 gigawatts of battery storage. Importantly, under the company's preferred plan, we're meeting our customer needs, protecting system reliability, maintaining affordability with monthly residential electric bills forecasted to increase on average by about 2.3% annually.

We continue to see a growing role for energy storage in Virginia. Our recently filed IRP is an update and represents a snapshot in time, but it already reflects a meaningful increase in storage relative to our prior plan. Importantly, Virginia also enacted significant energy storage legislation this year that establishes substantially higher targets for both short- and long-duration storage. We expect storage to play an increasingly important role as use cases continue to broaden and the technology continues to advance.

We're actively evaluating both short-duration battery storage and emerging long-duration technologies through the lens of reliability, affordability and customer need. And looking longer term, the proposed combination with NextEra Energy would bring together significant capabilities and experience in energy storage. We believe that positions the combined company exceptionally well to deploy storage at scale as the technology matures and system needs evolve.

Finally, on Millstone. In September, the Connecticut Department of Energy and Environmental Protection provided an update on the zero carbon energy request for proposals, indicating that it intends to announce a decision later this year. The facility's existing PPA has delivered tremendous value to customers, lower costs and significantly reduced volatility.

Despite being priced at the time in 2019 above prevailing price outlooks, the contract is expected to save customers over $245 million this year, including $200 million year-to-date, in addition to the over $200 million in savings to customers last year. Based on current forward curves, the contract is expected to save customers in Connecticut over $900 million over the 10-year life, driven by lower energy pricing. We remain focused on achieving a constructive outcome for the facility, which has delivered tremendous value and produced bill reductions for customers in Connecticut through its existing contract. We will continue to provide updates as things develop.

With that, let me summarize our remarks on Slide 11 by reiterating our focus on our 3 top priorities: consistently achieving our financial commitments; continued achievement of major construction milestones for the Coastal Virginia Offshore Wind project; and achieving constructive regulatory outcomes that demonstrate our ability to work cooperatively with regulators and stakeholders to deliver results that benefit both customers and shareholders. We remain committed to delivering reliable, affordable and increasingly clean power for our customers.

With that, we're ready to take your questions.

[Operator Instructions] And we will take our first question from Shar Pourreza with Wells Fargo.

So Bob, just on -- just as we're thinking about the deal and sort of the staff, I mean, 57 conditions. I guess, can you highlight where you and the staff are kind of furthest apart? What's the deal breaker? Is it, like, the ring-fencing? Is it the dividend restrictions? Can you close any of these gaps before the hearings next month? And then maybe just lastly, comment on the governor's intervention, which kind of seems a little bit excessive to us. How is that dialogue going?

Yes, Shar, great question. 57 conditions, a chunk of them are conditions that were ones that we had already voluntarily proposed. So I think it's important to keep that in mind.

But fundamentally, as you heard from John on NextEra's call a week or so ago, we're still focused on the statutory standard, which is no harm. That's what the judges are going to follow. We'll file our rebuttal testimony on Monday. Look forward to the hearing beginning on the 17th of November.

And we remain confident that our position goes beyond the statutory standard, will deliver benefits, not just no harm to Virginia customers, to employees and communities. It's going to keep our company locally led, still regulated by the SEC, fully accountable to them. John said it on their call, the judges of the SCC are going to follow the law. That's the best that we could possibly ask for. And we look forward to presenting our rebuttal testimony on Monday.

Got it. And then just the governor, how is that dialogue going? Just, I guess, I don't want to say behind closed doors, but is what we're seeing publicly different than what conversations you're having privately?

Well, the governor is participating as an intervenor in the case as she is obviously entitled to do, and we welcomed her intervention. We're participating in the case through the filings that we make in the case. We obviously talk to parties as makes sense. But really, our focus right now is the testimony that we're filing on Monday, making sure that we're all very focused on the no harm legal standard.

Got it. Perfect. And then just lastly, on CVOW, I mean, obviously, we saw a little bit of a healthy drop in the LCOE to $62. Obviously, a lot of that was driven by RECs going to $38. I guess, what are you seeing in the RECs market that drive that? And is sort of $38 kind of sustainable in your view?

Sure. It's Steve. It's hard to predict the price. We obviously reflect it quarterly when we update the filing, and very transparent about it. What we're seeing is a tightening of supply and demand, sort of unsurprisingly. And remember that a large portion of those RECs need to be generated by Virginia resources. And so that obviously adds an additional constraint, which pushes prices up. And remember, the way that math works is that we credit the revenue from those REC-generated sales by CVOW against the LCOE. That's why you see that price come down.

But we've seen it kind of go up and down. It was a little higher. Now it's back down a little lower in terms of the LCOE. I think the most important thing is we continue to believe CVOW will provide significant value to our customers.

Our next question comes from Nicholas Campanella with Barclays.

Maybe just sticking with the merger, similar question just on South Carolina. Any reactions to testimony there that recently came in? Is there a path forward to settle South Carolina? And any thoughts on just the bill credit, 4 years versus 2 years?

Yes. I'll give a similar answer, Nick, to the question I gave on Virginia. We're in the process, in the regulatory process there. We continue to work our way through. You all have the procedural time lines in front of you. Next step for us is for us to file our rebuttal testimony and then go into the hearing.

We continue to believe that we've presented a very strong package in South Carolina the same way we did in Virginia, and we look forward to an opportunity to demonstrate that to the commission. Obviously, we work with parties in all the states and all the regulatory proceedings that we're involved in to try to find a good outcome.

Okay. And then maybe moving to Millstone. I know you're saying there's a decision here potentially by year-end. Can you just remind folks of the general time line? Do you get term and price by then? Or is that just that Millstone could have been selected as part of this wider process? Maybe just a little mark-to-market on those discussions.

Nick, we're encouraged and constructively engaged with the parties in that process. A little difficult to say with certainty as to sort of what would be public at the end of the year. We don't -- certainly don't want to speak for or get ahead of the regulators in this case. But I do think we'll feel like we've got a little bit better sense of where that process is going by the end of the year. And then of course, as we have announcements to make, we'll be excited to make that public to folks.

Our next question is from Paul Zimbardo with Jefferies. We'll move to our next question from Anthony Crowdell with Mizuho.

How about now? Can you hear me? Sorry, has that worked?

Yes, it works. We were starting to get a little worried there.

I know. I think Paul is out trick or treating. So he's just probably getting his last candy.

We're glad to know you waited until the call was over.

I just have one quick question. You guys gave great clarity on CVOW, continuing to derisk it, I think you're 85% complete. I think maybe it's more of a sector-wide question. The sector is now approaching some large generating project construction. You guys have clearly plowed through this project, which is maybe one of the bigger ones going across the country.

I guess, how should investors think about execution risk across the sector as we're starting to see utilities pursue like larger generating units? You guys have plowed through it, you continue to derisk it. But I don't know if it's lessons learned or something, or what would you tell us we should focus on as you guys are successful with CVOW and we're seeing now other utilities go down this path?

Yes, that's a great question, Anthony. And I wouldn't limit our experience just to CVOW. It hasn't been that long since we finished some sizable combined cycles here in Virginia. And our focus is having an experienced project construction team that is working with contractors that we have familiarity with. They know the risks to look at. Our Board has become quite comfortable asking us questions about the risks that we should be focused on. Not surprisingly, those line up often around what are your potential labor constraints, how does the supply chain look, and having familiarity with all of that is really valuable.

So at least in our case, we're comforted by the fact that we have an experienced team that has handled big projects. Not just on the gen side, by the way, but on the transmission side of the house as well because we've done an awful lot of that work over the last few years to put that experienced team, combined with strong counterparties where we have confidence in the supply chain.

And then finally, familiarity with the permitting process. I mean, I think we all know that there could be challenges in these projects when permits get off track. And so having the relationships necessary in order to work your way through the permitting process is critical as well.

Our next question is from Carly Davenport with Goldman Sachs.

Maybe just to go back to CVOW. I appreciate the time from jack up to jack down is tracking in line with your expectations. I guess, could you just help us think about the other items that can impact the overall timing and how you expect those to trend as we look over the next few months just as we think about weather, et cetera, moving towards the end of the year?

Yes. I mean, beyond the jack up to jack down time, other factors that we think about that we've identified are weather, maintenance, transit and loadout time. We've made assumptions regarding weather. We don't have the ability to control that, obviously. And then on the other items, our loadout times continue to improve. Our transit times are defined by where we're going on the project. And I think the team has put together a very good schedule to minimize those transit times so that we are putting turbines up close to each other rather than crisscrossing across the project. And maintenance is a factor that we put in, and everything gets a little bit better as we move along.

So if you think about, Carly, when everything we've done on this project, we get quite a bit faster as we go along. Just give you a few statistics on the installation time. So our first 10 turbines took an average of 69 hours each to install. The next 25 took an average of 45 hours, so that's a 35% improvement. And then the most recent 9 averaged 38 hours, which is a 45% improvement to the first 10.

So we're improving on the installations of turbines the same way we improved our timing on monopiles, the same way we improved our timing on transition pieces. As I mentioned, we continue to get faster on the turns at port. Obviously, we don't do as many of those because we're loading 4 turbines each time. But we're getting faster with that as well. I think our plan is good on transit time. And any maintenance we have to do, if we've done it before, it will be faster the next time we do it, as we found going along.

Carly, I think it's a really fair question. If I can put some numbers around what I think you're asking about, in addition to the great answer Bob just provided. If you think about the last 3 months, we had about 91 days in that period. 14 were impacted by weather and about 36 by the vessel maintenance we've described, which means we installed about 13 turbines over about 41 available days, which equates to about 3.2 calendar days per turbine, which again is a little higher than the 2 because that doesn't include transit. And looking forward, we have about 425 calendar days left through the end of '27 to install the remaining 132 turbines, which, by coincidence, is also 3.2 days per turbine.

And I think what's important to note, as Bob just mentioned, is the timing for the jack up and jack down, even though our base assumption is 2 days, as he just mentioned, our most recent 9 have been closer to 1.5 days. If you were at 1.5 days, you'd be able to do the remaining turbine installations in about 200 days. If you stayed that 2 days per turbine, you'd be 265. And we expect about 33 of those loadouts at the port, each take about 4 days or 130 days in total.

So if you put all that together, 427 days, 200 to 265 days for turbine installation, 130 days for port turns, that leaves somewhere between 30 and 95 days for weather, maintenance and if you need more time for some of the more difficult locations for turbine installation. So I think that gives folks a little bit of a sense of sort of how much contingency is in the plan from a timing perspective, and that's what gives us that confidence. In addition to what Bob described, which is as we go through the various iterations of construction, it gets faster every single time.

Great. That's incredibly helpful context. And then the follow-up is just a housekeeping item. It looks like just for the 4Q drivers, O&M has shifted from being a drag to a help. Anything in particular that you flag as driving that? And is there any read-through on that into 2027 O&M trends with that in mind?

No, Carly, nothing specific. We obviously reevaluate those drivers quarter-by-quarter to reflect the latest perspective on the forecast. I would say we gave our guidance to be in the top half, and I think I put in my prepared remarks that, that includes some conservatism around November and December weather, as well as potential opportunities to derisk financial performance. So we're going to have that lever available to us as we go out to the last 2 months of the year to make sure we land solidly where our guidance is, updated guidance, but also take steps necessary to derisk future years.

Our next question comes from Paul Zimbardo with Jefferies.

I'm back. I think Anthony was ringing my doorbell, trick or treating.

Good to hear from you, Paul.

And I appreciate there's a lot of math in that last answer. So hopefully, an easier one. Could you describe the nuclear upgrade opportunities, more so the regulated fleet, but also the unregulated asset? And just kind of where you are in exploring some of these potential expansions?

Yes. Paul, good question. We've got some limited opportunities, we think, at Millstone, as we've discussed before. The regulated fleet, we've done a lot of upgrade work over the years. Our focus at the regulated fleet is the investments necessary for subsequent license renewal. We're extending the lives of those plants for another 20 years. So that's really where the work is going on right now. We always look for opportunities for updates where it makes sense we can do it safely within the appropriate safety margin.

Okay. Understand that. And then one last on kind of Virginia and the new IRP. I think you mentioned the 4 gigawatts and 2 gigawatts of incremental pull forward. Just -- if you could frame like what could that do to the capital plan, the rate base growth? Any kind of color you could provide there would be helpful.

Absolutely, Paul. So if you look at 2025's IRP relative to the latest IRP, it effectively through 2034 increases the battery on the system by about 4x. So for instance, in the 2025 IRP, 2030 through '34, battery was 850 megawatts. In the 2026 update, it's 3.3 gigawatts. And think about the capital cycle around that is about a 2-year time frame where you're spending that capital leading up to the actual COD.

So obviously, as we roll forward and pick up '31 in our 5-year plan, we'll be picking up 1 additional year of not just what the existing battery capital opportunity was, but actually this enhanced battery capital opportunity. And we framed that as every gigawatt being sort of $2.5 billion to $3 billion of opportunity.

Now keep in mind, some of the IRP would be under a PPA structure. Obviously, we don't -- wouldn't include that in our rate base, but the majority of it is under self-build, consistent with the Virginia Clean Economy Act. So I think as we think about roll forward, there's a very meaningful opportunity for capital enhancement in order to comply with the legislative and policy intent of the state.

We will take our next question from Nick Amicucci with Evercore ISI.

Sorry, I did want to just kind of revert back to the merger quickly, if I could. There was one point of contention just within the SCC's staff testimony there. And I just wanted to kind of clarify it to understand it, I guess.

Just as we think about the ring-fencing and the bankruptcy remote special purpose vehicle, I guess, what are they really looking for there? Like, I understand kind of like the protection for Dominion. But just, I guess, how would -- how does that structure kind of -- like what should -- how should we think about that structure?

Yes. Totally understand why you'd ask that question. But as I mentioned, we're working our way through the regulatory process now, which involves filing a rebuttal testimony on Monday and then a hearing just a few weeks away. So we're going to continue to present what we think is a very strong package through that regulatory process. But I can hope you understand why I wouldn't want to be getting into the details of that on the Friday before we file our rebuttal testimony.

Very fair. Very fair. And then just wanted to think through to just the funding requirement. Like as we think about that as we move into 2027, just how much flexibility exists if we have some load kind of acceleration and a potential, like, delay in any closing?

Are you asking, Nick, about our -- sort of where our 2027 financing needs might be and how that could be impacted?

Yes. If you think about it specifically on the equity issuance side.

Yes. So when we did our call in the fourth quarter, we gave a 5-year look. And we indicated that from -- at least from an equity perspective, it was very back-end loaded in sort of the last couple of years of our plan. I don't want to get out ahead of our sort of updates to the forecast. But generally speaking, we were seeing '27 and '28 as relatively lighter equity years. And I haven't seen anything that suggests that would be necessarily different.

Thank you. This concludes our question-and-answer session, so I'll turn it back to Bob Blue for closing remarks.

Thanks, everybody, for taking the time to join the call today. Enjoy the rest of the day. Thanks.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Welcome to the Dominion Energy's Second Quarter 2026 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to David McFarland, Senior Vice President, Investor Relations and Treasurer.

Good morning, and thank you for joining Dominion Energy's Second Quarter 2026 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 Stephen.

Thank you, David, and good morning, everyone. Since the conclusion of the business review almost 2.5 years ago, we've remained steadfastly focused on 3 top priorities: first, consistent achievement of our financial commitments; second, continued 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 benefit both customers and shareholders.

As we'll discuss today, we continue to demonstrate success against these priorities, extending our track record of high-quality and consistent execution. I'll cover financial results and demand trends in my remarks, then Bob will provide updates on the NextEra Energy combination, CVAL, regulatory results and other business items. Turning first to second quarter results, as shown on Slide 3. Second quarter operating earnings were $0.79 per share, which includes $0.03 of RNG 45Z credits. A summary of earnings drivers relative to the prior year period is included in Schedule 4 of the earnings release kit. Second quarter GAAP results were $0.37 per share.

A summary of all adjustments between operating and GAAP results is included in Schedule 2 of the earnings release kit. Similar to last year, we've had a strong first half, which positions us well to deliver strong full year results. Additionally, we are reaffirming all financial guidance provided on our fourth quarter earnings call, including operating earnings, credit, dividend and long-term growth guidance. Turning to financing on Slide 4. We've now completed our common equity program for 2026, consistent with our ATM guidance on the fourth quarter call.

