Dominion Energy, Inc.

Welcome to the Dominion Energy Third Quarter 2021 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 turn the call over to David McFarland, Director, Investor Relations.

Good morning, everyone, and thank you for joining the call. Earnings materials, including today's prepared remarks, may 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 of

jim chapman executive vice president chief financial officer and treasurer and other members of the executive management team i will now turn the call over to jim thank you david good morning everybody let me begin with a recap of our compelling investment proposition and highlight our focus on the consistent execution of our strategy we expect to grow our earnings per share by six and a half percent per year through at least 2025. growth that is driven by our $32 billion five-year growth capital plan. As outlined in our fourth quarter call in February, over 80% of that capital investment is emissions reduction enabling, and over 70% is rider recovery eligible. We offer a dividend yield of 3.5% and expect dividends per share to grow 6% per year based on a target payout ratio of 65%. Taken together, Dominion Energy offers an approximately 10% total return premised on a pure play state regulated utility profile operating in premier regions of the country. Our industry leading ESG positioning includes the largest regulated decarbonization investment opportunity in the nation. which, as you will hear in today's prepared remarks, is steadily transforming from opportunity to reality. We have quite a few exciting developments related to that transformation to discuss this morning, including the pending settlement of our triennial review and our offshore wind application in Virginia, in addition to other positive updates across our operating segments. Before handing it to Bob for those and other business updates, I'll discuss our third quarter results and related financial topics. First, our strong quarterly earnings. Our third quarter 2021 operating earnings, as shown on slide four, were $1.11 per share, which for this quarter represented normal weather in our utility service territories. These strong results were slightly above the top end of our quarterly guidance range. Positive factors as compared to last year include growth from regulated investment across electric and gas utility programs, higher electric sales due to increased usage from commercial and industrial segments, and the impact of the share repurchase completed late last year. Negative factors as compared to last year include higher depreciation expense and a return to normal weather. This is our 23rd consecutive quarter, so almost six years now. of delivering weather-normal quarterly results that meet or exceed the midpoint of our quarterly guidance ranges. Note that our third quarter and year-to-date gap in operating earnings together with comparative periods are adjusted to account for discontinued operations, including those associated with the sale of our gas, transmission, and storage assets. Third quarter gap earnings were 79 cents per share and reflect the non-cash mark-to-market impact of economic hedging activities unrealized changes in the value of our nuclear decommissioning trust fund the contribution from questar pipelines which we which will continue to be accounted for as discontinued operations until divested a year in and other adjustments a summary of all adjustments between operating and reporting results as usual included in schedule two of the earnings release kits turning out a guidance on slide five As usual, we're providing a quarterly guidance range, which is designed primarily to account for variations from normal weather. For the fourth quarter of 2021, we expect operating earnings to be between 85 cents and 95 cents per share. Positive drivers, as compared to last year, are expected to be normal course regulated rider growth, continued modest strengthening of sales from commercial and industrial segments, and slight margin help within contracted assets. Negative drivers as compared to last year are expected to be a slight catch up in COVID deferred O&M and tax timing. Given where we are in the year, we're narrowing our 2021 full year guidance range to $3.80 to $3.90 per share, preserving the same midpoint as our original guidance. Assuming normal weather for the remainder of the year, we expect operating earnings per share for 2021 to be in the upper half of this narrowed guidance range. We're also affirming long-term operating earnings and dividend growth guidance, no changes here from prior communications. We will, as usual, provide 2022 guidance on our fourth quarter call early in the new year, but we continue to expect the midpoint of our 2022 guidance range to be 6.5% higher than the midpoint of our 21 guidance range. We continue to be very focused on extending our track record of achieving weather normal results at or above the midpoint of our guidance on both a quarterly and annual basis. On slide six, we've summarized several important financial milestones achieved since our last call. First, We issued $1 billion in 10-year green bonds at our parent company at a cost of 2.25%. This follows right on the heels of the $6.9 billion in sustainability-linked credit facilities, which we announced on last quarter's call. So a lot of activity at Dominion on these types of innovative financings that support our ESG objectives. Thanks to all who participated in this important offering. And as a reminder, We'll have additional fixed income issuance at Dominion Energy Virginia, Dominion