The Southern Company

Good afternoon. My name is Rita, and I will be your conference operator today. At this time, I would like to welcome everyone to the Southern Company second quarter 2020 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. At that time, if you have a question, please press the 1 followed by the 4 on your telephone. As a reminder, this conference is being recorded Thursday, July 30, 2020. I would now like to turn the conference over to Mr. Scott Gamow, Investor Relations Director. Please go ahead, sir.

Thank you, Rita. Good afternoon, and welcome to Southern Company's second quarter 2020 earnings call. Joining me today are Tom Fanning, Chairman, President, and Chief Executive Officer of Southern Company, and Drew Evans, Chief Financial Officer. Let me remind you we'll be making forward-looking statements today, in addition to providing historical information. Various important factors could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our Form 10-K, Form 10-Qs, and subsequent filings. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measure are included in the financial information we released this morning, as well as the slides for this conference call, which are both available on our investor relations website at investor.suttercompany.com. At this time, I'll turn the call over to Tom.

Good afternoon, and thank you all for joining us. As you can see from the materials we released this morning, we reported strong adjusted results for the second quarter, meaningfully ahead of the estimate we provided last quarter. While we remain within our expected annual range of COVID-related revenue impacts, the second quarter impacts were not as severe as we originally estimated. Employees throughout the company have worked hard to maintain excellent levels of customer service and implemented thoughtful cost containment measures. Of course, our peak electric load occurs in the third quarter, and consistent with our longstanding practice, we will wait to address our annual guidance in October. Before turning to the business update, I want to recognize that these are unusual times on multiple fronts. Our role in the communities we are privileged to serve has never been more important and apparent. Whether it's our response to the COVID pandemic or working within our communities to promote racial justice, we continue to deliver results. I want to extend a huge thank you to our employees, customers, business partners, and public officials. Southern Company and our operating companies remain committed to supporting our communities today and throughout what is expected to be a prolonged recovery period. Let's turn now to an update on Plant Vogel Units 3 and 4. From a schedule perspective, we continue to remain focused on meeting the November 2021 and November 2022 regulatory approved in-service dates. We are maintaining an aggressive site work plan that targets a May 2021 in-service date for Unit 3 and seeks to provide margin to the regulatory-approved in-service date. From a cost perspective, Georgia Power's proportional share of the total project capital cost forecast increased in the second quarter by approximately $115 million to $8.5 billion, largely reflecting estimated COVID-19 impacts and other costs and a replenishment of contingency based on our projections for the remainder of the project. As a result of these collective actions, Georgia Power recorded an after-tax charge of approximately $110 million during the second quarter. Looking more closely at schedule, in the second quarter we experienced significant impacts from COVID-19, among other factors. While the recent workforce reduction was effective in decreasing density at the site and increasing efficiency, we were unable to achieve the anticipated level of production. Recognizing these challenges, in June we announced a re-sequencing of certain milestones. We shifted the expected start of cold hydro testing to the fall of 2020. With the timing of the structural integrity test and integrated leak rate test to precede cold hydro, both of these tests were successfully completed in mid-July. In fact, the integrated leak rate test approached only 30% of the allowable margin, an indication of the quality of the work being performed at the site. We accomplished several other interim milestones for Unit 3 during the second quarter. including the completion of closed vessel testing and the turbine assembly. The aggressive site work plan currently targets the September-October timeframe for the start of cold hydro testing. We now expect Unit 3 hot functional testing to commence during the fourth quarter, and we continue to see a path to Unit 3 fuel load by year end. However, recognizing that the aggressive site plan is now even more difficult to achieve than before the pandemic, it is important to remember that under the November benchmark, fuel load is not required until mid-2021. And as a reference point, even if Unit 3 fuel load occurred in March, it would support an in-service date of next summer. We also reevaluated our estimates for costs and time to complete the final phases of construction, which resulted in hours being added to the direct construction projections for both units. Reflecting these additions, today Unit 3 direct construction remains approximately 90% complete. We still expect construction completion of about 2% per month to be consistent with the aggressive site work plan, and completion of approximately 1% per month to be consistent with the November benchmark schedule. Importantly, even amid the outbreak of the pandemic and our need to significantly modify work practices, our average monthly construction completion rate was approximately 1.5%. Over the last four weeks, earned hours have surpassed our expectations relative to the November benchmark for each of the major work fronts, including electrical, mechanical, and civil. As we move ahead, critical areas of focus remain electrical and subcontract performance. Now turning to cost. We have always maintained that we expected to utilize our contingency account, but that was before the COVID pandemic occurred. As a result, we have increased Georgia Power's share of the total, capital cost forecast by approximately $150 million to $8.5 billion. This represents an increase of a little less than 2%, certainly not all, but largely due to the COVID impact. The second biggest factor was a re-estimate of the amount of effort and therefore hours required to complete the final phases of construction. Georgia Power allocated its remaining contingency and added new contingency of approximately $115 million, further reducing future cost risk through the completion of Unit 4. Embedded in the project's cost to complete are estimated COVID-19 related costs of between $70 million and $115 million for Georgia Power. Also recall the estimated cost of the time between the aggressive site work plan target dates and the regulatory approved November in-service dates or a scheduled cost margin of approximately $250 million is also included in Georgia Power's base capital forecast. Together, the replenished cost contingency and this scheduled cost margin continue to represent approximately 20% of the remaining estimated cost to complete. As we have said, we expect to utilize the entirety of contingency funds as we progress towards completion of the project. The team at Vogel Units 3 and 4 continues to work incredibly hard and drive meaningful progress at the site, even while managing through the pandemic. As we near the final phases of construction for Unit 3 and move closer to fuel load, I can assure you that the construction team, our management team, and our partners are more focused than ever on bringing the first unit of this historic project to completion next year. As we approach the final key milestones, we recognize that the aggressive site work plan is increasingly difficult, as most of our optionality relative to a May 2021 in-service date has been utilized, but both management at the site and workforce remain motivated to pursue the aggressive schedule to provide margin to the November regulatory and service dates. Drew, I'll turn it over to you now for an update on our financials and our outlook.