Full year 2025 and Q2 LTM FFO to debt metrics are both above 15%, demonstrating our continuing commitment to our previously communicated credit-related targets. Turning briefly to sales. We're continuing to see strong sales in our service areas, driven by continued economic growth and data center expansion. Notably, 9 of the Dom zones top 10 all-time peak days have occurred this year, including the 8 highest summer peak days, which have all occurred in the last 2 months.

We want to take a moment to acknowledge the outstanding work of our colleagues who have maintained exemplary system reliability in the face of record-setting demand and difficult weather conditions. Their commitment and dedication on behalf of our customers and communities is worthy of special recognition even if most of them would tell you they were simply doing their job. Turning to data centers on Slide 5. We now have over 53 gigawatts of data center capacity in various stages of contracting, including approximately 12 gigawatts of capacity contracted under electric service agreements.

To put that in context, we've added over 5 gigawatts of contracts or roughly 11% since the end of last year. Since our last update, we continue to see robust and durable demand from our differentiated, high-quality, low-risk data center customers. Importantly, these customers consistently tell us that many of their highest value workloads need to be built and need to stay in Virginia because of the unique network density, connectivity and ecosystem advantages that have made Virginia the world's leading data center market.

And we're bringing those customers onto our system in the right way, protecting existing customers from cost shifts while mitigating stranded cost risk by utilizing a large load framework that ensures these customers pay their fair share of the investments required to support their growth. In closing, we've had a strong first half of the year, and I am highly confident in our ability to deliver on our financial commitments, including our 2026 operating EPS and credit targets. Our financial plan strikes the right balance of appropriately conservative, but not unreasonably so. And with that, I'll turn the call over to Bob.

Thank you, Stephen. I'll begin with safety on Slide 6. Our employee OSHA injury recordable rate for the first half of the year was 0.36, which remains well below industry average. Safety is our first core value, and we must continue to focus relentlessly on improving our safety performance. Turning next to our announced combination with NextEra Energy.

As we detailed in May, this transaction represents a truly transformational opportunity to bring together 2 world-class utilities with 238 years of collective industry experience to even better serve millions of regulated customers across 4 states. Looking ahead, we believe we can accomplish far more together than we can apart. Under the proposed terms of the merger, Dominion Energy customers would receive $2.25 billion in shareholder-funded bill credits, representing meaningful customer value.

Over the longer term, customers and communities would benefit from a stronger company with the scale and capabilities to buy, build, finance and operate critical energy infrastructure more efficiently, helping support reliability, affordability and economic growth. Earlier this month, we filed our joint proxy statement on Form S-4 as well as our state and federal regulatory applications with the Virginia State Corporation Commission, the North Carolina Utilities Commission and the Public Service Commission of South Carolina as well as the Federal Energy Regulatory Commission and the Nuclear Regulatory Commission.

The Virginia State Corporation Commission has now issued a procedural schedule, including evidentiary hearings beginning on November 17. In South Carolina, the proposed scheduling order would set a hearing date of December 8, with the final order by January 29, 2027. The South Carolina Senate, House and Office of Regulatory Staff have indicated they do not object to the company's proposed schedule. We expect the commission to rule on the proposed time line next week. The time lines for each of the proceedings are shown on Slide 7. I could not be more excited about the combination of these 2 companies.

We'll continue to share updates as we progress through shareholder and regulatory processes. Turning next to offshore wind. As illustrated on Slide 8, CVOW continues to achieve significant derisking milestones as evidenced by its 81% completion status. Let me highlight a few factors that give me great confidence in the successful completion of this project. First, supply chain. We're making excellent progress toward completing all remaining equipment, a key project milestone. 100% of nacelles, 99% of towers and 85% of blades have now been fabricated. Towers will be completed in the coming days, followed by final blades in October. Second, installation.

As of today, we've successfully installed 31 turbines with the installation of the 32nd currently in progress, averaging approximately 2 days of operations per installation from jackup to jack down in line with our prior assumptions. It's worth noting that the 31 turbines installed to date have a capacity of more than 450 megawatts, rivaling the magnitude of some of our fossil units. We expect the third and final offshore substation to be energized by year-end, which is especially meaningful because it will signify that approximately half of project investment adjusted for network upgrade costs has achieved in-service status. That's a meaningful milestone toward project derisking.

And third, proof of concept. We've now successfully completed every major fabrication, construction, commissioning and operation evolution multiple times. This is noteworthy because we've clearly and affirmatively answered the question, will this work? Every type of component is in service and functioning as expected. Turbines, inter-array cables, substations, export cables and onshore transmission and distribution infrastructure are all working together to provide much needed power to our customers.

In fact, in recent weeks, as we've set new demand peaks, we've done everything possible at the request of system operators to deliver the maximum possible amount of power from CVOW. In my mind, it's critical to note that CVOW is significantly different from a traditional power plant, and we're not waiting for a final switch to be flipped to confirm proof of concept or to qualify investment for regulatory recovery. Rather, CVOW is effectively 176 individual power plants, each entering service upon completion.

This allows the project to clearly demonstrate technical feasibility and deliver energy to the grid well before the final turbine begins to spin. That's why for CVOW, it's important to note the project's derisking is heavily front-end loaded. -- and in our view, mostly behind us. Turning to Slide 9. Let me update you on expected timing of installation of the project's final turbine, which we're adjusting by 6 months to reflect 3 updated assumptions. First, given previously reported delays with Cardus and BOM suspension order, weather and vessel maintenance contingency had been significantly reduced.

Today, we're adding incremental weather and vessel maintenance schedule contingency to the plan, which assumes somewhat better than normal weather consistent with our overall weather experience thus far as well as the continued optimization of our installation iterations. Second, we're adjusting the schedule to account for additional time required for our loadouts at PMT based on observed performance times to date relative to our prior assumption. Finally, based on continued data gathering, we're adjusting the schedule to account for what we expect will be longer duration jacking operations for certain remaining turbine locations.

Relative to the other approximately 80% of turbine locations, we expect based on subsea geotechnical analysis, this subgroup to require additional time for jacking operations. Moving now to capital investment. As shown on Slide 10, we're updating the project cost estimate by a little less than $250 million. Our most recent budget was $11.4 billion, inclusive of $123 million of unused contingency.

As highlighted on our last call, we've added $228 million for additional tariff costs associated with revisions to the prior steel and aluminum guidance, and we've subtracted $502 million to account for the reallocation of certain PJMassigned network upgrade costs. We've also added about $234 million of miscellaneous costs that primarily reflect additional cable protection to account for faster underwater currents, fuel costs, mitigation costs for the more difficult jacking locations and final onshore construction costs.

The total of all these adjustments is a net reduction to project costs of around $40 million, so essentially a wash. From there, we've added about $288 million to account for the incremental 2 quarters to complete the final turbine installation. You'll note that this averages out to about $144 million per additional quarter, which is below the low end of our prior rule of thumb guidance of $150 million to $200 million per quarter. As a result, we're increasing our project cost estimate by approximately 2% to $11.65 billion, which continues to include $123 million of unused contingency. Turning to Slide 11. The project's cost sharing and risk sharing continue to work as intended to protect customers and shareholders with minimal changes to LCOE or customer bill impacts. We anticipate that approximately 1/3 of the most recent cost increase will be shared with our financing partner. CVA remains 1 of the most affordable sources of energy for our customers. Our analysis indicates that the project is expected to generate fuel savings of approximately $5 billion for customers during the project's first 10 years of operation.

On regulatory, we received a final order in our 2025 rider filing proceeding on July 29, approving 100% of our revenue request. As I mentioned last quarter, and all of the above approach to energy supply, including CVA is critical to ensuring continued reliability amidst real-time growing demand in our service areas as evidenced by new demand peaks that Stephen mentioned earlier. Building new energy generation is a core competency of ours as demonstrated in recent years with our successful development of thousands of megawatts of renewable generation as well as combined cycle plants at Greenville, Brunswick and Warren County.

We continue to advance the development of new generation capacity consistent with our update last quarter. We recently filed the air permits for two new natural gas fired combined cycle plants, Kennady station in South Carolina and at Mount Storm in West Virginia, representing nearly 5 gigawatts of new capacity. In addition to producing much needed energy for our customers, these projects will be an economic benefit for the states in which they operate. generating thousands of new jobs, billions of dollars of economic investment and meaningful local tax revenue.

Now I'll turn to other business updates as shown on Slide 12. In South Carolina, the comprehensive settlement agreement and DESC's electric rate case were unanimously approved by the Public Service Commission of South Carolina in June with rates becoming effective at the beginning of July. We appreciate the engagement of all parties. We now achieved successful settlements in each of our last 4 South Carolina base rate cases across our electric and gas businesses.

Finally, on Millstone. We've heard recently from the regulators in Connecticut, and we expect a solicitation decision from the Connecticut Department of Energy and Environmental Protection regarding the facilities bid in the 0 carbon energy request for proposals in the near term. Consistent with the process laid out previously, we anticipate negotiations with local state utilities will begin thereafter, and contracts will then be submitted to the Connecticut Public Utilities Regulatory Authority for approval. The time line for reaches up to 180 days.

The facility's existing PPA has delivered tremendous value to customers. Lower costs and significantly dampen volatility. Despite being priced at the time in 2019 above prevailing price outlooks, the contract is expected to save customers over $300 million this year including $190 million year-to-date in addition to the $200 million in savings to customers last year.

Based on current forward curves, the contract is expected to save customers in Connecticut over $900 million over the 10-year life. We remain focused on achieving a constructive outcome for the facility which has delivered tremendous value and produce bill reductions for customers in Connecticut through its existing contract. We will continue to provide updates as things develop.

With that, let me summarize our remarks on Slide 13 by reiterating our focus on our three top priorities: consistently achieving our financial commitments, continued achievement of major construction milestones for the Coastal Virginia offshore wind project and achieving constructive regulatory outcomes, that demonstrate our ability to work cooperatively with regulators and stakeholders to deliver results that benefit both customers and shareholders.

Our first question comes from Nick Campanella with Barclays.

Good morning. Thank you. Maybe just on the offshore wind time line, just part of this seems to be getting a better sense of your sequencing and installing the turbines, which you're just kind of repeating now. But just how would you kind of frame risk of further slippage? Are there any ongoing activities, I guess, that you're going to get new data on that should be monitored? And just what kind of informs confidence that year-end '27 is the right date now? .

Yes, that's a great question, Nick. And the short answer is I'm confident in the updated time line. But let me take a step back. The strategic value of Caval hasn't changed. It's remains one of the fastest ways to bring a lot of power to our customers. And it also remains one of the most affordable sources of energy for customers. And the financial plan, as we outlined, remains durable and resilient as we finish construction.

But there are really sort of two ways to think about progress in derisking -- and are largely the same. Have final completion, you don't have power. But CVA is different. As I mentioned, we already have more than 450 megawatts on the grid. That's comparable to a sizable generating unit.

It's also different from a regulatory recovery perspective. This isn't a project where the entire asset waits on one final COD event. We expect approximately half of project investment adjusted for network upgrade costs to be in service by the end of the year. So that's also a very meaningful derisking milestone. And so as we think about the schedule on remaining work, we continue to get better.

Our most recent reload of towers and cells and blades at the Portsmouth Marine terminal was our fastest we've had so far. We're continuing to refine our jackup times, our sequencing, our installation, our execution. Once we're jacked up, the installation process continues to get better. That's the same learning curve we've seen elsewhere on the project, whether it was monopiles or transition pieces.

Now at the same time, the updated schedule reflects what we have learned based on actual load out timing in Portsmouth. We've added cushion for weather and vessel maintenance contingency, and we now have added some longer jacking durations at certain and more challenging locations. So it's not a theoretical schedule. It's based on experience, which is what we said we would base it on, on prior calls.

So the way I would summarize it is this way, the final turbine date has moved but the project has been substantially derisked. CVAL is already producing power. It's already benefiting customers. It's already supporting regulatory recovery. We don't have to wait until the last turbine is installed at the end of 2027 to see the value of this project, we can see it now.

All fair points. Appreciate that. And then maybe just moving to the merger. It's great to see documents got filed at the respective regulators. I know there have been some headlines in Virginia that they like certain folks would like to see a more extended time period for review. But to your point, in the prepares the procedural schedule has been set. So just your expectation that the procedural schedule stays as is and just any data points you would highlight there?

Yes. I mean I would echo what John said on Nexera's call. The conversations that we've had with stakeholders thus far have gone well. As to the specific time line and the discussion that you mentioned, worth noting that at a June meeting of the Energy Commission of Virginia, the SEC staff indicated -- the SEC is used to working with statutory deadlines and they did not directly asked, didn't indicate they needed more time or more resources.

We also happen to believe the current time frame is sufficient, particularly when you look at the level of expertise on the Virginia Commission and the Virginia staff, they've done mergers before, they're used to working in these kind of time lines. They handle rate cases of great complexity in -- with statutory time lines all the time. So when we look at it that way, we think that the schedule that has been set forward makes a lot of sense, and we don't think it makes a lot of sense to change the rules in the middle of the game.

Our next question comes from Paul Zimbardo with Jefferies.

The first I was going to ask that there was another report in Virginia just around grid disruption, some of the data centers turning on their backups both or otherwise on the transmission line. Do you see a need to kind of incrementally strengthen the system with a transmission storage or elsewhere, just as here. ever very critical -- the most critical infrastructure in the U.S. in your service trajectory. Any change you see coming out of these events? .

Yes. Paul, it's a great question. At a high level, I'll answer that and then turn it over to Ed Bain, who is our EVP and CEO Utilities. The highlight is that this event is 1 that our planners handled very well. Our system operators handled very well, worked with but we can always learn. And to the sort of broader question that you asked before Ed gets into a little more of the specifics, we've been working very hard to upgrade the transmission system for some time. we feel like we're as good as anyone at operating a transmission system with these kinds of large loads.

We have more experience than anyone else. We've been investing heavily as you are aware in the transmission system over the years, including some very specific projects in that part of our territory in the last few years. So we'll keep that up. We'll keep learning from this event. But Ed, is there anything you want to sort of talk about specifically on that?

Yes. So Paul, you're right. We did have transmission line that experienced a fall last week did go out of service. And these are rare on our reliable grid, but they do occasionally occur. And we do expect typically the data centers would ride through these momentary events without shifting the backup power, but they didn't in this case. And as Bob mentioned, we have and will continue to collaborate closely with these customers to identify other mitigation opportunities.

We've been sharing information and we'll continue to do so and implement lessons learned. We don't feel like there is significant investments that need to be made because we've been doing that in the grid, but we do believe there will continue to be other mitigating items that we'll implement.

Okay. Great. And then somewhat related, just on the battery investment, the mandate by legislature this year, any time line or incremental color that you can give on when we should start seeing more proposals to meet those needs? .

Yes, Paul. Similar to what we shared on the last call, the legislation calls for an acceleration and an increase in the target, and we're in the process now of ramping up. As I mentioned, we have $2 billion in the current 5-year forecast, represents about 3% of the total 5-year capital plan. The two sort of milestones I'd point you to you to think about is there will be a technical conference this fall, where we'll go through -- it will be sponsored by the commission permitting and feasibility technical analyses around the ability for us to deploy battery more quickly.

And then in the IRP that will come out, we'll incorporate our latest perspectives and views on our ability to accelerate on the battery side. But I think as we mentioned in the last call, we would expect given the policy that, that's going to require that we're going to need to ramp up more quickly. And that means developing additional development expertise and building the pipeline for supply chain as well as building sort of a pipeline of developers much the same way we did on the solar side when we ramped up after the Virginia Clean Economy Act was passed.

Our next question comes from Carly Davenport with Goldman Sachs.

Just sort of follow-up on the turbine installations. Are you able to expand a bit more on where you see the most opportunity for efficiency in the time line just with the reduction in the days per turbine that's sort of embedded in the new target relative to where you've trended over the last couple of earnings calls.

Yes, Carly. I mean I think we laid it out, but the areas that we would be looking for would be quicker turnarounds at Portsmouth when we're in reloading. And as I mentioned, the turnaround this past weekend was the fastest 1 that we've had so far. -- and then the ability to jack the vessel up and jack the vessel down faster as we get into the more challenging locations. Those would be probably the 2 places that we would look the most to try to continue to pick up pace. And as we've experienced throughout the project as we do these iterations more times, we tend to get faster and more efficient.

Great. Okay. That's helpful. And then the follow-up, you had mentioned the proposed Mount Storm combined cycle plant. Just to confirm, that would be incremental to the base capital plan. I just want to make sure that's accurate. And then -- it seems like there's growing focus on West Virginia with the states focus on building out incremental data center capacity there. So just anything you could share on other opportunities you might see there? And just how we should think about the timing and path to regulatory filings.

