Southern Co (SOMN) 2020 Q3 法說會逐字稿

Good afternoon. My name is Emma, and I will be your conference operator today. At this time, I would like to welcome everyone to the Southern Company Third Quarter 2020 Earnings Call. (Operator Instructions) After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded, Thursday, October 29, 2020.

I would now like to turn the call over to Scott Gammill, Investor Relations Director. Please go ahead, sir.

Thank you, Emma. Good afternoon, and welcome to Southern Company's Third 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 provide 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 Fanning.

Thanks, Scott. 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 third quarter ahead of the estimate provided on our last conference call. COVID-19-related demand impacts have moderated from the levels we experienced earlier this year, and given results through September, we expect adjusted full year earnings per share to be at the top end of our guidance range.

Throughout 2020, our customers and communities have been faced with historic challenges and our businesses have continued to demonstrate resilience in serving and supporting them. While COVID-19 has resulted in many employees working from home, nearly half of our employees, staff, essential facilities and perform essential functions, which means they have been in the field. And in the case of our gas employees in homes and in businesses, working daily to ensure the delivery of clean, safe, reliable and affordable energy to our customers. Safety and health protocols have never been more important to protect both our employees and our customers.

Despite extraordinary circumstances in 2020 as a result of the COVID-19 pandemic, and an exceedingly busy storm season, our business model has demonstrated substantial resilience as we've delivered outstanding service to customers, provided excellent operational reliability and achieved strong year-to-date financial performance. As we reach completion of Vogtle Unit 3 and continued significant progress on Unit 4, we will set the foundation for an expected increase of our long-term earnings per share growth rate and improvement of our cash flow in a dramatically improving dividend payout ratio.

Let's turn now to an update on Plant Vogtle Units 3 and 4. We continue to focus on meeting the November 2021 and November 2022 regulatory approved in-service dates, and recently updated our work plan for the timing of Unit 3's remaining major milestones. Based on our current work plan, we now expect that the in-service date for Unit 3 to be during the third quarter of 2021, ahead of its November 2021 regulatory-approved in-service date. Now we continue to utilize an aggressive site work plan for Unit 4 as a tool to provide margin to its regulatory approved in-service date of November 2022, with a current targeted in-service date of June 2022. From a cost perspective, Georgia Power's share of the total project capital cost forecast is unchanged at $8.5 billion.

With Unit 3 direct construction approximately 94% complete, our expectations around the scheduled ranges for reaching major milestones continues to narrow. For about 3 years, and as we have discussed on prior earnings calls, we have used an aggressive on-site work plan to drive productivity and as a tool to provide margin to the November regulatory-approved in-service date for Unit 3. Now this strategy has served us well in motivating the workforce, advancing construction progress, providing for early testing of systems and components, and facilitating earlier identification and mitigation of risks. Indeed, this tool has created margin to the November regulatory-approved in-service date.

Considering the current pace of construction and milestones reached to date as well as assumptions for future productivity, we are shifting away from the use of an aggressive site work plan for Unit 3 to a work plan that reflects our current expectations. Under this updated work plan, we anticipate our next major milestone, hot functional testing, to start in January 2021, followed by fuel load in April of 2021. That work plan projects in-service as early as the third quarter of 2021, which provides approximately 2 to 3 months of margin to the November regulatory-approved in-service date. It is important to remember that for Unit 3, we expect hot functional testing could start as late as the end of March of 2021, and fuel load could occur as late as midyear of 2021 and still support the November regulatory-approved in-service date.

In mid-October, we successfully completed cold hydro testing for Unit 3, which was a major milestone for the project. Since our last call, we also completed civil construction on Unit 3 shield building, started to successfully operate the Unit 3 reactor coolant pumps for the first time and placed the Unit 3 turbine on its turning gear. As the site prepares for its next major milestone, hot functional testing, critical areas of focus remain the timing of system turnovers and electrical and subcontractor performance. While the site has experienced and managed through 2 waves of COVID-19, we expect the pandemic will present continued challenges as we work towards completion.

