Ladies and gentlemen, welcome to the Dominion Energy First Quarter 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 today's call. Earnings materials, including today's prepared remarks contain forward-looking statements and estimates that are subject to various risks and uncertainties.

Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management's estimates and expectations. This morning, we will discuss some measures of our company's performance that differ from those recognized by GAAP.

Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures, which we can calculate, are contained in the earnings release kit. I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit.

Joining today's call are Bob Blue, Chair, President and Chief Executive Officer; Steven Ridge, Executive Vice President and Chief Financial Officer; and Diane Leopold, Executive Vice President and Chief Operating Officer. I will now turn the call over to Steven..

Thank you, David, and good morning, everyone. Our first quarter 2024 operating earnings, as shown on Slide 3, were $0.55 per share, which included $0.06 of headwind from worse-than-normal weather in our utility service areas.

Offsets to weather included modest interest savings driven by an earlier-than-budgeted close of the East Ohio Gas Company sale as well as O&M timing. Relative to last year, positive factors for the quarter were higher sales, regulated investment growth and better weather.

Recall that we experienced a $0.10 weather headwind in the first quarter last year. So by comparison, a $0.06 weather headwind this quarter is actually a positive year-over-year driver. Other factors include higher interest expense and the revenue reduction at Dominion Energy Virginia related to moving certain riders to base rates.

A summary of all drivers for earnings relative to the prior year period is included in Schedule 4 of the earnings release kit.

First quarter GAAP results were $0.78 per share, which includes the net benefit from discontinued operations, primarily associated with the sale of gas distribution operations, unrealized noncash net gains on nuclear decommissioning trust funds, and the unrealized noncash mark-to-market impact of economic hedging activities.

A summary of all adjustments between operating and reported results is included in Schedule 2 of the earnings release kit. Turning to guidance on Page 4. We are affirming all of the financial guidance we provided at our March 1 Investor Meeting.

As such, we continue to expect 2024 operating earnings per share to be between $2.62 and $2.87 with a midpoint of $2.75. As discussed with the March investor meeting, we're no longer providing quarterly earnings guidance.

We are, however, replicating in the appendix of today's materials, the expected cadence of earnings across 2024, including anticipated year-over-year drivers by quarter. There haven't been any changes to that guidance from the investor meeting.

We continue to expect 2025 operating earnings per share to be between $3.25 and $3.54, inclusive of the impact of RNG 45Z credits with a midpoint of $3.40. We also continue to forecast an operating earnings annual growth rate range of 5% to 7% through 2029, up a midpoint of $3.30, which excludes the impact of the RNG 45Z credits.

As a reminder, authorizing legislation applies to produce RNG volumes in 2025, 2026 and 2027, but sunsets thereafter. For the avoidance of doubt, no changes to any of the other financial guidance we provided on March 1, including credit, dividend and financing guidance.

Turning now to a status update on our business review initiatives as shown on Slide 5. During the review, we announced transactions that represent approximately $21 billion of debt reduction.

With the closings of the Cove Point and East Ohio gas sales and completion of the DEV fuel securitization, we've now achieved 53% of the targeted debt reduction, representing over $11 billion.

With regard to the remaining 47%, we're working methodically towards timely closings for the sales of Questar Gas, Wexpro and Public Service of North Carolina as well as the noncontrolling equity financing for the Coastal Virginia offshore wind project. In all cases, no changes to our original timing expectations.

We look forward to continuing to work with involved parties and expect regulatory proceedings to conclude and transaction closings to occur during 2024.

For a little more color, in Utah, parties to the merger proceeding agreed to a comprehensive settlement in late March, which was followed by an evidentiary hearing in front of the commission on April 11. In Wyoming, a commission hearing is currently scheduled for May 23. And in North Carolina, a commission hearing is currently scheduled for June 11.

