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Dominion Energy, Inc. misses on earnings expectations. Reported EPS is $0.29 EPS, expectations were $0.4. Dominion Energy, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Welcome to the Dominion Energy Fourth Quarter Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to David McFarland, Vice President, Investor Relations and Treasurer.

David McFarland: Good morning and thank you for joining today’s call. Earnings materials, including today’s prepared remarks, contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management’s estimates and expectations. This morning, we will discuss some measures of our company’s performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures which we can calculate, are contained in the earnings release kit.

I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit. Joining today’s call are Bob Blue, Chair, President and Chief Executive Officer; Steven Ridge, Executive Vice President and Chief Financial Officer; and Diane Leopold, Executive Vice President and Chief Operating Officer. I will now turn the call over to Bob.

Bob Blue: Thank you, David. Good morning, everyone. As always, let me begin with safety, as shown on Slide 3. In 2023, our employee OSHA recordable incident rate was 0.45, a significant improvement to already strong historical performance. We also achieved a record low lost time restricted duty injury rate. We’re pleased but not satisfied with these results. I strongly believe that exemplary safety performance unlocks our ability to execute optimally across the 3 pillars of our mission, as shown on Slide 4. We maintained outstanding reliability in 2023 as our electric customers in Virginia and South Carolina had power 99.9% of the time, excluding major storms. Our residential rates continue to be well below the national and regional averages.

From 2005 through 2022, we’ve reduced Scope 1 carbon emissions from our electric operations by nearly 50%, even as annual energy generated over that period has increased 9%. Going forward, you’ll continue to hear how we’re executing against our mission because an exceptional customer experience positions our company to deliver the best results for our shareholders. I’m very pleased to share several important updates with you this morning as it relates to our business review in the Coastal Virginia Offshore Wind Project. Let me begin by reiterating my previous commentary regarding the review. Our guiding priorities and commitments are unchanged, as is my conviction around both the decision to undertake the review and the quality of the result I expect us to deliver.

The review will comprehensively and finally address foundational concerns that have eroded investor confidence in our company over the last several years. We will not pursue a series of partial solutions that leave key elements and risks unaddressed. Instead, we’ll deliver a comprehensive result that will provide a durable and high-quality strategic and financial profile that optimally positions Dominion Energy to provide compelling long-term value for shareholders, customers and employees. This morning, we announced a key part of that result with the execution of an agreement to add a non-controlling equity partner in the Coastal Virginia Offshore Wind project. This arrangement with Stonepeak, a global leader in infrastructure investing, represents the final strategic step in the business review and delivers an exciting result for our customers and our shareholders.

Before I walk through the transaction specifics, let me update you on the continued successful development of the project across all phases. The project is proceeding on time and on budget, consistent with the time lines and estimates previously provided. We continue to achieve significant project milestones, as shown on Slide 5. On permitting; last month BOEM provided final approval of our construction and operation plan which allows us to begin offshore construction in the second quarter. And the Army Corps of Engineers issued its permit which has allowed us to ramp up onshore construction. On materials and equipment; we’re on-track and making excellent progress. One of the keys to our success has been that from the beginning of the project, we insisted that our equipment be sourced from mature facilities under dedicated production allocations that are specific to our components.

We’ve received 24 monopiles from our supplier, EEW, at the Portsmouth Marine Terminal, with more on the way in the coming weeks. These monopiles will begin to be installed by DEME during the second quarter. Recall that we’ve scheduled monopile installation across 2 seasons, 2024 and 2025 which allows us to better mitigate any potential delays or disruptions without impacting final schedule. The first of 3 offshore substation topside structures is complete and has been delivered to Bladt/SEMco to be outfitted. We expect first delivery of transition pieces to Virginia during the second quarter. All 161 miles of onshore underground cable has been manufactured and approximately 200 out of 600 miles of offshore cable has been produced. Schedule for the manufacturing of our turbines remains on track; it’s worth noting that even though we won’t begin turbine installation until 2025, per our schedule, DEME is currently supporting an installation campaign for a project off the coast of Scotland that’s using the same Siemens Gamesa wind turbine model that CVOW will use.

The lessons learned from that project will benefit our project installation in the future. Moving onshore; construction activities have begun, including civil work, horizontal directional drills and the bores where the export cables come ashore. On regulatory; last November we made our 2023 rider filing representing $486 million of annual revenue. We’re currently in the testimony phase and expect the final order by August. Turning to Slide 6. There have been no changes to the project’s expected LCOE of $77 per megawatt hour. We’ve again provided sensitivities to show how the average lifetime cost to our customers is impacted by capital costs, capacity factor and interest rates. We remain well below the legislative prudency cap on this metric.