Now as we approach hot functional testing, system turnover and testing activities for Unit 3 continue to increase. And in the coming months, we expect ITAAC submittal and review to accelerate. Southern Nuclear and the NRC staff have been working together for years on a plan that provides Southern Nuclear the ability to submit the necessary documentation, and allows the NRC ample time to conduct a review of that documentation prior to Unit 3 fuel load. All of the UINs, or the uncompleted ITAAC notifications, have been submitted and accepted by the NRC for both Units 3 and 4. And nearly 40% of the 399 ITAAC closure notifications, we call these ICNs, have been verified as complete by the NRC for Unit 3. At this point, ITAAC progress is consistent with our expectations and milestone achievements.

Leading up to hot functional testing, We plan to submit over 100 ITAACs for review and verification to the NRC, followed by approximately 100 more during hot functional testing and approximately 50 more as we approach to fuel load. We expect that all Unit 3 ITAAC and ICNs will be submitted and reviewed in a timely fashion to support Unit 3 fuel load.

The Vogtle 3 and 4 operations team continues in preparation for initial fuel receipt later this year, and an increase in preoperational testing. The team successfully completed the pre-start-up safety review by the World Association of Nuclear Operators, highlighting the safely -- the strong safety culture we have developed to position the project for successful start-up in operation. We also completed the NRC-evaluated emergency preparedness exercise, and received 62 reactor and senior reactor operator licenses, the first operator licenses for Units 3 and 4. This number represents full staffing for both units. These accomplishments set the stage for the site to achieve approval for Unit 3 fuel load.

Now let's turn to cost. Based on our most recent assessment, there is no change in the total project capital cost forecast. In the third quarter of 2020, Georgia Power allocated approximately $5 million of the construction contingency to the base capital forecast, reflecting cost risks associated with construction productivity and field support. Now recall, the estimated cost of the time between the site work plan and the regulatory-approved November in-service dates or a scheduled cost margin is embedded in Georgia Power's base capital forecast. Following the update to Unit 3 and Unit 4 site work plans, approximately $90 million of this scheduled cost margin was utilized. The remaining scheduled cost margin and cost contingency combined represent approximately 18% of the remaining estimated cost to complete. As we have said, we expect to utilize all contingency funds as we progress towards completion of the project.

Through the remainder of this year and into the first quarter of 2021, the Vogtle team will continue to focus on the final phases of Unit 3 construction, system turnover and testing activities, ITAAC submittal and our transmission -- our transition into plant operations ahead of Unit 3's regulatory-approved in-service date. At the same time, a ramp-up in construction production is underway for Unit 4 related to its major milestones in 2021. While there is still uncertainty, our current expectation is that we will reach completion for Unit 3 ahead of the November 2021 regulatory-approved 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 you all are well. As Tom mentioned, we had a very strong quarter. Third quarter adjusted EPS was $1.22 per share. While $0.12 lower than last year, it is $0.07 above our estimate for the quarter. One of the drivers of this variance was significantly warmer-than-normal weather in the third quarter of 2019. The weather impact relative to normal for the third quarter of 2020 was a positive $0.04, last year was a positive $0.14, hence the variance. In addition, we had a modest decline in third quarter 2020 sales due to COVID-19, resulting in a $0.09 negative impact, which we mitigated through diligent cost control and constructive state regulatory actions at our utilities. A detailed reconciliation of our reported adjusted results is included in today's release and the earnings package.

Year-over-year, through September, the dynamics are very similar. For the first 9 months of the year, adjusted EPS was $2.78 per share, which is $0.06 lower than last year. This year's milder temperatures through September resulted in a $0.21 variance in EPS when compared to 2019. COVID-19 impacts year-to-date have reduced income by $0.20 and weather impacts compared to normal add an additional $0.08. Despite these headwinds, we have substantially mitigated both weather and COVID-19 impacts throughout 2020, allowing us to exceed our estimates on an adjusted basis in each of the first 3 quarters. With these solid results through September, we expect full year adjusted earnings per share to be at the top end of our guidance range of $3.10 to $3.22 per share.

We continue to assess the financial impacts of COVID-19 on our business. For the third quarter, the weather-normal impact of COVID-19 reduced sales by 3% in the aggregate and slightly better than our baseline expectation. As you would expect, we were still seeing a slight uplift from the residential sector due to people working from home. The trend for both commercial and industrial customer classes is markedly better relative to the troughs last spring. However, the time line to full recovery for both sectors remains uncertain. Factoring in impacts across all customer classes year-to-date, our nonfuel revenues came in slightly above our forecast. Our retail sales projection for the full year is unchanged, with the expected overall decline in the range of 2% to 5% on a weather-normal basis. Based on results to date, we expect total COVID-19 impacts to be approximately $300 million for the full year.