Carly, I'll take the first half, and Bob, you can speak to the second. But Carly, this is an incremental project to the current capital plan. we had outlined an acceleration of capital towards the back end of our plan, driven by some of these natural gas investments. And if you look at the most recent IRP, it actually sort of continues into the early 30s as well where we project a continued build-out of these resources to support the reliable service to our customers. .

And Carly, as to the second part, the focus on West Virginia is certainly not new for us. We've been operating the Mount Storm power station are for decades. That's been a really important workhorse of our fleet and continues to be. But we saw the opportunity to support our regulated footprint and the generation needed to serve growing demand that we've been describing for some time. We have the available property there. We can get gas there. And so it's a great opportunity for us to help our build program that we need to serve regulated customers, which is our focus.

Thank you for your question. This concludes our question-and-answer session. So I'll turn it back to Bob Blue for closing remarks.

Thanks, everyone, for taking the time to join the call today and enjoy the rest of the day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Good morning, and welcome to the NextEra Energy and Dominion Energy Merger Conference Call. [Operator Instructions]

I would now like to turn the call over to Mark Eidelman, Director of Investor Relations.

Good morning, everyone, and thank you for joining the special call regarding the combination of NextEra Energy and Dominion Energy.

Today's presentation includes references to non-GAAP financial measures. Please refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measures.

With me this morning are John Ketchum, Chairman, President and Chief Executive Officer of NextEra Energy; Bob Blue, Chair, President and Chief Executive Officer of Dominion Energy; Mike Dunne, Executive Vice President and Chief Financial Officer of NextEra Energy; and Steven Ridge, Executive Vice President and Chief Financial Officer of Dominion Energy.

This morning, we'll provide a transaction overview and discuss how we're forming the industry leader. Then we'll discuss why we believe this combination is good for customers, our team, our communities and shareholders. Then we'll discuss the anticipated time line to close and key takeaways.

With that, I'll turn the call over to John.

Thanks, Mark, and good morning, everyone. I can't tell you how excited I am to be in Richmond alongside Bob and his team at Dominion Energy. This is a historic day for our storied companies and for America. Our country is at an inflection point. Demand for electricity is increasing unlike anything we've seen in generations. Today, energy infrastructure projects are larger and more complex than ever before. Practically every corner of America needs power solutions, not someday, but right now.

Speed to power is critical. So too is maintaining affordability and reliability for customers. Unfortunately, a one-size-fits-all solution doesn't exist. It's not that simple. Meeting different customers' electricity demands requires different approaches and different solutions.

The complexity of this moment is as real as it is unavoidable. At the same time, the opportunity set is enormous. Meeting it requires us to enhance our customer value proposition. That starts with scale. Not for the sake of size, scale must translate into capital and operating efficiency, which simply put, enables us to buy, build, finance and operate more efficiently, all to deliver more reliable and affordable electricity to our customers. That's exactly what we fully expect combining NextEra Energy and Dominion Energy would do by uniting 2 industry leaders with 238 years of collective experience. Importantly, the experience for our customers would be seamless. The Dominion Energy name isn't changing nor is how we operate locally, serve our customers or engage with the community.

The same leaders and the same teams customers know and trust will continue serving Virginia, North Carolina and South Carolina. Through this combination, Dominion Energy and NextEra Energy will have access to an industry-leading platform and a robust balance sheet. This means projects can be built even faster and more efficiently. Meeting demand without sacrificing reliability or affordability.

NextEra Energy and Dominion Energy are already world-class utilities, serving millions of customers across 4 states. But we believe we can accomplish more together than we can apart. Combined, we'd be #1 in America in total power generation the world's leader in renewables and energy storage, America's #1 gas generator and second largest nuclear generator. The list goes on and on. When you add it all up, you see this as a unique situation where 1 plus 1 equals 3.

The combined company would serve 4 of America's fast-growing states in constructive regulatory environments. We would expect to grow adjusted EPS at 9% plus and regulatory capital employed at 11% through 2032, anchored by a massive more than 130 gigawatt large load pipeline, which is more than 3x the total installed capacity of the entire state of New York.

The combination only enhances our growth visibility with more than 15 ways to grow across a combined enterprise that's more than 80% regulated and growth drivers evenly balanced between regulated and long-term contracted businesses. Both companies put our customers and teams first as well as the communities we serve. Bottom line, we strongly believe that all stakeholders will benefit immensely from this combination.

Let me start by providing an overview of the transaction. We expect this to be a tax-free all-stock merger that would create a company with an enterprise value of roughly $420 billion and a market cap of roughly $249 billion. Importantly, we expect the transaction to be immediately accretive at closing.

NextEra Energy shareholders would own approximately 74.5% of the combined company, while Dominion Energy shareholders would own the remaining approximately 25.5%. This combination is about bringing together 2 exceptional companies for the benefit of our customers, which is why the combined company will maintain continuity in leadership, board representation and headquarters.

I'll serve as CEO of the combined company. Bob will serve as President and CEO of Regulated Utilities. Leadership at those regulated utilities would remain the same as it is today, with Ed Baine leading Dominion Energy Virginia and North Carolina; Keller Kissam, leading Dominion Energy South Carolina; and Scott Bores leading Florida Power & Light Company.

The combined company would have a 14 member Board of Directors with NextEra Energy appointing 10 of those members. I would serve as Chairman. We would mutually appoint 4 directors from Dominion Energy's Board of Directors with Bob Blue serving as one of the 4 directors. The combined company would trade as NextEra Energy on the New York Stock Exchange.

This transaction builds on a strong legacy of dedicated service across Virginia, North Carolina, South Carolina and Florida. The combined company will continue to put customers first and maintain a commitment to affordability. That would start with $2.25 billion in proposed bill credits for Dominion Energy customers in Virginia, North Carolina and South Carolina spread out over the first 2 years post closing.

The combined company would offer 18 months of job protection and 24 months of compensation and benefits protection post close for Dominion Energy employees. We expect to more than double the size of our combined company over the forecast period. We expect there to be good jobs for many years to come for our talented teams across the 4 states we serve and across America where we have operations.

The combined company will continue to foster strong relationships with local unions in Virginia, North Carolina and South Carolina. The company is also committed to our communities and with increased charitable giving in Virginia, North Carolina and South Carolina by $10 million annually for 5 years post close, which we expected to happen in 12 to 18 months, subject to regulatory approvals.

The combined company would have one of the highest adjusted EPS growth expectations and one of the strongest balance sheets in the industry. NextEra Energy's existing dividend policy would remain in place for the combined company. Dominion Energy shareholders would receive a one-time $360 million taxable cash payment distributed equally across outstanding shares at closing. Until then, Dominion Energy would maintain its existing dividend policy. We expect the combination would enable more efficient access to capital for the benefit of our customers, which I will lay out in more detail in a moment.

If approved, this combination would create a company with unmatched scale, capabilities and opportunities across the utility and energy infrastructure sectors, enabling us to keep bills affordable over time. We're taking the nation's largest utility, most experienced and capable energy infrastructure builder, the most efficient operator at NextEra Energy and teaming that up with another world-class utility sector leader and management team in Dominion Energy to serve 4 high-growth and constructive rate-regulated jurisdictions.

With unparalleled data and data analytics capabilities, the combined company would be optimally positioned to build the right projects at the right time, in the right place, driving what we believe is one of the industry's strongest customer and shareholder value propositions.

To really put our size and scale into perspective, consider this, the combined company's enterprise value would make us the third largest company in the energy sector in America behind ExxonMobil and just barely behind Chevron and bigger than the next 2 largest power companies combined.

Together, we would serve 4 states with a combined $4 trillion economy, which would be top 5 in the world if they were in their own country. And Virginia electricity sales grew twice as fast as the national average from 2021 to 2024. Both South Carolina and North Carolina experienced a surge in population growth, which is expected to accelerate over the next 3 years. And South Carolina continues to be one of the most attractive states for manufacturing.

The combined company's scale and expertise will enable us to deliver reliable and affordable power supporting economic development in all 4 states. That's because building new energy infrastructure creates jobs, building and maintaining affordable and reliable power attracts new residents and businesses, which then requires new infrastructure, and the cycle repeats.

We know this because we serve the rapidly growing state of Florida for more than a century, making smart strategic capital investments to build new energy infrastructure for the benefit of our customers. And we've done it while staying laser-focused on operating efficiently. It's why FPL's bill today is 30% below the national average and is only expected to grow 2% annually through the end of the decade.

The combined company's unmatched scale and operating platform would enable us to meet electricity demand while maintaining affordability across Florida, Virginia, North Carolina, and South Carolina.

Now I'd like to turn things over to Bob.

Thank you, John. First and foremost, let me just say this combination is great for customers. Dominion Energy's customers are at the heart of everything we do every single day, just like NextEra Energy. We're as committed as ever to delivering low bills, high reliability and outstanding customer service and this combination will enable us to continue to do so over the long term.

The collective strength of both companies enhances both our scale and the combined strength of our operating platform, enabling Dominion Energy to accelerate and more efficiently deploy capital to deliver even more reliable and affordable electricity for the benefit of our customers.

As John laid out, the stakes couldn't be any higher. Demand is coming from all sectors of the U.S. economy. Meeting this moment requires a company to buy, build, finance and operate more efficiently. It's easier said than done. It requires scale, deep skills and experience across the energy value chain, together with the ability to leverage technology. That's what NextEra Energy and Dominion Energy together can bring to the table at a time when projects are only getting bigger and more capital intensive.

Let's start with being able to buy more efficiently through a robust and wide-ranging supply chain. The combined company scale enables significant buying power and with an expected annual CapEx spend of roughly $59 billion from 2027 to 2032, that buying power only increases, providing the ability to drive capital efficiency across the supply chain on parts and equipment.

We've built a lot too. In just the last 5 years, NextEra Energy and Dominion Energy have built more power generation than the next 25 largest utilities combined by a wide margin. Remember, our companies have been building energy infrastructure for more than a century, learning with every project and fine-tuning our engineering and construction capabilities. And because we build so much, EPCs are at the ready to support our projects at a more competitive price given our buying power, which means more certainty on project time lines at a lower cost. As a combined company, we expect this should only get better.

Together, we expect the combined company would be able to finance projects more efficiently. We expect NextEra Energy's credit ratings to be reaffirmed. We also expect Dominion Energy Virginia to receive a ratings upgrade from S&P at closing, which should lower financing costs for Dominion Energy customers over time.

At the corporate level, Dominion Energy is also expected to receive credit upgrades, which would enable more economic refinancings as maturities occur. We also expect a 100 basis point improvement in the combined company's downgrade thresholds at S&P and Moody's and an improvement from Fitch.

The combined company is committed to maintaining a strong balance sheet and its current credit ratings. The overall strength of our balance sheet is more critical than ever to cost effectively build energy infrastructure for the benefit of our customers.

Lastly, we expect the combined company will operate more efficiently, leveraging our combined operating platform over more assets with lower costs substantially. Every new megawatt developed would be more efficient to build and operate. And then you layer on top of that, the benefits of scale from our combined 110 gigawatt fleet which is already the largest in America. That massive scale would only get bigger given we expect to more than double the size of our combined fleet by 2032, but it's more than that. No company in our industry can leverage data, analytics and technology better than our combined company using real-time information and proprietary algorithms to anticipate issues before they occur.

Fixing equipment before it breaks is less expensive than replacing a failed part. It's not an accident that the combined company's nonfuel O&M on a dollar per megawatt basis is significantly lower than the national average. The combined company will be better equipped than ever to leverage scale and reduce operating costs as it efficiently invest smart capital, helping drive affordability. That's important given the combined company expects to grow regulatory capital employed at 11% for the benefit of our customers. And it's not just power generation, smart capital investments in grid hardening, smart grid technology and remote operations translate into higher reliability and lower cost for our customers.

A stronger, smarter and more resilient energy grid also speeds restoration after storms. All of these are core tenets of our operating platform. When you put it all together, buying, building, financing and operating more efficiently by leveraging our combined platform adds up to a huge win for our customers today and tomorrow. That's because scale and a strong balance sheet matter more than ever in our industry. It's the winning formula to building projects faster and more efficiently.

This combination is also good for our team and the communities we serve. We understand that our duty to serve extends well beyond generating and delivering electricity. We're committed to being key community pillars. Both companies have a legacy of giving back, volunteering 173,000 combined hours last year alone. The combined company would enhance our charitable contributions, part of a long-standing commitment to make our communities a better place to live, work and raise a family. And we would remain committed to supporting low-income utility assistance programs, helping customers and families and hardship keep the lights on.

This is in lockstep with our core values. Both companies have so much in common. Safety would continue to be central to everything we do. We have a customer-first mindset. We're committed to excellence. We do the right thing, and we treat people with respect. We share a culture of continuous improvement to find ways to get even better for our customers and our communities, and we would operate with a one team mindset with the humility of understanding that being -- providing a critical service is an honor and bigger than any one of us.

As John mentioned earlier, we're committed to maintaining a strong local presence with dual headquarters in Virginia and Florida, along with Dominion Energy's operational headquarters in South Carolina. We'll continue to offer our employees meaningful career opportunities across the enterprise and at a growing company. Our people are our greatest asset. And everything we accomplish every day for our customers is due to the efforts of our industry-leading teams. For all these reasons and more I could not be more excited about this combination.

Now I'll turn things back over to John.

Thanks, Bob. I couldn't agree more with all the points you just made. For those same reasons and more, we expect this combination would also deliver a compelling long-term shareholder value proposition, anchored in strong visible growth. The combined company is targeting 9% plus long-term adjusted EPS growth, supported by 11% regulatory capital employed growth and high-quality cash flows growing in line with earnings.

As I said at the outset, we also expect the transaction to be immediately accretive at closing with a clear path to sustained value creation driven by scale, disciplined investment and execution. As we've discussed this morning, the combined company would become what we believe is an unmatched industry leader positioned to capture an opportunity set that has never been larger. A rate base of $138 billion would be the highest in the industry, reflecting smart capital investments to serve our customers with affordable and reliable power solutions.

The opportunity set is enormous, and we believe we can deploy roughly $59 billion of smart CapEx on an average annual basis for the benefit of our customers to provide the energy solutions they need. Our pipeline with large load customers alone is more than 130 gigawatts. To put that in perspective, our entire portfolio today is 110 gigawatts.

As a combined company, we have more than 15 ways to grow. Importantly, our forecasted growth is visible and balanced between our regulated and long-term contracted businesses. At the core of that expected growth would be the combined company's regulated businesses. The combined company's regulated capital investment would be about 80% higher than NextEra Energy's on a stand-alone basis. From there, we would expect the combined company to grow regulatory capital employed at about 11% annually through 2032.

These are smart, disciplined capital investments that benefit customers. We expect a big piece of that growth will come from population growth and large load demand. In fact, we believe the combined company will have the unmatched opportunity to be the leading partner for large load customers in the U.S. Remember, these are customers who spend capital at a 4:1 ratio to our investment. They can't afford to commit that sort of investment unless they have confidence that an energy company can deliver. That starts and ends with a strong balance sheet, which is exactly what our combined company would bring to the table.

It's also important to remember Dominion Energy has served the world's premier large load market for more than a decade. That experience, combined with the increased execution capabilities of the combined company, would be invaluable, and both companies are committed to both serving large load customers and maintaining affordability for existing customers. And that means large load must pay their fair share.

To meet this increased demand, we believe there's an opportunity to more than double our combined generation fleet with as much as 260 gigawatts of installed capacity by 2032. This would provide us with enormous scale that we expect would lead to enhanced capital and operating efficiencies for our customers. We expect the combined company's scale and diversification would be built on strong, regulated and long-term contracted cash flows. And the combination would add another layer of diversification, spreading the regulated portfolio across 4 distinct regulatory jurisdictions.

Underpinning this business mix and growth would be the combined company's strong balance sheet. It's foundational to everything we do. Whether markets are up or down, it's what has allowed NextEra Energy to consistently invest at scale and at a lower cost driving exceptional customer and shareholder value. In the simplest terms, the stronger our balance sheet, the more efficiently we can fund growth translating to real customer benefits.

Strong diversified cash flows minimize the need to issue equity and allow us to fund growth more efficiently. We expect our equity needs to be modest by any measure for the combined company. We expect to issue about $4 billion of equity annually through 2032, which is roughly 7% of our annual CapEx, less than 1% of enterprise value, approximately 1.6% of our expected market cap and about 1.2% of the company's expected average daily trading volume, all while having one of the most attractive adjusted earnings per share growth rates in the industry.