Project-to-date; we’ve invested approximately $3 billion and we expect to spend an additional $3 billion by year-end 2024. A little more than 92% of project costs are now fixed. We’ll gradually increase that percentage over the remainder of the project construction time line. At this stage of project completion, the current unused contingency at $351 million benchmarks competitively as a percentage of total budgeted costs when compared to other large infrastructure projects we’ve studied. It also compares favorably to the current level of unfixed costs. We’ve been very clear with our team and with our suppliers and partners that delivery of an on-budget project is the expectation. Along those lines, this morning, we posted an important video update to our Investor Relations website that features representatives from the senior executive management teams of all of our primary CVOW commercial partners, including Siemens Gamesa Renewable Energy, EEW, Bladt Industries, Semco Maritime, DEME and Prysmian, as well as the CEO of Seatrium, the constructor of our Jones Act-compliant installation vessel.

I strongly encourage our investors, government and regulatory partners, employees and other stakeholders to watch the short video. You’ll hear, in their own words, a course of unwavering enthusiasm for and commitment to an on-time and on-budget in-service for the project. We’re fortunate to enjoy such extraordinary support from our key suppliers and, together, we will deliver this exciting project. Moving to Slide 8, a couple of final points here on Charybdis. The vessel is currently 82% complete, up from 77% as of our last update. No change to our expected delivery time frame of late 2024 or early 2025. A few highlights. Labor levels have increased to over 1,200 and are continuing to be augmented as compared to approximately 1,000 last October and 800 last August.

Recent construction milestones have been met, including installation of the remaining jack-up legs. Jack-up system commissioning is underway. All major subcomponents are on-site and awaiting installation. We expect the vessel to be floated in coming weeks. And there’s been no change to project costs of $625 million, including financing costs. In summary, there is no change to the vessel’s expected availability to support the current CVOW construction schedule, including its availability to support any third-party charter agreements in 2025. As you can see, we feel very good about the progress we’re making with the support of our project partners towards an on-time and on-budget completion of this very important project. Throughout our robust and competitive offshore wind process, we had multiple high-quality strategic and financial potential partners deploy significant operational, regulatory, commercial, financial and legal resources to thoroughly diligence every aspect of the project.

And the consensus independent feedback was that the Coastal Virginia Offshore Wind Project is optimally positioned to be delivered on time and on budget and is supported by enthusiastic and committed suppliers and partners. With that, let me walk through the CVOW transaction, starting with Slide 9. We’re excited to be partnering with Stonepeak, one of the world’s largest energy infrastructure investors with over $61 billion in assets under management. Stonepeak has a track record of investment in large and complex energy infrastructure projects, including offshore wind. Their significant financial participation will benefit both our project and our customers. On transaction structure; Stonepeak will invest in a newly formed subsidiary of Dominion Energy Virginia.

It will be a public utility in Virginia and be entitled to recover its prudently incurred cost of constructing and operating the project under the existing offshore wind rider in Virginia. Dominion Energy will retain full operational control of the construction and operations of CVOW. And as a result, we expect to consolidate the partnership for accounting purposes. Stonepeak will own a non-controlling equity interest and will have customary minority interest rights. On cost sharing; the agreement provides for robust cost sharing that significantly improves the company’s credit profile and provides meaningful protection from any unforeseen project cost increases. Mandatory capital contributions, including an initial reimbursement, will be used to fund expenditures up to $11.3 billion on a 50-50 pro rata basis.

This represents 50-50 cost sharing up to 15% or nearly $1.5 billion higher than the project’s current budget, including unused contingency and up to 20% or nearly $2 billion higher than the project’s current pre-contingency budget. The agreement also provides for additional sharing of project costs, if any, between $11.3 billion and $13.7 billion. In that hypothetical case, Stonepeak would continue to share in project costs through a gradually increasing spectrum of dilution to Dominion’s share of project ownership. Slide 10 shows how Dominion and Stonepeak will share project funding and ownership under a variety of hypothetical cost scenarios and I stress hypothetical because we fully expect to deliver this project on time and on budget. Turning to Slide 11.

At closing, Stonepeak will make a cash payment to Dominion to reimburse 50% of the capital spent to date, less $145 million. This nearly $3 billion project cost reimbursement will be used to reduce parent-level debt. Thereafter, Stonepeak will fund their pro rata share of capital calls during construction, consistent with the schedule included in the appendix of today’s materials. At commercial operation, Stonepeak will make a payment to Dominion Energy, the amount of which will depend on the final construction cost, as shown on the slide. The transaction requires approvals from the Virginia SEC and North Carolina Utilities Commission as well as certain consents from BOEM and other regulatory agencies regarding the assignment of certain contracts and permits needed for the partnership post-closing.

We expect to obtain all necessary approvals and consents by the end of 2024. Continuing to Slide 12. I’m confident that this partnership is in the long-term best interest of our customers and our shareholders. The transaction achieved several key objectives. First, it adds an attractive, well-capitalized and high-quality partner who brings a track record of investment in large and complex infrastructure projects, including offshore wind, that will further derisk what is already a significantly derisked and well-developed project. Second, it provides for robust cost sharing and provides meaningful protection from any unforeseen project cost increases. And third, it improves our quantitative and qualitative business risk profile via a highly credit-positive partnership.

