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We continue to await final 45Z regulations, but we believe that the guidance incorporates the range of likely outcomes. Of course, we will update our disclosures if and as needed. Taken together, total operating earnings guidance at the midpoint is $3.57 per share. We are also showing credit and dividend guidance for 2026, which are consistent with our previous long-term guidance. As a reminder, we will 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 seven. 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 fourteen months.
As a result, we are 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 eight. As we roll forward our outlook, we are increasing our five-year total capital estimate from $50 billion to approximately $65 billion, representing a 30% increase. We are providing comprehensive and detailed disclosures in the appendix of today’s material, so I will 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 two-thirds of the updated capital spend will be eligible for recovery, subject to regulatory approval under rider mechanisms, and third, we have 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 nine. We are 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 two CTs and three CCGTs, we have secured our turbine slots for each project, and we will provide updates on development and permitting as they progress. The CCGT projects have projected in-service dates of 2032 through 2034. I would 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 for additional investment across the value chain, biased towards the early 2030s and beyond. We will 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 will address financing presently. As shown on slide 10, nearly 60% of our five-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 have 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 x45Z 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 have 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 three years and normally reduces operating EPS by between 8¢ and 10¢ due to lower sales and higher O&M expenses. We have previously communicated that through our five-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 three to four percent between our updated rate base and long-term earnings growth guidance. First, approximately 250 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 have reflected the impact of long lead projects, primarily gas generation, in the rate base growth through 2030, but we do not get the full cash flow of those projects until they enter service in the early 2030s, which is when we begin to collect depreciation and rates, thus stepping up cash flow and actualizing the projects’ full earnings potential. Before I hand it back to Bob, I will note that while we are pleased with our 2025 financial performance, it is really all about how we execute going forward.
Since the business review, we have seen tailwinds, and we have seen some headwinds. But what has not changed is our confidence in the plan which has been built to be appropriately but also not unreasonably conservative. And with that, I will turn the call over to Bob. Thank you, Steven. I will begin with safety on slide 14.
Robert M. Blue: Our OSHA recordable rate of 0.26 in 2025 was a record for the company, continuing the positive trend from the last three 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 will start our business update with the Coastal Virginia Offshore Wind project. Notably, we are now over 70% complete. We continue to be on track for the delivery of first power to the grid by 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 are 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. Inter-array cable installation is on track.
Deepwater export cables are now installed and inter-array cable fabrication is complete. All of the remaining cabling is now fabricated, and a 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 timeline on our Investor Relations website. No change to those materials, we have included them 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 are 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 are reviewing Friday’s Supreme Court tariff ruling. We will update the budget in the future as appropriate.
Finally, let me talk about wind turbine generator progress and timing. We are making excellent progress on fabrication. Around 70% of towers and nacelles 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 are 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 have learned over years of large project construction. Third, since we recommenced turbine installation upon receipt of the preliminary injunction on January 16, we have 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 two weeks. We will, of course, learn from this experience, and do not expect to see this type of delay repeat itself. Therefore, I would simply caution against making any conclusive predictions on the project’s expected timeline 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 do not 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 will 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%–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 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 bill 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 are not 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 have driven out cost 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 are focused on continuing to drive down O&M costs across all of our segments. Looking ahead, we are intently focused on ensuring our service is not just reliable, but that it remains affordable as well.
Now we will 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 have 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 firm 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 forecasts 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 produce 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 would achieve our demand forecast for the next approximately twenty years. Again, we believe this makes our data center market less risky and highly realistic.
All that said, we are, 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 are 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 one data point, it is 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 are 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 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 one-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 a 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 have 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.
Now 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 will 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, increasingly clean energy that powers our customers every day, which has resulted in an approximately 30% increase in our five-year capital plan. And CVOW continues to progress well in construction with robust cost sharing that protects customers and shareholders. We are 100% focused on execution. We know we must continue to deliver and we will. With that, we are ready to take your questions.
Operator: At this time, we will open the floor for questions. If you would like to ask a question, please press the star key followed by the one key on your touch-tone phone now. If at any time you would like to remove yourself from the question queue, please press star 2. Again, to ask a question at this time, please press star 1. We will take our first question from Shahriar Pourreza with Wells Fargo. Please go ahead. Your line is now open.
Shahriar Pourreza: Good morning. Just quickly, just a quick question on the 2026 and 2027 EPS. Just the CapEx is up about $3 billion in those years versus the previous guide and rate base 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 details. Thanks.
David McFarland: Yes. Shahriar, there is 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. We are aware of that thought. Keep in mind, prior consensus would have included 10¢ for 45Z credit. We have reduced that to seven, which I think on 2028 basis accounts for about half of the 6¢ delta, and we have 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 have 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 2028–2030. I think it should be interpreted very much as a bullish message. And with regard to Millstone, we will not today be giving any sort of specific color around what we have assumed in that upper half guidance as it relates to the pricing on Millstone post expiration of the PPA in August ’29.