Bottom line, we expect the combined company will be well positioned to improve our strong adjusted earnings per share growth. We expect 9% plus adjusted EPS growth through 2032 for the combined company, and we are targeting that same growth through 2035, all off the 2025 base.

Through this combination, we believe our growth is more visible and diversified than ever before. Combining NextEra Energy and Dominion Energy only strengthens that outlook. Moreover, we expect this combination to offer additional opportunities to drive upside growth. We believe the combined company can become the go-to partner for large load customers enabling us to expand and accelerate large load opportunities across our 4 regulated utilities and across America.

With NextEra Energy's world leadership in battery storage, there's a potential to accelerate Dominion Energy's capital plan to meet Virginia's storage goals while removing capacity deficit and a reliance on the PJM market. These are just 2 examples.

Now let me walk you through the path to close. The transaction requires customary regulatory approvals at the state and federal levels. It's a well-defined and expected path for a transaction of this scale. I feel terrific about our ability to close the merger in 12 to 18 months.

As we wrap up, I can't stress enough that this is a defining moment. The country needs more energy infrastructure built faster, more efficiently and more affordably than ever before. Combining 2 great American companies can better achieve the speed and scale this moment demands.

Dominion Energy brings a talented and experienced team, strong operating capabilities, 3 premier regulated utilities across 3 high-growth states and a leading position in the country's most critical large load market.

NextEra Energy brings a proven utility operating model, the sector's broadest all forms of energy development platform, a robust supply chain with unyielding buying power and one of the strongest balance sheets to deploy capital faster and more efficiently while leveraging data and technology better than any power company in the world.

Each is strong on its own, together were even stronger with the ability to buy, build, finance and operate more efficiently. That's good for customers. It's good for employees. It's good for our communities. It's good for shareholders. And I know I speak for Bob when I say I couldn't be more excited to get started.

We'll now take your questions.

[Operator Instructions] We'll move first to Steve Fleishman with Wolfe Research.

Can you hear me?

Yes.

Congrats to everyone. The -- John, maybe just there's a lot of strategic rationale here that makes a lot of sense. You arguably are the industry leader already before this deal and had kind of downplayed doing utility M&A. So I'm curious kind of what shifted in your strategic thinking that this made sense or do you like this made sense overall, acknowledging all the strategic rationale you did give.

Yes. Listen, I mean the strategic rationale and the industrial logic are extremely sound. But Steve, when you think about what we have been able to build at NextEra with the scale and the operating platform that we have in place and the ability to leverage technology, if you think about being able to add that and combine it together with another industry leader, it makes us even stronger. And so when you think about those scale benefits, you think about that operating platform, you think about combining the best practices of 4 outstanding utilities with terrific growth opportunities, it's a real opportunity to monetize and optimize the scale and operating platform, the operating efficiencies and the capital efficiencies that we have already very successfully built at NextEra and those only get stronger when you combine a company with the capabilities of Dominion Energy.

And when I think about what this does for shareholders, it couldn't come at a better time and for customers because power demand is higher than it has ever been. And so when you think about leveraging those capabilities that I just talked about that only get enhanced and stronger with this combination. It creates an enormously powerful unlock.

And we talked a lot at our investor conference about our 12 ways to grow. Now we add Dominion's capabilities of growth and all the growth potential that they have. We have 15 ways to grow now. That's incredible growth diversity that's balanced between regulated and long-term contracted. It gives us regulatory diversity across 4 fast-growing states with very constructive regulatory jurisdictions, a large load pipeline that's second to none at 130 gigawatts plus with the world's best large load market in Virginia. We have a chance, a real chance through the combination of all the skills and the operating platform these 2 companies bring together to really drive speed to power, right, which is so important, not only in these 4 states, but across the country to alleviate that supply-demand imbalance, which will really help customers making bills more affordable.

And then you think about the 11% regulatory capital employed growth, the 80% regulated -- 90% to 95% regulated long-term contracted combination of the business, the balance sheet uplift with 100 basis points improvement, the downgrade threshold, the uplift one notch upgrades for Dominion Energy and Dominion Energy in Virginia, the ability with confidence to be able to come out and grow at 9% plus, not only through '32, but targeting the same through '35. The incredible combination of the culture, the talent, the skills, the management team. These 2 teams really work all together, and they fit together like a perfect puzzle.

And we're #1 in just about every category. And we are the only ones out there really building across the United States. We are a builder at our heart, and we're going to bring development skills that I think are really going to help drive affordability for customers across these states. So when I think about it, it's striking to me the value creation for all stakeholders involved. Again, this is a perfect unlock. It's good for customers. It's good for the communities we serve. It's good for employees, and it's good for shareholders. And that's why we looked at this and said, "This is a no-brainer."

Got it. Ticks every box. I guess. So just one other question. Just could you talk to how you are comfortable with the offshore wind?

Yes. I mean, absolutely. So when we look at the offshore wind, I think the Dominion team has just made excellent progress on CVOW. It's on track, scheduled to go in service middle of next year. They already have 14 turbines that are delivering test energy. We know once you've achieved that milestone, you're in really good shape in bringing that project in COD. And you look at the last call that Dominion had and they actually brought the CapEx plan down from $11.5 billion down to $11.4 billion. So as we looked at it, we feel very good about it. We feel like that project is online. And given the investment that's been made there, it's the right thing to do to finish it.

We'll take our next question from Nicholas Campanella with Barclays.

Congrats to everyone on the transaction. I appreciate the time. So I guess I wanted to ask just about the merger process specifically as you kind of progress through the approval process in Virginia and the Carolinas, our understanding is there might have been a Virginia biennial. And just, I guess, how do you think about just rate case strategy as you're getting through the merger process.

Nick, it's Bob. So in Virginia, the expected time line, the statutory time line is up to 6 months. So we file -- if we expect to file in July then you're looking at a decision from the Virginia Commission in January. Our next biennial filing is after that. So we don't believe there's going to be a conflict or an overlap there.

Okay. And then I guess just this kind of marks a more formal entry into Virginia, obviously, in Dominion zones, specifically PJM, and I get that it's regulated size and scale, but just now that you're in PJM, maybe just kind of talk about how that impacts near 12 ways to grow? And if you should see additional kind of upside on the near side from participating in the battery build-out, for instance, that's happening, the gas build-out that's happening in that zone and unlocking those constraints.

Yes, absolutely, Nick. I mean as we look at it, I mean, there's an incredible opportunity here. Given that we're the world's leader in battery storage, the legislation that was just passed by Virginia, there is a tremendous opportunity to meet that capacity short quickly by deploying battery storage in the right places. And there's no better combination of being able to do that given our expertise and our supply chain position around batteries, the software we've been able to develop around optimization. We know what a big impact battery storage can have and how quickly it can have it on capacity short positions.

And so when we look at Dominion in Virginia with the PJM short capacity position, the reserve margin short position as well. I think there's a real opportunity to accelerate investment and accelerate investment in a smart way for the benefit of customers to alleviate some of those capacity payments by deploying battery. So big PJM opportunity.

And I also think, look, with a lot of the changes in the construct that continue to get bandied about in PJM, I think it's going to be up to the incumbent utilities to really help drive and solve the problem here and it creates an enormous opportunity to build more generation, which Dominion is already doing to help solve some of the issues that PJM is facing. I think more of these opportunities are going to inure and accrue to the rate-regulated utilities that are in PJM, which is another attractive part of this transaction. And that's all good for customers because to the extent that we're building generation in our own backyard, we're bringing batteries forward and alleviating that capacity short and the volatility that goes along with it. That is just a terrific answer for customers.

And again, taking the 12 ways to grow to 15, this is a big part of it. And I think we also have an opportunity to really try to help accelerate some of the large load queues and get more generation online quicker, which will really help drive growth and bring customer bills down in Virginia. And we're going to do that in a very responsible way.

Both companies firmly believe that large load has to pay their own fair share. You've seen that in Florida with the large load tariff that we already have in place. We just had a statute that was passed that basically reinforces the importance of that large load tariff. Virginia is no different. South Carolina is no different. North Carolina is no different. That's the mindset that we will bring, but there's just incredible growth opportunities and a chance in this increasing power demand environment to really drive smart capital investments for the benefit of customers to drive affordability.

We'll move next to Julien Dumoulin-Smith with Jefferies.

Nicely done. I got to hand it to you. Strategic rationale, pretty clear cut here. In fact, if I can follow up on Nick's line of questioning and talk about the regulated rate base growth. I mean you guys both had about a 10% number here previously. You're talking about 11% combined. Can you talk about some of the delta there? What is driving the increase in the combined overall rate base growth? I presume this is more of a focus on DevCo and unlocking them from a technology perspective and certainly storage comments earlier. But I just wanted to confirm what is changing when you think about the capital spending plan?

Yes. I mean a few things, Julien, I'll start and I'll turn it over to Bob as well. But when I look at this, first of all, is the balance sheet unlock. I mean you think about bringing these companies together, freeing up an additional 100 basis points in the downgrade threshold metric, getting the upgrade in the credit for Dominion Energy and Dominion Energy Virginia. We've got the balance sheet capacity to do it, which creates more opportunities for us going forward. You start to think about the scale and the operating platform and the ability to invest capital even more efficiently combined with that balance sheet strength that -- those are the things that really lead to the acceleration of the CapEx opportunity that really has us excited about the opportunities to get more generation online that we think benefits customers over the long term.

And sure, while this is an opportunity in Virginia, it's also really important that we continue to drive large load growth in South Carolina and North Carolina as well, but do that in a way that protects the general customer base again through large load tariffs. But you look at South Carolina has always been an economic growth engine, and we think that the investments that we can make, can make South Carolina even more attractive from a power price standpoint for companies to relocate because economic development is so critically important in that state as it is in Florida, as it is in Virginia and as it is in North Carolina and up and down the Southeast corridor, where you're seeing a lot of new investment for manufacturing and industrial concerns on top of the large load opportunity that we've seen around data centers. Bob?

Yes, everything John just said, I completely agree with. I think he is analyzing it correctly. I mean there's no -- I don't think it's any secret that we're seeing rapid growth in sales in Virginia and in the Dom zone. We have a robust plan in order to meet that demand. But with this platform, with the ability to buy, build and operate and finance more efficiently. We've got opportunities on behalf of our customers to serve that load. And I think, Julien, you correctly highlighted one particular area is in storage where the general assembly just added new storage requirements for us, which we think are going to be great for our customers and being able to work with NextEra and this combined company on that, I think, is really going to benefit our customers as we serve them better, and we'll deploy capital faster that way.

Awesome. If I can quickly follow up here around you talked about unlocking Virginia here with storage, how do you think about that unlocking more load growth, right, vis-a-vis data centers, right? I mean there's been a lot of talk about the congestion regionally. How do you think about actually accelerating and enabling Virginia? You guys seem mutually aligned with your state regulator around this. This would seem one of the more important dynamics around approval. But can you speak to that a little bit?

Yes, it's continuing to be important for us to be able to serve all of our load, all of our customers large load included and making sure that we do it in a way that is fair to our residential customers. We've been doing that well. As John pointed out, we have a large load tariff in Virginia. Our plans continue to be to make sure that all of our customers pay their fair share, but to the extent that there are benefits to the larger scale and the new platform, that's going to benefit all of our customers, and we're going to make sure that it does.

Yes, Julien, I would add to that, speed to power. That's what we do. That's what we do at NextEra. We find ways to get generation online quickly, given the development expertise that we have and the tools that we have and the scale and the operating platform, we also have the ability to do it cheaply and in a way that makes sense for customers and to find those right investment opportunities that, as Bob just said, makes sense for large load customers that don't hurt or drive up bills for the general body of customers that we have a duty to serve and that's critically, critically important.

And I think about just back to the Florida example, this is not a mystery on how to unlock. I mean we have been very successful in meeting speed to power, making smart capital investments in the right spots, but also maintaining affordability. And that comes down to the ability to invest capital smartly on the generation and transmission solutions that make sense, but do it in a way that leverages that scale, that operate in that capital efficiency and an operating platform, which is second to none. You think about a company that's #1 in just about every category it is going to be really, really tough for any of our peers or any of our competitors to do it quite as efficiently as we can. And it's an exciting opportunity, not only for Virginia, South Carolina, North Carolina and Florida, but for everything that we do across America.

We'll take our next question from Bill Appicelli with UBS.

Congratulations. Just a question around the cash flow profile, the asset recycling numbers are down a little bit. And I was just wondering if does the scale unlock the ability to monetize some of the tax credits or reduce the need for tax equity? Do you have a higher taxable income base going forward? Can you just sort of speak to that?

Sure. And it's Mike here. As we look at the capital recycling that has come down. I think one thing when you look at the investments that we're making, we are making investments that we think are attractive for our shareholders. And so we generally want to maintain those assets for the long term. As you look at what the business mix creates, it creates a situation where we are now 80% plus regulated and that creates a long-term stability for the growth of our business.

In addition, as you do look, there are some tax benefits that occur, incurred to our benefit as such that we will be able to utilize tax -- use more taxes on our balance sheet than we would have on a stand-alone basis at NextEra Energy. So when you combine those pieces with the reduction in the downgrade threshold from S&P from 18% down to 17% and Moody's from 17% down to 16% and the CFO to total debt basis and the improvement at Fitch, you have a situation where our key rating agencies are really approving this transaction. They like what this is doing from a regulated mix. They like what this is doing from a diversity. And then when you look at the benefits to our cash flows, there are some tax benefits that allow us to monetize more tax credits via the company and put a little bit less reliance in terms of what we are selling to -- or utilizing the tax equity.

Okay. All right. That's clear. And then just on the $2.25 billion rate credit, I guess, how is that being funded? And has that sort of been captured here in the financing plan?

That is captured in the financing plan. I would note that as the agencies have viewed this overall transaction, you're viewing those rate credits as a onetime piece and a onetime event in nature and not part of our ongoing FFO to debt or CFO to debt, respectively. So as we do work through this, what you will see is that, as John mentioned, we have $4 billion of average equity issuances to do per year. I would not expect that to change materially during those first few years, such that it's going to be relatively ratable across the entirety of the period.

We'll move next to David Arcaro with Morgan Stanley.

Congratulations. I was wondering if you could speak to whether there are any infrastructure opportunities that might traverse between your service territories as we look more regionally to the Southeast U.S., like whether there are pipeline or transmission plans that could be envisioned.

Yes, absolutely. I will take that question. So when you look at opportunities that we have through the Southeast and the chance to combine the scale and the platform that we have in place and all the development capabilities that we have across really the energy value platform, the growth opportunities are substantial across technologies. I wouldn't want to make comments today about what kind of opportunities that could create for pipeline investments. That's obviously a separate business that looks at opportunities outside the regulated context.

But when I think about the platform and I think about the combination of capabilities that we're able to bring together just a lot of opportunities. And one that comes to mind is large load, David. You think about the footprint that we have across the United States in 49 states where we do business, just -- and all the success that we're having with hyperscalers today, there's not only a chance in these 4 states to accommodate hyperscale build-out in any smart way, right, like I said before, through large load tariffs that protects the general body. Large load has to pay their own share. It always starts and ends with that. But if we can find the right investment opportunities in these 4 states with 130 gigawatt plus pipeline, I think that provides a direct opportunity for us.

And then when I think outside of the U.S., and you add those 2 together, it only strengthens the relationships and the partnerships that we have. And we've had a lot of success, for example, with the data center hubs. We've talked about what's happening with the 2 federal hubs that we've already been awarded in Texas and Pennsylvania, the same data center hub philosophies being brought to Florida. We could look at those same build-out opportunities in Virginia, for example, as well as a way to accommodate large load coming on.

But again, this has to be done in a way that doesn't compromise affordability for our general body of customers. But there are just so many different ways this combination will help support a company that is involved in every part of the energy value chain. There's nothing that we can't do on our own. There's no capability that we don't have. There is no company in America that looks like us and with this combination there's no company that can drive value across our stakeholders quite like this business can, whether you're thinking about customers, which we always put first, the communities we serve, the employees and the shareholder value proposition and the industrial and strategic logic behind this transaction.

Okay. Excellent. That's helpful. And I was wondering, could you speak to how accretive you expect the deal to be maybe in the near term? And as we're thinking about the 9 plus percent growth and that being up from 8% plus. How does that maybe come in? Like when do you start to realize that? Is that every year in your EPS plan now going forward, you would expect that? Or is it back-end loaded? Just how you would expect that to be shaped?