As it relates to our announced offshore wind partnership, the transaction requires approvals from the Virginia State Corporation Commission and North Carolina Utilities Commission as well as certain consents from the BOEM and other regulatory agencies.

All regulatory filings have now been submitted and procedural schedules have been published in both Virginia and North Carolina. We are excited to have a well-capitalized and experienced financing partner on terms that significantly derisked the project for Dominion Energy customers and shareholders.

On credit, the business review resulted in significant quantitative and qualitative improvement to our credit profile. Recent comments by the rating agencies with whom we maintain frequent engagement highlighted the credit positive nature of the business review results.

As a result of the review, we have strengthened the company's credit position with an existing consolidated rating categories at each of our 3 rating agencies. Turning to financing on Slide 6. No changes to the financing plans that we shared at the investor meeting.

Specific to 2024, we have normal course long-term debt issuance at DEV in the plan for later this year. We expect to issue between $600 million and $800 million of common equity during 2024, including $200 million through our DRIP program and between $400 million and $600 million via ATM.

We view this level of steady common equity issuance as prudent, EPS accretive and in the context of our sizable growth capital spending program, appropriate to keep our consolidated credit metrics within the guidelines for our strong credit ratings category. Our plan includes the ongoing utilization of hybrid securities in our capital structure.

We have $700 million of junior subordinated notes that will mature in August. And as a reminder, we expect to issue between $700 million and $1.5 billion of hybrids this year. We expect to structure any new hybrids to qualify for 50% equity treatment from the credit rating agencies.

In conclusion, I'll reiterate that I'm highly confident in our ability to deliver on our financial plan. The post review guidance has been built to be appropriately but also not unreasonably conservative to weather unforeseen challenges that may come our way. With that, I'll turn the call over to Bob..

transmission, distribution and generation infrastructure investment that has and will continue to drive utility rate base growth. We believe there may be opportunities for incremental regulated capital investment toward the back end of our plan and beyond.

As I've said before, we will look at incremental capital through the lenses of customer affordability, system reliability, balance sheet conservatism and our low-risk profile. Our IRPs take a longer-term view.

The 2023 IRP factored in significant load growth and investment in generation and transmission over the next 15 years to meet that load growth, while keeping the cumulative average growth in customer bill below 3%.

The most recent PJM load projections, along with our work to optimize the best ways to meet this load will be factored into our planning for this year's IRP. The 2024 IRP will be submitted to the SEC and NCUC in October 2024. We will continue to provide updates as things develop.

We remain focused on our core responsibility of safely providing reliable energy to our customers. With that, let me summarize our remarks on Slide 15. Our safety performance this quarter was outstanding, but there's more work to do to drive injuries to 0. We affirmed all financial guidance. Our offshore wind project is on time and on budget.

We continue to make the necessary investments to provide the reliable, affordable and increasingly clean energy that powers our customers every day, and we are 100% focused on execution. We know we must deliver and we will. With that, we're ready to take your questions..

[Operator Instructions]. We'll take our first question today from Shar Pourreza at Guggenheim Partners..

Maybe I can start with a two-part question on data centers. Bob, I know you made prior comments in media around self-generation and self-supply.

What are you seeing within the pipeline you just discussed as it relates to these 2 items, which can obviously mitigate some of the load growth you highlight? And secondly, how are you sort of thinking about rate design and tariff changes to make sure Virginia customers benefit or at least held harmless on things like interconnection costs?.

Yes, Shar, both really good questions. I may take them a little bit in reverse order. We've worked with data centers for many years, and we have very strong relationships with them. As you know, Loudoun County is home to the largest data center market in the world.

And we have had an opportunity to work with our data center customers for 15 or more years. So with those relationships, we're certainly looking into alternative rate designs and discussing potential structures with them. Obviously, anything that we would do there would need to be approved by the SCC.

So nothing specific to offer, but we certainly continue conversations with these customers that we've worked with so well for so long. As behind-the-meter solutions or some sort of self-supply, I suppose there could be some specific situations where that might make sense for some customers.

