Welcome to the Dominion Energy Third Quarter Earnings Conference Call. Currently, all lines are in listen-only mode. After today's presentation, we will open up for questions. I will now hand the call over to David McFarland, Vice President, Investor Relations and Treasurer.

Good morning and thank you for joining today's call. Earnings materials, including today's prepared remarks contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management's estimates and expectations. This morning, we will discuss some measures of our company's performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures which we can calculate are contained in the earnings release kit. I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit. Joining today's call are Bob Blue, Chair, President and Chief Executive Officer; Steven Ridge, Executive Vice President and Chief Financial Officer; and Diane Leopold, Executive Vice President and Chief Operating Officer. I will now turn the call over to Steven.

Thank you, David and good morning everyone. 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 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.

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 targets, 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 the coming weeks. All three offshore substations remain on track, with the first substation and final commissioning 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. 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 the 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, 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.

Thank you. We will now open the floor for questions. Our first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Hey guys, good morning.

Morning Shar.

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.

Yes, Shar, that's a great question. Our discussions with Amazon and others have primarily revolved around the new technology of small modular reactors (SMRs). Recently, SMRs have gained attention for three main reasons: significant demand growth, particularly from large users like data centers; a continuous focus on achieving around-the-clock carbon-free generation to meet reliability and carbon reduction goals; and the recognition that U.S. leadership in nuclear technology is vital for national security. Our Virginia utility is positioned at the center of these three factors. We are experiencing substantial load growth in Virginia, with power demand expected to double by 2039. The Virginia Clean Economy Act mandates a carbon-free grid by 2045, with provisions for reliability. Additionally, we supply power to major national security and defense sites such as the Pentagon, the CIA, Fort Belvoir, and the Norfolk naval base. Virginia is also one of the most nuclear-friendly states, with strong bipartisan support for next-generation nuclear initiatives. Governor Youngkin, Senators Warner and Kaine have publicly backed these efforts and were present at our announcement with Amazon. The Virginia legislature has passed bipartisan legislation allowing companies to seek cost recovery for certain SMR project developments. Given this context, it makes sense that our large customers are interested in collaborating with us, particularly because we have a good track record in nuclear operations. We've been in talks with Amazon and others. However, we must approach this carefully, ensuring we mitigate potential costs and development risks for our customers and our capital providers. We will thoroughly assess the feasibility of SMR technology in meeting our customers' needs. They will be part of our diverse energy strategy, alongside offshore wind and battery storage, potentially enhancing Virginia's clean energy mix. We issued a request for proposals last summer to evaluate technologies, but it’s important that we're also smart about financing. While I cannot discuss the specifics of our positioning with Amazon or other interested parties, I can say that we have a long-standing relationship with Amazon, which has shown interest in participating in funding. The structure could resemble a build-on transfer agreement. However, any agreement we forge with Amazon or other interested parties must address first-of-a-kind risk and cost overrun risk so that our customers and Dominion Energy are not burdened. It’s essential that we protect our balance sheet and our business risk profile. We are very optimistic about our partnership with Amazon and our discussions regarding small modular reactors, and we will remain steadfast on the principles I just outlined.

Do any of the hyperscalers have interest in offshore wind?

We've discussed them briefly, but our recent conversations have mainly centered around small modular reactors. As you know, we are currently in the process of building the regulated CVOW, for which cost recovery has been clearly established. As we mentioned earlier, we have two additional options, but we have not made any decisions or set timelines at this point. Our primary focus is on ensuring that CVOW is delivered on schedule and within budget. Therefore, discussing future offshore wind projects with them at this stage would be premature. We are currently progressing with the offshore wind project under the standard regulatory framework.

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.

Yes, that's a great question. We've experienced significant growth in our Virginia jurisdiction, which is very exciting. If you examine the IRP, we're making substantial investments across all areas of our generation portfolio. This includes the potential to double our offshore wind capacity, increase our natural gas facilities compared to last year's IRP, add more solar beyond the mandates of the Clean Economy Act, and significantly expand our battery storage capabilities. While we are aware of PJM's limitations, we are advancing an ambitious plan based on a strong demand forecast. We will continue to seek opportunities to enhance reliability and maintain customer affordability, but we believe our current plan is quite aggressive.