The transaction will improve our credit profile, reduce project concentration risk and lower our financing needs during construction. Further, the transaction is expected to improve our estimated 2024 consolidated FFO to debt by approximately 1%. Importantly, we reviewed the transaction with our credit rating agencies in advance of signing. And based on their feedback, we expect the transaction to be viewed as unambiguously credit positive and that is a very key benefit for our customers. A financially healthy utility with a strong balance sheet is optimally positioned to attract the capital it needs to provide an exceptional customer experience and support the state’s economic and environmental goals. In other words, this partnership will reduce our company’s business and financial risk profile which benefits our customers.

Let me provide a few final updates on the business review to conclude my prepared remarks. Turning to Slide 13. We’re working methodically towards regulatory approvals and timely closings for the sale of our gas utilities. No changes to our original expectations in any of these cases. We look forward to continuing to work with involved parties and expect regulatory proceedings to conclude and staggered transaction closings to occur during 2024. We intend to apply 100% of the estimated after-tax proceeds of nearly $9 billion to reduce parent-level debt which, based on current rates, will result in a reduction of around $500 million of pre-tax interest expense annually. Next, Virginia regulation. As part of the business review, we supported reasonable regulatory reform that positions Dominion Energy Virginia to serve customers, support the state’s goals and compete for investor capital in support of our customer beneficial investments.

Last November, Dominion Energy Virginia, State Corporation Commission staff, the Office of the Attorney General and other key parties reached a comprehensive settlement in the current biennial review. No parties to the case opposed the settlement. And last month, these same key parties reiterated their support to the original comprehensive agreement. We expect the final order in early March. On a related topic, last month, the General Assembly unanimously elected Sam Towell and Kelsey Bagot to serve as members of the State Corporation Commission, filling the two outstanding vacancies on the commission. They have extensive experience in both government and the private sector and we look forward to working cooperatively with these well-qualified new members.

Turning now to Slide 14. There have been no changes to our original business review commitments and priorities. First, for the avoidance of doubt, we have been and continue to be 100% committed to our current dividend. Earnings growth, combined with a period of low to no dividend growth, will restore our payout ratio to a peer-appropriate range over time. Second, last year, the Board, in direct response to investor feedback, modified my compensation structure for 2023 to align my economic incentives more closely with the financial interests of our shareholders. As a result, 100% of my 2023 long-term incentive compensation was performance-based. Last month, the Board approved my 2024 long-term compensation plan but like last year, it is 100% performance-based.

65% is premised solely on 3-year relative total shareholder return, with a 65th percentile relative performance required to achieve a 100% payout. This represents a high bar relative to industry practice but I believe it appropriately aligns my financial interest with those of our shareholders. Additional details around the increasing alignment of my compensation with our owners’ interest will be available in our proxy statement which will be published in March. Certainly, this has been a difficult time for our investors and I want them to understand how seriously I take that. Third, we continue to focus on costs and identify incremental savings, particularly in the area of corporate overhead. We are, have been and will continue to be one of the most efficient and most reliable electric utility companies in the country.

Finally, we’ve been focused on evaluating investor feedback around perceived earnings quality and plan risks. In his prepared remarks, Steven will provide an update on our treatment of unregulated investment tax credits and assumptions around our retirement benefit plans. Turning to Slide 15. Today’s announcement of an offshore wind partner marks the final strategic step of the business review. We’re in the process of finalizing our financial plan which will allow us to conclude the review. We’ve scheduled an investor meeting on March 1, at which time we will provide a comprehensive strategic and financial update for the company and participate in a question-and-answer session. We encourage our investors and other stakeholders to participate virtually as their schedule allows.

Following the event, we plan to initiate a comprehensive investor engagement effort to meet with our existing and prospective investors. As we prepare to conclude the review, I am more optimistic than I have ever been about the future of our company. We recognize that we must consistently execute against the financial targets we provided at the conclusion of the review. As is always the case, I am accountable for and my entire leadership team has embraced our commitment to consistently deliver high-quality earnings growth that meets that plan. With that, I’ll turn the call over to Steven.

Steven Ridge: Thank you, Bob and good morning. Our fourth quarter 2023 operating earnings were $0.29 per share. Full year 2023 operating earnings were $1.99 per share. Full year GAAP net income was $2.29 per share. A summary of all adjustments between operating and reported results is included in Schedule 2 of the earnings release kit. As shown on Slide 16, we’ve provided a reconciliation of actual operating earnings relative to the guidance we provided on the last earnings call. There were 3 key drivers for the variance to guidance. First, during the fourth quarter, we experienced $0.02 of worse-than-normal weather in our utility service territories. Second, we incurred $0.03 of hurt related to certain outages at Millstone.

Third, as part of the business review and after we had given earnings guidance in November, we elected to change our accounting methodology for the way we recognize investment tax credits and earnings. This resulted in a $0.02 quarterly and $0.07 annual negative variance to guidance. I’ll expand more on this accounting methodology change in a moment. A summary of all drivers for earnings relative to the prior year period is included in Schedule 4 of the earnings release kit. As we mentioned on our last earnings call, we view 2023 as a transition year for the company due to the pending results of actions we’ve taken as part of the business review to support our long-term objectives. With that in mind, let me refresh our housekeeping around 2023 results.

