Dominion Energy (ticker: NYSE:D) provided updates on its financial performance, operational progress, and strategic initiatives during its third-quarter earnings call. The company reported operating earnings of $0.98 per share and GAAP results of $1.12 per share. For 2024, Dominion narrowed its full-year earnings guidance to $2.68 to $2.83 per share, maintaining the midpoint at $2.75.
The company has completed significant debt reduction initiatives, totaling $21 billion across six transactions. The earnings call also highlighted the company’s response to Hurricane Helene, the progress of the Coastal Virginia Offshore Wind (CVOW) project, and the growth in data center connections.
Key Takeaways
Dominion Energy reported third-quarter operating earnings of $0.98 per share and GAAP results of $1.12 per share.
The company narrowed its 2024 earnings guidance to $2.68 to $2.83 per share, with the midpoint remaining at $2.75.
Debt reduction efforts were successful, with $21 billion in debt reduced through six transactions.
Hurricane Helene caused significant service disruptions in South Carolina, with costs estimated between $100 million and $200 million.
The CVOW project is on track, with 78 monopiles installed and an LCOE of approximately $56 per megawatt hour.
Dominion anticipates connecting 16 new data centers in 2024 and is studying around 8 gigawatts of additional demand.
The PJM DOM zone is seeing substantial load growth, with 63 construction delivery point requests year-to-date.
Company Outlook
Dominion Energy aims to meet financial and operational goals while supporting communities affected by Hurricane Helene.
The Charybdis vessel is 93% complete, with expectations for finalization in early 2025, supporting the CVOW construction schedule.
The company has connected 14 new data centers in Virginia this year, projecting a total of 16 for 2024.
Bearish Highlights
Increased financing costs and the early closure of the CVOW partnership are anticipated to impact Q4 earnings.
Restoration costs from Hurricane Helene are significant, with potential securitization discussions for the recovery efforts.
Bullish Highlights
Dominion’s residential electric rates are below the U.S. average in Virginia and South Carolina, with recent settlements expected to boost revenue.
The company’s comprehensive approach to energy demand focuses on reliability and affordability, alongside clean energy initiatives.
Misses
The company’s earnings guidance adjustment reflects challenges, including increased financing costs and project closures.
Q&A Highlights
Robert Blue discussed collaborations with Amazon (NASDAQ:AMZN) on SMR technology, emphasizing the strategic importance of Virginia’s nuclear capabilities.
Blue highlighted the company’s ambitious Integrated Resource Plan, which includes significant growth in generation capacity.
Discussions are ongoing to address regulatory lag in South Carolina, which is crucial for the utility’s financial health.
Dominion Energy’s third-quarter earnings call underscored the company’s commitment to managing its financial health, advancing key projects, and addressing the challenges of a changing energy landscape. With a narrowed earnings guidance and significant progress in debt reduction and infrastructure development, Dominion is positioning itself as a responsive and forward-looking energy provider. The company’s focus on clean energy and system reliability, coupled with strategic partnerships and regulatory engagement, signals its intent to navigate the complexities of the energy sector while delivering value to stakeholders.
InvestingPro Insights
Dominion Energy’s financial performance and strategic initiatives, as discussed in the earnings call, are further illuminated by key metrics and insights from InvestingPro. The company’s market capitalization stands at $49.94 billion, reflecting its significant presence in the utility sector.
One of the most notable InvestingPro Tips is that Dominion Energy “has maintained dividend payments for 42 consecutive years.” This impressive track record aligns with the company’s commitment to shareholder value, as highlighted in the earnings call. The current dividend yield of 4.49% underscores the attractiveness of Dominion Energy to income-focused investors.
Another relevant InvestingPro Tip indicates that the “stock generally trades with low price volatility.” This characteristic is particularly important in the context of the company’s recent narrowing of its 2024 earnings guidance, as it suggests a level of stability that investors may find appealing during periods of economic uncertainty.
The company’s P/E ratio of 31.39 and Price to Book ratio of 1.94 provide additional context to Dominion’s valuation. These metrics, when considered alongside the company’s strategic initiatives and growth prospects in areas such as data center connections and offshore wind projects, offer a more comprehensive picture of Dominion’s financial health and future potential.
It’s worth noting that InvestingPro has identified 8 additional tips for Dominion Energy, which could provide further insights into the company’s financial position and outlook. Investors seeking a deeper analysis may find these additional tips valuable in making informed decisions.
Full transcript – Dominion Energy Inc (D) Q3 2024:
Operator: Welcome to the Dominion Energy Third Quarter Earnings Conference Call. At this time, each of your line is in listen-only mode. At the conclusion of today’s presentation, we’ll open the floor for questions. [Operator Instructions] I would now like to turn the call over to David McFarland, Vice President, Investor Relations and Treasurer.
David McFarland: Good morning and thank you for joining today’s call. Earnings materials, including today’s prepared remarks contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management’s estimates and expectations. This morning, we will discuss some measures of our company’s performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures which we can calculate are contained in the earnings release kit. I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit. Joining today’s call are Bob Blue, Chair, President and Chief Executive Officer; Steven Ridge, Executive Vice President and Chief Financial Officer; and Diane Leopold, Executive Vice President and Chief Operating Officer. I will now turn the call over to Steven.