Yes, Bill, it's Mike here. I think as you know, we said this deal is immediately accretive. And the way that I think about this from a NextEra shareholder value perspective is that we have moved from having 12 ways to grow to having over 15 ways to grow. Those 15 ways to grow our balance between both our regulated growth and our growth in Energy Resources. And so therefore, we have multiple more ways to grow, more diversity and a higher long-term growth rate, one in which we have, as a management team, collectively moved up 100 basis points and have shown that financial visibility between now and 2035. So when we sit here and say, what is that value creation to our shareholders, we think that it's significant.

And then as John also mentioned, there are multiple upsides to where we sit today, particularly, as John mentioned, with 130 gigawatt data center pipeline and ability to have speed to market, data center hubs across the country, four utilities are all in strong, growing economic growth with constructive regulatory jurisdictions and a team that is 100% focused on finding solutions. We think that the addition of Dominion in combination with NextEra is going to create that 9% plus through 2035 and beyond. We both feel very strong about our stand-alone plans. But combined, we think that the value is undeniable.

We will take our next question from Nick Amicucci with Evercore ISI.

I just had one kind of quick one. Just John, you had kind of alluded to your confidence in being able to close in 12 to 18 months. Just any kind of color we can provide around that, just as we think about, obviously, it will be kind of under regulatory scrutiny and just a lot of hurdles to get by just what drives that confidence and why kind of a quicker than probably most would have expected timeframe to closing?

Yes, Nick, absolutely. So first of all, I think we have really tried to thoughtfully structure this transaction. We put customers first, and I think that shows in the structure that we have put together with the Dominion team. And when you think about this transaction, it's a totally different transaction at a totally different time under totally different circumstances with a totally different management team and a totally different approach.

We -- what's different for us this time is we have no asks, right? We are going into this regulatory approval process for the first time with no ask. We're not asking for a generation plan to be approved. We don't have other asks. So no ask. That's a big difference.

Second, we're providing immediate customer benefits with the $2.25 billion in bill credits. And then as you think about beyond that 2-year period with those bill credits with the world-class scale and operating platform that we have, that's going to really help with affordability over the long term as we invest capital to meet increased power demand needs in these 4-growing states.

And I think another really important part of this is we're going to have management continuity. I went through our approach on how Virginia and South Carolina and North Carolina are going to be managed. Local operations are going to be retained. It's going to be the same team and the same faces that customers know and trust. We're going to have a dual headquarters, Juno Beach and Richmond. We're going to have an operating headquarters in Cayce, South Carolina. It's a culture of putting customers first in everything that we're putting forward in our proposal.

And community support, we're increasing the community support by $10 million a year for the first 5 years. Low income support is going to be a big part of what we follow. It's very important to us. It's always been very important to us in Florida. It's always been very important to Bob in Virginia and South Carolina and North Carolina. So that's culturally the same between both companies. And we're a combined entity that's capable of offering all of the above energy solutions that make the most sense for our customers. And importantly, there's no operational overlap here. So when you start thinking about approvals, I mean there's just no operational overlap at all.

And look at Dominion, Dominion has got a great track record and experience in moving transactions forward that makes sense for customers. And these are 3 very important states for Dominion that they've been serving for quite some time. We're looking forward to partnering with them on our approach to all 3 states. And we feel really good about the value proposition that we're bringing forward and ultimately, the states will decide. But I think we've really tried to be thoughtful about the benefits for not only customers, the communities we serve and employees as well.

If I can just jump in for a second here. This is Bob. I think John described it correctly, this deal was built with customers and stakeholders in mind. And as John pointed out, we have some experience at Dominion Energy on getting deals closed, whether it was Questar or SCANA or the divestitures of our LDCs. This was a real focus of our Board from the very beginning after John approached me about a combination. And so we feel very good about the way the deal has come together with the focus on customers and communities that gives us a high degree of confidence.

One thing I'd say that we've done well over the years in getting transactions closed is working with partners on the other side who we were confident in their ability to work to get the deal closed. And so we took that very much into consideration here as we thought about this combination.

And this does conclude the Q&A portion of today's call. Thank you. This also concludes this morning's conference call. You may disconnect your lines, and enjoy your day.

Welcome to the Dominion Energy First Quarter 2026 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to David McFarland, Senior Vice President, Investor Relations and Treasurer.

Good morning, and thank you for joining Dominion Energy's First Quarter 2026 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 Stephen. .

Thank you, David, and good morning, everyone. Since the conclusion of the business review over 2 years ago, we've remained steadfastly focused on 3 top priorities: first, consistent achievement of our financial commitments; second, continued achievement of major construction milestones for the Coastal Virginia offshore Wind Project; and third, constructive achievement of regulatory outcomes that determine our ability -- that demonstrate our ability to work cooperatively with regulators and stakeholders to benefit both customers and shareholders.

As we'll discuss today, we continue to demonstrate success against these priorities as we build our track record of high quality and consistent execution. Turning to first quarter results, as shown on Slide 3. We're off to a strong start to the year with first quarter operating earnings of $0.95 per share. First quarter GAAP results were $0.69 per share.

As a reminder, a summary of all adjustments between operating and GAAP results is included in Schedule 2 of the Earnings Release Kit. We are affirming all financial guidance provided on our fourth quarter earnings call, including operating earnings, credit, dividend and long-term growth guidance.

We continue to guide to annual earnings growth at the midpoint of our 5% to 7% range with a bias starting in 2028 toward the upper half of the range. Our confidence in that outlook reflects disciplined financial management, attractive business fundamentals and the strength of our growing regulated investment profile. First and foremost, this is about our customers and meeting their needs affordably and reliably.

We're monitoring catalysts that could enhance and/or extend our long-term growth rate. We continue to see incremental opportunities to deploy regulated capital on behalf of customers, most recently supported by legislation in Virginia to expand grid scale energy storage targets. House Bill 895 and Senate Bill 448, which are now signed into law require that we petition for 20 gigawatts of short- and long-term storage projects by 2045, a significant increase from the current requirement of 3 gigawatts by 2035.

We'll reflect this new multiyear opportunity as well as other regulated investment opportunities in our capital update early next year. And as Bob will discuss in his prepared remarks, we expect increasing clarity later this year around the opportunity to recontract Millstone.

Turning to data centers on Slide 4. We now have over 50 gigawatts of data center capacity in various stages of contracting, including approximately 10.4 gigawatts of capacity contracted under electric service agreements. Since our last update, we continue to see accelerating and durable demand from our differentiated, high-quality, low-risk data center customers. Large load provisions ensure those customers will fund the infrastructure required for their growth, protecting existing customers from cost shifts and mitigating stranded cost risk.

Quickly on the financing plan and credit. Year-to-date, we have issued approximately $1.2 billion of common equity under the ATM leaving $400 million to $600 million for the remainder of the year, consistent with our Q4 call guidance.

As mentioned previously, there is no change to our credit-related targets. Full year 2025 and Q1 LTM FFO to debt metrics are both above 15% demonstrating our commitment to credit strength, and we continue to derisk CVOW as we achieve major milestones such as First Power in March. In closing, we are off to a good start to the year aligned with our guidance and capital plan and confident in our ability to execute. Our financial plan strikes the right balance of appropriately conservative, but not unreasonably so.

With that, I'll turn the call over to Bob.

Thank you, Steven. I'll begin with safety on Slide 5. Our employee OSHA injury recordable rate for the first quarter of the year was 0.42, which remains well below the industry average. Safety is our first core value, and we're continuing our efforts to drive to 0 workplace injuries. I'll start our business updates with the Coastal Virginia Offshore Wind project on Slide 6. The project is now over 75% complete. And as Steven mentioned, in March, we achieved a very significant milestone with the delivery of much needed power to customers.

General fabrication and installation continue to proceed very well. We've now completed installation of all 176 transition pieces that connect the [ monopile ] foundations to the turbine towers. All 3 substations are installed and commissioning is proceeding as planned. Deepwater export cables are installed and array cable installation is on track. All of the remaining cabling is now fabricated, and the majority is landed in Virginia, and we're making excellent progress on turbine fabrication.

Over 86% of towers, approximately 69% of nacelles and about 45% of blades have been fabricated. This progress tracks well relative to our schedule. With regard to wind turbine generators, we're seeing materially positive improvements in the installation cadence as shown on Slide 7. We affirm our previously communicated time line for project completion with the majority of turbines expected to be placed in service by the end of 2026 and the remainder in early 2027, prior to the end of June.

As of this morning, we've completed 9 turbines. During the first quarter, we successfully calibrated our procedures and equipment and navigated winter weather. Since then, we've been able to ramp the installation rate markedly including averaging approximately 2 days per installation for our last 4 turbines, which supports our existing time line for project completion. We continue to see path to optimize the process, resulting in improved installation times. In addition, we're moving into better weather windows for the next several months.

Please note the current project budget includes turbine installation schedule contingency for weather delays through July 2027 as needed, including [indiscernible] charter costs. I'll also reiterate our general rule of thumb. If the project extend beyond July 2027, we estimate that each additional quarter to complete turbine installation would add between $150 million and $200 million to the project cost, a portion of which would be allocated to our financing partner.

We'll continue to include data from additional installation iterations in our quarterly updates. As shown on Slide 8, the project budget now stands at $11.4 billion. which is approximately $100 million lower than our last update. We've updated the budget to reflect changes in tariff assumptions as a result of recent judicial and administrative actions. Unused contingency stands at $123 million. Looking forward on project costs, we're monitoring the potential of 2 recent events. First, certain regional transmission projects were captured in both the PJM transition cycle, which resulted in network upgrade costs allocated to CVOW and the subsequent broader RTEP award package. As a result, we would expect the overall network upgrade costs allocated by the PJM transition cycle across all generation projects, including CVOW to be reassessed and reduced.

Second, recently updated steel and aluminum tariffs, which are pending additional information from suppliers and guidance from the applicable agencies. As shown on Slide 9, the project's cost sharing and risk sharing continue to work as intended to protect customers and shareholders with no change to either LCOE or customer bill impacts. CVOW remains one of the most affordable sources of energy for our customers. Our updated analysis indicates that the project is expected to generate fuel savings of approximately $5 billion for customers during the project's first 10 years of operations.

Taking a step back and all of the above approach to energy supply, including CVOW is critical to ensuring continued reliability amidst real-time growing demand in our service areas. Building new energy generation as a core competency of ours. As demonstrated in recent years with our successful development of thousands of megawatts of renewable generation as well as combined cycle plants in Greensville, Brunswick and Warren County. We continue to advance the development of new generation capacity consistent with our update last quarter.

In addition to producing much needed energy for our customers, these projects will be an economic benefit for Virginia, generating thousands of new jobs, billions of dollars of economic investment and meaningful local tax revenue.

Turning to Slide 10. I'll reiterate that we view customer affordability as central to our public service obligation. And accordingly, we have a long record of maintaining competitive rates, which continued to compare favorably to the national average. Even while executing one of the largest regulated investment programs in the sector, we expect our customer bills will continue to grow at rates comparable to inflation over the long term, demonstrating disciplined capital deployment and our regulatory construct working as intended.

We continue to be recognized though that customers are feeling the pressure of higher cost for housing groceries and other essentials, including their electric bill. We have a number of programs designed to help our customers manage their bills, including budget billing, energy savings programs and financial assistance programs such as energy share. Late last year, we also launched a new online platform to put all our programs in one place so customers can more easily find the best options to meet their needs.

In addition to providing tools to help manage payments, we're also working to ensure fair and reasonable rates. For instance, the commission approved our recently proposed large load provisions in the 2025 biannual to ensure that our smaller customers aren't at risk of subsidizing our large customer classes nor be left with stranded costs.

We also plan to pursue fuel securitization in Virginia for unrecovered fuel costs to minimize the rate impact on customers. We work continuously to improve the efficiency of our operations while meeting high customer service standards and reliability needs. In recent years, we've driven out cost to improve processes, innovative use of technology and other best practice initiatives. On the technology front, we're focused on implementing technology initiatives that accelerate our mission, and we've recently deployed a range of AI tools.

For example, in our contact center, AI enables clear visibility into customer needs at scale and real-time insight into customer sentiment, allowing us to respond with greater precision and efficiency. Looking ahead, we're intently focused on ensuring our service isn't just reliable that it remains affordable as well.

Now I'll turn to other business updates, as shown on Slide 11. In South Carolina, DESC's electric rate case continues to progress. Staff and other interveners filed their testimony on March 31. We filed our rebuttal testimony on April 21 and expect [indiscernible] rebuttal testimony on May 5, consistent with the procedural schedule. Hearings are scheduled for mid-May, and we expect a decision in late June with rates effective in July.

Yesterday, we filed an electric rate case application and testimony for Dominion Energy, North Carolina to support the approximately $400 million investment placed in service by the company attributed to North Carolina since the 2024 rate case and ensure that we can continue to provide safe, reliable and cost-effective service to our North Carolina customers. We expect the decision in February 2027 with interim rates effective December '26, subject to true-up and finalization in March 2027.

Recall DENC represents about 4% of the company's investment base. Finally, on Millstone. I'll start by noting Governor [ Lamont's ] comments last week highlighting the hundreds of millions of dollars at the current Millstone contract to save customers and which is now resulting in a material customer bill reduction in Connecticut. In March, the facility submitted its bid in the Connecticut Department of Energy and Environmental Protection's zero carbon energy request for proposals.

Per DEEP's published schedule, solicitation decisions are expected in the second quarter with negotiations with the local state utilities to begin in the third quarter. Contracts will be submitted to the Connecticut Public Utilities Regulatory Authority for approval thereafter, the time line for which is up to 180 days. In addition to state-sponsor procurement, we continue to evaluate the prospect of supporting incremental data center activity as well. We remain focused on achieving a constructive outcome for the facility, and we'll continue to provide updates as things develop.

With that, let me summarize our remarks on Slide 12 by reiterating where Steven began the call with a focus on our top 3 priorities: consistently achieving our financial commitments, continued on-time achievement of major construction milestones for the Coastal Virginia Offshore Wind project and achieving constructive regulatory outcomes, that demonstrate our ability to work cooperatively with regulators and stakeholders to deliver results that benefit both customers and shareholders. We're 100% focused on execution. We remain committed to delivering reliable, affordable and increasingly clean power for our customers. With that, we're ready to take your questions.

[Operator Instructions] We'll take our first question from Nick Campanella with Barclays.

So I just wanted to ask on the [ HP 896 ] that you brought up on the battery side. Can you just kind of talk about what's embedded in the plan currently for battery storage, what your recovery mechanisms would be for this new opportunity? And then when you just kind of think about like supply chain, labor, the company's own balance sheet capacity, what does that kind of enable in terms of a gigawatt installation run rate? And what can we kind of expect here if you have any thoughts?

Yes, Nick, great question. So the $65 billion 5-year capital plan, which we produced as part of the Q4 call in February includes already about $2 billion or about 3% related to battery storage, subject to regulatory approval. And what the recent legislation means for us is that in order to achieve the updated targets, we're going to need to work diligently to accelerate the ramp of that capital. And so I'd say things to watch going forward. There's going to be a State Corporation Commission Technical Conference this year on the topic.

We'll, of course, update our IRP in the fall to reflect our most recent thinking on the ramping of the battery storage and then we'll update our capital plan in line with our normal cadence on the fourth quarter. General rule of thumb, a gigawatt overnight installed, including transmission network upgrades, et cetera. We sort of put into the $2.5 billion to $3 billion per gigawatt. Obviously, the increase to [ 20 ], which includes short and long term represents a meaningful opportunity over a long period of time. So we're excited about the opportunity. We already are -- we're working on the pipeline for this, as mentioned, with the $2 billion in the plan. This gives us an opportunity to potentially accelerate that. So we'll provide those updates and would recommend folks pay attention to those couple of public data points that will happen later this year.

Okay. Looking forward to it. And then maybe just moving to CVOW, just 2 questions there. I just wanted to clarify, the PJM upgrade costs, are they included or not in the figures you're putting out there today? Or is that still downward pressure? And then how are you thinking about the potential 232 steel tariffs.

Yes, Nick, another really good question. So today's mark does not reflect the potential for certain transmission costs that were allocated to CVOW being potentially reallocated and Bob mentioned sort of the process whereby that occurs and why that might occur. So that would be something to watch as we move forward into the year. And then on 232, we're also taking a mark on that, which is we're awaiting some additional interpretive guidance from the agencies. We're evaluating with our partners, many of whom are the importer of record, completely finalize that. So we estimate that, that has the potential to be in the $200-ish million range, which, as I mentioned, would have the potential of being offset by some of the reallocation of transmission costs. We're not -- we don't have exact precision on how those 2 will balance, but they seem to be somewhat generally in the same area. So those are the 2 things to watch going forward.

our next question from Shar Pourreza with Wells Fargo.