In 2023, our operating earnings per share were $1.99. Similar to last quarter, we believe it warrants highlighting many of the same adjustments that investors may consider to more accurately assess 2023 results. First, we experienced historically mild weather during 2023, representing $0.18 of full year earnings headwinds, including $0.02 in the fourth quarter. Recall that the second quarter was the mildest quarter relative to 15-year normal in the last 50 years. We don’t expect weather to deviate from historical normal in this manner going forward. Second, we continue to expect approximately $0.50 of annualized interest savings from parent-level debt repayment, driven by the sales of Cove Point and the gas utilities. Remember, the way discontinued operations is reflected in our 2023 results, 100% of the earnings from these assets are removed but the benefit from use of sale proceeds is not captured.

Third, 2023 results include approximately $0.11 of unexpected and unlikely-to-repeat hurt from extended planned or unplanned outages at Millstone, including $0.03 in the fourth quarter. We’ve continued to follow through on the steps discussed in previous earnings calls to ensure the plant performs consistent with its strong operating history. Note also that 2023 was a standard double-fueling outage year which is an additional around $0.10 hurt in 2023 that we won’t see in the next 2 years as double planned outages occur once every 3 years. Fourth, we expect approximately $0.15 of improvement as a result of the anticipated inclusion of market-based revenues from certain customers in the annual fuel factor as well as lower interest expense due to the securitization of $1.3 billion of deferred fuel balances that we financed with short-term debt during 2023.

We closed on the fuel securitization transaction last week. The transaction was met with very strong demand which allowed us to deliver a great result for our customers. Finally and in the opposite direction, we expect approximately $0.18 of additional hurt related to the $350 million annual Virginia rider revenue reduction at DEV, given that rate reduction did not impact first half 2023 results. Taken together, these adjustments would result in an illustrative 2023 operating earnings per share of around $2.85. As we said last quarter, some of the transition we experienced in 2023 will continue into 2024 which is why we continue to view 2025 as the foundational year for the company’s post-review financial performance. As part of the investor meeting, we will provide a comprehensive strategic and financial outlook that will run through 2029 and include operating earnings per share, EPS growth, credit, dividend, CapEx and financing guidance as well as other relevant financial information.

We believe that this presentation will provide reference information and insights that will help investors to better understand Dominion Energy’s updated profile as well as the key value drivers of each of our business segments. By way of reminder, the comments I made in the last call about drivers of 2025 earnings are unchanged and replicated on Slide 17. I’ll turn now to the reference Bob made in his prepared remarks regarding our evaluation of investor feedback around perceived earnings quality and planned risks. By way of background, over the last several months, we’ve engaged directly and extensively with our shareholders and received valuable feedback, much of which has affirmed our business review commitments and priorities. One consistent theme we have heard is dissatisfaction with past earnings quality and plan assumption risk levels and we’ve taken that feedback seriously.

We’ve made specific commitments around not pursuing unregulated solar investments for the purposes of generating upfront operating earnings from tax credits or reflecting gains from certain asset sales and operating earnings. Those commitments are unchanged. Today, we’re taking two additional steps. First, in December, we formally elected to change our accounting methodology for the way we recognize investment tax credits and earnings. Let me walk through the background and rationale for this accounting methodology change. Historically, Dominion Energy used what’s called the flow-through accounting method, under which 100% of the income associated with non-regulated investment tax credit was recognized immediately upon the project entering service.

Our past use of the flow-through method led to some very substantial operating earnings volatility associated with credits generated by unregulated solar investments. As a result of the Inflation Reduction Act, our previously committed investments in dairy and swine renewable natural gas projects are now eligible for investment tax credits. Absent a change in accounting method, these RNG credits would create operating earnings volatility identical to past unregulated solar credits. Therefore, we’ve made a change from the flow-through method to the deferral method. Under the deferral method, investment tax credit income is recognized over the expected life of the asset which, in the case of renewable natural gas projects, is 30 years. Switching to the deferral method reduces ITC-related earnings volatility.

In addition, the deferral method is considered the preferred method under GAAP and is the predominant practice amongst peer utility companies. This change in accounting method also aligns the treatment of our non-regulated ITCs with the treatment of our regulated ITCs, thereby creating additional consistency. So what does this change to a more preferable accounting method means for past, present and future results? Dominion Energy will recast, as reflected in the earnings materials released today, its financial results to apply the deferral method to ITC income that was historically recognized under the flow-through method. A summary of the affected line items will be presented in our upcoming Form 10-K which we expect to file tomorrow. I’ve explained the impact on 2023 results.

Our November guidance was based on the flow-through methodology. The adoption of the deferral method, combined with changes in RNG project completion dates, impacted actual results versus guidance. A number of projects that were originally expected to be completed in 2023 are now expected to achieve substantial completion in 2024. ITC income from those projects will now be recognized gradually over their estimated 30-year useful lives. As we look forward through 2029, we expect ITC income, including renewable natural gas generated credits, to account on average for approximately $0.03 to $0.04 of annual operating earnings per share. For the avoidance of doubt, there is no change to the underlying economics of RNG &D investments because there is no change in the underlying cash flows.

