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 speakers’ remarks, there will be a question-and-answer session. As a reminder, this conference is being recorded Thursday, July 30, 2020. I would now like to turn the conference over to Mr. Scott Gammill, 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.southerncompany.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 long-standing 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 regarding 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 Vogtle 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 through 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 $150 million to $8.5 billion, largely reflecting estimated COVID-19 impacts and other costs and replenishment of contingency, based on our projections for the remainder of the project. As a result of these selected actions, Georgia Power recorded an after-tax charge of approximately $110 million during the second quarter. Looking more closely at the 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 preceding 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, indicating 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 to complete at 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 accounts, 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 that the estimated cost of the time between the aggressive site work plan target date and the regulatory approved November in-service date, or a scheduled cost margin of approximately $250 million is also included in Georgia Power’s base capital forecast. Together, the replenished costs contingency and the 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 Vogtle 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 in 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 the May 2021 in-service date has been utilized. But both, management at the site and the workforce remain motivated to pursue the aggressive schedule to provide margin to the November regulatory in-service date. Drew, I’ll turn it over to you now for an update on the 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 $0.78, which is $0.02 lower than last year and $0.13 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 $0.10, and the weather impact relative to normal was negative $0.03. 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 were 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 $0.06 higher than last year. Year-to-date, COVID-19 impacts are estimated at negative $0.11 and weather impacts were negative $0.13 compared to normal. We continue to assess the financial impacts of COVID-19 on our business with the 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, while industrial impacts were a bit worse than we expected 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 forecasts 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 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’re 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 Commission in many of our states allowing us to address COVID-related costs and bad debt expense in future regulatory proceedings. Additionally, for the first half of 2020, we are on target to meet our annual capital plan. At this point, we do not anticipate that the future impacts of COVID-19 or the Vogtle impact Tom discussed, will materially impact credit metrics across the Company. And as we said last quarter, we do not expect these factors to affect our long-term outlook. Before I turn it back over 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 non-violence. 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 the issue of racial injustice 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 improvement. In my opinion, that’s where we should place our efforts today if we want to make lasting improvements to racial justice in America. We are having meaningful discussions in our company and are committed to long-term actions. 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, it 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 Vogtle 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. [Operator instructions] Our first question comes from the line of Julien Dumoulin-Smith with Bank of America. Please proceed with your question.

Turning to Vogtle, just if I can ask, COVID is making something of a wave -- 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 at least by the second wave?

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 mega projects. We had lots of Southern Company Board meetings, management time, site time, really thinking through what is the best course of action to take 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 Vogtle Units 3 and 4 were better protected at the site than they would be in the surrounding area or when they return home. We did things like we created a medical village at the site that provided testing, 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 should 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, was that we basically gave people the option to leave. 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. In fact, we finished the first wave with -- we measure the cases of COVID positive tests, and we had several periods of time where we went to zero. Everything we were doing was working. And, certainly, the productivity started to improve significantly. We think we are now in a second period of the COVID wave. I would probably measure this thing from Memorial Day as where it kind of started, many people left, coming back to the site, and they’ve gotten exposed to potentially other sources of impact from the COVID virus. So, we’re seeing that now. The question we have to ask ourselves is whether we are reaching a plateau? Are we starting to recover from this thing? We have our own medical staff that we 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.

Excellent. Well, I hope you’re doing well. Separately, 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?

Yes. So, think about it in two pieces, right? So, one piece is just a straight cost estimate. We’ve done things like added in additional hours, this effort we talked about here. We made an estimate on the completion of the construction activities about two years ago. And so, we made estimates on the final civil work, hanging concrete panels, what it would take to do the roof shield building. These are not increases in scope. Rather, they are really estimates of what we believe, how much effort, how many hours will be required in order to accomplish that scope. Another thing that we discuss is I&C, and this is about how difficult it is, how much effort is required to run cable from the sources of electricity to the cabinet to the terminal point in the plant. Mechanical work involves how much piping, how much effort will be needed to finish the pipe work, electrical, cable tray installation, cable poles; 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 taken into account other costs that ultimately go into an increase in the contingency account. It also -- we’ve added in an allowance for incurring per diem 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, and the other is scheduled contingency. Let’s make sure we all understand that. The dollar amount is $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 give you a point of reference, everything else being equal, if we finished in August, you would have roughly half of that scheduled contingency available. So, that’s another way to think about the scheduled contingency. Certainly, there could be other costs that can emerge over time. I’ll tell you one other thing, Julien. There was a great bit of debate about this whole issue. We really wrestled with this thing. When you think about it and we tried 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 said 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 and 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.