Steven Ridge: Thank you, David and good morning everyone. Now, that the final transaction associated with the business review is complete, let me start by saying that we have repositioned Dominion Energy to provide compelling long-term value for shareholders, customers, and employees. Since our March 1st investor meeting, we’ve consistently communicated the three following priorities; one, hitting our financial plan; two, delivering offshore wind on time and on budget; and three, achieving constructive regulatory outcomes. By achieving these goals, we empower our employees to deliver on our critical mission to provide the reliable, affordable, and increasingly clean energy that powers our customers every day. On today’s call, we’ll address each of these areas of focus. First, hitting our financial plan. Third quarter operating earnings, as shown on Slide 3, were $0.98 per share, which for this quarter represented normal weather in our utility service areas. Third quarter GAAP results were $1.12 per share. As always, a summary of all drivers for earnings 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 reported results are included in Schedule 2. With nine months of 2024 financial results reported, we’re narrowing our full year guidance range to $2.68 to $2.83 per share, while preserving the original guidance midpoint of $2.75. As we highlighted on the last call, fourth quarter earnings are expected to be impacted by higher-than-expected financing costs and normal course movement of operating and maintenance expense from the first half to the second half of the year. Fourth quarter earnings will also be negatively impacted by the earlier-than-planned closing of the CVOW partnership because the associated non-controlling interest hurt, net of debt reduction, is beginning earlier than we expected. Honestly, that’s an assumption I’m happy to have been too conservative about as early closing of the transaction represents a meaningful derisking of our plan. Quickly turning to 2025 through 2029, where there are no changes to our prior guidance. We are reaffirming all guidance, including 2025 operating earnings per share of between $3.25 and $3.54, inclusive of approximately $0.10 of RNG 45Z credit income with a midpoint of $3.40. We continue to forecast an operating earnings annual growth rate range of 5% to 7% through 2029, off a 2025 midpoint of $3.30, which excludes the impact of the RNG 45Z credits due to the legislative sunset of that credit at the end of 2027. As a reminder, we continue to expect to see variation within our annual 5% to 7% growth range as a result of the Millstone refueling cadence, which requires a second planned outage once every third year. Finally, we’ll provide a comprehensive capital investment forecast update through 2029 on our fourth quarter earnings call, which will take place as usual in early 2025. Turning now to Slide 4. As I mentioned earlier, I’m delighted to report that we have now closed on 100% of the debt reduction initiatives that we announced during the business review. Since our last update, we’ve successfully closed on the sale of the public service company of North Carolina to Enbridge (NYSE:ENB) and the CVOW partnership with Stonepeak. Combined with previous closings, this effort represented approximately $21 billion in debt reduction across six separate transactions requiring multiple federal and state regulatory approvals, all of which were completed in line with or ahead of our publicly announced timeline. We view this as a significant achievement made possible by the collaboration of our counterparties and hard work of our employees. We appreciate the thorough and comprehensive reviews performed by our regulators. I’ll finish my remarks on our financing plan as shown on Slide 5. With the completion of our third quarter financing activities, including our $1.2 billion VEPCO debt issuance and $200 million of ATM issuance, we have fully achieved our 2024 financing plan. We’ll continue to monitor ways to derisk the company’s 2025 financing needs by opportunistically accessing the market through the remainder of the year if and when conditions warrant. For instance, as you’ll see in the 10-Q filing, we’ve gotten a head start on 2025 guided ATM issuance, selling approximately $200 million of shares under the traditional forward sales structure that we expect to settle at the end of 2025. In conclusion, I’ll reiterate that I am 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.
Robert Blue: Thank you, Steven and good morning. I’ll start my remarks by highlighting our safety performance. As shown on Slide 6, our employee OSHA injury recordable rate for the first nine months of the year was 0.44, in line with the continued positive trend from the last two years. I commend my colleagues for their consistent focus on employee safety, which is our first core value. In late September, Hurricane Helene caused historic devastation to many communities, including within our South Carolina service area. As a result, we saw significant destruction of our infrastructure, which caused nearly 450,000 service disruptions. At its peak, Helene left nearly half of our South Carolina electric customers without power. This was the largest storm to hit our South Carolina system since Hurricane Hugo 35 years ago. Our employees, many of whom didn’t have power or water themselves, worked around the clock in challenging conditions to quickly and safely restore power to our customers. They were joined by over 1,000 of our Virginia team members and partners who traveled south to lend their assistance. The restoration involved replacing over 1,000 transformers, 2,300 poles, and 7,000 spans of wire. Although we’ve not completed our final accounting, our preliminary estimate of restoration costs, including capital expenditures, is in the range of $100 million to $200 million. Given that costs are expected to be in excess of $100 million, we intend to work with the Office of Regulatory Staff and key stakeholders to evaluate a potential securitization of those deferred costs. We know that this storm impacted the lives of many, including our employees, and our thoughts continue to be with the families and communities that are rebuilding. I’m incredibly proud of our employees and commend all involved for their commitment to serving our customers. We’ve provided direct financial aid to over 20 different local organizations and the communities impacted by the storm to support disaster recovery and response, including meals, shelter, emergency services, and supplies. And we will continue to look for ways to support our customers, employees, and communities. With that, let me provide a few updates on the execution of our plan, beginning with CVOW. The project is proceeding on time and on budget, consistent with the timelines and estimates previously provided. We just completed a very successful first monopile installation season. As shown on Slide 7, we’ve