While this change in accounting methodology impacts when an investment tax credit is recognized in book income, the cash value of the tax credits are the same under either methodology. Now let me share a few comments on our retirement benefit plans, as shown on Slide 19. We are evaluating a rebalancing of plan assets from return-seeking toward lower-risk classes. This is expected to reduce future funding risk and overall plan asset variability. This evaluation will take place during 2024, with the final reallocation of assets occurring in early 2025. Let me address what I expect maybe some questions related to this decision. First, the background. Dominion Energy was later than many other companies to move away from offering traditional defined benefit pension plans to new employees and as a result, still has several thousand employees that are accruing final average pay retirement benefits under traditional pension plans.

This results in a relatively long liability duration which we estimate to be in the 75th percentile relative to a large sample of corporate plan sponsors. Dominion Energy’s current expected return on assets or EROA assumption is based on an asset allocation which reflects the long-dated nature of our liabilities. Next, why now? Given the robust funding levels across our retirement benefit plans, specifically 117% in aggregate at year-end, we believe that now is the time to evaluate ways to derisk plan assets by rebalancing toward lower-risk asset classes that reduce volatility and increase the portfolio’s implied hedge ratio. Finally, what’s the impact to our financial plan? The determination of EROA is subject to many factors, including equity returns and interest rates and we cannot, at this time, predict precisely what our future assumptions will be.

However, for illustrative purposes, we believe a rebalancing could result in a 100 basis point reduction in our EROA which would put our assumption roughly in line with peers. Such a reduction in EROA would reduce operating earnings each year by $0.08 to $0.10 per share. Further, under a 100 basis point EROA reduction scenario, we expect retirement plan-related operating earnings per share to account, on average, between 2025 and 2029 for around $0.20 per share. With that, let me summarize our remarks on Slide 20. Our annual safety performance was the second best in our company’s history. We continue to make the necessary investments to provide the reliable, affordable and increasingly clean energy that powers our customers every day. Our offshore wind project is on time and on budget.

We’ve taken significant steps to achieve the objectives of the business review, including adding a non-controlling equity financing partner for CVOW. We are moving with urgency and care to complete the review. We recognize the importance of delivering a compelling result and executing flawlessly thereafter. And we look forward to concluding the review and discussing our strategic and financial update at our March 1 Investor Meeting. With that, we are ready for your questions.

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Operator: [Operator Instructions] And we’ll take our first question from the line of Shar Pourreza with Guggenheim Partners.

Shahriar Pourreza: Can you hear me, Bob?

Bob Blue: Yes.

Shahriar Pourreza: Excellent. Just, obviously, congrats on the sale and getting the review to this point. Just on the process itself, can you just maybe speak a little bit more in depth of the bidding interest and why you settled on this sharing structure in the agreement? And just to confirm, this is a true sort of 50-50 pro rata sharing through the $11.3 billion, right? So the 1% difference in Slide 10, this is just tied to the potential movement of the withholding amount. Is that correct?

Bob Blue: You have that exactly right, Shar. So it is 50-50 through $11.3 billion and then there’s the adjustment that we described. So on the process, we attracted quite a bit of interest from financial and strategic counterparties. We talked a little bit about that on the last call that we were in late stages with several attractive parties. And they diligenced this project extensively. They came in with their own experts in offshore wind, obviously, teams related to regulation, finance and so forth. And what was really encouraging to me was to hear unanimously from parties who participated how well this project is going. So it was — there was nobody who got in diligence who was concerned about the project at all and that was really helpful.

So then as we thought about how we were going to choose a partner, if you refer back to some of the things that we’ve said before, on the last call, we noted the importance of having pro rata sharing of costs. And we’ve achieved that here and we feel very good about that. We said that we needed a transaction that made sense for our customers and our shareholders and that was in keeping with the objectives that we set out in terms of the business review. And we believe this transaction with Stonepeak meets that extremely well. The cost sharing, with protection from any hypothetical or unforeseen project cost increases but having a well-capitalized partner to help us there was critical. And improving our credit profile means that this is going to be extraordinarily beneficial for our customers and our capital providers, so this is a very good deal.

We’re very pleased with it. We’re pleased with the way the process worked.

Shahriar Pourreza: Got it. And then sorry, Bob, do you have an option to farm down a stake again in any sort of succeeding offshore wind projects, let’s say, CVOW 2?

Bob Blue: This legislation that permitted this partnership structure, I think, was designed for this project. And so we’re focused very heavily on on-time, on-budget on offshore wind right now and we’ve got a very good partner to work with to do that.

Shahriar Pourreza: Got it. And then just lastly, not to get too far ahead of next week, I mean, you’ve obviously sought to minimize external equity through this whole process. I guess, how does this announcement today inform your views around this, especially as we’re thinking about an ATM versus a block? And are there sort of any other efficient sources remaining we should be aware of; thinking particularly around the vessel here with RNG may be off the table?