So just real quick on Millstone. Obviously, you guys highlighted [ Governor Lamont ] recently touted the savings generated for ratepayers by Millstone. I guess how much headroom do you have to recontract at the higher prices. Maybe just elaborate a little bit further on the alternative paths you may have outside of the deep process. There's obviously something we're all monitoring given the affordability rhetoric. Connecticut necessarily hasn't been very open to data centers. So are we talking about a virtual deal here?

Shar. First of all, it's great that we can talk about Millstone with you again. I feel like it's been a while. And you're right, we are very pleased with the Governor's comments Commissioner. [ Dike's ] also talked about the value of the existing PPA. Just as a reminder, currently contracted a little more than half through August of 2029. And so the process at Millstone today in Connecticut would be for procurement, we would expect after the expiration of the existing PPA. There's not in that process, a limit on how much could be potentially contracted with the state.

As we've talked about in the past, other states in New England have also expressed an interest, and we're certainly happy to work with them as well. because they recognize the value of Millstone in the same way that we do. As to data centers, we continue to have some interest from data centers to contract there. But I do want to reiterate what we've said in the past, which is our view is any outcome there needs to have the support of stakeholders in Connecticut. We think that's the smart way to pursue it. And what's in front of us right now is this RFP, and we'll continue working on that.

Got it. Appreciate it. I've been waiting years for you to answer my Millstone questions. And then just on nuclear on the topic, obviously, Dominion in the past is really focused on SMRs, but there seems to be a little bit of a momentum building from a consortium of utilities looking to build new AP1000s with some cost inflation protections from the off-takers being the hyperscalers and maybe some backstop from the U.S. government. Would you be sort of willing to participate in this consortium in AP1000? I guess what are the puts and takes on SMRs versus the AP1000s that you do have -- a like an early site permit with North Anna. So just curious there.

Yes, Shar. We do have an early site permit at [ North Anna ] And we also, as you know, have been exploring SMRs as well. I mean if you step back, as we've talked about before, we're in a very pro nuclear state in Virginia. I think arguably the most nuclear-friendly state in the U.S., and you can see that from the support of the governor both Senators Kane and Warner have expressed support for nuclear, general assembly, a couple of years ago passed legislation allowing us to recover some costs for nuclear project development we filed with the SEC and got an approval for that.

We have a lot of nuclear supply chain here, the nuclear navy here and the units at Surry and North Anna. As we think about nuclear development in any sense, we're going to continue to be guided on 3 principles that were resolute. The first is any structure has to address first-of-a-kind risk. So if we're talking about SMRs, we need to address that. It's got to address cost overrun risk so that our customers and our shareholders are not bearing that burden, and we need to protect our balance sheet and our business risk profile. So we'll continue to investigate and explore alternatives on the nuclear front, but we're going to be guided by those principles, and we'll continue to work with policymakers.

Fantastic results [indiscernible]

We'll move next to Paul Zimbardo with Jefferies.

The first I wanted to ask on, obviously, you have a unique position in PJM. Just thoughts on the backstop procurement, the auction feature. And just if there's any ways that you can accelerate generation or kind of spread the cost more broadly across PJM, but just kind of overall thoughts on that process.

Yes. Paul, thanks for that question. We support PJM's effort to develop a backstop auction to get or process to get additional capacity for load-serving entities that aren't developing generation or lack of state regulated framework to do that. We're different. We're vertically integrated. So it doesn't change our existing process. We don't expect to change to our plan. We have an integrated resource plan that's designed to meet policy goals in Virginia and the incredible demand growth that we're experiencing, and that includes as you know, incremental generation.

It is also important to note, as you think about this, the difference between the Dom Zone, which we serve as a transmission operator and our load serving entity that we serve from a generation standpoint. So we'll take a look at the process that PJM is ultimately doing. But the plan that we have is through our state-regulated utility vertically integrated, and we're going to need to build generation to serve load in Virginia, regardless of the outcome of the PJM process.

Okay. very true. And then if I could follow up on the battery bill the successful one there. Any way to kind of frame the cadence of that? Should we kind of think about the megawatt deployment targets is ratable? Or kind of more back-end loaded, front-end loaded? Any kind of shaping would be useful, too.

Yes, Paul, we probably don't have great guidance on how to model exactly what that cadence will look like. we'll take steps to start accelerating that spend, which we recover via rider mechanism in Virginia as quickly as we possibly can. So I think there'll be some upward bias in our 5-year capital plan associated with that. And then you'll likely see in the 30s, you'll start seeing a higher run rate associated with that. But I would say stay tuned for that IRP because that will show where the model sort of selects those installations coming in.

We'll move next to Stephen D’Ambrisi with RBC Capital Markets.

Just a quick one. You talked about some of the -- we've talked about the battery storage, but you added up to Slide 3, the line monitoring catalysts that could enhance or extend the growth rate. So can you just talk a little bit about, one, what that means and what the buckets are? Presumably, it's storage, Millstone, potentially an acceleration of data center, but just what, I guess, of those could either drive an enhancement or an extension and just how you're thinking about adding that language to the slides.

Thanks, Steve. I'm glad you noticed that language. It was pretty deliberate, which is -- as we mentioned in the script, I'd say, first and foremost, our growth is about meeting our customers' needs quickly affordably and reliably. And I think we feel like we've positioned the company to be ideally situated to meet accelerating need across generation, transmission and distribution. And that's why fortressing our balance sheet as part of the business review was so critical as we saw the need for incremental capital coming.

And you've seen this trend reflected in our most recent Q4 call update. So the most recent was an increase of 30% of capital over the 5-year plan and the one before that was about 15% higher than the prior. And we continue to see those opportunities to deploy regulated capital to serve our customers. And the battery storage legislation is just an example of that, but it definitely expands beyond that, which is across, as I mentioned, other forms of generation, transmission opportunities, broadly distribution.

So certainly, I would say battery storage as a potential catalyst, I'd say, more generally, regulated capital across other applications as a catalyst that we see in the potential 5-plus year plan. And then you correctly ascertain Millstone, which we view as a potential for another win-win for customers, which -- and we'll be in a position to share more on that later this year. But I'd say, we feel like we've been appropriately conservative in our plan around Millstone. And to the extent that we're successful in finding a win-win for customers that would have the dual benefit of continuing to hedge that exposure for customers, much like the first contract has done and also potentially recognize the increased value across nuclear capacity in the United States.

Great. That's helpful. And then can you -- just on the Millstone point, I think previously, obviously, we have the very visible deep process. But can you talk about potentially interest from surrounding states? And just if there are any formal processes to -- and if you would be willing to contract more than, call it, the 50% that you've done historically?

Yes. The answer to the second question is yes. We'd be willing to contract more than 55%. Other states don't have a formal process in place the way Connecticut does but we've certainly been talking to them. And I think they've expressed interest.

Next question from Anthony Crowdell with Mizuho.

Just a couple here. On the CVOW installation cadence, you're averaging about 2 days per turbine on recent installations. Just what gives you confidence this pace is sustainable as you move through their project?

Great question, Anthony. Let's take a step back for a second. We've been building projects on time and on budget for a long time, whether it's [indiscernible]-- the combined cycles we built in 2010 are big transmission projects.

Building infrastructure well is one of our strengths. And for CVOW we got first power to the grid in March, which was in line original time line. That was a big milestone. And then as for turbine installations, we noted upfront, we have been able to ramp installation productivity meaningfully. If you think about some of the other parts of this project, think about transition pieces or monopiles when we started off, those were modest.

I think we did 4 monopiles in May of '24, the first month we were doing those. We did something like 13 transition pieces in January of '25, which was the first month we did those. Then by the time you got to the end, we were doing 21 monopiles in a month and 38 transition pieces. So really dramatic improvement as we went along. And we're seeing that same dynamic that's playing out here where we start with the measure twice and cut once approach that we've learned in doing big projects over the years. That rate is accelerating.

I think we've got a lot of opportunities to optimize that process more. We also started in the winter, the winter months are the worst weather months. Now that we're in the summer, that will give us more opportunities to refine our process and improve cadence. So if you think about that, you take all that together, the productivity progression improving weather windows, that's what gives us confidence in hitting the time line.

And I'd say really what's most important, 3 things. One is it's the fastest source of new power for our customers. Two, it's the most affordable option; and three, we have great confidence in our financial plan to be durable and resilient as we work through construction.

Great. And if I could just throw on a follow-up on the balance sheet. I believe the target is above 15%. As you know, the CVOW construction kind of winds down I think rate base investment accelerates. Are there any key risks that you highlight to maintaining above the 15%.

No, Anthony, we've put out a financing plan as part of the Q4 call that is 100% supportive of maintaining that cushion, which we've indicated, we think is adequate in order to safeguard from unintended headwinds that we may face. I'm really pleased with where the balance sheet is as a result of the business review. As I mentioned earlier, pleased with where we printed in '25 [ over 15% ] and LTM above that as well. So I think you take everything put together, and we're in great shape on the balance sheet. We're already at that cushion level. It's not a situation where we're ramping over time to get there.

We'll move next to Richard Sunderland with Truist Securities.

Circling back to that Slide 3 commentary, the addition at the bottom, appreciating the buckets and what are some of the pieces there. And you've already, I guess, expressed a bias on the growth rate. But just thinking more about how these opportunities aggregate, is it still about working in the range of that 5%, 7% growth? Or do you see the potential for structurally higher growth over time?

That's a very clever question. Rich, I think we've said it exactly as we want to say it, which I think I mentioned our plan is appropriately conservative not unreasonably so. But we are focused on building a track record of successful high-quality execution quarter after quarter, year after year. And I think we feel very well positioned with tailwinds we have, the strength of the balance sheet, to be in a position to monitor catalysts that will enhance our and/or extend our long-term growth rate range. .

Very clear. I had to try. And then on the battery side, I know you've picked out some of the different components and thinking around there but [indiscernible] on the long duration component. How do you think you might address that, any thoughts on technology and timing? Just any opportunity there around long duration in the next, say, 5 to 10 years? Or is that more going to be in the out years?

Yes, a little early on giving specificity on that. I mean we've got a couple of pilots on longer duration storage underway right now, evaluating technologies. As a result of this legislation, we'll continue to ramp that up, explore more opportunities with more vendors, but we're not really in a position to identify specifics on that today.

We'll move next to Carly Davenport with Goldman Sachs.

I just had a quick follow-up on Anthony's question on the cadence of the turbine installation. I know you've mentioned the pace has sort of picked up here as you've already gone through and honed the best practices. I guess should we think about that 2 turbines -- 2 days per turbine as the target? Or are there still any identifiable items that could get you towards maybe that 1 day to 1.5 days range that maybe have been quoted for some other projects out there.

We're always interested in getting that number down. and we will continue to push for that. Just -- the main message here is the really impressive improvement that the team has made each time with the pace that they've been able to install. I mean there's obviously a limit on that curve. But we're going to continue to push our way down that. So we'll update on installation cadence on every call, and we'll have an opportunity to talk about the ways that we have improved. I expect we're going to continue like we did with monopiles and transition pieces to get the pace up faster as we go along.

Got it. Okay. That's super helpful. And then just on the data center pipeline. I know you guys are uniquely positioned in PJM. But just curious if you're seeing any shifts in terms of the cadence of load development or progression through your pipeline due to some of the broader uncertainty on the constructs and PJM governing pricing of capacity and kind of cost allocation?

No, we continue to see incredibly strong demand for new data centers in Virginia. We noted in our prepared remarks, we've added commitments in all stages of contracting since December that interest has not waned at all in recent months. So short answer is no detectable change.

And I would now like to turn the call to Bob Blue for closing remarks.

Thanks, everyone, for taking the time to join the call today. Please enjoy the rest of your day.

Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Welcome to the Dominion Energy Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

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 Dominion Energy's Fourth 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.

Thank you, David, and good morning, everyone. Over the last 24 months since the conclusion of our business review, we've consistently reiterated our focus on 3 principal priorities: first, consistent achievement of our financial commitments; second, continued 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 benefit both customers and shareholders. Looking back on 2025, we successfully executed against these guiding priorities and our focus for 2026 is unchanged. As we execute, we empower our employees to provide the reliable, affordable and increasingly clean energy that powers our customers every day. And we position ourselves to continue to deliver on the commitments we made at the conclusion of the business review.

Turning first to 2025 results as shown on Slide 5. As the first full year post business review, 2025 was a critical year for demonstrating our ability to produce high-quality earnings and robust credit results consistent with our original guidance. Therefore, I'm pleased to report that we successfully delivered with full year 2025 operating earnings of $3.42 per share and operating earnings, excluding RNG 45Z credits of $3.33 per share, both above the midpoint of our guidance. I'd also note that full year 2025 GAAP earnings of $3.45 per share were higher than operating EPS. As always, please refer to schedules 2 and 4 of the earnings release kit for more details.

Continuing that theme, we delivered equally strong credit results. Of particular note is our estimate of Moody's full year CFO pre-working capital to debt, which is both nearly 100 basis points above our downgrade threshold and the highest result we've reported for this metric since 2012, 13 years ago. Balance sheet strength is critical given the substantial need for regulated capital investment across our system to meet our customers' growth over the next several years, and our robust 2025 credit results position us well for that future.

Turning now to 2026 guidance on Slide 6. We expect 2026 operating earnings per share, excluding RNG 45Z credit income to be between $3.40 and $3.60 per share with a midpoint of $3.50. As is our standard practice, we're using a range to account for variations from normal weather in our utility service territories. The midpoint represents a 6.1% increase relative to our comparable 2025 guidance midpoint of $3.30 despite 2026 being a double outage year at Millstone, driven by continued strength in sales and higher regulated investment.

Our expectations for RNG 45Z income, which we continue to report separately, reflect updated credit scoring and lower production assumptions, which we've been highlighting for a while now. We continue to await final 45Z regulations, but we believe that the guidance incorporates the range of likely outcomes. We'll, of course, update our disclosures if and as needed. Taken together, total operating earnings guidance at the midpoint is $3.57 per share. We're also showing credit and dividend guidance for 2026, which are consistent with our previous long-term guidance. As a reminder, we'll revisit our dividend per share growth rate when we achieve a peer aligned payout ratio.

Before turning it over to Bob, let me hit on a few final related topics from our long-term financial outlook. First, electric demand growth, which for Virginia is illustrated on Slide 7. Bob will cover specific drivers in his prepared remarks, including the differentiated high-quality and low-risk nature of our data center pipeline. We are continuing to observe tangible data points that underscore the real-time nature of this accelerating demand trend. For instance, in 2025, weather-normal sales in the Dominion Energy Virginia LSE increased 5.4% and all of the top 20 peak demand days in the Dominion zone have occurred in the last 14 months. As a result, we're seeing the need for incremental investment across our system to ensure continued reliability amid continually growing demand in our service areas, which leads me to our updated capital investment forecast as shown on Slide 8.

As we roll forward our outlook, we're increasing our 5-year total capital estimate from $50 billion to approximately $65 billion, representing a 30% increase. We're providing comprehensive and detailed disclosures in the appendix of today's material, so I'll summarize a few key points here. First, much of this increase, over 90% is happening at Dominion Energy Virginia, our largest utility operating company and home to the largest data center market in the world. Second, nearly 2/3 of the updated capital spend will be eligible for recovery subject to regulatory approval under rider mechanisms. And third, we've updated the compounded annual growth rate of our investment base to approximately 10%. This capital investment growth is happening across a diverse portfolio of well-developed projects as shown on Slide 9.

We're seeing continued strength in electric transmission and distribution, and a notable increase in generation, consistent with our most recent integrated resource plans. On gas generation, which includes 2 CTs and 3 CCGTs, we have secured our turbine slots for each project, and we'll provide updates on development and permitting as they progress. The CCGT projects have projected in-service dates of 2032 through 2034. I'd also note that our share of the remaining spend on CVOW represents less than 2% of the updated capital plan. Outside of today's update, we continue to see opportunities for additional investment across the value chain biased towards the early 2030s and beyond. We'll include those opportunities in future updates as warranted by their development status. A capital update of this size requires a thoughtful approach to both customer affordability and financing. Bob will review our efforts around the former in his prepared remarks. I'll address financing presently.