installed 78 monopiles as well as 4 pen piles that support the first of three planned offshore substations. Additionally, we’ve laid the first two of nine marine deepwater export cables ahead of schedule. I’m very pleased with our progress during this first season. Not only did we achieve our installations target, we also gained invaluable experience and process expertise that will make the next installation season even more productive. I also want to thank our partners at DEME for the high-quality work they delivered. Additional CVOW project updates can be found on Slide 8, but a few items to highlight. On materials and equipment, thus far, we’ve taken receipt of 96 monopiles at the Portsmouth Marine Terminal, representing 55% of the project total. Our partner, EEW, continues to make strong progress, and we expect deliveries to continue steadily in coming weeks. All three offshore substations remain on track, with the first substation and final commissioning and expected to be completed and shipped to Virginia for installation before the next monopile season begins. 82 transition pieces have completed final assembly, of which 33 have been delivered to the Portsmouth Marine Terminal. Additionally, with fabrication of towers commencing last June, the schedule for the manufacturing of our turbines remains on track. We anticipate the nacelle and blade production will begin in the first quarter of 2025. On regulatory, as you may have seen, we made our 2024 offshore wind rider filing this morning, representing $640 million of annual revenue. Turning to Slide 9. The project’s expected LCOE has improved to approximately $56 per megawatt hour, the primary driver being forecasted REC prices, which have increased in value considerably. Keep in mind that higher REC prices are credited against the levelized cost of energy as value delivered to customers. Project-to-date, as of September 30th, we’ve invested approximately $5.3 billion and remain on target to spend approximately $6 billion by year-end 2024. Also per the quarterly filing update today, current unused contingency is $121 million compared to $143 million last quarter. The current contingency level continues to benchmark competitively as a percentage of total budgeted costs remaining when compared to other large infrastructure projects we’ve studied and ones that we’ve completed in the past. We have been very clear with our team and with our suppliers and partners that delivery of an on-budget project is the expectation. Lastly, the project is currently 43% complete, and we’ve highlighted the remaining major milestones on Slide 10. Turning to Slide 11, let me now provide a few updates on Charybdis. Since August, we’ve completed engine load testing to support crane operations with parallel engine testing underway. In the coming weeks, the final sections of the legs will be set by the crane as well as overall electrical work to allow for commissioning activities. The vessel is currently 93% complete, up from 89% as of our last update. We expect completion of Charybdis in early 2025, consistent with our previous guidance range of late 2024, early 2025. The vessel will complete sea trials and then return to port for additional work that will allow it to hold the turbine towers, blades, and nacelles. There’s no change to the vessel’s expected availability to support the current CVOW construction schedule, which we anticipate will start in the third quarter next year. There’s also no change to the vessel’s cost of $715 million. Moving now to Slide 12, we continue to see strong data center growth in Virginia and have already connected 14 new data centers year-to-date. We now expect to connect 16 data centers in 2024, up from 15 as of our last update. Since 2013, we’ve averaged around 15 data center connections per year. Turning to data center demand on Slide 13. These contracts are broken into: one, substation engineering letters of authorization; two, construction letters of authorization; and three, electrical service agreements. As customers move from one to three, the cost commitment and obligation by the customer increases. We’re currently studying approximately 8 gigawatts of data center demand within the substation engineering letters of authorization stage, which means that customers requested the company to begin the necessary engineering for new distribution and substation infrastructure required to serve the customer. There are also about 6 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. Should customers in this stage elect to discontinue projects, they’re obligated to reimburse the company for our investment to date. Finally, the 8 gigawatts included in electrical service agreements, or ESA, represent contracts for electric service between Dominion Energy and a customer. Each contract is structured for an individual account. By signing an ESA, the customer is committing to consuming a certain level of electricity annually, often with ramp schedules where the contracted usage grows over time. In aggregate, we have data center demand of over 21 gigawatts as of July 2024, which compares to around 16 gigawatts as of July 2023. These contracted amounts do not contemplate the many data center projects that are in development phase and have not yet reached a point in the service connection process where a contract is executed. Turning to Slide 14, let me update you on our transmission system planning. As I’ve shared previously, the PJM DOM zone is experiencing unprecedented load growth. This has resulted in a similarly unprecedented increase in both the quantity and size of delivery point requests for transmission service on our system. For context, we’ve received 63 construction delivery point requests year-to-date September, representing nearly 13 gigawatts of capacity. Since 2020, we’ve received 280 construction delivery point requests, representing nearly 40 gigawatts of capacity. We’ve recently begun implementing changes to our process that will only affect new delivery point requests. This will allow us to organize load requests into batches and serve them in the order they’re received. Importantly, this will ensure our customers can continue to count on high system reliability even as demand increases materially. Since we began communicating these changes, we’ve continued to see robust demand from customers. Turning to Slide 15, let me share a few additional business updates. First, on the transmission side, we submitted project proposals in September in PJM’s latest open window process for our own transmission portfolio and as part of a joint planning agreement along with AEP and FirstEnergy (NYSE:FE). We believe this regional collaborative approach allows our companies to offer better solutions to customers than what we could offer alone. While final project selections by PJM won’t be made until early 2025, there’s a robust need for new transmission across the region, and we expect this open window to reflect