Steven Ridge: Thanks, Shar. Steve. I’ll take it. So what we’ve said is that the offshore wind is the final strategic step in our process. And that next week, we look forward to sharing our comprehensive strategic and financial plan. We’re not going to comment today on any specifics with regard to financing plan. I’d reiterate what we’ve shared since the beginning of the review that we’re seeking to meet and exceed our downgrade thresholds, while seeking also to minimize the amount of external equity need. We think that the transactions we’ve announced to date have been very supportive of our objective. But we’ll provide a fulsome plan next week and I think we’re going to hold off on giving pieces and parts until we get there.

Shahriar Pourreza: Fantastic, guys. Congrats and we’ll chat next week.

Steven Ridge: Thanks, Shar.

Operator: And we’ll take our next question from the line of Nick Campanella with Barclays.

Nick Campanella: So yes, congrats. So I guess, just — you had this view in the slide out on 2025 considerations on the third quarter call and the drivers are largely the same. But you’ve also kind of introduced this pension and ITC disclosure. So I guess, just as you kind of think through the $0.08 to $0.10 of detriment and then from pension and then the $0.03 to $0.04 of ITC, is that kind of incremental to that 2025 view?

Steven Ridge: Yes. Nick, this is Steve. So just to be clear, we have never given 2025 guidance and we’ve been very careful not to do that. On the last call, we talked about sharing that list to emphasize the fact that, in order to create a view on 2025 as an external party, you need to be thoughtful about a variety of factors, many of which we haven’t given any information on. And we went through that list just to highlight what some of those could be. We don’t have insight into what folks have assumed around ITC or EROA in any of their internal models or estimates. So it’s very difficult for us to be in a position to sort of describe how they ought to consider our updated information on those topics today in their view. And we’re going to hold off from sort of providing anything like that.

What I can say is, we look forward again to sharing what we think will be a very compelling result next week. And we’ve tried to be thorough in helping folks understand, again, what some of those drivers that they ought to be considering should be.

Nick Campanella: Okay. I appreciate that. And I guess, just — it’s great to hear the agency feedback does seem like it was positive and you’re highlighting 100 basis points increase to FFO to debt from this transaction. I guess, just from a numeric perspective versus where the agencies want you to be out of this review, where does that kind of put you holistically?

Steven Ridge: Yes. Nick, again, we’re not going to disclose kind of where our pro forma credit metrics are going to be. We’ll provide that next week. Certainly, from a qualitative and quantitative perspective, the agencies have been publicly forthcoming with regard to their support of the steps we’ve been taking in the review. And so we’ll — again, we’ll — not trying to be coy but trying to be consistent with how we’ve approached the review for the last 15 months, we’re not going to give you our sort of pro forma credit view. We’ll provide that next week.

Nick Campanella: Understood. Understood. Looking forward to next week. And congrats again. Thank you.

Steven Ridge: Thanks, Nick.

Operator: And we’ll take our next question from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: Just wanted to kind of follow up on that last line of questioning a bit. And I appreciate there’s some things that won’t be said today be said next week. But some of the agency communications that we had seen said that current FFO to debt with this type of arrangement would look very strong. But then over the construction cycle, that would soften and put pressure there. And was just wondering if you have any — anything you can share there as far as thoughts on how that stacks up, if the agencies have previewed this transaction? Or just any other thoughts in general, I guess, over the time period, the pressures, that cash drag this project had.

Steven Ridge: Yes. Thanks, Jeremy. So what I would say on that topic is, generally, I think we agree with effectively how the agencies were describing it which was some prefunding of some very heavy capital plans that we have in our plan which we’ve talked about in previous calls. We haven’t given specific numbers. Tomorrow, when the K comes out, you’ll see our capital investment this year is $10 billion which is relative to an average of $6 billion for our company. And so there was some — effectively, some prefunding from asset sales and I think that’s what they were signaling. Just generally on our relationship with the agencies, we just — we don’t speak for them. And I will say that we have been very deliberate throughout the process and making sure that they understood, in some detail, some confidential detail, how we were thinking about the review and gathering their perspectives as it related to how they think about our company.

And that has extended some — I can share, it’s extended to some formal engagements with rating agencies that have allowed us to make sure that we have a good sense of where they are relative to how we’re thinking about our plan and our business risk profile. And with regard to this transaction, specifically, as I mentioned and as we typically will do, we walked them through in some fairly detailed manner the terms of the offshore wind partnership transaction before we signed and made sure that we were comfortable indicating in our script today that we think that they’ll view it as unambiguously credit positive.

Jeremy Tonet: Got it. That’s very helpful. And I just wanted to pivot a little bit. Maybe I might have missed it here but language around the dividend, dividend outlook here, is there any new messaging that we should take away? Or should we just be waiting for next week?

Bob Blue: There is no new messaging. It’s the same as it has been since we started which is we are 100% committed to the current dividend.

Steven Ridge: And Jeremy, I’ll go out on a limb and suggest that you won’t hear something different next week, either on the dividend, sort of beat that like a drum this whole time period. So I don’t want people to think that we’re saying that today and we’ll change our tune next week. We’re obviously aware of trends in the space around payout ratios. We’re aware of that but no change. And you shouldn’t expect a change next week from what we’ve said publicly around our dividend and where we see the dividend going over time.