Thanks, Tom, and good afternoon, everyone. I hope that you all are well. As Tom mentioned, we had a very strong quarter. Second quarter adjusted earnings per share, was 78 cents, which is 2 cents lower than last year and 13 cents above our estimate for the quarter. The primary driver compared to last year was a decline in sales led by COVID-19-related demand reduction, largely offset by diligent cost control and constructive state regulatory actions completed in 2019 at our utilities. The estimated impact during the quarter from COVID-19 was negative 10 cents, and the weather impact relative to normal was negative 3 cents. A detailed reconciliation of our reported and adjusted results is included in today's releases and earnings package. Year-to-date through June, the dynamics are similar, though COVID-19 impacts were largely absent in the first quarter. For the first six months of the year, adjusted EPS was $1.56, which is 6 cents higher than last year. Year-to-date, COVID-19 impacts are estimated at negative 11 cents and weather impacts were negative 13 cents compared to normal. We continue to assess the financial impacts of COVID-19 on our business with key focus areas being sales declines, customer arrears, and bad debt expectations. In the second quarter, total kilowatt-hour sales impacts from COVID-19 were in line with the expectations we provided last quarter. Weather normalized retail sales were down approximately 8%, with residential sales up 5%, commercial sales down 12%, and industrial sales down 14%. COVID-19-related sales impacts on our commercial classes were a bit better than we anticipated, with industrial impacts a bit worse than expectation for the quarter. Factoring in all customer classes, our non-fuel revenue came in slightly above our forecast. Looking ahead, we continue to base our COVID-19 forecast for 2020 on a U-shaped recession with modest economic recovery across our service territories over the balance of the year. Our retail sales projection for the full year is unchanged with an expected overall decline in the range of 2% to 5% on a weather-normal basis. Let me also reiterate our expectation that retail sales in these ranges will with lower total non-fuel electric revenues by approximately $250 million to $400 million on a consolidated basis. Based on what we have achieved through the second quarter, we also continue to believe that pandemic-related sales impacts in 2020 can be mitigated through interim cost containment measures. As we undertake cost containment initiatives, we are maintaining our focus on safety, customer service, reliability, and affordability. With our solid results through the first half of the year, we're well positioned as we head into the peak electric load season. Our estimate for the third quarter of 2020 is $1.15 per share on an adjusted basis, and consistent with historical practice, we will address earnings for the year relative to our EPS guidance after the third quarter. In addition to sales, we've also been monitoring customer arrears and the potential for an increase in bad debt expense. Customer arrears have trended better than anticipated across our operating companies and our liquidity position remains robust. Constructive mechanisms have been put in place by the commissions in many of our states, allowing us to address COVID-related costs and bad debt expense in future regulatory proceedings. Additionally, through the first half of 2020, we are on target to meet our annual capital plan. At this point, we do not anticipate that future impacts of COVID-19 or the Vogel impacts Tom discussed will materially impact credit metrics across the companies. And as we said last quarter, we do expect these factors – we do not expect these factors to affect our long-term outlook. Before I turn it over back to Tom, I'd like to highlight some statistics in our energy mix trends so far this year – Through June, generation from coal represents just 13% of our energy mix, and over one-third of our generation mix was from zero carbon resources. For the full year, our projections indicate that generation from coal could be below 20% for the first time in modern history. We acknowledge that this near-term outcome is partially driven by extremely low natural gas prices and electricity demand reductions from both the pandemic as well as mild weather, But the long-term trend is also driven by less temporal factors, including a combination of coal plant retirements and a concerted effort to increase our renewables portfolio. In the coming weeks, we expect to publish a supplement to our 2018 carbon report. The supplemental report provides additional detail on potential pathways to achieve Southern Company's goal of net zero emissions by 2050. This is an important transition for our company, and we look forward to discussing this report with you in the months ahead. With that, Tom, I'll turn it back over to you.

Thanks, Drew. Before we take your questions, let me acknowledge Congressman John Lewis. His funeral is being held in Atlanta today. He was a wonderful man. We are thankful for his service and his work combating racial injustice and his commitment to nonviolence. I also want to address the topic of racial injustice. Recent events have resulted in demonstrations around the world that are leading to necessary and important discussions about racial injustice in our society. One way to think about racial injustice issue is to imagine a series of sine waves over time. Every so often, the peak of the sine wave rises to the point that this issue impacts our national consciousness, and frankly, we all see it. But with the passage of time, these events fade from the headlines of our nation. However, we all know the underlying systemic problems still exist. One of our objectives at Southern is to keep these important issues at the forefront by focusing on sustained improvements. In my opinion, that's where we should place our efforts today if we want to make lasting improvement to racial justice in America. We are having meaningful discussions in our company and are committed to long-term action. In closing, these are unusual times for our world and nation as we contend with the COVID pandemic, economic uncertainty, and racial injustice. While it is not unusual is the way our company is responding. We're delivering clean, safe, reliable, and affordable energy to our customers. We are consistently working to understand and meet the needs of our employees, customers, and communities. And we remain focused on our key business objectives, including operating our utilities at best-in-class levels, demonstrating cost discipline, and working diligently to bring Vogel Units 3 and 4 online by the November regulatory approved in-service dates. We believe Southern Company is well positioned to successfully execute on these fronts and uphold our goal of achieving an attractive risk-adjusted return for our shareholders. We so appreciate you joining us this afternoon. Operator, we are now ready to take questions.

Thank you. If you would like to register a question, please press the 1 followed by the 4 on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered and you would like to withdraw your registration, please press the 1 followed by the 3. Again, as a reminder, to register for a question or comment, please press the 1-4 on your telephone now. One moment, please, for the first question. Our first question comes from the line of Julian Dumoulin-Smith with Bank of America. Please proceed with your question.

Hey, Julian, how are you?

Yeah, good afternoon. Thanks very much for the time. Indeed. You bet. Congrats on the progress here. Thank you. If I can, you're quite welcome. Turning to Vogel, just If I can ask, you know, COVID is making something of a second wave here. How do you think about factoring that into your contingencies? And then separately, I want to come back to the comments you made, because it sounds like worker productivity and absenteeism is not being impacted by the second wave as well.