Our next question comes from the line of Steve Fleishman with Wolfe Research. Please proceed with your question.

So, look, I think since your last call, we got the staff report on Volvo, and the staff did seem to disagree on some things. And I think they say that the November date is highly unlikely. And also kind of talk to a potential $1 billion cost increase and other factors that they mentioned. Could you just address, in your view, where are the differences in opinion here?

You bet. 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. Certainly, there’s no new data that they’re working on. We used the same data. It’s really how you view the data that 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 1.45. 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 of this electrical work particularly has been especially difficult to do. We call that scheduled versus unscheduled electrical. As we move into the scheduled electrical work, it 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 1. So, as we move forward and get the hard work behind us, there is some, at least reasonable expectation, we will be able to at least maintain the 1.3 CPI. So, we don’t believe in their 1.4, 1.45 assumption. The other thing they would say 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 not a lot -- a good bit of schedule float. And in fact, we’ve consumed a lot of that here recently with the re-estimate and 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: hot functional tests of fuel load is 5 to 6 months long. Well, we really think it’s more like three months. They would say fuel load 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. So, look, we have a planned margin. We think that all adds up to that 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. 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 test soon after, and then you just test 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?

Yes. Well, it’s almost like you extrapolate from the worst data point and you project results. Our actual results have been better than that. Yes. Look, I mean, the data is the same. We did 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, if you think about values, assumption of risk and return. Yes, 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. 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, and integrated leak rate test. With the allowable margin on the ILRT, we were only at 30% of the allowable margin. I think even the 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. 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.

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.

Yes. But, I was completely asymptomatic. My wife Sarah actually was the one that started feeling ill, and when she did, she tested positive. I then went in and tested, and I was positive. But I think no germ will have me; I never had a bad case -- 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.

Hey, do you have any -- can you tell us anything you know about what’s going on with the Chinese plants, the sentiment? Is there, any -- are other lessons 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?

Sure. 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 reactor coolant pumps, but we’ve gotten through that, and no issues that we’ve seen on our site, didn’t expect any. 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, and there won’t be as many lessons learned just from the work process.

Got you. And 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 now maybe you can update on where you think the IRP process is going and future opportunities for the construction of plants. And on the same token, what are your plans going forward for Southern Power?

Drew, why don’t you take the regulatory stuff? I’ll do Southern.

I’ll take a crack on regulatory. We’ve largely resolved the resource planning that was done in Alabama. I think that you can take a look at what we filed in the Q, but specifically we will construct a gas facility. We will purchase the gas facility, and we will enter into some contracts for additional capacity. We have two other jurisdictions that are involved in rate making. D&G 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 year. And then, Atlanta Gas Light 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.

And remember, Georgia has just completed its triennial deal and not much there. We do have a BCM filing in February, then it will be important. Otherwise, we’re carrying out the IRP. We’ve not received the final order in Alabama. Southern Power is doing what we were doing, we’re out in those markets, particularly wind and solar, some storage, and we just find that market to be extraordinarily challenging. We were big into it for a while, but that’s an end market that was hot. The contract periods are shorter; I mean the contract terms are tougher. We found that to be a tougher place to allocate capital. What you see is that more than 90% of our net income is coming from these wonderful franchise businesses that are the electrics and the gas. We allocated one time -- I forget how much it was; it was like $6 billion one year. But now, our allocation of capital to Southern Power and PowerSecure 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 had closed a couple of wind deals, both -- they were called Redding and Beech 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 Redding and in the process of construction at Beech Ridge. 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, giving 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.

It’s fascinating about kind of where we cast our die at this point. It’s with the franchise businesses. 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 franchises. That’s how we’re making our money going forward.