Jeremy Tonet: Got it. That’s very helpful. I’ll leave it there.

Steven Ridge: Thanks, Jeremy.

Operator: [Operator Instructions]

David McFarland: Operator, it sounds like there’s a technical issue. I know there were some other folks in the queue before that. We apologize, of course.

Operator: We are getting people requeued now.

David McFarland: Okay, all right. Thanks.

Operator: Okay. We’ll take the question from Jeremy Tonet next.

Jeremy Tonet: I figured I would take another shot here, if there was room. And just realizing all the news today is very fresh but maybe if you could provide any more color with regards to stakeholder feedback at this point or from the regulators, I guess, just how you’re expecting this transaction to move forward?

Bob Blue: Yes. Jeremy, we just talked to the regulatory staff this morning after the announcement went out. But let me just talk sort of generally about how we expect this to be received; so just to start with the process. We need to get approval from the State Corporation Commission in Virginia, the North Carolina Utilities Commission. We need some administrative approvals from BOEM but the primary approvals are at the state level. And as I mentioned earlier and as I believe you know, legislation that was passed unanimously in Virginia last year enabled this partnership structure that we’ve put together. So it has to be approved by the SEC under the Utility Affiliates and Transfers Act. And the standard there is adequate service at reasonable rates have to be maintained and that the arrangements are otherwise in the public interest.

And then we need Affiliates Act approval in North Carolina as well. In Virginia, that Affiliates Act approval has a statutory time line of 90 days. The other regulatory approvals don’t have particular time lines on them but we think it’s reasonable to assume we’d get approval by the end of the year; so that’s the process. But if you sort of step back for a moment, both Virginia and North Carolina policymakers both understand the value of a strong balance sheet. If you look at Virginia’s general obligation bonds, they’ve been rated AAA by Moody’s since 1938, by S&P since 1962 and by Fitch since 1991. And I can tell you that when you talk to policymakers in Virginia about the AAA bond rating, they usually use the adjective coveted. And that’s because they realized that a strong balance sheet for the state allows them to provide the best service to their constituents.

And the same is true for our company. If we have a healthy balance sheet, we’re going to provide the best customer experience. We’re going to be able to invest to meet the state’s goals. That is a very compelling reason for regulators to approve this transaction and I’m highly confident that they’ll see the benefits and approve it.

Jeremy Tonet: Got it. That’s very helpful there. And maybe if you might be able to talk a little bit more, I guess, on the emerging PJM transmission opportunity, with PJM recently increasing the 10-year low-growth CAGR and Domain’s ability to capitalize [indiscernible].

Bob Blue: Diane will talk a little bit about that. And Jeremy, we’re quite impressed with your ability to navigate the technical issues here.

Diane Leopold: Yes. Jeremy, so yes, you’re absolutely right. The latest PJM forecast was somewhat higher than last year. So we’re at about 5.5% a year in Dom’s zone. Some of that is with our neighboring co-ops that are within our zone. We continue to see a lot of transmission investment opportunities. In the last PJM open window, there were about $2.5 billion of additional projects that were awarded to us. Much of that supports growth in the data centers and we fully expect there will be additional projects in future years to keep pace with that demand growth.

Jeremy Tonet: Got it. That’s helpful. I’ll leave it there.

Bob Blue: Thanks, Jeremy.

Operator: And our next question, please state your name and company name before asking your questions.

Steve Fleishman: This is Steve Fleishman — is that me?

Bob Blue: Steve, we can hear you. Thank you for hanging in there.

Steve Fleishman: Yes. That was interesting. The — I guess, just — I assume, can you — you can’t really comment on where the FFO to debt is laying out overall but should we assume, based on kind of the downgrade threshold that we’ve seen in the past are likely to stay the same by the agencies from this review?

Bob Blue: Yes.

Steve Fleishman: Okay, that’s helpful. And also, just a side question on — it was a quiet legislative session this year, as far as I can tell. I just want to make sure there was nothing going on in the legislative session that we should be aware of.

Bob Blue: Steve, your characterization is accurate. Major issues that General Assembly was dealing with didn’t have much to do with energy. They obviously elected the SEC judges. And there were legislative proposals related to energy but they’re none that are still active in the General Assembly at this point.

Operator: And we’ll take our next question from the line of Ross Fowler with UBS.

Ross Fowler: So a couple of questions; commercial load growth was up almost 9% in 2023. And I think you guys talked a little bit about data centers. But if I remember correctly, there were a lot of constraints in sort of putting data centers into Northern Virginia because of transmission. How do you think about that growth going forward into 2024, is there a constraint that limits that in 2024? Or should I be thinking about something of the same scale over the coming year?