Energy South Carolina, and at our parent company during the remainder of this year. In October, we announced the sale of Questar pipelines to Southwest Gas Holdings. This all-cash transaction was valued at nearly $2 billion, including the assumption of about $430 million of existing debt. Proceeds from the sale will be used primarily to reduce parent-level debt. We very much expect to close by the end of this year, subject only to HSR approval. Obviously, there's quite a bit of press attention currently on some of the dynamics unfolding around various shareholders of Southwest Gas, but I would highlight that there is no early termination mechanism in our purchase and sale agreement. As a reminder, this transaction does not impact Dominion Energy's existing financial guidance this quarter or otherwise. Questar pipelines have been and will continue to be accounted for as discontinued operations excluded from our company's calculation of operating earnings. Next, as a result of our continuous focus on both our capital allocation process and on our corporate credit profile, We've elected to monetize additional value from our investment in Cove Point by financing our stake with an attractive non-recourse term loan. We've received binding commitments on a $2.5 billion non-recourse term loan, which is at the entity that holds our 50% non-controlling equity method investment in the Cove Point facility. Proceeds from this EPS neutral financing are being used to reduce parent level debt. Over the past few years, we've taken intentional and significant steps to effectuate fundamental change to lower our business risks, to maximize the recycling of capital into our attractive regulated utility businesses, and to improve our credit metrics. And this financing is another step along that same path. We expect this non-recourse recapitalization to be completed by year end. Bigger picture, this financing provides a good opportunity to take a quick look back on the capital flows from that asset, CodePoint. As you will recall, we invested approximately $4 billion in the construction of the CodePoint liquefaction project. And through the combination of prior stake sales and the project financing we're announcing today, we will have monetized well over $6 billion of capital to date, even before accounting for any distribution. Turning now to electric sales trends. Weather normalized sales increased 2.4% year-over-year in the third quarter in Virginia and 1% in South Carolina. In both states, consistent with the trends seen last quarter, we've observed increasing usage from commercial and industrial segments, overcoming declines among residential users as the stay-at-home impact of COVID waned. Looking ahead, we continue to expect electric sales growth in our Virginia and South Carolina service territories to continue at a run rate of 1% to 1.5% per year, similar to what we were observing pre-pandemic, so no changes there from prior communication. Next, let me discuss what we're seeing around rising natural gas prices. We're hearing a lot about this topic across the industry this quarter. We prioritize our customer rate affordability and implement price mitigation strategies across our businesses in a variety of ways to account for the impact of changes in gas prices. So across our electric and gas utilities, We have very clear-cut pass-through mechanisms for fuel costs. So this is less of an issue as to how the recent price increases may impact earnings if they're sustained, but rather how they'll impact our customers' bills, something we obviously care about and we watch very closely. So let me share a little bit of color on what measures we have in place to mitigate those kinds of impacts. In our gas distribution service territories, we expect the bill impact of rising fuel prices to be less pronounced than what some recent headlines suggest due to a few things. The proximity of gas resources, our widespread use of storage to offset peak day requirements, and the effectiveness of our gas supply hedging strategies. In our western states, our unique state regulated cost of service gas production also helps customers avoid price spikes in fact we estimate that our customers save over a hundred million dollars over just a seven day period during the winter storms experienced last february thanks to this regulatory structure in our electric service territories we also have long-standing risk mitigation strategies including hedging and storage with most fuel costs trued up to customer bills on on a delayed basis a structure which helps to smooth out the bill impact of commodity swings in summary we certainly don't want to see any increased costs for any of our electric and gas customers so we'll continue to employ these mitigation measures to keep any increases as muted as possible but for the avoidance of doubt We currently don't see any impact to our decarbonization-focused growth capital investment plan. In wrapping up, we'll plan to use our fourth quarter call early next year to provide a comprehensive update and roll forward of capital investment, financial outlook, and related disclosures akin to the format of our last fourth quarter earnings call, which we believe was well received. Investors should expect further evidence in support of several fundamental Dominion Energy themes, compelling earnings and dividend growth, combined with the largest regulated decarbonization opportunity in the industry, and an unyielding focus on extending our track record of successful project, regulatory, and financial performance. With that, I'll turn the call over to Bob.