But we think given their need for reliability and affordability, we think the majority of those solutions are going to want to access the broader network of system resources that are in front of the meter.

And I think it's really important to keep in mind, regardless of the source of generation, substantial transmission investment, which we've noted before. So fundamentally, given our long history with data center customers, we're quite confident in our ability to find solutions that work for them, for other customers and for our shareholders..

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

Could this kind of be accretive to the plan?.

Yes. Again, I'll take the second part first. So as to potential incremental capital, as we said in our prepared remarks, toward the end of the plan, we could certainly see some additional capacity. We described the way data centers are ramping in faster than they have before that their requests are bigger than they've been before.

We don't forecast demand based on engineering assessments. We do that based on signed contracts. And then in the later years, customer intelligence, we're pretty confident in our ability to do that. So there may be potentially some upside there as we go out.

As I said in our prepared remarks, our investments are going to be driven by policy and customer needs. We'll be very thoughtful about our balance sheet and our business risk profile as we make additional investment decisions. Fundamentally, it's just a very exciting time for the industry, particularly for us, given our experience with data centers.

As to PJM as I expect you know, Shar, from 2007 to 2022, we participated in the PJM capacity market through the reliability pricing model. In 2021, we announced we were going to elect FRR because that made the most sense for our customers.

Now with PJM's most recent capacity market reforms and assumptions, it makes sense for us to return to the capacity auction starting with the '25, '26 auction. Returned us to the way we did business for many years. It doesn't change guidance. It doesn't change the way we operate our system or the way we think about the world.

In fact, all the auction planning parameters released by PJM in April, are quite consistent with our view. We're going to see substantial load growth driven by electrification data centers for the foreseeable future..

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

I wanted to ask on South Carolina. I think HB 5118 has been kind of progressing through and it's our understanding that can maybe kind of change a few things on the regulatory footprint there.

Can you just kind of talk through if that affects your capital plans or your assumptions at all and how we should kind of think about that?.

Yes. Nick, I appreciate that question. The legislature is scheduled to adjourn next week in keeping with our standard practice, I'm not going to talk about pending legislation today. We'll know where everything lands next week. I can tell you what we're very focused on in South Carolina.

First, a constructive outcome in our electric base rate case that's pending right now. As we mentioned in our opening remarks, we've invested $1.6 billion on behalf of our customers since the last case. Our rates in South Carolina are low. Our reliability is outstanding. So we think we're in a very good place with respect to that case.

And then beyond that, we're very focused on continuing to serve our customers well, and getting closer to earning our authorized return in South Carolina. If you just sort of look big picture, South Carolina is a great state to do business. We want to be in a position to continue to invest in growth capital as the state grows.

So that's what we're focused on, and we'll see how the legislature lands here in a week or so..

I appreciate that. And then I guess just on the ship, these ship to be certain, you kind of talked about derisking the project timeline and you seem ahead of schedule. Is that versus the ISD, the '24 to early '25? Or is that more relative to where it falls in your kind of current offshore wind construction schedule.

And then maybe you can kind of remind us what's in the plan today for future contracting opportunities for that ship after you're done with Virginia Offshore win?.

Nick, I'll take the second part first with regard to what we've assumed. So we've made some assumptions of the ability to contract the vessel to third parties at the conclusion of the work it does for CVOW, and we continue to see robust interest in that vessel, given sort of the unique nature of what it provides.

So we feel like we've made reasonably conservative, not unduly conservative assumptions on that, and that's included in the guidance that we provided with regard to the Dominion Energy contracted energy segment at the Investor Day materials.

With regard to the timeline and sort of what it all means, no change to the expectation that the vessel will complete its sea trials in late '24, early 2025. And with the termination of the charter that we discussed in the call, that doesn't change the broader expectation for timeline for the project.