Bob Blue: So when you say Northern Virginia, it was one area of Loudoun County, Virginia which is where there are a heavy concentration of data centers and we did have some transmission constraints. We’ve undertaken several shorter-term projects that were — we’ve either completed or about to complete. And then we have, ultimately, two transmission line — 500 kV transmission line projects, one of which is underway. The other is in the regulatory process. Those, frankly, that first one of those two 500 lines will relieve the constraint in Loudoun. And we’ve been able to start up connects on data centers. We had a brief period where we took a pause to make sure we understood exactly what we were doing but we’ve restarted. But I think the broader question is we will absolutely be able to serve the data center growth that we expect is coming.

It will require investment in transmission. Diane just talked about that, out of the most recent PJM open window. We’ve had a lot of data center growth in our company, in our service territory for some years. We have very good relationships with the data centers. And we expect to see that growth continue and we expect to be able to serve it.

Ross Fowler: That’s great, Bob. Thank you for that update. and then one more, if I may. I appreciate you can’t answer a lot of questions around a lot of things today until we get to the Analyst Day next week. But hopefully, when you can discuss, fixed costs are now, I think, at 92 — just north of 92% on this and there’s about 700 — just south of $750 million on fixed costs. How are you thinking about your capabilities and time line to lock more of that on fixed costs in — on this project?

Bob Blue: Yes. It will come in sort of gradually as we move closer to the end of the project. The way it worked earlier, we would lock in a contract and you might get a pretty big chunk at one time or another. From here on out, it’s some onshore transmission, it’s fuel for vessels that will be doing the offshore construction. And that’s just going to sort of come down overtime.

Diane Leopold: And the only other is miscellaneous project management cost, just our own project management through time. So those are the largest factors.

Operator: And we’ll take our last question from the line of Durgesh Chopra with Evercore ISI.

Durgesh Chopra: Two quick questions. Sorry, I just want to be absolutely clear. The — with the announced offshore sale, this is the last asset sale that we should be expecting? Or are there portfolio optimizations we should be expecting heading into the Investor Day next week?

Bob Blue: You’re correct. That’s the last one. As we signaled on the last call, the potential for an offshore wind equity partner was the last strategic step. We’ve taken that step.

Durgesh Chopra: Got it. And then just one small net, maybe this is for Steve. When we talk about the ITC accounting change and then the pension accounting change, Steve, can you just remind us what is embedded in your ’23 representative number there, EPS number there? What is kind of baked into that number?

Steven Ridge: Yes. In 2023 — you’ll see in Footnote 22 of the 10-K tomorrow, you can actually calculate it. We disclose all this. You’ll see that in 2023, we’ll have generated about $0.40 of earnings associated with pension-related income. And so going forward, we’ve talked a little bit about EROA. There’s another driver that I’ll talk just briefly about that would bring us from $0.40 closer to that average of $0.20. We — like the majority of corporate sponsors of pension plans, we calculate one of those key numbers, our expected return which like interest cost and service cost, as a component of the net income or expense for pension. We effectively smooth the actual asset returns over a 4-year period and apply our expected return on asset to that sort of smooth asset value.

And that’s not only permissible, that’s standard. Some people smooth, I think, over 5 years. We smooth over 4 years. Again, that’s pretty standard. And because of 2022’s performance, at least in our portfolio, where we experienced a very significant loss to value across, to be honest, both the equity and fixed income portions of our portfolio which, again, I don’t think is unusual for folks. What you’ll see between ’23,’24,’25 and ’26 is you see that smoothing occur such that the impact of that loss is fully recognized by 2026. Now it’s not just as simple as saying ’22 was down and I’m going to take a portion of that each year. Every year, we do that. So you effectively have the stacked Excel spreadsheet, where each year, you’re adding a little more of that — the prior year and some years are dropping off that schedule.

So it kind of it’s a net look of your asset value with this smoothing construct. Hopefully, I haven’t just confused you. But as a result of 2022’s hurt flowing through, that will be a driver. If you’re asking — if you’re at $0.40 today and you’re telling it needs to be closer to $0.20 and you’ve given us a sensitivity around 100 basis points, how would you get to the next? That’s a big driver of that remaining amount. For ITC, in 2023 as a result of the switch to deferral method, I think we’ll end up with something like $0.03 in our 2023 results. And again, what that’s from is the recast of historical results. We go back and we say, hey, if we had not accounted for this as a flow-through, if we accounted for it as deferral, some of that value is over that 30-year period.

So as I mentioned, $0.03 to $0.04 of expected operating EPS from ITC credit going forward and that’s about where we would be in 2023 as well.

Durgesh Chopra: Perfect. And Steve, just to be clear, I apologize, this is under the weeds. But — so if I’m thinking about prospective EPS, net-net, we should be — versus ’23, $2.85 [ph] in ’23, we should be $0.20 lower net-net, right, ITC being just kind of the same and the pension being $0.20 lower.

Steven Ridge: Yes, it’s not probably quite so precise. We’re using — we’re giving you $0.20 as the average over ’25 to ’29 and there is some fluctuation in that. But generically, versus 2023, $0.40 would be moving something to closer $0.20 over the ’25 to ’29 period.

Durgesh Chopra: Thank you, Steve.

Operator: Thank you. This does conclude this morning’s conference call. You may disconnect your lines and enjoy your day. Thank you.