Thanks, Jim. I'll start as usual by commenting on our safety performance. As shown on slide 7, I'm very pleased that our results over the first three quarters of this year are tracking closely to the record-setting OSHA rate that we achieved in 2020. As it relates to our electric utilities, I would note that through the first three quarters of this year, we're in the top quartile of performance for the Southeastern Electric Exchange in combined incident rates. In fact, we're number one. Now I'll turn to updates around the execution of our growth plan as shown on slide 8. At gas distribution, in North Carolina, we reached a comprehensive settlement with the public staff last month for our gas operations with rates based on a 9.6% ROE to be effective this month and generally in line with our financial plan expectations. The agreement also includes three new clean energy programs, a new hydrogen blending pilot, which, like our existing blending pilot in Utah, is part of our goal to be ready to blend hydrogen across our entire gas utility footprint by 2030, a new option to allow our customers to purchase RNG attributes, and new and expanded energy efficiency programs. The settlement is pending commission approval. In Utah, we received approval for a program that would enable customers to purchase voluntary carbon offsets. For $5 per month on a typical residential bill, customers who opt into the program will fully offset the carbon impact of their gas distribution use. This program, which, like our existing Green Therm program, allows customers to make choices about how to manage and lower their individual carbon profiles. It's just one example of how gas distribution service intersects with an increasingly sustainable energy future. In South Carolina, new rates were effective beginning September 1st, after the South Carolina Public Service Commission, with the support of all parties, unanimously approved the proposed comprehensive settlement in the general electric rate case. It's also worth noting that in September, we filed an interim update to our modified 2020 IRP, And Resource Plan 8 remains the preferred plan, calling for the retirement of all coal-fired generation in our South Carolina system by the end of the decade. Turning now to Virginia. Last month, we announced a comprehensive rate settlement agreement in our pending triennial rate case in conjunction with the State Corporation Commission staff, the Office of Attorney General, and other intervener parties. We appreciate the balanced, reasonable, and cost-effective approach among the parties, which allowed an agreement which supports continued capital investments in Virginia in order to meet the Commonwealth's clean energy priorities and the needs of customers. Those investments include the development of offshore wind, which I'll touch on in a few minutes, as well as growing one of the leading state-regulated utility solar and battery portfolios in the country. This element also provides significant customer benefits, as shown on slide 9. and supports our existing financial earnings guidance. We're very pleased to be extending the track record of constructive regulatory outcomes to the benefit of all stakeholders. We look forward to a final order likely around the end of the year. We'll now move to our clean energy filings in Virginia as shown on slide 10. In September, we made our largest to date multi-project clean energy rider approval submission. The filing included about 1,000 megawatts of solar and battery storage, and we expect to receive an order from the FCC in the second quarter of 2022. In October, we filed for wider cost recovery for the capital investment associated with extending the lives of our two nuclear units at the Surrey Power Station and our two nuclear units at the North Anna Power Station, each for an additional 20 years. These units will be upgraded to continue providing significant environmental and economic benefits for many years to come. We expect to receive a final order by mid-2022. Lastly, we've made progress on our grid transformation plans. We participated in hearings with the Commission, and based on our filings and testimony, the SEC staff supports or does not oppose approval for nearly all of our capital requests. We expect a final order late this year. Turning to offshore wind, where we have an exciting announcement. Today we're filing our offshore wind application with the FCC consistent with the project schedule that we communicated previously. Key project milestones are shown on slide 11. The filing will outline the important details of our process and costs, including contractor selection and terms, project components, transmission routing, capacity factors, and permitting. Due to the importance