It certainly is less than the first time. Look, if you remember when the United States went through this first wave, there was even a lot of conversation about stopping megaprojects. We had lots of Southern Company board meetings, management time, site time, really thinking through what is the best course of action to play here. And as you remember, and I think we've talked about this in the past, we took extraordinary measures to make sure that the workforce at Vogel Units 3 and 4 were better protected at the site than they would be kind of in the surrounding area or when they return home. We did things like we created a medical village at the site that provided testing and PPE and all sorts of things. And we received national acclaim for those steps by folks like the United States Building Trades. So we did a whole lot. Even so, as we thought about what do we do about the workforce there, we saw a great deal of absenteeism. And so one of the byproducts of the workforce reduction that we did at the site, roughly 2,000 people, we basically gave people the option to leave and those people that were most concerned about working in a COVID environment left. The people that have agreed to stay get the idea that we've got to continue work, that the COVID protocols we put in place make sense, and that their health is being looked after in an excellent way. And the data would show that. And, in fact, we finished the first wave with, you know, we measure the cases of COVID positive tests. We had several periods of time where we went to zero. And so everything we were doing was working. And certainly the productivity started doing pretty well. We are, we think now, in a second period of COVID wave. And we have seen, and I would probably measure this thing probably from Memorial Day is where it kind of started. A lot of people left or coming back to the site, and they've gotten exposed to potentially other sources of impact from the COVID virus. And so we're seeing that now. So the question we have to ourselves is, are we reaching a plateau? Are we starting to recover from this thing? We have our own medical staff that we've hired to oversee. There are some beliefs that this thing will have a shape similar to the first wave, and then it will start to erode, but time will tell, okay? Okay. I mean, the other thing we don't know, Julian, is whether it will be a third wave and a fourth wave. We just don't know. But certainly the folks that are working right now get the idea of working in a COVID environment. And I don't know whether you guys saw my time on Squawk Box this morning. We have a chart in your package, I forget what page it is, that also suggests, I guess it's on page 12, that also suggests that America may be adapting to this new reality, and we're seeing it in our numbers. We absolutely don't know whether that will sustain, but it's a very interesting chart.

Excellent. Well, I hope you're doing well. Thank you. Absolutely. If I can, on the contingencies, just to wrap this up, What contingencies remain? How do you frame that? You made a lot of comments at the outset on contingency. I just want to try to summarize that a little bit more precisely and talk about what latitude remains here.

Yeah, so think about it in two pieces, right? So one piece is just a straight cost estimate, okay? And so we've done things like added in additional hours. This effort we talked about, And this really, we made estimates on the completion of the construction activities about two years ago. And so we made estimates on the final civil work, you know, hanging concrete panels, what it would take to do the roof shield building. These are not increases in scope. Rather, they are re-estimates of what we believe, how much effort, how much hours will be required in order to accomplish that scope. Another thing that we talk about is INC. And this is how difficult it is, how much effort is required to run cable from, say, the source of electricity to the cabinet, to the terminal points in the plant. Mechanical, how much piping, how much effort will be to finish the pipe work. Electrical. cable tray installation, cable pulls. We've talked about the size of the cables and the amount of effort to terminate those cables. I could go on, but that is where we have kind of taken into account other costs that ultimately go into an increase in the contingency accounts. And also, we've added in an allowance for incurring per DM costs through 2021, really the finish of the construction of Unit 4. That wasn't in there before. So we've added a lot in here. And let's think about it in two pieces. One is cost. One is scheduled contingency. Let's make sure we all understand that. 100% dollars, it's $540 million. Georgia Power's share, $250 million. you could make your own judgment about when we're going to finish the project, but that amount of money is derived from the cost of completing in May to November. So, just to pick, just to give you a point of reference, everything else being equal, if you finished in August, you would have roughly half of that scheduled contingency available. So, That's another way to think about scheduled contingency. Certainly, there could be other costs that emerge over time. I'll tell you one other thing, Julian. There was a great bit of debate about this whole issue. We really wrestled with this thing. When you think about it, and we try to have these concepts in the script, as we have allocated the remaining contingency and then added back to this 20% number, it is pretty clear to us that we have reduced risk. Because we've identified risk items, we've allocated current contingency and added new. So there was some argument that says we don't need 20% right now. Maybe we should go with a lower number. At the end of the day, we think we took prudent action by this. Let's keep contingency at 20%. Let's not hit any of the contingency available on schedule. And let's move forward on that basis. We think this is a disciplined approach. We think it is conservative. And I think we're in a good spot.

I'll leave it there. Thank you.

You bet. Thank you.

Thank you. Our next question comes from the line of Steve Fleischman with Wolf Research. Please proceed with your question.

Hello, Steve. Hey, good afternoon. Good afternoon, Tom. Hope you and your family are doing well.

Oh, thank you. No, we're doing great.

That's great to hear. So look, I think since your last call in between, we got this staff report on Vogel, and the staff did seem to disagree on some things, and I think they say that the November date is highly unlikely, and also talked to a billion-dollar potential cost increase and other kind of factors that they mentioned. Could you just address in your, I guess, view of it, like where are the differences in view here?

You bet. Yeah, and I think it's going to be pretty clear stuff, and I think we're going to give testimony here pretty soon about how we see it versus what they see. And certainly there's no new data that they're working on. We use the same data. It's really how you view the data is what gives rise to a difference. Like, for example, we really start with data that was established some two years ago. And the staff doesn't give us credit for the work done over the past year in which we have earned a CPI multiple of 1.3. In order to derive their numbers, they use somewhere between 1.4 and 145. Well, in fact, they are ignoring our performance over the last two years. And we would argue that, and we've talked about this on prior calls, that all this electrical work particularly has been especially difficult to do. We call that scheduled versus unscheduled electrical. And as we move into the scheduled electrical work, has been really hard, and it has given us high CPI numbers. But as we get to the unscheduled CPI numbers, we're getting numbers less than one. So as we move forward and get the hard work behind us, there is some at least reasonable expectation we'll be able to at least maintain the 1.3 CPI. But we don't believe in their 1.4, 1.4.5 assumption. The other thing they would say is, is that they go back to our assumptions, if you recall, on the schedule that was put in place two years ago in which we had lots, well, lots, that's a qualitative term, but a good bit of scheduled float time, okay? And, in fact, we've consumed a lot of that here recently with the re-estimate and the re-sequencing and all that, and that's where we said we've taken a lot of that margin out But the schedule they would use would say things like this, that hot functional test to fuel load is five to six months long. Well, we really think it's more like three months. They would say fuel load to in-service is six months long. Well, we really think it's four months. What they're doing is counting all that management margin time that we now account for. We, you know, look, we have a planned margin. We think that all adds up to about four to five months difference from their own estimate. And I want to say, I hope somebody will correct me here, that their own estimate said something like February of 23 for Unit 4. If you take four to five months away from that, that puts us in the summer well in advance of November at a lower cost. Those would be the big items.

Great. Great. The other thing that was mentioned, which I think you've addressed before and just even today, was just on the testing, and they highlighted like 80% of tests failed initially, but then I think you guys said a lot of them then passed soon after, and then you just passed these other key tests that you mentioned. Could you just give more color on that issue and just clarify why that wasn't an important data point, I guess?