In addition to sales, we are continuing to monitor customer arrears and the potential for an increase in bad debt expense. We have worked closely with customers across our regulated utilities, offering special payment plans for those with past due account balances. Customer arrears have actually trended better than anticipated across our operating companies, and our liquidity position remains robust.

Constructive mechanisms have also been put in place by the commissions in many of our states, allowing us to address COVID-19 related costs and bad debt expense in future regulatory proceedings. Additionally, through the first 3 quarters of 2020, we are on target to meet our annual capital deployment plans.

Turning to a brief capital markets update. During the third quarter, Southern Company and several subsidiaries raised an aggregate of $3.4 billion, locking in record low coupon rates, increasing our liquidity positions and allowing us to redeem $1 billion of higher rate notes at the parent. Importantly, recall we still forecast no equity need until at least 2024. From a ratings perspective, during the third quarter, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa1. Fitch also upgraded Mississippi Power's senior unsecured rating to A-. Lastly, Fitch moved its outlook to stable for all issuers, except Georgia Power. These positive changes demonstrate the continued commitment of Southern Company and our operating companies to financial integrity and strong credit ratings, both of which provide significant benefit to customers and investors.

Before I turn it back to Tom, I'd like to highlight our energy mix trends so far for this year. Through September, nearly 1/3 of our energy supply was from 0 carbon resources and coal represented just 16%. We continue to project that for the full year, generation from coal could be below 20% for the first time in modern history. Last month, we published a supplemental carbon report called Implementation and Action toward Net Zero, in which we outlined our approach to achieving our goal of net zero by 2050. We've made significant progress towards this goal, and currently project that we will achieve our 2030 interim goal of a 50% reduction in greenhouse gas emissions as early as 2025. At a high level, we expect our path to net zero to be comprised of several key elements, including continued coal transition, utilization of natural gas to enable this transition, further growth in our portfolio of 0 carbon resources, negative carbon solutions, enhanced energy efficiency initiatives and continued focus on R&D for clean energy technologies. We do look forward to discussing these endeavors with you as we continue to decarbonize our fleets in the years ahead.

With that, Tom, I'll turn it back to you.

Thanks, Drew. Adding to your comments and reinforcing the notion that Southern is the industry leader in research and development, the United States Department of Energy's Office of Fossil Energy and the National Energy Technology Laboratory recently renewed an agreement with Southern Company to operate the National Carbon Capture Center located in Wilsonville, Alabama. Through this $140 million agreement, Southern Company will continue to manage and operate the research center for an additional 5 years. Over the past decade, the National Carbon Capture Center has successfully advanced a wide range of technologies toward commercial scale while improving performance and reducing cost. Southern Company is also partnering with EPRI and Gas Technology Institute, to sponsor the low-carbon resources initiative to accelerate the development and demonstration of low-carbon energy technologies. And we recently received the Edison Award, our industry's highest honor from the Edison Electric Institute for Southern's work involving energy storage research and development. Through the Energy Storage Research Center, an industry-wide hub for battery energy storage technology testing, evaluation and large-scale demonstration in Birmingham, Alabama, Southern Company is providing leadership and technical expertise to advance energy storage. Delivering a decarbonized future will require an influx of advanced technologies, so it's essential that we leverage collaboration to find and advance those next-generation and transformational solutions. Despite unprecedented circumstances in 2020, our company and employees continue to demonstrate exemplary operational performance, which has translated into solid financial performance for the year-to-date. As we move ahead, key priorities remain operating our utilities at best-in-class service 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 that 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.

In closing, earlier today, Georgia Power announced that Paul Bowers plans to retire concurrent with the Unit 3 fuel load expected in April 2021, after a remarkable 42-year career with Southern Company. For more than a decade, he has led Georgia Power to be the premier energy company it is today. From industry-leading storm response and customer satisfaction, to the growth of a diverse energy portfolio and a deep commitment to the communities we serve, he has positioned the company for continued success. He's led the company through the construction of Vogtle 3 and 4, and will be here as we continue progress at the site and begin loading fuel in Unit 3. The impact he's had on our company, its employees, our customers and our communities in the state of Georgia is immeasurable.

