Dominion Energy Q3 2024 Earnings Call Transcript

Quartr
Provided by Quartr
November 1, 2024

Key Takeaways

  • Dominion reported Q3 operating EPS of $0.98 (GAAP $1.12) and narrowed its full-year 2024 guidance to $2.68–$2.83, while reaffirming its 2025–2029 operating earnings growth target of 5%–7% annually.
  • The company completed approximately $21 billion in debt reduction across six transactions and fully achieved its 2024 financing plan, with plans to opportunistically derisk 2025 financing needs.
  • Its Coastal Virginia Offshore Wind project is 43% complete, remains on time and on budget, and has seen its LCOE improve to about $56/MWh as a result of higher REC price forecasts.
  • Dominion signed an MOU with Amazon to explore deploying small modular reactors (SMRs) at North Anna, structuring partnerships to shield customers and capital providers from first-of-a-kind development risks.
  • Virginia’s data center growth and transmission demand continue to surge, with over 21 GW of contracted data center demand and 63 delivery point requests (~13 GW) prompting new batching processes and PJM open-window project submissions.
AI Generated. May Contain Errors.
Earnings Conference Call
Dominion Energy Q3 2024
00:00 / 00:00

There are 9 speakers on the call.

Operator

Welcome to the Dominion Energy Third Quarter Earnings Conference Call. At this time, each of your lines is in a listen only mode. At the conclusion of today's presentation, we will open the floor for questions. Instructions will be given for the procedure to follow if you would like to ask a question. I would now like to turn the call over to David MacFarlane, Vice President, Investor Relations and Treasurer.

Speaker 1

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 ks 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.

Speaker 1

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 Stephen 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 Stephen. 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.

Speaker 1

Since our March 1 investor meeting, we've consistently communicated the 3 following priorities: 1, hitting our financial plan 2, delivering offshore wind on time and on budget and 3, 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. 1st, hitting our financial plan. 3rd 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.

Speaker 1

3rd 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 9 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, 4th 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. 4th quarter earnings will also be negatively impacted by the earlier than planned closing of the CVAU 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.

Speaker 1

Quickly turning to 2025 through 2029 where there are no changes to our prior guidance. We are reaffirming all guidance, including 20.25 operating earnings per share of between $3.25 $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 3rd year. Finally, we'll provide a comprehensive capital investment forecast update through 2029 on our Q4 earnings call, which will take place as usual in early 2025. Turning now to slide 4.

Speaker 1

As I mentioned earlier, I'm delighted to report that we have now closed on 100 percent 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 CVAU partnership with Stonepeak. Combined with previous closings, this effort represented approximately $21,000,000,000 in debt reduction across 6 separate transactions requiring multiple federal and state regulatory approvals,

Speaker 2

all of

Speaker 1

it 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 Q3 financing activities, including our $1,200,000,000 VEPCO debt issuance and $200,000,000 of ATM issuance, we have fully achieved our 2024 financing plan.

Speaker 1

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 $200,000,000 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.

Speaker 3

Thank you, Stephen, 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 1st 9 months of the year was 0.44, in line with the continued positive trend from the last 2 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.

Speaker 3

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.

Speaker 3

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 $100,000,000 to $200,000,000 Given that costs are expected to be in excess of $100,000,000 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 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.

Speaker 3

With that, let me provide a few updates on the execution of our plan. Beginning with CVAL, 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 3 planned offshore substations. Additionally, we've laid the first 2 of 9 marine deepwater export cables ahead of schedule.

Speaker 3

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.

Speaker 3

Our partner, EEW, continues to make strong progress and we expect deliveries to continue steadily in coming weeks. All 3 offshore substations remain on track with the 1st substation and final commissioning and expected to be completed and shipped to Virginia for installation before the next bonapile 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 Q1 of 2025.

Speaker 3

On regulatory, as you may have seen, we made our 2024 offshore wind rider filing this morning, representing $640,000,000 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 credit against the levelized cost of energy as value delivered to customers. Project to date, as of September 30, we've invested approximately $5,300,000,000 and remain on target to spend approximately $6,000,000,000 by year end 2024.

Speaker 3

Also per the quarterly filing update today, current unused contingency is $121,000,000 compared to $143,000,000 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.

Speaker 3

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 Caribus 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 the cells.

Speaker 3

There's no change to the vessel's expected availability to support the current CVOW construction schedule, which we anticipate will start in the Q3 next year. There's also no change to the vessel's cost of $715,000,000 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.

Speaker 3

These contracts are broken into 1, substation engineering letters of authorization 2, construction letters of authorization and 3, electrical service agreements. As customers move from 1 to 3, 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.

Speaker 2

There are

Speaker 3

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.

Speaker 3

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 dam 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.

Speaker 3

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 2 80 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.

Speaker 3

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.