Well, it's almost like, you know, you extrapolate from the worst data point and you project a result. Our actual results have been better than that. And, yeah, look, I mean, the data is the same. We did, you know, have some failure rates on our early testing. We maintain that early testing is so illuminating to the future challenges of the project. And we have said forever that if you think about values of function of risk and return, yeah, we spend a little more money. to do early testing, but we think it is well worth it in risk reduction in thinking about problems that may lay ahead. If we learn quickly, fail quickly, and then correct in the future, I think that really helps reduce risk in the project, and I think we've done a great job there. From that 80% number, we have put Tiger teams in place. We have seen improvements. And if you look at these two major tests that were just done, they were put ahead of the cold hydro testing, the structural integrity test, integrated leak rate test. With the allowable margin on the ILRT, we were only at 30% of the allowable margin. I think even oversight people were surprised at how well that went. I think that really speaks to the future quality of work. There will always be problems, and that's part of what testing is all about. You find the problems and you fix them. So I'm not saying there won't be problems, but I think the rate that they use to extrapolate into the future is way too high.

Okay, great. Thanks for clarifying those things. I appreciate it.

You bet. Thank you.

Thank you. Our next question comes from the line of Michael Weinstein from Credit Suisse. Please proceed with your question.

Hey, Michael. How are you? All right. I'm good. I'm glad to hear that you sound like you're doing well. I saw some headlines that you had tested positive at one point.

Yeah, you know, I was completely asymptomatic. My wife, Sarah, actually... was the one that started feeling ill, and when she did, she tested positive, and then I went in and tested, and I was positive, but I think no germ will have me. I never had a bad, and now I'm negative.

Well, I'm glad to hear that. I just wanted to give my well wishes on your health. Thank you, sir. Hey, do you have any, can you tell us anything you know about what's going on with the Chinese plants at Sandman? Are there any lessons learned? that you're already starting to apply now as you enter the testing phase and sort of entering the final stages of construction. Have there been any lessons learned from China that you're beginning to apply to lower risk?

Oh, sure. You know, I think the good news is that they are all running well and that any lesson we've had we've taken into account, and we've actually gone back and improved some processes that even – are newer since. You remember everybody was kind of freaked out, and probably rightfully so, on the reactor coolant pumps, but we've gotten through that, and no issues that we've seen on our site. Didn't expect any. You know, the only other thing I would say, especially as we're approaching kind of completion of our unit, is that we have much more automation in terms of finishing construction, in terms of testing, and a variety of other things. The Chinese plant tended to throw personnel at any issue. So I think we're going to be a little bit different. There won't be as many lessons learned just in the work process. So anyway.

Gotcha.

Hey, maybe we could just get kind of a regulatory update. I know there's not much to update on this area, but I think there were some filings that you're planning on making this fall on the gas utility side and Maybe you could update on where you think the IRP process is going and future opportunities for construction of plants. And on the same token, what are your plans going forward for Southern Power?

I want to hear the regulatory stuff.

I'll do Southern Power. I'll take a crack on regulatory. We've largely resolved the resource planning that was done in Alabama, and I think that You can take a look at what we filed in the queue, but specifically we will construct a gas facility, we will purchase a gas facility, and we will enter into some contracts for additional capacity. We have two other jurisdictions that are involved in rate making. VNG filed with the expectation that rates will be in effect subject to refund at the beginning of next year and will be resolved sometime in the first or second quarter of next. And then AGL Resources – I'm sorry, Atlanta Gaslight filed its annual gram filing with the expectation that will be finalized by year end. So those are sort of the two outstanding but three major rate filings for the year.

Yeah, and remember, Georgia has kind of just completed its triennial deal, so not much there. If we do have a VCM filing in February, then it'll be important. They always are. Otherwise, we're carrying out the IRPs. We've not received a final order in Alabama yet. So wait for that. Southern Power. We are where we were. You know, we're out in those markets, particularly wind and solar, some storage. And we just find that market to be extraordinarily challenging. And, you know, we were big into it for a while, but that's when that market was hot. The contract periods are shorter. The contract terms are tougher. We found that to be a tougher place to allocate capital. And so what you see is, you know, more than 90% of our net income is coming from these wonderful franchise businesses that are the electrics and the gas. We've allocated, you know, at one time, I forget how much it was. It was like $6 billion one year. But now our allocation of capital to Southern Power, Power Secure, is now about $500 million a year. And I don't know whether we'll spend that or not. We'll just see. But it doesn't have much of a near-term impact. We have closed a couple wind deals. They were called Redding and Beach Ridge. But again, it's not that big a deal. In terms of their operating performance, they're doing great. They're producing what we thought they would. We're just not allocating a lot of future capital that way.

Completed construction at Reading. In the process of construction at Skookumchuck, I'd say our opportunities are largely wind-related, although there are two projects that we're working on within the California jurisdiction for battery, which I think is an interesting place for us to explore and understand these battery additions to existing solar facilities. I think give us good intelligence on how to produce the asset, what the economics of the asset are, and what the operational characteristics are. So I'm pretty excited about that.

What's fascinating about kind of where we've passed our die at this point, it's with the franchise businesses. You know, we used to talk a whole lot about Southern Power and what the markets were. Right now, we think regular, predictable, sustainable earnings on a good risk-adjusted basis are coming out of our franchise, and that's how we're making our money going forward.

The vast majority of our total capital plan over the next five years?

Yep. You know, hey, one last question along these lines. You know, there's a big nuclear plant about to come online. Are you guys thinking about maybe some experiments in terms of the hydrogen economy, producing hydrogen off a nuclear plant to create green? being gas? Just a thought I had.

As a matter of fact, we are. Now, at the risk of telling a long story, I'll tell a short story. Three years, I kind of term here, we did something called a SoPrize, kind of built along the XPrize concept. One of the six winners was hydrogen. So we've been working on hydrogen now for seven years, roughly. And Very fascinating kind of idea about hydrogen is that it's a great storage medium, and you can pair hydrogen or hydrogen technology with kind of electrolysis and solar and a variety of other things. The other thing we're looking at is future gas generation that may be able to use hydrogen as a mix with natural gas or even at the extreme exclusively in place of natural gas. Remember, we toyed around a little bit of this with Plant Rackless. We think there are applications going forward, and we are hard at work at that. It's one of these things that's R&D for sure. I think right now it's kind of out of the money. But remember, the job of R&D is to take things that are out of the money and make them in the money. That does occupy a certain segment of our R&D budget right now. Funny you should ask that. Okay, well, thank you very much. You bet. Thank you.

Thank you. Our next question comes from the line of Angie Storosinski from Seaport Global. Please proceed with your question.

Angie, yeah, Angie, welcome back. Glad to have you.