But as we have always approached our financial planning subsequent to the business review, I would just say we have 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 has been the consistent message we have delivered to investors for the last several months. That has not changed. We see rate-based investment certainly in capital over the five-year plan, but we get the stronger value for that towards the back end. And so I would just say, we are very comfortable with maintaining sort of original guidance 2028–2030. Our motto is to underpromise and overdeliver, and that is what we anticipate to continue to do going forward.
Shahriar Pourreza: Got it. That is actually super helpful. I appreciate that. And then just lastly, as we are 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? If 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. Thanks.
Robert M. Blue: Yes, Shahriar. I mean, data expectations are based on years of experience. I think as we have described, we are not forecasting based on load letters, or inquiries. We are actually showing precisely what we expect coincident demand to be. And as we made clear in our opening remarks, that is being driven by our current ESAs out for a decade, and then, you know, you start getting the CLOAs, get you above our current projections by 2045. If they ramp faster, then we will address that, obviously.
But we have a lot of experience with the rate at which these companies ramp and, you know, we think it is smart to make our forecast based on what we are confident of rather than, you know, projecting some sort of capital allocation based on a letter that we got that may or may not show up. And Shahriar, I would just add that, you know, the name of the game for us is sales, yes.
Shahriar Pourreza: That is very positive. But, really, it is 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 are going to ramp based on historical performance that is 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.
Shahriar Pourreza: Got it. Super comprehensive. Thank you both.
Steven Fleishman: Thanks, Shahriar.
Operator: Thank you. We will take our next question from Nicholas Joseph Campanella with Barclays. Please go ahead. Your line is now open.
Nicholas Joseph Campanella: Hey. Good morning. Thanks for taking my question. Good morning, Nick. I just wanted 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, it goes past to July ’27, timeline that you brought up. Just how many maybe kind of clearly delineate how many turbines per quarter you are trying to, you know, install here to make that, and then my question on that is, you know, if you do have upside risk to the budget, did your financing partners already indicate that they participate alongside you? Thanks.
Robert M. Blue: Yes. I am sorry, Nick. I missed the first part of the question. It had to do with turbine installation cadence, but I was not exactly the a word blurred out for me there. How many how many turbines do you need to install per quarter to make the July 2027 timeline that you laid out? Yes. I would answer it this way. I mean, our expectation is we get the majority in 2026, and then some into 2027. And as we think about it, we are looking at, you know, sort of a 2.25 days per installation. That is over a period of time.
When the weather is worse, like in the winter, it is going to be slower than that. But that is what we would look at in order to hit the schedule that we have laid out. And then on the second part of the question, yes, Stonepeak has been a great partner with us, and, you know, we have got the contractual provisions on how we would move forward if it extends into that longer period, which, as I mentioned, we do not expect.
Nicholas Joseph Campanella: Okay. And then one last one there. If the timeline 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?
David McFarland: Yes, Nick. I think you are hitting on absolutely the right point, which is given the way the regulatory recovery works, the amount of capital to be recovered in rate base is at this point effectively fixed. It is at the cap of what was allowed to be socialized to customers. And so, installation will largely be EPS neutral in the form of deferrals if we over- or under-recover in a certain rate year.
There should be some cash impacts associated with that, but that is exactly why we maintain in our internal models a very robust cushion to our existing credit downgrade thresholds is so that if in the event something like that happens, and this is just one example, we are 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?
Nicholas Joseph Campanella: This is project COD slipping to the right if you are moving installation past July ’27.
Robert M. Blue: The way to think about COD is just as the turbines come on. This is not like a combined cycle, where there is 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.
Nicholas Joseph Campanella: I will get back in the queue. Thank you.
David McFarland: Sorry about that, Nick. I tried to make that even more complicated question than I think you were actually asking.
Operator: Thank you. We will take our next question from Steven Fleishman with Wolfe Research. Please go ahead. Your line is now open.
Steven Fleishman: Yes. Hi. Good morning. Thanks. So just on the utility capital plan, is the PJM transmission that you noted, the open season, is that I assume that is that in the plan?
Robert M. Blue: Yes. Oh, yes. A lot of it. Some of it extends beyond 2030, Steve. It is sort of a portfolio approach. So we have a number of those awarded projects that ultimately are seven or eight years in duration. So we have captured all of what has been awarded through ’23 in the updated plan.
Steven Fleishman: Okay. Is there any current projects you have identified that are not in the plan during the that would be in the period, and you are just waiting for some approvals, or is pretty much everything that is kind of planned right now for the five years in there?