that. Recall that last year, we were awarded over 150 transmission projects totaling $2.5 billion. On the generation front, we’ve announced a number of updates in recent weeks. First, on October 1st, we filed our annual update in the subsequent license renewal proceeding for our nuclear units at Surry and North Anna, seeking recovery of costs incurred for the North Anna extension and cost for Phase 2 of the overall nuclear life extension program, consisting of investments during calendar years 2025 through 2027. On October 15th, we filed our next set of utility-scale solar projects with the Virginia SEC, representing approximately $600 million of investment. Also on October 15th, we filed our 2024 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 and changes in PJM’s resource adequacy values. The IRP calls for more of every resource, including more solar, more storage, more wind, more gas, and even more nuclear. On that note, turning to Slide 16. On October 16th, we announced an MOU with Amazon to further explore the feasibility of developing SMR technology at North Anna. To be clear, our interest is in supporting customer power needs and advancing next-generation nuclear in a way that protects our customers, our capital providers, our business risk profile, and balance sheet from development risks including first of a kind risk. We’re in early stages here so I’m going to be limited in what I can share on potential structures and the like. But I’ve explained the factors we’ll consider in evaluating any final agreement and we’ll provide more details in the future as we’re able. I will say that it’s very encouraging to see large power users, including technology companies, express a willingness to invest, partner and collaborate to bring this exciting baseload carbon-free technology into fruition. Finally, I’d note that we’re actively involved in discussions with other potential partners that are very interested in pursuing similar arrangements. On October 24th, we closed on the acquisition of an approximately 40,000-acre offshore wind lease from Avangrid (NYSE:AGR), representing approximately 800 megawatts of additional possible regulated offshore wind generation. This is in addition to the lease area we secured adjacent to CVOW, which could support even more regulated offshore wind in the future. No timelines on how or when or how much it will cost to advance these options further. Our unique expertise and proprietary knowledge associated with offshore wind developed through our CVOW project gives our customers a competitive advantage. These announcements altogether reflect an all-of-the-above approach to meeting growing demand, and we look forward to working constructively with all stakeholders on these projects. As we’ve said before, when we consider demand growth, we think about the full value chain, transmission, distribution, and generation infrastructure investment that has and will continue to drive utility rate base growth. Given these drivers, we expect there to be opportunities for incremental regulated capital investment towards the back end of our plan and beyond. As noted, we plan to update our capital guidance on our fourth quarter earnings call in early 2025. As always, we will look at incremental capital through the lenses of customer affordability, system reliability, balance sheet conservatism, and our low-risk profile. On customer affordability, as shown on Slide 17, our current residential electric rates at DEV and DESC are 14% and 11% below 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. Turning to regulatory updates in South Carolina and North Carolina on Slide 18. As mentioned last quarter, we agreed to a settlement with the Office of Regulatory Staff and other interveners in South Carolina in our electric rate case proceeding, which was approved by the South Carolina Public Service Commission in August with rates becoming effective on September 1st. In addition, policymakers continue to evaluate potential energy legislation, and we’re appreciative of the significant time spent to-date by the legislature on this important topic. As we’ve indicated in the past, we’re committed to supporting South Carolina’s growing economy. However, as we’ve testified, the regulatory framework for DESC creates regulatory lag that makes it practically impossible to earn our allowed return, especially as compared to other regulated jurisdictions and the surrounding Southeast regulatory jurisdictions as well. In North Carolina, we reached a settlement with the public staff and other interveners in our base rate proceeding on October 1st, providing approximately $37 million increase in revenue requirement premised upon a 9.95% ROE and a 52.5% equity layer. The agreement also stipulates that $9 million in annual ongoing CCR costs be removed from base rates and placed in a stand-alone rider, subject to approval. Interim rates become effective today in North Carolina, pending the commission’s final order. Overall, we continue to achieve constructive outcomes in all of our regulated service territories. Before I conclude my remarks, let me provide a few comments on Millstone. As we’ve said in the past, we view Millstone as a very valuable asset. It provides more than 90% of Connecticut’s carbon-free electricity and 55% of its output is under a fixed price contract through late 2029. The remaining output is significantly derisked by our hedging program. As many of you are aware, there has been recent legislative activity in New England and in Massachusetts specifically, aimed at authorizing future additional procurements of nuclear power. And we’ve continued to engage with multiple parties there to find the best value for Millstone. In addition to state-sponsored procurement, we’re exploring the idea 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. At this point, we don’t have a timeline for any potential announcements but this remains top of mind for us. With that, let me summarize our remarks on Slide 19. Our safety performance this quarter remains strong, but there’s more work to do to drive injuries to zero. We reaffirmed all financial guidance from March 1 and narrowed our 2024 earnings guidance range. Our offshore wind project remains 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 continue to deliver and we will. With that, we’re ready to take your questions.
Operator: Thank you. And at this time, we will open the floor for questions. [Operator Instructions] And we will take our first question from Shar Pourreza with Guggenheim Partners. Please go ahead.
Shar Pourreza: Hey guys, good morning.
Robert Blue: Morning Shar.
Shar Pourreza: Bob, just coming back to your comments around the Amazon deal and other potential partners. And can you just give us a bit more color on what these other conversations are? What’s the timeline? Is it the same technology? Different types of SMRs? And have you had any kind of hyperscale or interest in the OSW? Thanks.