of today's filing milestone, and especially given the sizable volume of information which will be included in this filing, I'm going to spend a little more time than normal this morning summarizing the important aspects. Some background. First, this project represents a viable and needed opportunity for Virginia to achieve its clean energy goals. Once complete in late 2026, this project will generate enough clean energy to power up to 660,000 customer homes and avoid as much as 5 million metric tons of carbon dioxide emissions annually, which is the carbon equivalent of removing more than a million cars off the road each year. Further, the project is essential to meeting the policy goals set forth in the VCEA and other legislation mandating the development and deployment of renewable generation resources. Lastly, as was contemplated in the VCEA, this investment will be 100% regulated and eligible for rider recovery. As a reminder, capital invested under riders allow for more timely recovery of prudently incurred investments and costs. They're filed and trued up annually in single-issue proceedings. In Virginia, rider recovery mechanisms use a forward-looking test period and allow for construction work in progress, all of which minimizes traditional regulatory lag. As outlined on slide 12, we estimate this project will create hundreds of jobs, hundreds of millions of dollars of economic output, and millions of dollars of tax revenue for the state and localities, as well as supporting Virginia in becoming a major hub for the burgeoning offshore wind industry in North America. For example, last week, Siemens Gamesa announced plans to establish the first offshore wind turbine blade factory in the United States. The facility, located in Hampton Roads, Virginia, will create new jobs and supply turbine blades to offshore wind projects in Virginia and throughout the North American offshore wind industry. Our filing details how we've satisfied the requirements for offshore wind, but let me touch on three key tasks required for rider cost recovery. First, we've complied with the competitive procurement and solicitation standards for the project. Second, our projected levelized cost of energy, or LCOE, of $87 per megawatt hour is substantially lower than the $125 per megawatt hour maximum established by the VCEA. More on that theme in a moment. And third, the VCEA requires that the project's construction commences prior to 2024 for U.S. income tax purposes or is a plan to enter service prior to 2028. Our project schedule satisfies both milestones. The long-term cost to our customers of this project, which we believe is the most important metric for a regulated project of this nature, is $87 per megawatt hour and remains within previously guided levelized cost of energy range of $80 to $90 per megawatt hour. Potential savings realized through future tax legislation could also be passed on to customers. For example, it's still early, but we estimate that further expansion to tax credits benefiting offshore wind would reduce the cost to our customers to $80 per megawatt hour. As we've developed the project to its current stage, we've gained critical insights from two primary sources. First, our 12 megawatt pilot project, which consists of the only operating turbines in federal waters, has provided considerable benefit to the development and planning of the full-scale development. For example, the pilot project is providing better information about the wind resources off the coast of Virginia. Initially, we assumed a lifetime capacity factor of 41.5% for the full-scale deployment. After further evaluation of turbine design and wind resources, in addition to the real-time data we've gathered from our test turbines, we've determined that our original assumption was too low. We've revised the lifetime capacity factor to be 43.3%. This is beneficial both for the project as well as our customers because higher generation will result in a lower LCOE. Secondly, we've contracted with firms that have significant experience in offshore wind farm design, construction, and operations to support the project. When we announced the project in September of 2019, the initial pre-engineering and pre-RFP estimated cost was approximately $8 billion. Since that time, through the process of detailed engineering, and most importantly through competitive solicitations for all components and services, we've now developed a detailed budget of approximately $10 billion. As I've been discussing across several quarterly calls now, the cost increase can be attributed to, among other things, commodity and general cost pressures, as seems to be the case across a number of industries right now, and the completion of the conceptual design phase