What it does is it allows us to make sure that we can stay on track of that schedule. It gives us opportunities to begin installation when weather is most favorable. It will allow us without that first charter, we won't need the time to reconfigure the vessels outfitting between charters to accommodate our project's turbine size.

So if you think about the vessel availability as on track, consistent with how we've thought about it in the past. To the extent we're able to bring it forward, that's great to the vessel, to the project. But I wouldn't think of it as bringing the back end of the project in. It's just another way that we can mitigate what will be.

I'm sure things that happen along the way that we don't currently foresee, but we want to build as much cushion as we possibly can, and that's what this will accomplish for us..

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

Just one quick question.

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

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

Okay. Great. And then just going back to the kind of tie in with the data center in IRP and the like. Bob, you mentioned dispatchable generation and then potentially gas storage.

Could you just give a little -- it sounds like maybe you've got like a winter tightness that maybe need to deal with? And just would you be investing in the storage? And just how we should think about those needs?.

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

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

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

It's Jeremy Tonet from JPMorgan. Continuing, I guess, with the data center line of thought, if I could. And I appreciate that this is a sensitive topic overall.

But just any thoughts that you could provide with regards to the uncontracted Millstone capacity and that could possibly supply power to data centers? And how have conversations with stakeholders evolved there?.

Jeremy, this is Diane. Really nothing new to report from what we said before in February of '23. We signed an MOU with NE Edge to work together on development of a data center on Millstone property. And they are continuing to work with the state agencies and legislators to gain approvals to move that project forward.

If the permits are granted, then we remain ready to support the project, and that would include providing land and a long-term PPA for power from a portion of Millstone, which will be about a few hundred megawatts..

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

Got it. That's very helpful. And continuing with this line of thought, if I could. I believe there's legislation passed in Virginia to possibly recover some cost of SMR development in the state. And just given how provides the 24/7 baseload that seems to match up well with data center needs.

Just wondering any thoughts you see there on the potential over time? We see Ontario Power really moving forward swiftly on SMR development.

And just wondering, any high-level thoughts you might be able to share there?.

Yes, Jeremy, first. I think that legislation confirms a continued commitment in Virginia among policymakers in support of nuclear power. We operate 4 units in Virginia and have well for many years. The Navy has a substantial nuclear fleet. Many of those vessels ported in Virginia.

And there are other parts of the nuclear industry that are all represented in Virginia. So I think it was a very positive sign that, that legislation passed that continues to support nuclear power in Virginia. We included SMRs in our last IRP out toward the end of the plan.

We continue to investigate the opportunity to be able to deploy SMRs on the behalf of our customers. But I would add, just like with every other investment that we think about, we need to make sure that it's customer-friendly, that it fits within the parameters of our balance sheet and our business risk profile.

So we're continuing to explore SMRs, as you point out, they are dispatchable and nonemitting, but we've got ways to go yet..

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

Most of my questions have been answered, but just piling on the data center, just a couple of comments that you made there. You commented the ramp times have been accelerating.

Can you maybe just describe how that's playing out? Like, for example, the 15 that you're connecting this year, when would you expect them to be at full run rate?.

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

But we don't have specifics regarding those 15 that we expect to connect this year..

Okay.

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

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

Okay. That's helpful. And then I guess just more broadly, again, on the same topic.

Can you just share a little bit about the process of evaluation with the data center developers and how you structure the contracts and their commitments in terms of having the load show up and so that you're restructuring the cost profile appropriately to protect ratepayers?.

Yes, Bill, great question. They -- our data centers are on the rate schedule that applies to all our large customers. And that's been that way for some time.

And the State Corporation Commission would have to make any changes if we were talking about -- approve any changes if we're talking about any changes to that, which not on the table at the moment.

The sort of thinking about the way we structure contracts, they have contract minimum demands that they are obligated to achieve in order to cover the incremental cost of the infrastructure that we're building for them. And that has been in place for us for some time..

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