David McFarland: Yes. I mean, everything that we feel, you know, confident in executing to the five years is in the plan. As we have 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 will reflect that as appropriate in future updates. But this is a good snapshot of sort of where we see it today.
Steven Fleishman: Okay. And then just on two 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 would kind of apply to kind of your thinking on the timing of resuming dividend growth?
David McFarland: Yes. We have not we have not sort of made a final financial decision as it relates to the payout ratio. We are certainly aware of the trend you are describing, which is folks bringing the payout ratio as a source of funding for their enlarged capital plan. And that is something certainly we will 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 of we have a little bit of time to make a final determination as to when and how much we start growing the dividend.
Steven Fleishman: Okay. And then lastly, going back you were talking about making a decision on kind of 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 five years for a new nuclear?
Robert M. Blue: Yes. Steve, we are still in the final stages of evaluating technology. We have 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 do not have capital in the plan, this five-year plan, for an SMR. If you look at our integrated resource plan, we are still a ways away from when we would expect to be deploying SMRs. As we have 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.
Steven Fleishman: Okay. Understood. Thank you.
Operator: Thank you. We will take our next question from Steven D’Ambrosi with RBC Capital Markets. Please go ahead. Your line is now open.
Steven D’Ambrosi: Just had a quick one. Or maybe two. Just in terms of 2026 and kind of following on Shahriar’s question, you know, you are able to guide to 6% EPS growth on the operating business for ’26 with the inclusion of the Millstone double outage. And 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 do not recur in ’27, or why it takes a little bit longer to get there.
David McFarland: Yes. Steve, let me let me try that again and see if I can be more responsive. In ’26, we are 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 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 do not typically we do not 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 is less pronounced in Virginia, of course, because of the forward-looking rates, but we have that in South Carolina. So that is kind of why you see that cadence between 2026 and 2027. 2027, even though you have 8¢ to 10¢ from the lack of a double outage year, you are sort of gearing up for that next rate case, and you would see the potentially the impacts of that later in ’28. Does that help?
Steven D’Ambrosi: Yes. That is perfect. That is that is kind of what I figured. I just wanted to clarify. And then just on the 45Z credits, you know, I totally understand changing the assumptions or being more conservative, I guess. But just you did book 9¢ in ’25. Is there a reason why that falls into like, outer years? Is that just, like, changes in, I do not know, I guess, CI scores or something, or what is what is driving that?
David McFarland: It is exactly that. It is a change in CI scores. 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 does not mean that ’25 is at risk. It is not a backward-looking model in our view. We had the rules in ’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 have sort of effectively adjusted our CI scoring to reflect that, which is why we put a 5¢ to 9¢ range around that 7¢. We see the outcome of that sort of ultimate CI score somewhere in that 5¢ to 9¢.
Steven D’Ambrosi: Okay. That makes sense. Thanks very much for the time. Appreciate it, guys.
Operator: Thank you. We will take our next question from Anthony Crowdell with Mizuho. Please go ahead. Your line is open.
Anthony Crowdell: Hey, good morning. Just two quick ones. On a follow-up from Steve’s question, what is the lag you are assuming in your Virginia and South Carolina jurisdictions? I know you said there is a catch up on the rate the timing of the rate case benefit this year. But could you tell us maybe what you are assuming in 2026 for lag and in 2027?
David McFarland: Yes. That is a great question, Anthony. So there 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 do not go in as frequently for rate cases, and it is more traditionally back-looking for us. So that is a driver of, we will call it, the majority of the driver of something like a 30 to 40 basis point lower than the 10.4, so weighted average allowed that we have, and then we have another non-jurisdictional 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 have talked about at the lowest under-earning part of the South Carolina cycle, we under-earn by as 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 will start closing the gap on that. And then as we look forward, we are encouraged by legislative activity like the RSA that would potentially allow us to be in a more frequent sort of formulaic rate cases.
Still backward-looking, but more frequent, which would allow us to, as we have said in the past, try and abate that run rate of 150 to 200 basis points to something closer to 75 to 100 on a go-forward basis.
Anthony Crowdell: Great. And then just one follow-up. You had mentioned legislative I am thinking about in Virginia, and I do not know if it was proposed yesterday. I wonder if you would comment on it. There is a, I guess, proposal in the Senate of maybe eliminating a data center tax benefit or a tax shield going on. Just thoughts if you could comment on that thoughts of maybe that impacting your forecast for load growth, and that is it.
Robert M. Blue: Yes. As is always the case on our fourth quarter call, the Virginia General Assembly is ongoing. And so it is difficult to predict any kind of an outcome. I 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 are expecting off of them. We expect that to continue.