for the onshore transmission route, which has gone through extensive stakeholder engagement with consideration given for resiliency and connection into our existing 500 kV systems. as well as to minimize impacts on the surrounding communities, including environmental justice communities, private lands, environment, scenic, and historic resources. A summary of the major components of the competitive bidding process are outlined on slide 14. These five major agreements collectively represent about $6.9 billion. The remaining project costs include $1.4 billion for onshore transmission substation facilities and currently projected system upgrades, as well as approximately $1.5 billion for other project costs, including contingency. The onshore transmission facilities are necessary to interconnect the offshore generation components reliably. and to maintain the structural integrity and reliability of the transmission system in compliance with mandatory NERC standards. As we observed within the industry recently, utility systems are only as good as they are resilient. Our decision to connect this project to the 500 kV transmission system meets these goals. and provides the best mechanism to ensure that the project's power will be dispersed and used by customers throughout our service territory. We believe the decisions we're making around onshore engineering configurations will result in the best value for customers. As it relates to our Jones Act compliant wind turbine installation vessel, construction remains on track with delivery expected in late 2023, and we continue to expect it to be an invaluable resource to the growing U.S. offshore wind industry. Turning to slide 15, let me discuss how our project costs compares to the other U.S. offshore wind projects. A few observations. First, most of these unregulated or merchant projects remain in the permitting and approval process. For our project, I would note that it's the only state-regulated offshore wind project. We've made considerable progress on development to date and remain on track to complete construction in late 2026. Next, these offshore wind projects located up and down the East Coast obviously differ significantly in their timing or vintage size and scope. For example, the announced capital cost and expected LCOEs for some projects include the cost for necessary onshore transmission upgrades and interconnections, as our budget does, but some do not. And some headlines focus on the year one PPA pricing for many of these unregulated or merchant projects without reflecting the full cost and incorporating such factors as pricing escalation, which we incorporate. Regardless, we show here a comparison based on publicly available information including all such factors of the levelized cost of energy of those merchant projects to our own regulated project. Turning to slide 16, let me address customer rates in Virginia inclusive of our offshore wind project. First, a reminder that between 2008 and 2020, our typical residential customer rate increased on average by less than 1% per year, which is much lower than the average annual inflation over that period of closer to 2%. Second, based on EIA data, our typical customer rate is 17% lower than the national average and 36% lower than other states that, like Virginia, have joined Reggie. And third, going forward, we see typical residential rates increasing by a compound annual growth rate of around 2.1% through 2035, which is a comprehensive estimate and includes, among other factors, the impact of the decarbonization investment programs like our offshore wind project discussed today. If we move the starting point back to 2008, that rate of increase falls to 1.8%, which is lower than projected inflation for 2021. In summary, we continue to be on an unwavering path to meet Virginia's clean energy goals by 2045, and it's incumbent upon us to deliver energy that is safe, reliable, increasingly sustainable, and affordable. With that, let me summarize our remarks on slide 17. Our safety performance year-to-date is tracking closely to our record-setting achievement from last year. We reported our 23rd consecutive quarterly result that normalized for weather meets or exceeds the midpoint of our guidance range. We narrowed the range of our 2021 earnings guidance and affirmed our existing long-term earnings and our dividend growth guidance. We're focused on executing on project construction and achieving regulatory outcomes that serve our customers well, and we're aggressively pursuing our vision to be the most sustainable regulated energy company in America. Lastly, we look forward to seeing many of you next week in person at the EEI Financial Conference. With that, we're ready to take your questions.