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

Hey, one last question along these lines. The 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 and green 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. We did something called a SO Prize kind of built along the XPRIZE concept. One of the six winners was hydrogen. We’ve been working on hydrogen for roughly seven years. A very fascinating kind of idea about hydrogen is that it’s a great storage medium. 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 with this with Plant Ratcliffe. We think there are applications going forward, and we are hard at work with 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 say 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.

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

So, I have a question about the contingency. So, 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 the construction cycle for Unit 3. I think, what is somewhat surprising is that you have rescaled with the contingency and that by writing down this additional process, I assume that you will not be seeking recovery of the additional funding, even though it seems like it’s driven by COVID, which is not something that you could have control. And then, secondly, we’re getting seemingly very close, as I said, to the end of construction, at least for Unit 3. Some of those assertions that you’ve been making about the project progressing faster than what the staff believes—are we about to be validated? So, how can you make us more comfortable that one, there’s no additional, basically realignment of the construction plan for Unit 3 coming within the next three months? And then, well, that is probably the main issue: is one, why did you increase the contingency and wrote it down, and two, how comfortable should we feel about this new schedule, given that we have still little time left until the end of the year?

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

Okay. And the second part, which is if you will be able to look to by the end of this year, or even early next year? I mean, how soon in the sense will you know if that is achievable come the EI where we know?

Yes, good question. If I got you to page seven or the chart seven, whatever it is, Vogtle unit three direct, construction and major milestones, we suggested that we could start cold hydro, kind of in the September, October time frame. I think that is what that blue is meant to do. We think there is probably a month difference between the start of cold hydro and the start of hot functional testing. I mentioned cold hydro tests about -.

I'm sorry, you complete that cold hydro in a month.

Oh gosh. We can complete it in 10-days.

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 the staff has said was typically for other nuclear plants, both in this country and other countries, it is roughly six months from the end of hot functional testing until fuel load and then another six months to commercial operation. So they are sort of looking at the body of nuclear plants that have come before Vogtle 3 and 4. What gives you confidence, I guess, in your planning process that you think you can do that more quickly?

Yes. I mean, the simple volley on that logic sale is that they are using data that is more than 30 years old, you know, that is 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, our numbers, and we have our own opinion. But the other thing that I should have mentioned before, but I will say now, Westinghouse is consistent between the work in China and the work here in the United States at Vogtle. We get the benefit of their experience. Remember, we’ve always had people in China looking at all that experience; we have had our own people there. So, I think that is an obvious, in my opinion, and I hope they don't make anybody mad, but I just think there is a logic law that is you are 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 would like to clarify maybe one thing, because that may be helpful to other folks on the call, a Slide 7. This is an important slide for us. So let me help you maybe decipher it a little bit. The blue circle represents the aggressive site work plan 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 needs to start those activities to maintain the November schedule.

And even the orange could be moved. You could start hot functional test later than what we show here and still hit November. If you chose to do November, you can actually start hot functional test much later than what we indicate here and still hit November.

I guess my first question is, how many remaining ITACs are there on unit three?

261. Those are open; that is out of 399. So, we have completed 138, just to save you from the math. Paul, one another thing on the 261, a lot of those are what we call UIN. That means we have essentially had these ITACs approved, except for the results of the test.

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

Yes.

Okay. And then do you have construction work hours scheduled after the revised sort 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. If you have construction work hours after 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.

In the coding phase.

Okay. And then I guess this cold hydro testing needs to be completed before hot functional testing begins, or can you see doing both at this?

Yes.

It does have to be complete?

Yes, sir.

Okay, because if I go to your slide seven then -.

So let's say we start kind of early September around cold hydro. I think that is what that blue is meant to do. We think there is probably a month difference between the start of cold hydro and the start of hot functional testing, I mentioned cold hydro test about -.

I'm sorry, you complete that 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 the staff has said was typically for other nuclear plants, both in this country and other countries, it is roughly six months from the end of hot functional testing until fuel load and then another six months to commercial operation. So they are sort of looking at the body of nuclear plants that have come before Vogtle 3 and 4. What gives you confidence, I guess, in your planning process that you think you can do that more quickly?

Yes. I mean, the simple volley on that logic sale is that they are using data that is more than 30 years old, the world is different now, and we have a much better marker for experience in China than we do those projects.