At Southern Company, we have strong leadership across our system and operating companies, fostered by our commitment to cross-functional training and development. This is how we continue our long-standing tradition of effective succession planning, ensuring we always have strong leaders ready to continue serving our customers. I am very pleased that Chris Womack, our Executive Vice President and President of External Affairs, will succeed Paul. Chris will serve as President of Georgia Power effective November 1, 2020, and assume his additional responsibilities as Chairman and CEO upon Paul's retirement. Now we knew it would take a remarkable leader to follow after Paul, and we are confident Chris is that leader. With extensive experience leading at the national level, Chris has remained very active and well known in Georgia and across the South. He also previously served as Chief Production Officer, and Head of External Affairs for Georgia Power. His depth of experience in the energy industry, government and regulatory affairs and the state will be incredibly valuable as Georgia Power works to continue providing clean, safe, reliable and affordable energy for millions of Georgians. More importantly, Chris leads with a passion for people. The company, its employees and its customers and its communities are in awfully good hands.

One final note. We have thousands of people today working to restore power from Hurricane Zeta that came across New Orleans, but then hit the bulk of its fury in Mississippi, Alabama and even here at Georgia, where we experienced wind gust in excess of 60 miles an hour. My report as of this call was that at our max, we had around 1.2 million customers out. And as of 1:00, we're now about down to 1 million customers. So we've already made some progress. In the days ahead, I know that we will continue our excellent track record of restoring service quickly, and not only providing electricity, but hope to the communities we serve. So thanks to those people for their efforts, and I know they'll work safely.

So thank you for joining us this afternoon. Operator, we're now ready to take questions.

(Operator Instructions) Our first question comes from the line of Julien Dumoulin-Smith with Bank of America.

This is actually [Richie] here for Julien. I was just curious if you can provide a little bit color. Comparing the time line for the hot functional testing from start to finish with what you've allocated, it looks like roughly 60 days compared to the peer China plant, where it seems like 77 days has been cited in the news. And I know it might be a direct comparison given labor and other political items, but just curious if you can provide a little context on the differences there.

Yes. Well, honestly, the 77 days, I think, appeared in a magazine article. We've researched it. We can't figure out where that number came from. In fact, in came out of a magazine. We -- I'll just say this. You know we've had people at the plant site, Sandman and Haiyang, as they went through these procedures. We had our own people there. We have people from Westinghouse there. And in fact, the people from Westinghouse that went through start-up and hot functional tests and all of that are now with us at Plant Vogtle 3 and 4. The people from Westinghouse endorse our plan to complete this test as we have laid it out. So I don't know where that number comes from. We essentially plan for, from the beginning of hot functional tests, to kind of fuel load about 100 days. That's comprised of 45 days of starting the test and running the test, and then 55 days from assessing kind of where we are at the end of hot functional test to fuel load. That will include things like filing the last ITAAC. And as we mentioned, I know there's been some conversation about the pace of ITAACs. Recall, you don't file ITAACs every month just because of the passage of time. We file ITAACs associated with the turnover of systems associated with the accomplishment of milestones. And so as we laid it out, there's about 100 ITAAC, round numbers, that, before we start hot functional test that we will file, during the tests, another 100. Following the test, the 4Q load, yet another 50. So that's very clear, I think. The other thing that, I don't know, but I'm just guessing here, may confuse how you start and begin or the duration of a test, we are very disciplined with what we're calling the start of hot functional test. And that will involve the pressurization of the reactor area. There's a lot of activities that I guess conceivably, you could say are pre-start activity, you could say, begin hot functional tests. And maybe that's where they came up with 77. So let me just finish it with the folks that were there in China are on site here, and they have been constructive and endorsed our plan as we put it forward.

Got it. That's very helpful. Appreciate the clarifying remarks there. And then just maybe turning over to Unit 4. I know you guys have indicated here that targeting June 2020, but in VCM 23, it looks like it's just slightly slipping behind the November schedule in terms of percentage of fleet per month. Just curious if you can provide a little bit of color there on getting back on track, especially considering the remaining milestones needed to complete with Unit 3 here.