Operator: Thank you. We will take our next question from Carly S. Davenport with Goldman Sachs. Please go ahead. Your line is open.
Carly S. Davenport: Hey. Good morning. Thanks for taking my question. 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 hybrid minority interest sales?
David McFarland: Yes. That is a great question. So we think about the cadence of equity. About a third of that total five-year equity, we expect between ’26, ’27, and ’28, and about two-thirds 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, distribution and transmission, that we have got. And then with regard to alternative funding sources, we think the hybrid is such a really it is a really good product. I mean, the market for that has been super strong.
The sort of plus or so percent we can get for 50 at 50% equity credit is very attractive. As I mentioned, we are 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 will always, as you know, consider alternative sources of financing to the extent that they are more attractive than what we have sort of laid out. So we will maintain any. But right now, we feel really good about the sort of plan we have laid out. We think it is balanced. It is achievable. And it is appropriate for our credit metrics.
Carly S. Davenport: Great. Okay. That is super helpful. And then maybe just there have been a couple comments in the last few weeks from the administration on appealing the preliminary injunctions that were granted for a number of wind projects, including CVOW. Just curious if you if you do see any incremental litigation risk or headline risk on the project from sort of external involvement.
Robert M. Blue: 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 does not make sense.
Carly S. Davenport: Great. Thank you so much for the time.
Operator: Thank you. We will take our next question from Jeremy Tonet with JPMorgan. Please go ahead. Your line is open.
Jeremy Tonet: Hi. Good morning. Want to come back, I guess, to some of the earlier points with the turbine installation too. And just want to make sure it is clear. When you say early 2027, does that mean, like, a January, or does it mean a first quarter? And can you just walk through the differences between the early 2027, how that is different than the July ’27 that you are referencing before? Just want to make sure we were clear.
Robert M. Blue: Yes. Hey, Jeremy. Early means early. We did not 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 is all in the current budget of $11.05. And then if for some reason we are delayed beyond that, we have given you that benchmark of $150 to $200 million a quarter. The reason we are sort of talking this way is we are early in the installation process.
And if you would ask me, you know, two weeks into monopiles, I would have said, we are not tracking with what we expect in order to hit our schedule. And by the way, remember with monopiles, we had seasonal restrictions. So the cadence was really important to be able to hit your day. And then, of course, as we went along, we ended up finishing a month or a couple months early. Similarly, with transition pieces, we started slower, and then we picked up. And so, we will update on the cadence of turbine installation.
But given early stages, given that it is the worst weather time of the year, it just does not make sense to be drawing any sort of conclusions. We still feel good about the schedule.
Jeremy Tonet: Got it. Thank you for that. And if I could just pivot a little bit here, if you would be able to update us on how CVOW potentially faces, you know, potentially facing reduced energy deliverability until, you know, the PJM identified transmission upgrades, you know, hit completion there. Just wondering impacts on Dominion, if you could just update us your latest thoughts there.
Robert M. Blue: Yes. Look. CVOW is a really important project. It is just a few months away from delivering electricity to our customers. We asked 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 will do that study every year. And so we have been saying that some network upgrades that may not be done when CVOW is finished. But we will continue to work through making sure the project can deliver as much as safely as possible. So we have assumed 50% deliverability for this rider, and we will update it if that assumption turns out to be needed to be adjusted.
Jeremy Tonet: Got it. Thanks. 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.
David McFarland: Yes. Jeremy, the lion’s share or a good chunk of that is fuel. We categorize nuclear fuels as capital. So it is SLR, and it is fuel. And then some maintenance.
Jeremy Tonet: Got it. Thank you very much.
Operator: Thank you. We will take our next question from David Arcaro with Morgan Stanley.
David Arcaro: Morning. I was wondering, you know, another positive update here on the data center activity and contracting front. But I was wondering are you seeing data center, you know, requests to interconnect? Is that crowding out any other customer activity, whether it would be, you know, large industrial or commercial projects? How do those interact? And is there still room on your system for other large customers to connect in?
Robert M. Blue: The answer is there is absolutely room for other large customers to connect in, and they are not being crowded out. A good example, we mentioned it actually in the prepared remarks, is that Eli Lilly facility just west of Richmond. You know, large load, lots of jobs, aggressive time schedule, which we were able to meet. So we are 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.
David Arcaro: Yep. Got it. Got it. Thanks for that. 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?
Robert M. Blue: We do our IRPs every two years with an update in between. So you can see continue to update the IRP annually.
David Arcaro: Okay. Great. Thanks so much.
Operator: Thank you. This concludes our question and answer session. So I will turn it back to Bob Blue for closing remarks.
Robert M. Blue: Thanks, everybody, for taking the time to join the call today. Please enjoy the rest of your day.
Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
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