Thank you, Tom. Thank you. So I have a question about the contingency. I think we all expected that you guys are going to tap into this contingency at some point. We're hopefully getting close to the end of construction cycle for Unit 3. I think what is somewhat surprising is, one, that you have refilled the contingency and that, you know, by writing down this additional, you know, cost estimate, I think assume that you will not be seeking recovery of the additional spending, even though it seems like it's, you know, driven by COVID, which is not something that you could have controlled. And then secondly, so, you know, we're getting seemingly very close, as I said, to the end of construction, at least for Unit 3, and so you know, some of those assertions that you've been making about, you know, the project progressing faster than what the staff of the Georgia UPSC believes are about to be, in a sense, validated. So how can you make us more comfortable that, one, there is no additional, you know, additional, basically, realignment of the construction plan for Unit 3 coming within the next, say, three months? And then... Well, that's probably the main issue is, one, why did you increase the contingency and wrote it down? And, two, you know, how comfortable should we feel about this new schedule, you know, given that we have so little time left until the end of the year?

That's right. And thank you for all the questions. You're at the heart. I think I mentioned before that we really had enormous debates internally about all this. You know, let's just kind of put it this way. In the script, I referred to the fact that when we established the original contingency, it was before we had COVID. And COVID was arguably the biggest factor in thinking about, you know, reestablishing a higher contingency level. Of course, there were other factors, but that was one of them. And, you know, with respect to recovery, you know, I think that's an issue for the future. We're not saying no and never, and I know there have been some writings in the analyst community about likelihood there, but I don't think it's appropriate for us to go through those issues right now. And therefore, we would not seek to offset an accounting charge with a belief, a probable outcome in that regard. The other one that came into that argument was schedule. You know, I'll let you all make your own belief about what schedule is. We think May, this is consistent with every time we've ever said this, the May aggressive schedule is aggressive, less than 50%, et cetera. And recently we said it's even gotten tougher because we've removed margin. At the same time, we say that we expect to achieve November. So we try to suggest that there's a range between May and November, and all other things being equal, forget other new challenges we may face, some of that scheduled contingency may be available. But we weren't willing, and I should say that scheduled contingency is also referred to in the tent here as owner's contingency, which requires all of our co-owners, Oglethorpe, Neang, Dalton, to agree to. So we have left it in place. I think the approach we've taken, Angie, with respect to the accounting charge associated with the increase in costs, and part of that increase in costs was a replenishment with contingency, is just conservative and prudent. And we think it's the right thing to do.

Okay. And the second part, which is, you know, if you will be able to load fuel by the end of this year or even early next year, I mean, how soon, in a sense, will you know if that's achievable come the EEI? You know, will we know?

Yeah. Good question. So if I got you to page seven or chart seven, whatever it is, Vogel Unit 3 direct construction and major milestones. We suggested that we could start cold hydro kind of in the September-October timeframe and that it would take, you know, I don't know, 10 days and then shortly thereafter we'll start hot functional testing. It's so interesting listening to the investors and thank you for hanging with us through all this. A lot of the bets, if you will, on Southern are taken by the accomplishment of these milestones. You know, we've suggested in the past, geez, if you get to fuel load, that certainly is a whole lot of information. That means you pass a functional test or you basically have an operating plant and it just doesn't operate off nuclear fuel yet and we pass the ITAC and now we load nuclear fuel and we go on from there. Other people have suggested the next big lever is the hot functional testing. In other words, with a third party, if you will, heat source, not nuclear fuel, does the plant work? Every milestone that we've been passing so far has given us comfort that we have a quality plant and that we'll be able to hit, you know, a schedule expectation. This chart, I think, lays out our best guess. as to what those things may be. And the other thing we added to the script this time was just to give you some comfort on variance, Angie, and it really goes to the idea. We've said that fuel load by the end of the year is our objective, and the site is working like dogs to get there. But even if we were three months late, then that suggests perhaps a summer in service dates. I think all this is meant to give you some sensitivity and an indication of our ability to hit November. I hope that's helpful.

Yes, thank you.

Thank you.

Thank you. Our next question comes from the line of Sophie Karp with KeyBank. Please proceed with your question.

Hello, Sophie. How are you?

Hi. Good afternoon, guys. I'm doing well. How are you?

Fantastic. Thanks for being with us.

Of course. Thank you for taking my question. I want to ask a non-verbal question. I feel a little weird doing that right now.

All questions are welcome.

Yeah. So I'm looking at slide 10 on your earnings deck, right? And it seems like what you have here is $0.05 tailwind from O&M, right? Is that net of $0.10 negative with COVID impact? Is that, like, the right way of reading that?

No, so, Sophie, COVID impacts are in rates, pricing, usage, and other. And so that would be the impact of COVID, which we've denominated for you for each of the two periods, And then you would add back to it any changes in rates or usage of the utilities related to the rate activity from last year. And so these really represent O&M relative to last year's performance.

Okay. So basically the O&M is a clean $0.05 O&M number. And should we expect a similar kind of run rate for the second half?

You know, it's a good question. We're spending an awful lot of time thinking about costs in general, Southern has always been a very strong, had a strong ability to compensate for changes in weather demand in particular. This year, we've been faced with weather demand and with impacts related to the coronavirus. And we've been very pleased with the discipline that each of our employees has exhibited. We're looking at the components of those costs. And in general, you could imagine You know, with the cessation of hiring, we'll have a reduction in headcount relative to our expectation, no reduction in our actual workforce, which leads to a reduction in benefits and incentives and travel and entertainment and a number of cascading factors. We've also had a series of expenses related to operations of facilities, which are not safety related, but because generation has been lighter due to COVID and weather, we actually have been able to through normal cycle, defer. This is not a deferral of maintenance, but a maintenance that will pass until the unit has operated a certain number of hours is maybe the right way to think about it. We also have other factors like vegetation management that works against the seven-year cycle. But suffice it to say, there are a number of items that are, one, in period, and two, that might create headwind for future. And we're just monitoring those buckets, and we want to make sure we're responsive to Current period, but also future period. And so I wouldn't say that these would necessarily hold in that we'll examine what our needs are after we get through the next three months, which is the lion's share of the summer cooling season.

Yeah, I think you said exceedingly well. And we've talked about this in years past, you know, where we have some optionality in terms of spending, right? Some stuff we have to do and we do it. Some stuff we have the ability to do it today, tomorrow, the next month and the next month or perhaps the next year. And if we have the ability through better than expected weather, et cetera, we'll do them this year. So we can move with loads. And that's what's kind of interesting about what Drew said earlier about kind of where we are in our revenue expectation for this COVID, where we set it up this year. I mean, I'm just going to guess right now we're midpoint or below, certainly not trending adversely. And if you look at that July thing, I don't know whether that's going to sustain or not, but our revenue picture is coming in a little better than what we thought. Therefore, that may open up some opportunities, spend some more L&M. We'll see.