Robert Blue: Yes, Shar, great question. Our conversations with Amazon and others have really focused around this new technology of SMR. Let me talk a little bit about that if I could. If you think about why SMRs have become prominent in the national conversation recently, it’s really three reasons; one is significant demand growth, driven in large part by large users like data centers. Second, a continued focus on around-the-clock carbon-free generation to meet reliability and carbon reduction goals. And the third, a view that U.S. leadership and nuclear technology is important to national security. And if you think about it, our Virginia utility is right at the intersection of all three of those. We’re obviously continuing to see significant load growth in Virginia. Our power demand forecasted to double by 2039. We have a state law in Virginia, the Virginia Clean Economy Act, that calls for a carbon-free grid by 2045 with off-ramps for reliability. And then we serve some of the most important national security and defense installations in the country, like the Pentagon, the CIA, Fort Belvoir, the Norfolk naval base. And then I might add, Virginia is arguably the most nuclear-friendly state in the United States with strong bipartisan support for next-generation nuclear initiatives. Governor Youngkin, Senators Warner and Kaine have all endorsed these efforts. They were at our Amazon announcement recently. The Virginia legislature on a very bipartisan and overwhelming basis passed legislation that allows companies to petition for cost recovery related to certain SMR project development. And then if you think about it, our state is home to significant nuclear operations, Huntington Ingalls (NYSE:HII), Newport News, BWXT, and Framatome in Lynchburg and then, of course, our long operating units at North Anna and Surry. So, if you think about that context, it’s not surprising that our large customers would be interested as they think about us as a good operator of nuclear to work together on maybe advancing those kinds of technologies. So, we’ve been talking with Amazon obviously and others. Now, all that said, we’ve got to be very clear headed in the way we go about this, and we’ve got to make sure we mitigate potential cost and development risk for our customers and our provider of capital. So, we’re going to think very clearly and evaluate the feasibility of SMR technology to support our customers’ needs. They can play a role in our all-of-the-above approach, along with offshore wind and battery storage. They’re going to potentially be an important part of Virginia’s growing clean energy mix. So, we issued an RFP last summer to evaluate technologies. But beyond technology, we also need to be smart about financing. And as I mentioned in the prepared remarks, I can’t really talk about the specifics of our positioning with Amazon or these other interested parties. But I can tell you, it builds on — these are customers, particularly Amazon we have a long-standing relationship with. And they’ve indicated a willingness and interest to participate in funding. So, structure could be something like a build-on transfer. But fundamentally, in any structure we agree on with Amazon or other parties who have expressed interest in this, that structure needs to address first of a kind risk. It needs to address cost overrun risk so that our customers and Dominion Energy don’t bear that burden. And we need to protect our balance sheet and our business risk profile. So, we’re very excited and optimistic about our agreement with Amazon and our conversations with other parties around small modular reactors. And we’re going to be unyielding on those principles that I just identified.
Shar Pourreza: Do any of the hyperscalers have interest in offshore wind?
Robert Blue: We’ve talked a little bit about them, but the focus of our conversations recently with them has been on SMRs. Remember, we’ve got the contracted — I mean, the regulated CVOW that we’re building now that’s already — its cost recovery is already well identified. And as we said in the prepared remarks, Shar, we’ve got these other two options, but we’re not at a point now where we have any decisions or timelines. We’re very focused in bringing CVOW in on time and on budget. So, it really would be premature to be having conversations with them about future offshore wind. And we’ve got the offshore wind project underway today under standard regulatory construct.
Shar Pourreza: Got it. And then just lastly on the IRP filed a few weeks ago. The portfolio scenarios seem to indicate you would be somewhat of a short position in the state from a capacity standpoint. Why not add more generation to the plan at this point? Too much political sensitivity to gas in the state? Why lean on PJM so much in the plan? Thanks guys.
Robert Blue: Yes, sure. That’s a great question. We’ve got a lot of growth in our Virginia jurisdiction, which is really exciting. And we’re — if you look at the IRP, we’re building a heck of a lot and it’s across all facets of the generation portfolio. It’s potentially doubling the amount of offshore wind. It’s adding a substantial amount more natural gas than last year’s IRP. It’s adding additional solar even beyond what the Clean Economy Act calls for and also large amounts of battery storage. So, I think it would be fair to say that while we’re certainly mindful of what PJM’s capabilities are, we’re building a heck of a lot in this plan. We’ll always look for opportunities when it makes sense from a reliability and a customer affordability point of view to do more. But we feel like it’s a pretty aggressive plan as it is based on a very substantial demand forecast.
Shar Pourreza: Congrats, guys, on the results, really. See you in a week.
Robert Blue: Thanks Shar.
Operator: Thank you. And we will take our next question from Nick Campanella with Barclays. Please go ahead.
Nick Campanella: Hey thanks for taking my question.
Robert Blue: Morning Nick.
Nick Campanella: Morning. I wanted to check in on the Millstone commentary just continue on the nuclear side. You’re kind of talking about finding the best value for it. It does seem like the opportunity set has expanded versus what maybe you were kind of contemplating at the Analyst Day offset there. And maybe can you just talk about like if there was to be a data center there? I believe you’ve already done an uprate there, but are there any options for additionality to contemplate? And how could this all come together? Thanks.
Robert Blue: Yes. Nick, we’re studying whether there is a possibility of uprates at Millstone, particularly Unit 2 there, which is the smaller of the 2 units. But as we said in our prepared remarks, there are potential options for contracted procurement in New England. There are potential options for a data center location if it can be done in a way that works for all stakeholders in Connecticut. But it’s early days in terms of those conversations so we don’t have more to report to you today than what we’ve already identified.