As shown on Slide 10, nearly 60% of our 5-year investing cash flows and projected dividends will be satisfied by internally generated operating cash flows. About 10% will come from net hybrid issuance, which keeps us well below the credit agency prescribed maximums. 10% or so will come from common equity issued via our standing DRIP and ATM programs. We view this level of programmatic equity as appropriate given our sizable capital investment plan and our commitment to strong investment-grade ratings. And the final roughly 20% will come from long and short-term debt. I should note that this financing plan will support our robust credit expectations and credit rating targets, consistent with our prior guidance, as shown on Slide 11.

Finally, the combination of updated sales growth, capital investment, rate base growth and financing plans leads to our long-term operating earnings per share guidance as shown on Slide 12. Please recall that given the existing legislative sunset for 45Z credits at the end of 2029, we've always broken RNG 45Z credits out separately, a practice we continue here. As a result, we continue to provide long-term earnings growth guidance on an ex 45Z basis. With all that said, we are reaffirming our existing long-term operating earnings per share guidance of 5% to 7% annually off of the original 2025 guidance midpoint of $3.30 per share.

As we've highlighted before, no change to our expectation of variation within that range year-to-year to account for years in which our Millstone Nuclear Power Station experiences refueling outages at both units. This occurs once every 3 years and normally reduces operating EPS by between $0.08 and $0.10 due to lower sales and higher O&M expenses.

We've previously communicated that through our 5-year outlook, we expect annual growth to average around the midpoint of the growth rate range or 6%. However, given improved business fundamentals, which includes more regulated investment, partially offset by headwinds, including lower RNG production, lower future day rate assumptions for our Jones Act-compliant wind turbine installation vessel, Charybdis and higher financing costs, we now expect to achieve the upper half of the 5% to 7% growth rate range starting in 2028. Executing on this updated growth bias will require successful regulatory and construction execution, stable financing markets and a thoughtful approach to customer affordability, among other drivers for which we feel well positioned.

In anticipation of the question, let me explain the drivers of the difference between 3% to 4% between our updated rate base and long-term earnings growth guidance. First, approximately 250 basis points is caused by equity dilution. Even with attractive regulatory recovery mechanisms in place, the scale of our capital program requires us to issue on average roughly 2.5% of our market cap annually to fund growth. We view this level of steady equity issuance under existing programs as prudent and EPS accretive. And given the magnitude of our capital spending, appropriate to keep our consolidated credit metrics well within the guidelines for our strong credit ratings category.

Another driver is increased parent level interest-related expense, which reflects today's interest rate outlook and increased financing in support of the higher capital plan. And finally, we've reflected the impact of long lead projects, primarily gas generation in the rate base growth through 2030, but we don't get the full cash flow of those projects until they enter service in the early 2030s, which is when we begin to collect depreciation in rates thus stepping up cash flow and actualizing the project's full earnings potential.

Before I hand it back to Bob, I'll note that while we are pleased with our 2025 financial performance, it's really all about how we execute going forward. Since the business review, we've seen tailwinds and we've seen some headwinds, but what hasn't changed is our confidence in the plan, which has been built to be appropriately but also not unreasonably conservative.

And with that, I'll turn the call over to Bob.

Thank you, Steven. I'll begin with safety on Slide 14. Our OSHA recordable rate of 0.26 in 2025 was a record for the company, continuing the positive trend from the last 3 years. We also broke a record with our company's lowest Lost Day Restricted Duty rate, which is a safety metric that tends to reflect more serious injuries. But we know that safety is ultimately about people, not numbers. Continuing to focus relentlessly on improving our safety performance is one way we can honor the memory of our colleague, Ryan Barwick, who we lost in an accident last year.

I'll start our business update with the Coastal Virginia Offshore Wind project. Notably, we're now over 70% complete. We continue to be on track for the delivery of first power to the grid by the end of March. That will represent a remarkable project milestone. General fabrication and installation have gone exceptionally well. Let me provide a few quick examples. We completed installation of the 176 monopiles more quickly than expected. We're ahead of schedule on transition pieces as well with over 70% installed and the remainder at the Portsmouth Marine Terminal. The third and final offshore substation was installed this past Saturday. Commissioning is proceeding as planned. Deepwater export cables are now installed and inter-array cable installation is on track. All of the remaining cabling is now fabricated, and majority is landed in Virginia, and onshore work to accept first Power is complete. The project budget stands at $11.5 billion, including unused contingency of $155 million.

On January 30, we filed our quarterly status report with the State Corporation Commission as well as provided a comprehensive and detailed update on the project's cost and time line on our Investor Relations website. No change to those materials, which we've included in the appendix of today's material. We have continued to provide an update to our potential tariff exposure across discrete tariff categories and illustrative durations. We're showing the impact of country-specific tariffs through March 2026 and the impact of steel tariffs through completion of project construction in early 2027. Please note, we're reviewing Friday's Supreme Court tariff ruling, and we'll update the budget in the future as appropriate.

Finally, let me talk about wind turbine generator progress and timing. We're making excellent progress on fabrication. Around 70% of towers in the cells and 30% of blades have been fabricated. This progress tracks well relative to our schedule. With regard to installation, a few comments. First, successful completion of the first turbine in January marked a major milestone for CVOW as we demonstrated our ability to safely complete each of the major elements of the overall project. Second, during the first few iterations, we're deliberately moving more slowly in order to ensure we figuratively measure twice and cut once. We view this as prudent construction management, aligned with the lessons we've learned over years of large project construction. Third, since we recommenced turbine installation upon receipt of the preliminary injunction on January 16, we've been navigating winter weather, which has accounted for over a week of downtime. Fourth, we needed to pause installation occasionally to refine procedures and equipment as is typical during first time stages of any construction project.

Let me provide one meaningful example. After successfully installing the third blade of the first turbine, a human performance error, which was unrelated to Charybdis operations, resulted in damage to the affixed blade. That required us to assess the damage, remove the blade, replace it with a new blade and immediately return to port to offload the damaged blade and reload a new one. That iteration took almost 2 weeks. We'll, of course, learn from this experience and don't expect to see this type of delay repeat itself. Therefore, I simply caution against making any conclusive predictions on the project's expected time line solely based on the first iterations of this process. Please note that current project budget includes turbine installation schedule contingency for weather delays through July 2027 as needed, including Charybdis charter costs.

As a general rule of thumb, if the project extends beyond that for some reason, and we don't expect it will, we estimate that each additional quarter to complete turbine installation would add between $150 million and $200 million to the project cost, a portion of which would be allocated to our financing partner. We'll include data from additional installation iterations in future quarterly updates.

Turning to Slide 16. As Steven previewed, we view customer affordability as central to our public service obligation. And accordingly, we have a long record of maintaining competitive rates, which compare favorably to the national average. Our current customer rates at both DEV and DESC continue to be lower than the national average, 4% and 12%, respectively. And going forward, we expect to see typical residential rates increasing by a compound annual growth rate of around 2.6% and 2.8% at DEV and DESC, respectively.

Additionally, as shown on Slide 17, DEV and DESC's average residential electric customer bills as a percentage of median household income have improved by 7% and 29% more than the national electric utility average, respectively, since 2014. We recognize though that customers are feeling the pressure of higher costs for housing, groceries and other essentials, including their electric bill. We have a number of programs designed to help our customers manage their electric bills, including budget billing, energy savings programs and financial assistance programs such as EnergyShare.

Late last year, we also launched a new online platform to put all of our programs in one place. so customers can more easily find the best options to meet their needs. Furthermore, our recently approved large load provisions ensure that our smaller customers aren't at risk of subsidizing our largest customer classes. We also work continuously to improve the efficiency of our operations while meeting high customer service standards and reliability needs. In recent years, we've driven out costs through improved processes, innovative use of technology and other best practice initiatives.

As shown on Slide 18, based on the most recent data filed with FERC, we have a proven track record of being one of the most efficient companies for the benefit of our customers in the industry. We're focused on continuing to drive down O&M costs across all of our segments. Looking ahead, we're intently focused on ensuring our service isn't just reliable, but that it remains affordable as well.

Now I'll turn to business updates. Steven provided a brief overview of sales growth trends. Let me offer some specific comments on our data center customers. On Slide 19, we've updated our typical disclosure around the data center pipeline. We now have over 48 gigawatts in various stages of contracting as of December 2025, which compares to around 47 gigawatts as of September, an increase of approximately 1.4 gigawatts or 3%. 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. Starting in January 2027, large load customers with demand of 25 megawatts or greater will be subject to minimum demand charges. And a customer that signs a new ESA will also be subject to four contract terms with exit fees and enhanced collateral requirements. We believe that we have a differentiated opportunity around our data center customers. Our projected demand growth is high quality, as shown on Slide 20, because the forecast that drive our planned capital spend are based on insights gained from over a decade of meter-level historical data, long-term working relationships with some of the largest and most sophisticated technology companies in the world and validation from 20-plus gigawatts of signed ESA and CLOA contracts.

The vast majority of our demand growth is driven by steady and consistent batches of cloud and inference data center modules, which we view as lower risk and produces consistent results over time. This strategy has worked well for us for years and helps limit our reliance on any single project or customer.

Let me spend a few minutes on Slide 21 because I want to make sure everyone understands its significance. As the slide shows, our forecasted data center demand through 2045 is more than covered by existing signed ESAs and CLOAs. That means we do not forecast demand based on SELOAs. That also means that by working diligently through the existing backlog and connecting the existing projects under construction, we'd achieve our demand forecast for the next approximately 20 years. Again, we believe this makes our data center market less risky and highly realistic.

All that said, we're, of course, working as quickly as possible to work through our queue because we know these investments are of vital importance to our data center customers. We welcome them to our system and recognize the important contribution they 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.

In Virginia specifically, residential rates have averaged 9% below the national average, even as data center load has grown at a 20% CAGR since 2016, as shown on Slide 22. Data center demand should and can be a win-win for our state, our customers and our company. And while just data point, it's worth noting that for the ninth consecutive year, our economic development team has been recognized as a top utility for economic development. Two projects were highlighted, including Eli Lilly and Hampton Lumber. In September 2025, Eli Lilly and Company announced plans for a $5 billion state-of-the-art manufacturing facility that will generate 650 high-wage jobs and 1,800 construction jobs in Virginia. In addition, Allendale, South Carolina welcomed Hampton Lumber in July when the company established its first East Coast sawmill, bringing more than 125 new jobs to the region. We're proud to contribute to these outcomes. Projects we supported in the last year alone will create more than 3,600 jobs and attract $7.4 billion in new capital investment, delivering lasting value and strong community growth across our service territory.

Finally, let me share a few additional business updates as shown on Slide 23. First, on November 25, the Virginia State Corporation Commission published its final order in the 2025 biennial review proceeding. The commission's order approved the large load provisions I discussed earlier, designed to ensure continued fair allocation of costs among customers and to mitigate the risk of stranded assets. Also on November 25, the Virginia SEC approved the Certificate of Public Convenience and Necessity and Rider for the Chesterfield Energy Reliability Center, an approximately 1 gigawatt gas-fired electric generating facility expected to cost approximately $1.5 billion and be placed in service in 2029. In its order, the commission highlighted that the project addresses an imminent reliability threat in accordance with the public interest. On February 12, the commission affirmed their order and denied a petition for reconsideration.

On February 13, PJM announced its final selections in the latest transmission open window process, awarding us a portfolio of projects totaling over $5 billion with various in-service dates through 2032. This represents the largest proposed investment by Dominion Energy Virginia since PJM began its open window process. Next, in South Carolina, DESC filed an electric rate case application and testimony with the Public Service Commission of South Carolina on January 2 to support the $1.4 billion invested in the South Carolina electric system since 2023 and ensure that we can continue meeting customer demand safely, reliably and efficiently. We expect a decision in June with rates effective in July.

Finally, on Millstone. The facility continues to provide over 90% of Connecticut's carbon-free electricity and 55% of its output is under a fixed price contract through late 2029. The remaining output continues to be significantly derisked by our hedging program, which we've updated in the appendix of today's materials. During 2025, Millstone performed well and achieved a capacity factor of over 91%, aligning with our expectations of exemplary performance and reflecting our unwavering commitment to safety and best-in-class operations.

In January, the Connecticut Department of Energy and Environmental Protection issued a zero carbon energy request for proposals for which Millstone is eligible. Bids are due in the RFP in March. The Connecticut RFP process also intends to coordinate bid evaluation in conjunction with other New England states. In addition to state-sponsored procurement, we continue to evaluate the prospect of supporting incremental data center activity as well. We feel strongly that any data center option needs to be pursued in a collaborative fashion with stakeholders in Connecticut. We remain focused on achieving a constructive outcome for the facility, and we'll continue to provide updates as things develop.

With that, let me summarize our remarks on Slide 24. We achieved record-setting safety performance as measured by both OSHA and LDRD rates last year. We achieved 2025 operating earnings above the midpoint of our guidance and delivered our strongest credit results in the last several years. We initiated our 2026 operating earnings guidance range and reaffirmed our existing long-term operating earnings per share growth rate of 5% to 7% with a bias to the upper half of that range, 2028 to 2030. We reaffirmed our credit and dividend guidance.

In collaboration with our policymakers, regulators and stakeholders, we continue to make the necessary investments to provide the reliable, affordable and increasingly clean energy that powers our customers every day, which has resulted in an approximately 30% increase in our 5-year capital plan. And CVOW continues to progress well in construction with robust cost sharing that protects customers and shareholders. We're 100% focused on execution. We know we must continue to deliver, and we will.

With that, we're ready to take your questions.

[Operator Instructions] We will take our first question from Shar Pourreza with Wells Fargo.

Just a quick question on the '26 and '27 EPS. Just the CapEx is up about $3 billion in those years versus the previous guide and rate base in Virginia is considerably higher. Can you just maybe talk about some of the puts and takes that get you to a 6% growth rate in those years versus the upper half of the range? I mean the updated trajectory is kind of modestly below consensus. I guess, where is there conservatism in plan? Anything to call out? I think Millstone comes to mind there, but just a little bit more detail.

Yes, Shar. There's a couple of things there. So let me hit on them. And if I miss anything, let me know. You mentioned a little bit about consensus, aware of that thought. Keep in mind, prior consensus would have included $0.10 for 45Z credit. We've reduced that to $0.07, which I think on 2028 basis accounts for about half of the $0.06 delta. We've always broken 45Z out. If you look at the sum of the parts, folks are generally ascribing a fairly insignificant amount of value to that. And the reason we've done that since the beginning of the review is because we view it, a, as having a legislative sunset; and b, not truly indicative of the core operating earnings power of the base utility business. So today, we announced a 6% increase year-over-year on that base business. We increased the longer-term guidance to the upper half in '28 through '30. I think it should be interpreted very much as a bullish message.

And with regard to Millstone, we won't today be giving any sort of specific color around what we've assumed in that upper half guidance as it relates to the pricing on Millstone post expiration of the PPA in August of 29. But as we have always approached our financial planning subsequent to the business review, I would just say we've been appropriately conservative. And we expect to have some clarity around the outcome of the RFP towards the back half end of this year. And at that point, we can give people a little bit more information around the ultimate trajectory of Millstone and if and whether that will change the trajectory towards the back half of our plan.

And then I think finally, starting with or ending with what you started, which is the trajectory. Look, we see most of these tailwinds manifesting most strongly towards the back end of our plan. That's been a consistent message we've delivered to investors for the last several months. That has not changed. We see rate base investment certainly in capital over the 5-year plan, but we get the strong value for that towards the back end. And so I would just say we're very comfortable with maintaining sort of original guidance '26 to '27. Our motto is to underpromise and overdeliver, and that's what we anticipate to continue to do going forward.

Got it. That's actually super helpful. I appreciate that. And then just lastly, as we're thinking about the data center ramp with the updated slides like on '21, with the ESAs and the higher CapEx outlook, are you assuming sort of minimum take-or-pays in the current plan so the data center customer ramps quicker and consumes more than the minimum over time, would that be accretive to the current plan? Just want to get a sense there, too.

Yes, Shar. I mean, our data center expectations are based on years of experience. I think as we have described, we're not forecasting based on load letters or inquiries. We're actually showing precisely what we expect coincident demand to be. And as we made clear in our opening remarks, that's being driven by our current ESAs out for a decade. And then you start getting the CLOAs get you above our current projections by 2045. If they ramp faster, then we'll address that, obviously. But we've got a lot of experience with the rate at which these companies ramp. And we think it's smart to make our forecast based on what we're confident of rather than projecting some sort of capital allocation based on the letter that we got that may or may not show up.