Speaker 3

Recall that last year we were awarded over 150 transmission projects totaling $2,500,000,000 On the generation front, we've announced a number of updates in recent weeks. 1st, on October 1st, we filed our annual update and the subsequent license renewal proceeding for our nuclear units at Surrey and North Anna. Seeking recovery of costs incurred for the North Anna extension and costs 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 SCC representing approximately $600,000,000 of investment. Also on October 15, 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.

Speaker 3

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 16, we announced an MOU with Amazon to further explore the feasibility of developing SMR technology at Northanna. 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.

Speaker 3

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 24, 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.

Speaker 3

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 SIVOW 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 based growth. Given these drivers, we expect there to be opportunities for incremental regulated capital investment towards the back end of our plan and beyond.

Speaker 3

As noted, we plan to update our capital guidance on our Q4 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.

Speaker 3

And based on the build plans proposed in both states' latest IRPs, both will maintain customer build 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 1. 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.

Speaker 3

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 in 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 $37,000,000 increase in revenue requirement premised upon a 9.95 percent ROE and a 52.5 percent equity layer. The agreement also stipulates that $9,000,000 in annual ongoing CCR costs be removed from base rates and placed in a standalone 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.

Speaker 3

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 de risked 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.

Speaker 3

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.

Speaker 3

Our safety performance this quarter remains strong, but there's more work to do to drive injuries to 0. 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.

Speaker 3

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. And we will take our first question from Shahriar Pourreza with Guggenheim Partners. Please go ahead.

Speaker 4

Hey, guys. Good morning.

Speaker 5

Good morning, Shahriar.

Speaker 4

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?

Speaker 4

And have you had any kind of hyperscaler interest in the OSW? Thanks.

Speaker 3

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. 1 is significant demand growth driven in large part by large users like data centers.

Speaker 3

2nd, 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 in 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.

Speaker 3

We're obviously continuing to see significant load growth in Virginia. Our power demand forecasted to double by 2,039. We have a state law in Virginia, the Virginia Clean Economy Act that calls for a carbon free grid by 2,045 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.

Speaker 3

Governor Youngkin, Senators Warner and Cain 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, Newport News, BWXT and Framatome and Lynchburg and then of course, our long operating units at North Anna and Surrey. 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.

Speaker 3

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.

Speaker 3

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.

Speaker 3

So a structure could be something like a build own 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 in 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.

Speaker 5

Do any of the hyperscalers

Speaker 4

have interest in offshore wind?

Speaker 3

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, CVAL 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 CVAU in on time and on budget. So it really would be premature to be having conversations with them about future offshore wind.

Speaker 3

And we've got, the offshore wind project underway today under standard regulatory construct.

Speaker 4

Got it. And then just lastly on the IRP filed a few weeks ago, the portfolio scenario seemed 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.

Speaker 3

Yes, Shar, 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.

Speaker 3

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 pretty aggressive plan as it is based on a very substantial demand forecast.

Speaker 4

Perfect. Congrats guys on the results. Really see you in a week.

Speaker 5

Thanks, Art.

Operator

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

Speaker 6

Hey, thanks for taking my questions.

Speaker 2

Morning, Nick.

Speaker 6

Good morning. So I wanted to check-in on the

Speaker 5

Millstone commentary, just continue on the nuclear side. You're kind

Speaker 6

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 we just talk about like if there was to be a data center there, I believe you've already done an upgrade there, but are there any options for additionality to contemplate and how could this all come together? Thanks.

Speaker 3

Yes, Nick, we're studying whether there is a possibility of upgrades 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 you today than what we've already identified.

Speaker 6

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 Q4 call. And obviously, CapEx is going up. But just when you consider the balance sheet, 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?

Speaker 6

Does it extend the current rate base growth or is it really kind of more additive? And I'll leave it there.

Speaker 3

Yes, Nick, that's a great question. And we think about that a lot. So at our March 1 Analyst Day, we're 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.

Speaker 3

Now we operate in premium markets in the Southeast and 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 Q4 call just 3 months from now. And there we will underscore our commitment to disciplined growth and operational excellence.

Speaker 3

But 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 March. Execution against the targets that we already laid out on the 1st March. And Nick, I

Speaker 1

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 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.

Speaker 1

Not all capital projects are equal. 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.

Speaker 6

All right. Thanks for the thoughts today.

Speaker 1

Thanks, Nick.

Operator

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

Speaker 5

Good 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 also a new nuclear opportunity there or an opportunity around nuclear?

Speaker 5

I mean, how do we contextualize the experience with BC Summer that we've been through versus there is space on that site to maybe do SMRs or something else?

Speaker 3

Yes. So let me start with the second part first. I think as we said publicly, we're not pursuing a restart of VC 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 24 session. Those discussions, as you know, continue to center on authorization for us to partner with Sandy Cooper on a combined cycle plant there.