Yes. Thanks, Richie. And in fact, it's really not off track, it's by plan. If you recall, when we went back to the onset of the COVID virus at the site, recall we went through essentially a lessening of density at the site and reducing personnel from, say, 9,000 to 7,000. That also required us to resequence work, which we disclosed along the way here. One of the ideas that we put into place was to borrow -- as we brought the numbers down, was borrow some personnel from Unit 4 and put them on Unit 3 so we could maintain the progress of Unit 3. We intentionally brought down the productivity of Unit 4 for a period of time. Now in order to achieve November by -- no, in order to achieve the aggressive schedule for Unit 4, we need about 1.4% per year -- per month in order to hit June. What we have done is, in October, achieved 1.4% on Unit 4. We're going to add more people as we finish 3 that will move over to the other unit and drive that number up. So yes, it would appear that for the months of, say, July, August, September, that it looks like we really went down on Unit 4. We did, that was part of the plan, and now we're ramping back up. And I think our productivity in October is evidence of that.

It's sort of an odd concept and you probably shouldn't use the idea of reduced complexity when you're referring to a nuclear site. But I think it is completely fair to say that, as we move through Unit 3 construction and move the principal focus to Unit 4, that we'll absolutely see improvements in productivity over time. It's just a natural course of construction.

And just recall, too, that as we went through Unit 3, we had lots of learnings. And so one of the things that we've been able to do on Unit 4 is apply those learnings. Resequencing work. I remember initial energization we did early on 3, we're going to push that on 4 and improve productivity there, because there was frankly a lot of turn on and turn off of equipment involved in that.

Richie, as we move into -- or move through hot functional testing, we'll start to provide you probably in the first quarter of next year, good sets of schedules per unit work completion and construction completion.

And I really like on the material we gave you today. I guess it's Page 6. It's just a great visual of where we are on Unit 3. It shows the aggressive time frame. It shows the November time frame, and there it shows our actual -- well, sure enough, if you look at where we're projecting our expectation to be. And our expectation actually has an additional 30 days that we already had 30 days of contingent -- scheduled contingency in there. We actually added another month in order to hit the end of the third quarter. I think we'll provide that kind of information, as Drew is suggesting, for Unit 4 now.

Got it. That's very helpful. And then just one more, if I can slip it in. I guess, in terms of the operational data points for Unit 3 in between now and hot functional testing, I know there's some subcontractor work left to be done, but anything that we should be focusing on here in the next couple of months?

Yes. I think there's kind of 3 things that I'm very mindful of right now. In terms of actual construction, I feel pretty good about that. I really think that our big focus, and we have a SWAT team assigned to this, involves kind of the nomenclature of the paper, that is making sure that the as-built condition of the systems that we will turn over actually are reflected in the engineering plans. So if you want to just broadly call that, make sure the paper works, that the as-builts conform to the engineering and that, that goes into the ITAAC as we submit them. Don't underscore that. I mean that's a big deal. Don't underestimate that. Second, we have said consistently really through the past 6 months or whatever, electrical productivity at the site continues to be a pacing factor. We think we have a reasonable schedule to do that. And then thirdly is subcontractor performance. And I feel confident we'll get there, but it's one of the 3 areas we have a particular focus on now. And what do we mean by that? It's like insulation, like the elevators need to be insulated before we can go through hot functional test. So it's things like that. It's the seals on perforations through walls to make sure that they're tied up. It's a whole lot of knits that are involved in making sure we can get to hot functional test effectively. Those are the 3 things. Like -- I'll just say it again: the paper, electrical, and subcontractor performance.

Our next question comes from the line of Shar Pourreza with Guggenheim Partners.

Just a couple of quick questions here. So the cost contingency in this scheduled cost margin came down to 18% from 20% when it was replenished on the second quarter call. So $91 million in scheduled cost margin was used during the quarter as you sort of highlighted, Tom, in your prepared remarks. How should we sort of think about the shape of the remaining contingency going forward for the remaining months? Should we think about it more front-end loaded or vice versa, as we kind of look to monitor the amounts you'll be utilizing? So just maybe for us trying to assess if you're kind of on track or not over the next several months as we're trying to monitor the contingencies.