Paul, I would like to clarify maybe one thing, because that may be helpful to other folks on the call, a Slide 7. This is an important slide for us. So let me help you maybe decipher it a little bit. The blue circle represents the aggressive site work plan 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 needs to start those activities to maintain the November schedule.

And even the orange could be moved. You could start hot functional test later than what we show here and still hit November. If you chose to do November, you can actually start hot functional test much later than what we indicate here and still hit November.

Good afternoon, Tom. I just want to echo, I'm glad to hear that you and your wife are feeling better. My first question is, if I understand your answer Sofia'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 are a few months into the pandemic and modified utility operations, what is your latest thinking on how much cost-saving initiatives might be sustainable as opposed to one-time?

Well, listen, you are hitting a very interesting question. Whatever, how much of the O&M saving through Drew and were arguing about this the other day is deferrals and those are going to show up later 15%. So, 85% are captured and permanent is what we believe. Only 15% is temporal. That may be made up with what happened at the summer. In other words, we get a long period of warm weather or less than expected COVID impacts or not, then we will turn that money on this year, it probably would be more vegetation management related and it would say deferral of outages because through explained it beautifully. If the plants not running, you take an outage based on essentially the time on turbines and things like that. If they're not running, you defer the outage. Was that helpful?

Yes. I think you said exceedingly well. We have talked about this in years past, 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 after next year. If we have the ability through better-than-expected weather, etc., we will do here. So, we can move with loads, that is kind of interesting about what Drew said earlier about where we are in our revenue expectation for this COVID, where we set it up this year. I just going to guess right now we are mid-point or below, certainly not trending adversely.

Lastly, switching to midstream, not a huge focus of yours obviously, but in light of dominions asset sale and ACTB and cancels a few questions. Would you consider selling your assets or would you describe your appetite for new midstream projects? And lastly, would you consider taking capacity on MVP to diversify your supply sources?

Yes, so let's dial the clock back to when we were just getting buffeted by all sorts of offers. Whether there was something like five different big deals that we were looking at, and then one came in at the end. We have never been committed in a kind of deep way to pipeline growth. We bought 50% of the Southern Natural Gas system, owned by Kinder Morgan at the time. 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 SONAP Southern Natural Gas Pipe. Because we bought that at a good price, it was really important to Kinder Morgan for us to say a customer. We viewed this as an annuity. It is 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 have done a few things around the edges, but nothing material. Our appetite going forward -- look, I just think that is an extraordinarily difficult business right now and I’m sorry for my friends, Tom Farrell, and Lynn Good on ACP. I know they work very hard to make that a reality. It was just the right thing for us not to be part of that.

I would say the character of our midstream businesses is also very different. You touched on it with SONAP. But if we have never really been involved in gathering and processing. We have very modest storage representation, although we own a fair amount of storage within our LDPs. The transportation leg that is the dominant piece of our investment is a primary supply source for our Southeast utilities. That has a character that looks a little bit more like transmission and transportation than midstream.

What is the future of gas pipeline? Look, I said when we did the AGL deal that I thought gas was a bridge to 2050. I kind of blanked in that now to say boy beyond 2050. But to hit net zero, what we are going to have to do -- that is 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 are doing that. There is 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 are doing all sorts of other money where our mouth is activities to deal with carbon. That is why we are confident. As we think about the portfolio going forward, we are investing in optionality to keep gas part of the solution, but we will have to deal with the carbon atoms.

Okay, great. And MVP appetite?

I'm sorry, what was that?

Mountain Valley Pipeline?

I don't think so. That is something – you would have to hear from our utilities directly from -.

It is not a front burner issue though.

So, 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 the construction cycle for Unit 3.

Thanks, everybody. These are unique times, aren't they? I think we are going to look back at 2020 and maybe the way we look back at 1968 or some other big years in history in the United States. When I think about the work being done at Vogtle 3 and 4 and the adjustments those people have made to continue to progress the Vogtle 3 and 4 site, it is nothing short of heroic. They deserve our gratitude. 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 in the first unit of this historic project to completion next year. Thank you all for following us. We appreciate your time today.

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