Nick Campanella: Okay, I appreciate that. And then just thinking through what’s kind of incremental since you’ve outlined the Analyst Day, you filed this IRP. You’ve highlighted this RTEP process, which I’m sure we’ll get clarity on by the fourth quarter call. And obviously, CapEx is going up, but just when you consider the balance sheet and the financing outlook and also considering that maybe some of this capital is going to be more formulaic than it has been in the past, just where do you think you can really bring rate base growth from where it stands today? Is it — does it extend the current rate base growth or is it really kind of more additive? And I’ll leave it there.
Robert Blue: Yes, Nick, that’s a great question. And we think about that a lot. So, at our March 1 Analyst Day, we were very clear that we were providing a high-quality durable operational and financial plan with targets that we expect to achieve consistently, and I put emphasis on that word, consistently. So, the plan is built on appropriately conservative assumptions. Now, we operate in premium markets in the Southeast, in Virginia and South Carolina, so we see additional opportunities that can further strengthen our position. And as you alluded to, potentially even extend the long-term growth rate. That’s going to be in the later part of the plan. But we’re focused on an approach that positions us to deliver predictable year-over-year results and strong performance for the long-term. So, we’ll, as you noted, provide an update on our CapEx plan on the fourth quarter call just three months from now. And there, we will underscore our commitment to disciplined growth and operational excellence. But I — the investor feedback that I have received agrees with an approach of consistent execution against the targets that we already laid out on the 1st of March.
Steven Ridge: And Nick, I would just add, we’ve said, I think, in several venues and here on this call again today is I think we believe if there is bias around our capital plan, it is upward. We think that, that opportunity would probably present itself, given how long it takes to get projects planned and capital invested and deployed, it would be towards the back end of that framework of 2025 through 2029. And you mentioned balance sheet. We’ve worked really hard during the review to establish a balance sheet with an appropriate amount of cushion. And as new capital comes into our plan, we’ll be thoughtful about how we finance that. Not all capital projects are equal. We spend a lot of time internally thinking about the speed of cash conversion. Some projects turn investment into cash flow more quickly than other projects. And we’ll need a mix of those characteristics as we build our plan, but we will be very mindful about how we make sure we finance it in a way that preserves that cushion that we’ve worked so hard to achieve and we’ll continue to have.
Nick Campanella: All right. Thanks for the thoughts today.
Robert Blue: Thanks Nick.
Operator: Thank you. And we will take our next question from Ross Fowler with Bank of America. Please go ahead.
Ross Fowler: Morning. So, just maybe talking about South Carolina a little bit. You’ve obviously got the electric settlement there and the approval. How do you think about the schedule from here around legislation moving forward potentially next year? And is that sort of thoughts around economic development on one side, but also sort of, as you said kind of in your comments, Bob, there’s got to be something there to sort of address regulatory lag in the state as well? And then the corollary is there, is there also a new nuclear opportunity there, an opportunity around nuclear? I mean, how do we contextualize the experience with V.C. Summer that we’ve been through versus there is space on that site to maybe do SMRs or something else?
Robert Blue: Yes. So, let me start with the second part first. I think as we said publicly, we’re not pursuing a restart of V.C. Summer on that — of the new units on that site. So, more broadly though, on your question, as you know, as you referenced, the Senate Select Energy Committee is still meeting regularly to produce a companion bill to the one that the House sent over at the end of the 2024 session. Those discussions, as you know, have — continue to center on authorization for us to partner with Sandy Cooper on a combined cycle plant there. They focus on permitting reform. And also, there have been a lot of conversations recently on regulatory lag. The original legislation talked about the financial health of the utility. And as we think about the financial health of utility, addressing regulatory lag is very important and that conversation has, I think, its focus has sharpened recently. So, we’re very supportive of the work that they’re doing. It’s a great — South Carolina’s a great place to do business. It’s the fastest-growing state in the country or certainly among them. It’s a great state for business. And I think we’ve got great opportunities to invest there. We’re going to work with policymakers to address this lag issue. It’s top of mind for us. It appears to be on the minds of legislators down there, which is good. And we’ll have a session coming up at the beginning of next year and see how it all sorts itself out.
Ross Fowler: Okay, Bob, thank you for that. And then maybe moving to storm recovery. Obviously, I think you guys did a phenomenal job on getting everybody back up on power that can take power after the hurricane, so congratulations to you on that. But how do I think about the schedule from here around getting cost estimates finalized, thinking about how much of that is capital versus O&M? And then remind us how the recovery mechanisms for those costs kind of work?
Robert Blue: Yes. Before Steven answers that, I was able to spend some time down in South Carolina right after the storm, particularly in Akin County, which was the most damaged. And it was — the damage there was significant. And I was just so proud of our team for how hard they were working and continue to work to get the lights back on for folks. And as we think about it, that’s the most important part of this discussion. But I’ll turn it to Steven to talk a little bit about the timing of recovery.
Steven Ridge: In South Carolina, we defer these to the balance sheet. Given the nature of the storm, the bias of that estimated cost is actually more towards capital than O&M. That’s a little bit unusual for like large outage events we have in South Carolina and in Virginia. As part of our most recent settlement on the electric, we agreed with the staff that in good faith pursue potential securitization for storm costs that exceed $100 million. So, we’ll have those discussions with them. And I don’t have specific timing for you but we would expect this to be a constructive recovery outcome.
Ross Fowler: Okay. Thanks Steve. And maybe 1 last 1 for me back to the MOU with Amazon and I appreciate you can’t give us any details here. But just remind us, there’s rate structures in Virginia like we have had under the offshore wind where other non-utilities can put capital in. And I believe it’s up to 80% of the capital for a project. And is that something that you’re kind of referencing with your build-on transfer potential comments?