And Shar, I'd just add that the name of the game for us is sales, yes, that's very positive. But really, it's the investment across the low-risk regulated business that supports that sales, which ultimately is going to be driving the long-term earnings growth and credit strength in the name. As you know, we forecast forward in our base biennial in Virginia that includes sales volumes. We do it in our riders as well. So for us, we assume they're going to ramp based on historical performance. That's largely above the minimums, of course. But for us, the big picture driver is the ability to deploy capital on behalf of our customers, which ultimately will drive the long-term financial performance.

We'll take our next question from Nicholas Campanella with Barclays.

I just want to follow up on the CVOW update. Appreciate all the updates you gave there, especially on the turbine installation progress. Just, you gave this kind of per quarter sensitivity on cost, I believe if it goes past the July '27 time line that you brought up. Just how many -- maybe kind of clearly delineate how many turbines per quarter you're trying to install here to make that? And then my follow-up question on that is if you do have upside risk to the budget, did your financing partners already indicate that they participate alongside you?

Yes. I'm sorry, Nick, I missed the first part of the question. It had to do with turbine installation cadence, but I wasn't exactly -- a word blurred out for me there.

How many turbines do you need to install per quarter to make the July 2027 time line that you laid out?

Yes. I'd answer it this way. I mean our expectation is we get the majority in, in '26 and then some into 2027. And as we think about it, we're looking at sort of a 2.25 days per installation. That's over a period of time when the weather is worse, like in the winter, it's going to be slower than that. But that's what we would look at in order to hit the schedule that we've laid out. And then on the second part of the question, yes, Stonepeak has been a great partner with us. And we've got the contractual provisions on how we would move forward if it extends into that longer period, which, as I mentioned, we don't expect.

Okay. And then one last one there. If the time line is going past July '27, is the overall COD you think still kind of intact then? And then I know that you kind of bring these on in strings, so the earnings cadence is less material to that COD. Could you just remind folks of how that works?

Yes, Nick, I think you're hitting on absolutely the right point, which is given the way the regulatory recovery works, the sort of amount of capital to be recovered in rate base is at this point, effectively fixed. It's at the cap of what was allowed to be socialized to customers. And so changes in installation will largely be EPS neutral in the form of deferrals if we over underrecover in a certain rate year. There to be some cash impacts associated with that, but that's exactly why we maintain in our internal models a very robust cushion to our existing credit downgrade thresholds so that in the event something like that happens, and this is just one example, we're well positioned to absorb it and still stay above the downgrade threshold. And then I think with regard to your first question, was that with regard to Stonepeak? Did I understand the first part of your question correctly?

Just the project COD slipping to the right if you're moving installation past July '27.

Yes. Like what impact that has on our arrangement with Stonepeak? Or something totally not related to Stonepeak. And I've totally missed it.

Yes, I think that -- I think, Nick, the way to think about COD is just as the turbines come on, this is not like a combined cycle where there's a COD date for the end. We bring, as you said in the question, we bring turbines on in strings and they go in that way.

Sorry about that, Nick. I tried to make that even more complicated question than I think you were actually asking.

We'll take our next question from Steve Fleishman with Wolfe Research.

So just on the utility capital plan, is the PJM transmission that you noted, the open season, is that -- I assume that's -- is that in the plan?

Yes, a lot of it. Some of it extends beyond 2030, Steve. It's sort of a portfolio approach. So we have a number of those awarded projects that ultimately are 7 or 8 years in duration. So we've captured all of what's been awarded in the -- through 2030 in the updated plan.

Okay. Is there any kind of projects you've identified that are not in the plan during the -- that would be in the period and you're just waiting for some approvals? Or is pretty much everything that's kind of planned right now for the 5 years in there?

Yes. I mean everything that we feel confident in executing through the 5 years in the plan, as we've noted in today's script and in prior scripts, we continue to see opportunities for incremental capital to support the customer growth across our systems. And so we'll reflect that as appropriate in future updates. But this is a good snapshot of sort of where we see it today.

Okay. And then just on 2 other questions. Just you mentioned the dividend payout and kind of considering it as you look relative to peers. I think peers have been generally kind of been reducing their payout targets in recent quarters and the like. Is that -- is that something that thus, we kind of apply to kind of your thinking on the timing of resuming dividend growth?

Yes. We haven't sort of made a financial -- final financial decision as it relates to the payout ratio. We're certainly aware of the trend you're describing, which is folks bringing the payout ratio as a source of funding for their enlarged capital plan. And that's something certainly we'll take into consideration when we get to that point. You can do the math around the EPS growth rate and the current dividend and probably get a sense that we might be a little bit -- we have a little bit of time to make a final determination as to when and how much we start growing the dividend.

Okay. And then lastly, going back, you were talking about making a decision on kind of new nuclear technology preference maybe by the end of last year. Is there any update on that? And then just how much is in the plan over the 5 years for on a new nuclear?

Yes. Steve, we're still in the final stages of evaluating technology. We've got, I believe, as you know, authorization in Virginia through a rider to recover costs for small modular reactor development up to a certain point. And we don't have capital in the plan, this 5-year plan for an SMR. If you look at our integrated resource plan, we're still a ways away from when we would expect to be deploying SMRs. As we've discussed before, Virginia is a very pro-nuclear state. We want to make sure that we support that, but we also want to make sure we do it in a way that is respectful of our customers and our balance sheet.

We'll take our next question from Steve D'Ambrisi with RBC Capital Markets.

Just had a quick one or maybe 2. Just in terms of 2026 and kind of following on Shar's question, you're able to guide to 6% EPS growth on the operating business for '26 with the inclusion of the Millstone double outage. And so can you just talk a little bit about like effectively what are the positives that are enabling you to grow 6%? And then just like effectively why maybe those don't recur in '27 or why it takes a little bit longer to get there?

Yes, Steve, let me try that again and see if I can be more responsive. In '26, we're getting the benefit of a couple of sort of helpful items. One is the full impact of the biennial rate increase in Virginia and second is a half year impact associated with the South Carolina rate case. So think of it as '26 as sort of a catch-up year because in those jurisdictions, prior to going in for those rate reliefs, we would have been under earning. And then because we don't typically go in the next year for additional rate relief, you can see that lag sort of catching up with us a little bit. And it's less pronounced in Virginia, of course, because of the forward-looking rates, but we have that in South Carolina. So that's kind of why you see that cadence between '26 and '27. '27, even though you have $0.08 to $0.10 from the lack of a double outage year, you're sort of gearing up for that next rate case and you'd see potentially the impacts of that later in '28. Does that help?

Yes, that's perfect. That's kind of what I figured. I just wanted to clarify. And then just on the 45Z credits, I totally understand changing the assumptions are being more conservative, I guess. But just you did book $0.09 in '25. Is there a reason why that falls into like outer years? Is that just like changes in, I don't know, I guess, CI scores or something? Or what's driving that?

It's exactly that. It's a change in CI score. So one of the changes that happened is that a new GREET model was published in '26. The ultimate RNG 45Z model for '26 and beyond will be based on that. That initial GREET model suggests to us a little bit of degradation in CI relative to what we booked. Now that doesn't mean that '25 is at risk. It's not a backward-looking model in our view. We had the rules for '25. We booked this according to the rules that were in place in '25. But because of the view we have now based on the most recent model in '26 and beyond, we've sort of effectively adjusted our CI scoring to reflect that, which is why we put a $0.05 to $0.09 range around that $0.07. We see the outcome of that sort of ultimate CI score somewhere in that $0.05 to $0.09.

We'll take our next question from Anthony Crowdell with Mizuho.

Just two quick ones. On a follow-up from Steve's question, what's the lag you're assuming in your Virginia and South Carolina jurisdictions? I know you said there's a catch-up in the rate, the timing of the rate case benefit this year. But could you tell us maybe what you're assuming in '26 for lag and in '27?

Yes. That's a great question, Anthony. So the majority of the lag we see in the composite Virginia earned ROE is related to our North Carolina segment of the business, which is quite small, but it is much more. We don't go in this frequently for rate cases, and it's more traditionally backward looking for us. So that is a driver of, we'll call it, the majority of the driver of something like a 30 to 40 basis point lower than the 10.4% or so weighted average allowed that we have. And then we have another nonjurisdictional customer that kind of follows that exact same trend. So those are the drivers of it in Virginia.

And in South Carolina, obviously, before we get rate relief, we've talked about at the lowest underearning part of the South Carolina cycle, we underearn as by much as 150 to 200 basis points. And so I would expect us to sort of be on that in the front half of the year. And then by the end of the year, once we get relief, we'll start closing the gap on that. And then as we look forward, we're encouraged by legislative activity like the RSA that would potentially allow us to be in for more frequent sort of formulaic rate cases, still backward looking, but more frequent, which would allow us to, as we've said in the past, try and about have that run rate of 150 to 200 basis points to something closer to 75 to 100 on a go-forward basis.

Great. And then just one follow-up. You had mentioned legislative. I'm thinking about in Virginia, and I don't know if it was proposed yesterday, I wonder if you could comment on it. There's a, I guess, proposal in the Senate of maybe eliminating a data center tax benefit or tax shield going on. Just thoughts if you could comment on that, thoughts of maybe that impacting your forecast for load growth, and that's it.

Yes. As is always the case on our fourth quarter call, the Virginia General Assembly is ongoing. And so it's difficult to predict any kind of an outcome. I'd just say that in our view, data centers are very beneficial to the state and local economies. We look forward to continuing to serve them for some time. And you can see the kind of growth we're expecting off of them. We expect that to continue.

We'll take our next question from Carly Davenport with Goldman Sachs.

Maybe just as we think about the equity plans, you have the explicit guidance for '26. Just any color you can provide on how to think about the cadence of the remainder of the common equity issuance? And then are there any other levers on the funding side you might consider outside of the hybrids like minority interest sales?

Yes, great question. So we think about the cadence of equity, about 1/3 of that total 5-year equity, we expect between '26, '27 and '28 and about 2/3 in '29 and '30, which is when we see the most substantial capital increases in the business and particularly around some of that gas generation spend, which, as I mentioned before, is less cash converting, at least initially relative to some of the other portfolios like distribution and transmission than we've got.

And then with regard to alternative funding sources, we think the hybrid is such a really -- it's a really good product. I mean the market for that has been super strong. The sort of 6-ish plus -- 6-ish or so percent we can get for 50% equity credit is very attractive. As I mentioned, we're well below the prescribed maximums at both Moody's and S&P as it relates to that, even with what we have in our current plan. We'll always, as you know, consider alternative sources of financing to the extent that they're more attractive than what we've sort of laid out. So we'll maintain any optionality. But right now, we feel really good about the sort of plan we've laid out. I think it's balanced, it's achievable, and it's appropriate for our credit metrics.

Great. Okay. That's super helpful. And then maybe just -- there have been a couple of comments in the last few weeks from the administration on appealing the preliminary injunctions that were granted for a number of offshore wind projects, including CVOW. Just curious if you do see any incremental litigation risk or headline risk on execution on the project from sort of external involvement.

Carly, we continue to see CVOW as the fastest way to get a significant amount of electricity at a low-cost way on for our customers who are leading the AI race who are building ships for the Navy. And so we continue to believe it just makes sense for this project to be allowed to continue slowing it down as was demonstrated with the last stop work order adds costs, and adding costs and delays in the data center capital of the world, we think that doesn't make sense.

We'll take our next question from Jeremy Tonet with JPMorgan.

Just want to come back, I guess, to some of the earlier points with the turbine installation [ CV ]. I just want to make sure I was clear. When you say early '27, does that mean like a Jan? Or does it mean a first quarter? And could you just walk through the differences between the early 2027, how that's different than the July '27 that you're referencing before? I just want to make sure we were clear.

Yes. Jeremy, early means early. It's -- we didn't put a specific date around it. And so what we wanted to do was just give some sort of guideposts for people who can sort of think about the way this goes going forward. So if weather delays us out to July, -- that's all in the current budget of $11.5 million. And then if for some reason, we're delayed beyond that, we've given you that benchmark of $150 million to $200 million a quarter. The reason we're sort of talking this way is we're early in the installation process. And if you had asked me 2 weeks into monopiles, I would have said we're not tracking with what we expect in order to hit our schedule. And by the way, remember, with monopiles, we had a season -- we had seasonal restrictions. So it was really important to be able to hit your date.

And then, of course, as we went along, we end up finishing a month or a couple of months early. Similarly, with transition pieces, we started slower and then we picked up. And so we'll update on the cadence of turbine installation. But given early stages, given that it's the worst weather time of the year, it just doesn't make sense to be drawing any sort of conclusions. We still feel good about the schedule.

Got it. And if I could just pivot a little bit here, if you'd be able to update us on how CVOW potentially facing reduced energy deliverability until the PJM identified transmission upgrades completion there. Just wondering impacts on Dominion. And if you could just update us your latest thoughts there.

Yes. Look, it's -- CVOW is a really important project. It's just a few months away from delivering electricity to our customers. We ask PJM to do an interim deliverability study to determine if there are going to be any limits on the project's ability to deliver its full output. We'll do that study every year. And so we've been saying that some network upgrades that may not be done when CVOW is finished. But we'll continue to work through making sure the project can deliver as much as safely as possible. So we've assumed 50% deliverability for this Ryder, and we'll update it if that assumption turns out to be -- needed to be adjusted.

Got it. One last one, if I could. Just 7% of the capital plan is focused on nuclear. I see the relicensing in there. So just wondering if you could help us unpack a little bit more about what that might be is in that bucket.

Yes, Jeremy, the lion's share or a good chunk of that is fuel. We categorize nuclear fuel as capital. So it's SLR and it's fuel and then some maintenance.

We'll take our next question from David Arcaro with Morgan Stanley.

Let's see. I was wondering, another positive update here on the data center activity and contracting front. But I was wondering, are you seeing data center requests to interconnect? Is that crowding out any other customer activity, whether it be large industrial or commercial projects? How do those interact? And is there still room on your system for other large customers to connect in?

The answer is there's absolutely room for other large customers to connect in, and they're not being crowded out. A good example, we mentioned it actually in the prepared remarks is that Eli Lilly facility just west of Richmond. Large load, lots of jobs, aggressive time schedule, which we were able to meet. So we're able to meet the needs of our customers. As we mentioned in the prepared remarks, we have a great economic development team. We continue to see exciting possibilities outside of data centers as well.

Yes. Got it. Got it. And then just one other quick one. I was just curious, when might the next iteration be of your generation outlook in Virginia in terms of the next slice at the IRP and when you might reassess the generation needs?

I mean we do our IRPs every 2 years with an update in between. So you can see, we'll continue to update the IRP annually.

This concludes our question-and-answer session. So I'll turn it back to Bob Blue for closing remarks.

Thanks, everybody, for taking the time to join the call today. Please enjoy the rest of your day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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.

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.

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 $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.

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 and 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.

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 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 maintenance 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 and 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 a 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.

On final note on Charybdis project Five, 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.

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.

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 [indiscernible] 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 we going to wake up 1 day and the Trump administration now blocks this project, just given the lack of connection whether Republican governor, have you spoken to span burger? Just any thoughts around the political backdrop would be great.

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 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.

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?

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 million. 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.

We'll go next now to Nick Campanella at Barclays.

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?

Yes, once we get through the punch list, we're ready to go.

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?

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, anti-Coper. 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.

We'll go next now to Steve Fleishman of Wolfe Research.

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.

That's it, Steve. There is nothing related to the government shutdown or anything else.

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?

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.

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?

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 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.

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?

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.

We'll go next now to Paul Zimbardo with Jefferies.

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?

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.

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.

And I like that for a 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.

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.

Go next now to Carly Davenport with Goldman Sachs.

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?

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.

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?

Yes. So under the agreement we have with Stonepeak capital between 11.3% and 11.8% is shared about 2/3 at Dominion and 1/3 was 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 12316 on Slide 11.

We'll go next now to Jeremy Tonet at JPMorgan.

Happy Halloween.

Thank you, Jeremy.

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.

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.

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?

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 if 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 Carolina 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.

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.

They would be incredibly valuable, yes.

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?

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.

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 guide at this point? Or is that kind of just small at this point and won't really think of it as much of a headwind when it comes [indiscernible]

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.

We'll go next now to Anthony Crowdell at Mizuho.

I'm going to ask -- this is my last 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?

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 gigish 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.

Great. No, that's perfect. And then just 1 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?

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.

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.

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

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.