Thank you, sir. At this time, we'll open the floor for questions. If you would like to ask a question, please press the star key followed by the 1 key on your touchtone phone now. Again, that is star 1. If at any time you would like to remove yourself from the questioning queue, please press star 2. Again, to ask a question, please press star 1 now. Thank you. Our first question will come from Char Perez with Guggenheim Partners.

Morning, Char.

So, Babaji, you got this settlement, which, as you mentioned in the prepared remarks, does de-risk even the second triennial review. I guess I just want to touch a little bit on the level of confidence in your plan now. How does that sort of tie in to the 6.5% EPS growth target that's been out there? And can we see some changes around the capital program as a result of the settlement, maybe when you report your end results?

Yeah, thanks, Char. You know, when we set that 6.5% rate in July of last year, July of 2020, and we were confident then. We were asked some about it, and we said that, you know, there's no obviously one input. We were asked a lot about this triennial at the time. There's no one input. to setting a growth rate like that. It's a variety of inputs. And one of the things that we mentioned at the time was we assume that we're going to have constructive regulatory outcomes. And we've had those. We had one in South Carolina and in North Carolina and in this Virginia triennial. All of that is supportive of that 6.5% growth rate. So we were confident at the time we announced it. We remain confident. We think we've executed well on regulatory outcomes. And this most recent triennial settlement is a good example of that. As to capital, we'll update capital on the fourth quarter call, as we mentioned in our prepared remarks. So the bottom line is we remain as confident in 6.5% as we did when we announced it.

Got it, got it. And then just lastly, on coastal wind, it's a huge data dump, so appreciate that incremental color you provided. The $87 LCOE capital costs are higher, so obviously you're seeing some cost pressures despite being below the projections and still within the range, right? I think the initial cost, correct me if I'm wrong, was $8 billion. Can you touch on sort of the customer bill impact here as costs are higher, just isolating this project? And it seems that the input cost pressures are kind of widespread. So how do you sort of think about mitigating factors, assuming these cost headwinds have some persistency?

Yeah, so the cost, you're right, the capital cost number is that we estimated earlier now that we've done all of the competitive bidding process and moved from conceptual to firm contracts has gone up some. But as we mentioned, the production expectation, the capacity factor out of this has also gone up as we've gotten more data, which means that the customer bill impact is the same. As we said, it'd be in an $80 to $90 per megawatt-hour range, and we're squarely within that at $87. So, you can't focus just on the capital input here on a project like this. You also have to focus on how much electricity is it generating, since it's going to be generating more than we had previously assumed. That's what lands that customer impact right where we've been talking about in the $80 to $90 range.

Okay, great, terrific. I think that sort of touches on it. See you in a few days. Bye, guys. Thanks, Char.

Thank you. Our next question comes from David Peters with Wolf Research.

Hey, good morning, guys. Morning, David. First question I have is just on the recent election outcomes in Virginia. You know, obviously a lot of focus there nationally, and given that you now have a Republican governor and I think the General Assembly flipped too, Wondering if you could maybe just provide some perspective on what you think may or may not change going forward, you know, particularly with respect to energy policy in the state.

Yeah, thanks, David. You know, in the last, if you look back over the last 15 years or so in Virginia, I think the party in power in the governor's mansion has changed twice. In the Virginia House of Delegates, it's changed twice. In the state Senate, it's changed several times. The Senate wasn't up for election this time. It was the governor and House of Delegates. What's remained consistent throughout that period is that our company has maintained constructive relationships with members of both parties. And we don't see any reason that that would change. And the reason is that what has remained also consistent over that period and even before is is a bipartisan commitment to economic growth and jobs and the economy in Virginia. And if you look at what Governor-elect Youngkin ran on, not surprisingly, given his extensive business background, he ran on a platform of increasing jobs and economic growth. And we obviously support that. We're going to do everything we can to help him achieve the objectives of growing Virginia's economy. We do that by providing reliable electricity by keeping energy prices affordable. We've done that over the years. That was our reliability and affordability were recognized by the FCC staff in the recent triennial review. So we have a track record there. So what I would expect is that Virginia will continue that bipartisan commitment to jobs and economic development. As witnessed in the announcement we talked about in our prepared remarks, the Siemens Gamesa offshore wind blade finishing factory, that was the result of bipartisan work, both parties deserve credit for that kind of job creation in Tidewater, Virginia. We would expect that that's going to continue going forward.