Speaker 3

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 the 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 is a great place to do business.

Speaker 3

It's 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.

Speaker 3

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.

Speaker 5

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.

Speaker 5

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 and M? And then remind us how the recovery mechanisms for those costs kind of work?

Speaker 3

Yes. Before Stephen answers that, I was able to spend some time down in South Carolina right after the storm, particularly in Aiken County, which was the most damage. 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.

Speaker 3

But I'll turn it to Stephen to talk a little bit about the timing of recovery.

Speaker 1

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 and M. That's a little bit unusual for like large outage events we have in North in South Carolina and in Virginia. As part of our most recent settlement on the electric, we agreed with the staff to in good faith pursue potential securitization for storm costs that exceeded $100,000,000 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.

Speaker 5

Okay. Thanks, David. And maybe one last one for me back to the MOU with Amazon and I appreciate you can't give us many details here, but just remind us that 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?

Speaker 3

Yes. I'm not exactly sure what you're talking to on the 80%. And the investment in offshore our 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.

Speaker 3

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.

Speaker 5

Okay, understood. Thank you.

Speaker 1

Thanks, Ross.

Operator

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

Speaker 7

Hi, good morning.

Speaker 5

Good morning, Jeremy.

Speaker 7

This is Jeremy Tonet from JPMorgan. Just quick ones, if you could, a lot of good detail here. For the latest rec value in C Val's LCOE here, Can you walk through the factors driving the revision and how sensitive that assumption is to low growth and renewable additions in the future? Just want to see, I guess, what we should be thinking here?

Speaker 1

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 is $125 per megawatt hour. And so let me walk you through those the 3 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.

Speaker 1

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 sensitivities to say, hey, if interest rates or financing costs go up or down, here's how the LCO would change. We've given sensitivities if capital goes up or down.

Speaker 1

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 value, which I think makes sense.

Speaker 1

And we don't 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 our 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 nonrenewable 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.

Speaker 1

And that steps up through 2,045. 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 turbine, you really need to give credit to C Val for the production of these RECs. And as the market value of RECs go up, the value of the C Val project with the RECs that it creates becomes more valuable for customers.

Speaker 1

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. 1 is a ratcheting up of the demand for which we have to procure a specific percentage, it's all like capacity in that prospect, as well as the need for us to achieve a growing percentage of that demand. So it steps up from 23%.

Speaker 1

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?

Speaker 1

We don't know. We provide you the table with both with and without RECs, 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 we 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.

Speaker 7

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 AP and FirstEnergy there?

Speaker 7

Just really how these projects fit within PGA's transmission system today as it stands and as load growth continues here? Thinking about also as well, I guess, further out, you mentioned opportunities in the back half of the plan. Any additional thoughts on the cadence of when that could come to fruition?

Speaker 3

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 and 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.

Speaker 2

It could

Speaker 3

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 Q1 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.

Speaker 3

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 $150,000,000 for us 150 transmission projects totaling $2,500,000,000

Speaker 7

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?

Speaker 7

And at the same time, EPA regs as it relates to CCS for natural gas plants, just wondering any thoughts there on how that impacts your thought process?

Speaker 3

Yes. Jeremy, first, I'm impressed that you asked this 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.

Speaker 3

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 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 the what we're building. So we're going to sort of keep working through the regulations. They're obviously being litigated.

Speaker 3

But when we ran the models for the IRP, not a huge change between with and without those new EPA regs.

Speaker 7

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

Operator

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

Speaker 2

Hey, good morning team. Unlike Jeremy, I just have one question. And it's 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 based growth story and maybe updating that.

Speaker 2

Obviously, news yesterday, we saw utilities revising earnings growth rates. I'm just curious on what's the calculus or what do you guys look at when you evaluate your financial plan, whether it's something like sustainable or not, like about whether it provisions on rate based 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.

Speaker 3

We largely answered Nick's question, but we'll let Stephen offer up a

Speaker 1

little bit more. 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 low growth and more opportunities to deploy capital and strong regulatory regimes.

Speaker 1

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 based 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.

Speaker 1

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 1.

Speaker 2

Great. Thanks for taking my questions. That's all.

Operator

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

Speaker 8

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 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?

Speaker 3

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 subject of litigation with EPA. But the plan that we put out takes into account the regulations by just adjusting for the capacity factor.

Speaker 8

Got it. Okay. Appreciate the clarification there. That's super helpful. And then maybe just one quick follow-up, a high level question as you think about the opportunities surrounding SMRs.

Speaker 8

As you think about potential timing to commercialization of that technology, I know you've got the 2,034 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?

Speaker 3

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 in the timelines that we put in the IRP.

Speaker 8

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.

Speaker 3

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.

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