Yep. Terrific. Thank you for this, Keller. And then, you know, I was just wondering on the COVID impact as it relates to Vogel, right? So clearly that's causing some of the impact here. and that's not something that was contemplated or, you know, obviously foreseen at the time of 2017 settlement. Is there a point where it's merit for you to revisit that settlement, or is it just too insignificant in the grand scheme of things right now to be thinking about that?

Oh, no, I think it's a fair question, but I think it's a question for kind of, Right now, everything you're dealing with is an estimate. It really isn't a cash impact right now, not a material one. This is really what we're estimating going forward. Let some time pass, and let's see what we're doing. And we certainly have the history of ongoing constructive conversations with regulators about unforeseen circumstances. And that's probably not going to happen this year. Let's see in the future.

Got it. Well, thank you so much. I appreciate your taking my question.

Thank you. Always glad to have you with us.

Thank you. Our next question comes from the line of Durgesh Chopra with Evercore. Please proceed with your question.

Durgesh, thanks for joining us. Hey. Hey, thanks, Tom, and glad to see you doing well. Thank you for taking my question. So maybe, Drew, first to you, you showed this very good slide on slide 11, that is, which shows sort of the projection and the actual results. What is embedded into the Q3 115 EPS guidance on that front? What kind of retail load projection are you embedding specifically in that Q3 number? Can you share that with us? Sure.

What I can tell you is that we think that Q3 might have an impact that is very similar in aggregate to Q2, which would make it a smaller percentage of the total, maybe 10 or 11 cents in aggregate. And that's simply because the summer period is a much higher sustained output of kilowatt-hour sales, given that it's a cooling load.

Understood. Thank you for that. And just one quick one. You don't put out any materials reaffirming your long-term guidance and capital plan, and I think that is consistent with how you've done it previously, but the Q1 print actually had you reaffirming the long-term growth guidance, I guess. But no change to your – I think you said this in your commentary, but I wanted to clarify. No change to your long-term capital plan as well as your long-term EPS growth cake, correct?

And capital requirements. All three of those factors are true, in fact.

And once again, historically, we deal with that in our first quarter, or no, our year-end call, which would be early February. We'll update all that. But, yeah, and if there was something material, we would say so. But you should just travel with what you have.

Understood. Thank you, guys. Be safe and healthy. Thanks. Thank you so much.

Thank you. Our next question comes from the line of Paul Fremont with Mizuho Securities. Please proceed with your question.

Hello, Paul. Good afternoon.

Good afternoon. I guess my first question is how many remaining ITACs are there on Unit 3?

261. Those are open. That's out of 399. So we've completed 138, just to save you from the math.

Okay.

And, hey, Paul, one other thing. On the 261, a lot of those are what we call UINs. That means we've essentially had the ITAC approved at the commission except for the result of the test.

So, I mean, I think if I recalled on the first quarter call, it looks like you've reduced that number by roughly 10 from the first quarter call?

Yeah. Yeah.

Okay. And then, do you have construction work hours scheduled after the revised start of hot functional testing? I think one of the things that staff mentioned in their report was it was unusual normally that construction is complete when you start hot functional testing.

Yes, but I wouldn't get excited about that. We made that change in February. And so if you have construction work hours after a hot functional test, it would be things that aren't critical to the operation of the plant. In other words, not critical to the nuclear operation. So it may be civil work.

Yeah. Okay.

And then I guess Does cold hydrotesting need to be completed before hot functional testing begins, or can you be doing both at the same time? Oh, it does have to be complete.

Yes, sir.

Okay, because if I go to your slide seven, then... Yeah, let's go.

So let's say we start... kind of early September on cold hydro. I think that's what that blue is meant to do. We think there's probably a month difference between the start of cold hydro and the start of hot functions. I mentioned cold hydro takes about 10 days.

I'm sorry, so you can complete the cold hydro in a month?

Oh, gosh, we can complete it in 10 days.

Okay. I just wanted to understand sort of the timeline a little bit better. And then last thing is, I mean, you talked about sort of looking at what staff is looking for in terms of scheduling versus what Southern's plan is and the differences there. But I think what staff had said was typically for other nuclear plants, both in this country and in other countries, it's roughly six months from the end of hot functional testing until fuel load, and then another six months to commercial operation. So they're sort of looking at the body of nuclear plants that have come before Vogel 3 and 4. What gives you confidence, I guess, in your planning process that you think you can do that more quickly?

Yeah, I mean, the simple volley on that logic fail – is that they're using data that is more than 30 years old. You know, that's kind of the way they think about it in that regard. The more relevant way to think about it is what China was able to do. We originally allowed six months. China was able to do it in four and a half months round numbers. And we have our own opinions. The other thing that I might should have mentioned before, but I should, I'll say now. Westinghouse is consistent between the work in China and the work here in the United States at Vogel. And we get the benefit of their experience. And remember, we've always had people in China looking at all that experience. We've had our own people there. So I just, I think that's an obvious, in my opinion, and I hope I don't make anybody mad, but I just think that's a logic flaw. that if you're going to make your estimate based on, heaven forbid, 1970s, 80s data, the world is different now. And we have a much better marker for experience in China than we do those projects.

Paul, I'd like to clarify maybe one thing because that may be helpful to other folks on the call. Slide 7 is an important slide for us, and so let me help you maybe decipher it a little bit. The blue circle represents the aggressive site work plan project. and when those milestones would need to start to stay on that plan. It is not meant to be the duration between the orange and the blue. The orange circle represents the point at which we think that we need to start those activities to maintain the November schedule.

Yeah, no, no. I think that one.

And even the orange could be moved. You could start high functional tests later than what we show here. That That's a good schedule shot of what November would look like if you chose to do November. You could actually start a high-functional test much later than what we indicate here and still hit November.

And high-functional test is roughly three months based on what you guys had talked about in earlier calls?

It's two months. Two months, okay. We used to have in there, Paul, and what you may be remembering is 30 days of kind of management time. But it's a two-month schedule.

Great. Thank you. That's it for me.

Thank you, sir.

Thank you. Our next question comes from the line of Andrew Weissel with Scotiabank. Please proceed with your question.

Hello, Andrew. Welcome.

Hi. Good afternoon. Tom, I just want to echo. I'm glad to hear that you and your wife are feeling better.

Thank you.

I appreciate it. My first question is if I understand your answers to Sophie's questions, It sounds like most of the O&M savings in 2020 are going to be related to timing flexibility or short-term adjustments in reaction to COVID-19. But now that we're a few months into the pandemic and modified utility operations, what's your latest thinking on how much these cost-saving initiatives might be sustainable as opposed to one-time?