Congrats, guys, on the results, really. See you in a week.

Thanks Shar.

Thank you. And we will take our next question from Nick Campanella with Barclays. Please go ahead.

Hey thanks for taking my question.

Morning Nick.

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.

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.

I appreciate that. Considering the updates since your Analyst Day, you have filed this IRP and highlighted the RTEP process, which we expect to have more clarity on by the fourth quarter call. CapEx is increasing, but when you look at the balance sheet and financing outlook, as well as the possibility that some of this capital may be more formulaic than before, where do you think you can achieve rate base growth from the current position? Does it extend the existing rate base growth, or is it more of an additive growth? I will leave it at that.

Yes, Nick, that's an excellent question. We think about that a lot. At our Analyst Day on March 1, we made it clear that we are providing a high-quality, sustainable operational and financial plan with targets we expect to achieve consistently. The plan is based on carefully conservative assumptions. We operate in premium markets in the Southeast, specifically Virginia and South Carolina, which offers additional opportunities to strengthen our position and potentially extend our long-term growth rate. This aspect will be addressed in the later part of the plan. Our focus is on delivering predictable year-over-year results and strong long-term performance. We will provide an update on our CapEx plan during the fourth quarter call in three months, where we will emphasize our commitment to disciplined growth and operational excellence. The investor feedback I've received aligns with our strategy of consistent execution against the targets we announced on March 1.

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.

All right. Thanks for the thoughts today.

Thanks Nick.

Thank you. And we will take our next question from Ross Fowler with Bank of America. Please go ahead.

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?

Yes, let me begin with the second part of your question. As we have stated publicly, we are not looking to restart the new units at V.C. Summer. More broadly, regarding your inquiry, the Senate Select Energy Committee continues to meet regularly to create a companion bill to the legislation that the House passed at the end of the 2024 session. These discussions are primarily focused on authorizing a partnership with Sandy Cooper for a combined cycle plant and on permitting reform. There has also been considerable recent dialogue about regulatory lag. The initial legislation addressed the financial health of the utility, and as we consider this aspect, tackling regulatory lag becomes crucial. This topic has gained renewed attention lately. We fully support the ongoing initiatives, as South Carolina is an excellent place to conduct business; it is one of the fastest-growing states in the country. We see significant investment opportunities there. We intend to collaborate with policymakers to resolve this lag issue, which is very important to us and appears to be a priority for the legislators as well. A session is scheduled for the beginning of next year, and we will observe how developments unfold.

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?

Yes. Before Steven responds to that, I was able to visit South Carolina right after the storm, especially in Akin County, which experienced the most damage. The destruction there was substantial. I felt such pride in our team for their hard work and ongoing efforts to restore power to the community. As we consider this situation, that aspect is the most crucial part of our discussion. Now, I'll hand it over to Steven to discuss the timing of the recovery.

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.

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?

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.

Okay, understood. Thank you.

Thanks Ross.

Thank you. And we will take our next question from Jeremy Tonet with JPMorgan. Please go ahead.

Hi, good morning.

Morning Jeremy.

It's Jeremy Tonet from JPMorgan. I have a quick question. There's a lot of good detail here. Can you explain the factors influencing the latest REC value in CVOW's LCOE and how sensitive that assumption is to load growth and future renewable additions? I just want to understand what we should consider moving forward.