Robert Blue: Yes, I’m not exactly sure what you’re talking to on the 80%. And the investment in offshore or offshore wind project was specifically authorized by legislation in 2023. But there are certainly opportunities for special contract rates with customers or special tariffs. So, that may be a possibility here. But really beyond that and beyond the principles that I talked about earlier, there’s not a lot more I can add at this stage.
Ross Fowler: Okay, understood. Thank you.
Robert Blue: Thanks Ross.
Operator: Thank you. And we will take our next question from Jeremy Tonet with JPMorgan. Please go ahead.
Jeremy Tonet: Hi, good morning.
Robert Blue: Morning Jeremy.
Jeremy Tonet: It’s Jeremy Tonet from JPMorgan. Just quick ones, if you could. A lot of good detail here. For the latest REC value in CVOW’s LCOE here, can you walk through the factors driving the revision and how that — how sensitive that assumption is to load growth and renewable additions in the future? Just wanted to see, I guess, what we should be thinking here?
Steven Ridge: Yes, Jeremy, that’s a really good question. So, obviously, we saw a very substantial move in the LCOE for CVOW. And we highlighted the driver for that, which is higher expected REC pricing. And when you think about the LCOE calculation, we created that metric to be able to compare it to the reference legislative cap, which is a combustion turbine, which in 2017 dollars is $125 per megawatt hour. And so let me walk through the three components in that calc, so you can think about how that number may move. So, the first is a sort of fairly straightforward revenue requirement associated with cost of service buildup, so it’s depreciation, maintenance, property taxes as applicable. It’s return on capital, both the financing for the debt as well as the return on equity. So, that’s pretty straightforward. And we’ve given sensitivity to say, hey, if interest rates are financing up or down, here’s how the LCOE would change. We’ve given sensitivities if capital goes up or down. So, that would all impact that. That’s all pretty straightforward. The next is PTCs or ITCs. It’s PTCs because that’s the best for customers. But we credit against that cost of service, the PTC (NASDAQ:PTC) value, which I think makes sense and anticipate huge changes there. We do have a sensitivity for capacity factor, which would affect the denominator and also the amount of PTC, and we’ve shared that sensitivity as well. The last item is this REC value. So, under a renewable portfolio standard, which the Virginia Clean Economy Act established in Virginia, just like RPS standards in other states, that legislation effectively gives credit to a renewable generation resource to put it closer to being on level playing field with a non-renewable resource. And so in the absence of this project, the CVOW project, our customers would need to procure that REC value. And it’s a phased approach so a percentage of our overall load with an adjustment for nuclear megawatt hours, and that steps up through 2045 so it sort of gradually moves up. A percentage of that load has to be met with RECs. And so — and that allows us to say, hey, relative to this reference resource of the combustion, you really need to give credit to CVOW for the production of these RECs. And as the market value of RECs go up, the value of the CVOW project with the RECs that it creates becomes more valuable for customers. So, that gets netted as well. We don’t have perfect clarity as to where market REC prices will go. We know there’s been upward pressure on it as a result of two things. One is the ratcheting up of the demand for which we have to procure up specific percentage, like capacity in that respect, as well as the need for us to achieve a growing percentage of that demand. So, it steps-up from 2023. And then in 2025, the law stipulates that 75% of those RECs need to be procured from Virginia-based resources, which is a change. In previous, it could be procured from anywhere in PJM. Now, it needs to be 75%. So, put all that together and the market is reflecting a supply/demand balance, which is favoring a higher REC price. So, where will it go? We don’t know. We provide you the table with both with and without REC so you can sort of see with this impact and without this impact. That’s how we’ve presented it to our regulators. I suspect those values will still be — they’ll stay strong, given the dynamics I just described, but we’ll just watch it and we’ll be transparent with folks. But bottom-line is that we feel like the regulated construct that our policymakers created for offshore wind has resulted in a very good outcome for our customers, and we’re very, very focused on making sure we deliver on that promise.
Jeremy Tonet: Got it. That’s very helpful. Thank you for that. And maybe going back to transmission for a little bit more, if I could. For PJM’s open window, can you expand a bit more on the opportunity through your joint projects with AEP and FirstEnergy there. Just really how these projects fit within PJ’s transmission system today as it stands and as load growth continues here. Thinking about also as well, I guess, further route, you mentioned opportunities in the back half of the plan. Any additional thoughts on the cadence of when that could come to fruition?
Robert Blue: Yes Jeremy. As we described in our remarks, we submitted these proposals in early October in PJM’s latest open window process. And there’s growth happening throughout PJM and the opportunity to do something innovative like this with AEP and FirstEnergy, we believe really we’re leveraging the expertise of our incredible transmission group, AEP’s incredible transmission group, FE’s incredible transmission group, to get the most cost-effective solutions as demand is growing. And we’re going to — we’ve been talking about this for a while, need additional transmission in order to remain reliable to be able to work with those companies to do something a little bit different, we think, makes a lot of sense. It could represent additional CapEx above the March 1 plan if the projects are ultimately awarded by PJM, but those projects are currently under review. They’re in the early stages of development. We don’t anticipate selection by PJM until the first quarter of next year. So, it is hard for us at this stage to tell you what the cadence of CapEx or the amount of CapEx would be, given we’re waiting more from PJM. But I would just leave you with that we expect this open window could be as big, if not even bigger than last year’s, which was, as I mentioned, 150 for us, 150 transmission projects totaling $2.5 billion.