Oh, listen. Well, you're hitting some – I'm going to attack the question differently. You're hitting a very interesting question. Okay. Okay. How much of the O&M savings, Drew and I were arguing about this the other day, is deferrals? In other words, they're going to show up later. 15%? About 15%. So 85% are captured and permanent is what we believe. Okay. So only 15% is temporal. And that may be made up with what happens kind of at the summer. We get, you know, prolonged period of warm weather or less than expected COVID impacts or then we'll turn that money on this year. It probably would be more vegetation management related than it would say deferral of outages because Drew explained it beautifully. If the plant's not running, you take an outage based on essentially the time on turbines and things like that. And if they're not running, you defer the outage. Was that helpful?

I think part of the question that you're asking too is that will some of these things be made permanent? And I don't know that that's necessarily a fair assertion to make. We built our budgets around what we thought was a complement of people that we thought we needed to operate our business or grow our business. And we've had to take a pause in hiring this year because we have to be responsive to customers and responsive to shareholders. And so we've waited a bit. When we're outside of COVID, we might certainly make the determination that these are things that we still need to do. Now, there are absolutely things that we've examined. There are work groups that are working remotely now that are incredibly efficient that we might ultimately determine can work in that mode for a while. But I'm not sure we're ready to put a stake in the ground around 2021 or a non-COVID environment. So we've had a little bit more time to operate the way we're operating.

But he's exactly right. I mean, we are debating these things around the management council table. That's the CEOs of all of our opcos and the major functional heads. It's a fascinating question. What does this tell us about a way to operate more efficiently in the future? I think we have gained on O&M. I think we do lose by the collegiality of walking down the halls and working with each other. We're trying to make that up, you know, with texts and phone calls and e-mails. But it's not the same. But there's something in between that we need to capture.

Okay, great. That's definitely helpful. Lastly, switching to midstream, not a huge focus of yours, obviously, but in light of Dominion's asset sale and ACP being canceled, a few questions. Obviously, you've exited ACP, but I guess how committed are you to this business? Would you consider selling your assets? Or conversely, how would you describe your appetite for new midstream projects? And then lastly, would you consider taking capacity on MVP to diversify your supply sources?

Yeah, so let's dial the clock back to when we were just getting buffeted by all sorts of offers, if you will, expressions of interest for us. Right, but there were – I think I've mentioned this before. There were something like five different big deals that we were looking at, and then one came in at the end, so it was almost five and a half. I don't know. We've never been committed in a kind of deep way – to pipeline growth. So what did we do? Go back and look. It was we bought 50% of the southern natural gas system owned by Kinder Morgan at the time. And recall that the reason we did that deal was we felt that natural gas generation, particularly in the northern half of our system, was inextricably tied to SONAC, southern natural gas pipes. And if you remember that day, I think most everybody would say we bought that well. We got a good price. It was really important, I think, to Kinder Morgan for us to stay a customer. And so we were able to do that. I forget what our share is of that pipe. It's 50% or better of the throughput of Sonat comes to us. So there was this kind of notion of synergy and integration. The other thing we said that day was we viewed this as an annuity. It's a good annuity because we bought it at a good price. We did not include any expansion of that pipe in any of our financial plans. We've done a few things around the edges, but nothing material. So here's my view. There was so much symbiosis. between Sonat and our plans for Generation and Southern, we felt like that was a smart bet. And because we were able to buy it well, it fit in very well in our portfolio, but it fits in as an annuity, not as a growth engine. In terms of our appetite going forward, look, I just think that's an extraordinarily difficult business right now. And, you know, I'm sorry for my friends Tom Farrell and Lynn Good on ACP. I know they worked very hard to make that a reality. It was just the right thing for us not to be part of that.

And I'd say the character of our midstream businesses is also very different. You touched on it with Sonat. But we've never really been involved in gathering and processing. We have very modest storage facilities. representation, although we own a fair amount of storage within our LDCs. And the transportation leg that is the dominant piece of our investment is a primary supply source for our southeast utilities. And so it has a character that looks a little bit more like transmission and transportation than midstream in aggregate.

And the other thing is, what's the future of gas pipelines? Look, I said when we did the AGL deal that I thought gas was a bridge to 2050. I kind of lengthened that now to say, boy, it's beyond 2050. But in order to hit net zero, what we're going to have to do, and that's what Southern does uniquely compared to any other company in our industry, is invest in technologies that are going to be able to deal with the carbon atom coming off gas generation. We're doing that. There's no national leader that compares to us. We run the nation's carbon capture research center. We run the International Carbon Capture Research Center. We're doing all sorts of other money-where-our-mouth-is activities to deal with carbon. That's why we're confident, as we think about the portfolio going forward, that we're investing in optionality that's going to be able to keep gas part of the solution. But we will have to deal with the carbon atom.

Okay, great. And MVP appetite?

I'm sorry, what was that?

Mountain Valley Pipeline. I don't think so. That's something you'd have to hear from our utilities directly from, not something that we talk about here.

It's not a front burner issue, though.

All right. Thank you so much.

Thank you, sir.

Thank you. Our next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed with your question.

Hello, Paul. How are you? All right. How are you doing?

Fantastic.

I'm glad to hear it. It sounds like you might have been a silent spreader, right? Right.

You never know.

I'm glad that – and congrats on the company's ability to sort of navigate COVID-19 with the big project and everything. What I wanted to ask you about, I guess, is Footnote 3 in the release discusses – The last sentence discusses that there might be some potential future write-offs. And I was wondering whether or not associated with Vogel. And I was wondering, is that just basically sort of boilerplate standard, you know, safe harbor stuff? Or is this something that we should be – is there anything more you would elaborate on that in terms of what we should be expecting with respect to that?

You know, I've looked through all this stuff. That one doesn't jump off the page. It sounds like, you know, we believe in conservative disclosures. We don't know of any exposure to future write-offs in the future. I mean, we've given you everything we know. Is it possible there could be further?

Yeah, sure. Okay. I got you. No, I just noticed it, and it looked a little – I just wanted to make sure. The other thing was on the leveraged leases – It looks to me like you guys have written off the entire value of those, but there's some language about how there might be, I'm not clear whether or not there's some additional obligations you might have with respect to closing it. Is there any exposure here that you think is material that we should be thinking about?