Yes, Jeremy, that's a really good question. We observed a significant change in the Levelized Cost of Energy (LCOE) for the Coastal Virginia Offshore Wind (CVOW) project, driven primarily by expected increases in Renewable Energy Credit (REC) pricing. The LCOE metric was designed to allow comparison with the reference legislative cap, which is a combustion turbine costing $125 per megawatt hour in 2017 dollars. Let's break down the three components of that calculation. First, we have the revenue requirement connected to the cost of service, encompassing depreciation, maintenance, property taxes as applicable, and return on capital, including both debt financing and equity return. This aspect is pretty straightforward, and we've provided sensitivities to illustrate how LCOE would change based on fluctuations in interest rates or capital costs. Next is the Production Tax Credits (PTCs) or Investment Tax Credits (ITCs). PTCs are more beneficial for customers, and we account for their value against the cost of service, which should not lead to dramatic changes. We also factor in a sensitivity for capacity factor, which would impact the denominator and the PTC amount. The final element is the REC value. The Virginia Clean Economy Act, similar to renewable portfolio standards in other states, credits renewable generation resources, enabling them to compete with non-renewable resources. Without the CVOW project, our customers would need to acquire that REC value. This requirement gradually increases through 2045, with a specific percentage of our load needing to be met with RECs. This allows us to credit the CVOW project for the RECs it produces, which enhances its value for customers as REC market prices rise. Although we cannot predict the exact trajectory of market REC prices, we are aware of upward pressure from increasing demand and the necessity to meet growing percentages starting in 2023. By 2025, the law mandates that 75% of RECs must come from Virginia-based resources, contrasting with previous rules allowing procurement from anywhere in PJM. Together, these factors are shifting market dynamics in favor of higher REC prices. While we cannot specify future prices, we provide insights with and without REC impacts for our regulators to evaluate. We believe these values will remain strong based on the described dynamics, and we will maintain transparency. Ultimately, we feel the regulatory framework established for offshore wind has resulted in positive outcomes for our customers, and we are committed to fulfilling that promise.

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?

Yes, Jeremy. As we mentioned, we submitted these proposals in early October during PJM's latest open window process. There is growth occurring throughout PJM, and we see an opportunity to innovate with AEP and FirstEnergy. We are utilizing the expertise of our exceptional transmission teams to develop the most cost-effective solutions as demand increases. As we've discussed, additional transmission is necessary to maintain reliability, and collaborating with those companies to pursue a different approach makes a lot of sense. These projects could result in additional capital expenditures beyond the March 1 plan if PJM ultimately awards them, but they are currently under review and in the early development stages. We do not expect PJM to make selections until the first quarter of next year, making it difficult for us to determine the timing or amount of capital expenditures at this stage. However, I want to emphasize that we believe this open window could be substantial, potentially even larger than last year's, which featured 150 transmission projects totaling $2.5 billion.

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?

Yes, Jeremy, I appreciate that you asked multiple questions even with others in the queue. Regarding EPA regulations and fossil retirements, both of these issues are addressed in the IRP we recently submitted. The IRP offers a 15-year outlook and shows no fossil retirements in the planning horizon, which is directly related to the load growth we’ve discussed and what the IRP highlights. Therefore, we do not anticipate retiring any fossil units in the next 15 years based on our current understanding. Additionally, we conducted IRP scenarios both including and excluding the new EPA regulations, and the difference in our construction plans was minimal. We will continue to navigate these regulations, which are currently subject to legal challenges, but our models showed only slight variations with the new EPA requirements.

Got it. Thank you for that. I'll have to think of more questions for next time. Thank you.

Thanks Jeremy.

Thank you. And we will take our next question from Anthony Crowdell with Mizuho. Please go ahead.

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.

We largely answered it in Nick's question, but we'll let Steven offer up a little bit more.

Anthony, that's a great question. It's quite relevant given the discussions this season. I would say that we released a financial plan on March 1st, which we are very confident in our ability to consistently achieve. If we continue to see positive trends from the various factors we've discussed, such as significant load growth, more capital deployment opportunities, and supportive regulatory environments, we will reassess our plan annually. Our primary goal is to achieve consistently high-quality, predictable, low-risk earnings through our financial strategy. If there are chances to improve, whether in terms of rate base growth or earnings growth, we will consider those opportunities carefully, ensuring that we don't undermine our commitment to delivering consistent, predictable, high-quality, low-risk earnings. We will also finance it in a way that upholds that framework. So, while this may sound somewhat vague, we will reevaluate this each year when we update our plan or our capital outlook. We have some positive trends similar to others in the industry, but we are very optimistic about the plan we outlined on March 1st.

Great. Thanks for taking my question. That’s all.

Thank you. And we will take our next question from Carly Davenport with Goldman Sachs. Please go ahead.

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?

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.

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?

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.

Great. Thank you so much for the color.

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

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.

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