Great. Second question, just switching gears a little bit, just on kind of what's being proposed in Washington for this potential reconciliation bill. Wondering, Jim, maybe if you could comment on how meaningful something like a direct pay option would be for potentially loosening or lessening future equity needs given the the many renewable projects that you guys have here kind of on the come?

Yeah, David, it's a good question. A lot of commentary on that topic so far this earnings season. I've been listening to some of that. And I agree with certainly one thing that's come up a lot, that it's super hard to speculate on moving target, pending and draft legislation hasn't landed yet. It's funny, a couple quarters ago on this call, we were all speculating the impacts of a straight-up corporate rate increase, corporate tax rate increase, so how things have changed. But a few thoughts. Hard to say exactly what's going to be in the final version, but it does seem to us that something is going to pass. So we'll see here in the next month or two. We imagine it will include the clean energy tax incentives and the direct pay feature you're talking about. So that kind of thing, an extension of the tax credits and the refundable basis, it's pretty clear that's going to be valuable and will benefit probably both our customers and shareholders, we expect. I mean, the incentives are going to reduce the cost of renewables to our customers, could accelerate everything we're doing in our clean energy transition. and probably provide some pretty nice cash flow features to fund additional capital investment. So it all seems pretty good. Details to come. Now, in the same package, there's the minimum tax. So not too disturbing for us. We're already a cash taxpayer. Not everybody is. But that's going to be based on gap earnings. It doesn't start until 2023 is the current proposal. So, it's still early. How exactly that's going to work, there's a lot of detail to come. But even that part, we expect as part of this overall package, we think this is all pretty manageable within our existing financial profile and financial trajectory. So, We'll get more clarity over time. Maybe next quarter we can be talking about facts instead of speculation, but it all looks like it's manageable as a package.

I appreciate that detail. Thank you, guys.

Thank you.

Thank you. Our next question comes from Paul Zimbardo with Bank of America.

Hi, good morning. Good morning, Paul. Hi. Hi. Thanks for the time and a nice set of updates overall. I want to follow up on Char's offshore wind question. How should we think about the earnings potential and also credit considerations from the $2 billion increase in the estimated cost?

Yeah, Paul, let me talk to that. So as we mentioned a couple times here, we're going to provide a pretty comprehensive update on our fourth quarter call on all those details. We're going to do a one-year roll forward of our capital plan and we'll go through everything that's related to that in detail like we did last year or earlier this year. So, the increase in the capital cost is one part of the LCOE, the increase in the capital cost and offshore wind. So, a couple of things. Keep in mind, that's spread over six years. So when we do a one-year roll forward, it's going to include that 2026 year. The previous version only went through 25. So that will be included. But keep in mind that there are some other gives and takes, some other moving parts in our plan. For example, we announced in our IRP in September that we were undertaking a postponement for further evaluation of a couple things. like some CTs in Virginia and pump storage projects. So that's not in the current version of the near-term plan. So a lot of gives and takes, some puts and takes. We're going to go through all that on the fourth quarter call, but for the avoidance of doubt, we expect all those updates are going to be supportive of EPS and dividend growth guidance, but you need to look at it holistically and not just based on the impact of the offshore wind project alone.

Okay, great. That's clear. Looking forward to that update. And then I know you commented on the bus start pipe and prepared marks, but if you could elaborate a little bit on the confidence in the transaction closing, given some of the uncertainties you mentioned, and confirming the counterparty could not proactively pay a termination fee to exit. Thank you.

Yeah, sure. And let me answer that a little bit higher level just for everyone's benefit, if they're not following maybe as closely. So we mentioned on the last call, very robust participation. This auction we ran, we feel very good about the announcement we made in October to sell that asset to Southwest Gas Holdings, all-cash transaction, almost $2 billion, and it is on track. We expect that to close this quarter, subject only to HSR So, yeah, there's a lot of back and forth right in the press. We get that. But we don't see any impact on our transaction. Our agreement is intentionally on both sides. It's airtight. Southwest Gas has fully committed financing. It's not dependent on completing equity issuance or anything like that. There are no conditions other than HSR, and there's no kind of provision where it could be terminated early. So we feel really good about that, pretty straightforward, so we look forward to closing later this quarter.