Jeremy Tonet: Got it, fair enough. I shouldn’t get too ahead of myself here. Real quick last one, if I could. Just as far as it relates to the call on generation today, given all this load growth. If you could provide any updated thoughts on how this could or maybe doesn’t impact coal plant retirement timelines in general? And at the same time, these EPA regs as it relates to CCS for natural gas plants. Just wondering, any thoughts there on how that impacts your thought process?
Robert Blue: Yes. Jeremy, first, I’m impressed that you asked us many questions when you aren’t the only person in the queue. Well done. But let me say on the question of EPA regulations and fossil retirements. First of all, you can — both those questions are really addressed in the IRP that we just filed. So, it’s a 15-year look and you can see there’s no fossil retirements in the IRP planning horizon precisely because of the load growth we’ve been talking about and the load growth that’s identified in the IRP. So, no expectation, as that document exists today, as everything that we see today, that we would be retiring any fossil units in the next a decade and a half. And then as to the new EPA regulations, we actually ran scenarios in the IRP with and without those EPA regulations and it did not swing that much what we’re building. So, we’re going to sort of keep working through the regulations. They’re obviously being litigated. But when we ran the models for the IRP, not a huge change between with and without those new EPA RECs.
Jeremy Tonet: Got it. Thank you for that. I’ll have to think of more questions for next time. Thank you.
Robert Blue: Thanks Jeremy.
Operator: Thank you. And we will take our next question from Anthony Crowdell with Mizuho. Please go ahead.
Anthony Crowdell: Hey good morning team, unlike Jeremy, I just have one question. And kind of off of Nick’s question, so honestly, if you say we answered it with Nick’s question, that’s fine. Nick, I thought, was focused more on the rate base growth story and maybe updating that. Obviously, new you saw utilities revising earnings growth rates. I’m just curious on what’s the calculus, sort of what do you guys look at when you evaluate your financial plan? Whether it’s something like sustainable or not, like about whether it’s your visions on rate base growth, and I’m actually leaning more towards like an earnings growth number. And again, feel free to say you answered it in Nick’s question.
Robert Blue: We largely answered it in Nick’s question, but we’ll let Steven offer up a little bit more.
Steven Ridge: Anthony, I think it’s a very good question. It’s very topical, given calls this season. And I guess the way I would describe it is we put out — as Bob mentioned, we put out a financial plan on March 1st that we feel very confident in our ability to consistently meet. To the extent that we see continued tailwinds in this — among the various drivers we’ve talked about, which is very, very strong load growth and more opportunities to deploy capital and strong regulatory regimes. Every year we put out an update, we’re going to be thinking about what the right plan looks like. For us, we think achieving consistently high-quality, predictable, low-risk earnings is the number one objective of our financial plan. And to the extent that we are in a position to do something better, either from a rate base growth perspective or from an earnings growth perspective, we’ll consider that very carefully, making sure we’re not doing something that’s going to jeopardize our ability to deliver on that consistent, predictable, high-quality, low-risk earnings trajectory. And we’ll make sure we finance it in a way that preserves that framework as well. So, it’s kind of a little bit of a non-answer, which is sort of — we’ll evaluate that every year when we come out with our updated plan or revised, refreshed capital outlook. We obviously have some tailwinds like a number of folks in the industry but we feel really good about the plan we put out on March 1st.
Anthony Crowdell: Great. Thanks for taking my question. That’s all.
Operator: Thank you. And we will take our next question from Carly Davenport with Goldman Sachs. Please go ahead.
Carly Davenport: Hey, good morning. Thanks so much for taking my question. Just wanted to ask a follow-up on Jeremy’s question on the IRP and the EPA regulations. So, it looks like there’s still a fair bit of gas, including combined cycle units in that plan. So, just to confirm based on your comments, that does take into account the cost of potentially fitting those assets with CCS technology?
Robert Blue: No, it doesn’t take into account the cost of fitting them with CCS, but it does take into account the capacity factor limits within those regulations. So, as we’ve said, we don’t think that CCS is adequately demonstrated. That’s obviously going to be a subject of litigation with EPA. But the plan that we put out takes into account the regulations by just adjusting for the capacity factor.
Carly Davenport: Got it, okay. I appreciate the clarification. That’s super helpful. And then maybe just 1 quick follow-up, a high-level question as you think about the opportunities surrounding SMRs. As you think about potential timing to commercialization of that technology, I know you’ve got the 2034 kind of starting date in the IRP. Is that sort of indicative of your views on when you think you could see sort of scaled commercialization of SMRs? Or just any broad views on kind of the timing from that perspective would be helpful?
Robert Blue: Yes, the IRP does reflect our view on timing. So, again, we’re going to stick with the principles I outlined. But assuming that we achieve those, what we think is feasible would be and the timelines that we put in the IRP.
Carly Davenport: Great. Thank you so much for the color.
Operator: Thank you. This concludes our question-and-answer session, so I’ll turn it back to Bob Blue for closing remarks.
Robert Blue: Thanks everyone for taking time to join the call today. Everybody, enjoy the rest of your day, your weekend, and we’ll see you at EEI. Thanks very much.
Operator: Thank you. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
This article was generated with the support of AI and reviewed by an editor. For more information see our T&C.