You know what? I don't think so. I mean, and just to replay this one, this was This is a legacy business, and it was very important to, if you guys remember, Southern Energy. It started out Southern Electric International. In fact, I was effectively the CFO of that for a while. And then it became Southern Energy, and then we spun it out and became Merit. In the spin-out, we took over the leasing business. Those guys liked financial engineering. I don't like financial engineering, never have. But the leasing business was kind of hot at one time in the world because you could kind of structure net income. That was the idea. Choctaw was one of those projects. The reassessment really dealt with the terminal value of that plant. And I think it has a power sales contract with TVA that expires in 32. We re-evaluated the terminal value based on what it costs, we think, to operate the plant in 33 and beyond relative to the market for this plant compared to, say, natural gas. Natural gas prices are 35% cheaper this year than they were last year, and therefore the assessment of terminal value went to zero, and therefore you failed the impairment test, and therefore we wrote the whole thing off.

Okay. I just want to make sure on that. And then With respect to the $150 million in COVID-19, it says COVID-19 and other costs. Is there any significant other costs that you'd call out on this? Just sort of what's the sense of how much is sort of COVID-19 versus something else, I guess? And if there is something else that's significant, what might that be?

It's funny you pick up on that. We kind of drafted around that one a little bit. The 75 to 115 refers to COVID. Okay, comma, and then there are other potential costs.

Okay?

So what you're reading there, 75 to 115 is COVID, and then there may be other things. And other things may go to the performance of subcontractors. It may go to, you know, I don't know, just per GM extension in 21, beyond where we are now, things like that.

Awesome. So thanks so much for the presentation. Very helpful. And glad everybody's doing well.

Okay. Super. Thank you, my friend.

Thank you. Our next question comes from the line of Michael Weber from Weber Research. Please proceed with your question.

Hello, Michael. Hey, good afternoon, guys. Hey, good afternoon, guys. How are you? Super. Good. Thanks for squeezing us in. I just wanted to circle back real quick to a couple of global EPC-related questions, and specifically to kind of get our arms around on-site headcount and craft labor productivity in a pre- kind of in a pre-COVID and a kind of a post-COVID world or a mid-COVID world. And forgive me, I know you touched on this a bit already, so forgive me if I missed it. But to be clear, is the headcount that's currently on site in line or enough to hit that May 21 in-service date? And then maybe more specifically, have there been any changes to the underlying craft labor productivity assumptions used to kind of get to that timeframe?

Yeah, terrific. we're adding. We're a little below. So if you do, they're just the big numbers. You know, we went from 9,000 to 7,000. We're actually a week below 7,000. We're adding back now about 100 to 200 new electricians. And in effect, this is a summary of what we've said before, but recall we moved people off of Unit 4 to Unit 3, and we're adding back electricians to kind of catch up on Unit 4 now. That's kind of the way you should think about it. So that's about where we are. The other thing that's kind of good is we think there's personnel available, particularly on the Gulf Coast and some other areas. The labor unions, U.S. Building Trades and others have been terrific to work with here.

And then just the second part of that in terms of the underlying craft labor productivity assumptions that are kind of underpinning that May 21 date, have there been any changes to those in kind of the post-COVID environment?

Well, it doesn't assume. So remember the aggressive schedule is aggressive, okay? It does assume improvement in productivity for sure. So, I mean, you know, the other data point I guess I could give you is if you just kind of extend where we have been with no improvement, we're kind of hit between the 2% per month and the 1% per month. 2% associated with the aggressive schedule, 1% associated with November. We're kind of hitting right down the middle of the airway with no improvement. Let me assure you, we are trying to reach improvement. And the other thing I mentioned earlier on this call that I hope people remember, we're finishing up this tough part of electrical. That's the cable trays and pulling these gigantic cables and terminating them in very closed spaces. And remember, we refer to this in the language in the script, when we talk about losing the production. As we went to a COVID protocol, we, for example, instead of having an army of people in a closed space, we would have like no more than three people in a work space. So we couldn't get the amount of production done just because we had fewer people there. That pushed out construction. And that gave rise to the change in the estimates. All of those are covert impacts. Gotcha. Hey, it's going to work hard to get it done. We'll see.

No, that's very helpful. And just specifically related to productivity-related costs, does Bechtel or any of their major contractors have any risk or cost share exposure there, specifically in the case of productivity-related costs?

Yeah, their fee is at risk. That's the big thing. Let me just bag on those guys. Brendan Bechtel, Jack Future, Brian. Anyway, they're terrific. Brian Riley, they are terrific folks to work with. We meet with them all the time. I'm in the meetings where we meet with them now. Our on-site team, that'd be Steve Kaczynski, Glenn Chick, and others, meets with them daily, right? But there are monthly meetings where Brendan Bechtel himself, Jack Futcher himself, come to the meetings with Paul Bauer, CEO of Georgia Power, me. Drew Evans is there. Our co-owners are there. Dr. Jacobs is there. The PSD staff. DOE is there, for heaven's sake. NRC. NRC is there. Everybody sees a completely transparent picture of where we are. And we think this has served us so well.

Gotcha. Just to dig into that in terms of how exactly there's a fee at risk, what mechanism?

Yeah, I think that's a question you'd rather ask Bechtel or even, you know, boiler room kind of stuff. Gotcha. But it's just a success fee. Incentive fee is the way to go.

Fair enough. Well, first of all, that sounds like a very big room with all the seal there, but I appreciate the... I appreciate the caller, and thanks again for squeezing in.

Oh, sure. Thank you.

Thank you. And that will conclude today's question and answer session. Sir, are there any closing remarks?

Thanks, everybody. Boy, these are unique times, aren't they? I think we're going to look back at 2020 maybe the way we look back at 1968 or some other big years in history in the United States. You know, when I think about the work being done at Vogel 3 and 4 and the adjustments those people have made to continue to progress the Vogel 3 and 4 site, it is nothing short of heroic. And they deserve our gratitude. And I think they continue to make great progress under a lot of duress. So thanks to that team there. Thanks to our coworkers at Bechtel and all the subcontractors. I know it's important to you guys. We see ourselves now in the short rows of that process, at least for Unit 3, and it's such an exciting time to look at the end of the tunnel and, in fact, see daylight. So we look forward to making progress in October when we meet back with you at the end of the third quarter. We'll have a lot more transparency on what the summer did for revenues, and we'll have, I think, a new estimate on what we're going to do this year. And in terms of guidance, and we'll have a lot more, I think, visibility on where we are in three and four. Such exciting times. If we can just get our social unrest under order and pay attention to making sure that not only the what's of our business are done well, but the how's of our business are done well in a systemic way, not in a periodic way. I think we'll all be better as a company and as a nation. Thank you all so much for following us. We appreciate your time today. Operator, that concludes the call.

Thank you, sir. Ladies and gentlemen, this concludes the Southern Company second quarter 2020 earnings call. You may now disconnect.