Okay, thank you. Very clear. Looking forward to EI.

Thanks, Paul. You too.

Thank you. Our next question comes from Jeremy Tonay with J.P. Morgan.

Hi. Good morning. Morning, Jeremy. Just wanted to follow up with offshore wind a little bit more here if I could. Just wanted to see how do you see customer bill impacts through the completion of this initial offshore wind phase? And, you know, just thinking what would be the bill impact under the 80 LCOE scenario? I think you might have touched on there with tax credits.

Yeah. Obviously, that would improve the customer bill impact associated with the project, as you correctly identify. If there's a tax benefit that gets passed on to customers, we're still sorting through that. But again, based on the inputs that we've defined here, we're just staying right in that $80 to $90 range. So, We get the lower end better for customers, and obviously we'll have to see how that plays out.

Got it. Thanks for that. And then just understanding there's a cross focus with the offshore wind here. Could you outline how the economic benefits and supplier agreements you outlined have evolved since this project was first announced?

Yeah, I think that they've evolved to be pretty consistent with what we expected when the project was first announced. So, you know, we had a pretty good idea of what would be involved in terms of construction and construction onshore for the electric transmission. There may be some additional benefits probably with onshore construction. electrical because that's going to be given what we had to do to route this and to make sure we're connecting to the 500 kV. That's part of what's driving the overall capital cost being greater. So bigger investment there, more job creation there. But, you know, I think the bottom line is this is going to be good for the Hampton Roads economy, good for the Virginia economy. And I think that that Siemens-Gamesa announcement is really important because it starts the process here in Virginia, a state that is very well positioned, given its location on the East Coast, given its port and the access to the port, unobstructed by bridges and the deep water port, to be a real hub of offshore wind economic activity. We certainly support that. We supported that in working with Siemens Gamesa to put that blade factory here. So the more the better.

Got it. Maybe just one last quick one, if I could. Could you speak a bit more to the RNG and hydrogen pilots, how they progressed over the past quarter?

Hi, good morning, Jeremy. This is Diane Leopold. I'll take that one. So RNG, our program, I think, is far beyond a pilot now, and we're up and running. We have one project that's already in service, so obviously starting very small, but we have five projects that are under construction now, two of which should be entering service in the next couple of months. and four more that are expected to be under construction by year end. This is across both our swine and our dairy projects. All projects are going well on time on budget, and we're expecting to keep up that rough pace next year. So that's on the RNG side. On hydrogen, that certainly is at the pilot phase. Our Utah pilot, which was at a training facility in Salt Lake City, is just about complete, and the tests focused on residential end-use appliances, leak survey equipment, nitrous oxide emissions. The results of those tests confirmed that 5% hydrogen blend would not adversely affect the distribution system. All appliances operated safely. There weren't a lot of changes to, you know, in the system when the hydrogen was added. So we're still doing a few additional tests. We did increase hydrogen blend up to 10% and still did not see any significant impacts from that testing, but we want to keep doing some more testing on final results with that. So on next steps, we've been looking at several isolated regions on system to do a live test and started the initial design phase. We're meeting with the regulators on our test results and on our planned test, and we'll be meeting with them over the coming months so that we can launch an expanded pilot probably in early 2023. And then finally, as Bob mentioned, our North Carolina, we're going to start a similar initial project in North Carolina subject to commission approval of our settlement.

Got it. That's very helpful on the hydrogen project side. Thank you so much. I'm looking forward to seeing the team at EEI.

Jeremy, thanks a lot. See you out there. See you down there.

Thank you. This does conclude this morning's conference call. You may now disconnect your lines and enjoy your day.