Yes. I mean, look, I think we'll get there in terms of everything we know about costs right now. We think we'll use the contingency, and we see no reason to increase it right now. One of the things that gives us a lot of comfort, if you recall the -- go back to the call where we increased the estimated cost to complete, we actually funded through contingency a lot of risks, both for Unit 3 and for Unit 4. So the landscape, if you will, a variability with respect to cost has really been reduced. Now is there a chance that we could need more eventually? Sure. We don't know. We're continuing to monitor COVID. The estimates that we have given you so far, and moreover, the estimated time of completion that we now have guided you to, does take into account our experience on COVID. Could COVID get a lot worse? Conceivably. But with the pace of COVID impact, that's the kind of estimate we've produced going forward.

Shar, you asked a little bit about time. And so one of the ways that I've been thinking about it is if you look at fuel load to COD, our budgets -- our schedules are sort of 145 days -- 144 days. And we plan for something that's probably more like 110. If you compare those to the Chinese averages, I think they were 138, the best was 112. I think our planning assumptions around fuel load to COD are very, very consistent with global experience, maybe put it in that term. And so the answer to your question maybe is likely in the very near term that we'll understand where we fall between the site schedule and the regulatory and service date for Unit 3.

Yes. And there is the cost of kind of schedule breakeven, right? We kind of watch that. I don't know. It's somewhere in October, November. It's somewhere in there. We have funded that. So we'll keep our eye on that as well. If we ever slip past the third quarter, substantially, I guess, that could have an impact on cost.

Got it. Perfect. And maybe just shifting from Vogtle for a second and just looking at the backdrop. Obviously, you narrowed your forecasted load impact and the impact on revenues for the year. Just maybe how are you sort of thinking about the recovery into '21 across the territories? I mean, we've seen -- and the reason why I ask is we've seen in this space of several players that essentially have assumptions that are a lot more conservative, i.e., assuming a gradual recovery versus a V-shaped recovery. But the reality is, is the recovery is a lot faster than what's embedded in plan and any sort of economics for the forecasting there. So what are you -- I guess, Tom, what are you seeing as we head into '21 around that?

Yes. So look, I guess when COVID hit, we gave the estimate of 2.5% to 5% load reductions. I'm guessing now -- revenue reduction. I'm guessing now we're going to come in around 3%, $250 million to $400 million. We're projecting now around $300 million. So I think the estimates that we are using assume about a midyear recovery. And we are expecting, since we're down for the year, probably what, Drew? 3%?

Yes.

On revenue that we're going to recover back about 3%. Now that puts us flat to '19. But I would assume, and if you watch all the stuff on Squawk and all that this morning, that's kind of following what people believe about GDP. So that's kind of my expectation. Drew?

Yes. The only nuance I'd say is we probably came out of the recovery a little bit -- came out of the pandemic from its depths a little bit faster than we anticipated, but the duration may be a bit longer. So you integrate that and you get to sort of 3% for the year. If we see a continuation of that through 2021, I think both the mechanisms that we've put in place with regard to cost control have been very effective and will serve us very well into next year. We're likely not to see a cost base for the businesses that's materially different than 2019. And so I think we've got a lot of pathways should the pandemic prove to be depressive to revenue. The other important thing to note, though, and I think it's in one of our slides, probably Page 11, is that the mix of impact has been very different -- a little bit different than what we anticipated. Residential is quite strong. Commercial was much less than what we had anticipated, although still negative. And industrial has been a little bit deeper than we thought. But as Tom talked about this morning, on Squawk Box, 8 of the 10 measurements that we're taking within the industrial sector are showing generally positive signs, sort of expansive signs through the third quarter.

Yes. And so let me just repeat that. And year-over-year, we're all down, all these segments. But as I said this morning, the first derivative, the momentum statistic would show 8 of 10 improving, second quarter, third quarter. Hey, and that gives me the opportunity to correct something. I don't know, on live TV, every now and then you have a brain cramp. Becky asked me which one was down and which one was flat. And for some reason, I said Chemicals was flat. Chemicals was down. Heck, I knew that. Chemicals was down. That was the only segment down. Petroleum was flat. So I just misspoke on the call and said that chemicals was flat. Chemicals was the only one down. The rest of the answer was okay.

Got it. And then just one last one for me, if I may. Just shift to Illinois and just thinking about Nicor. Obviously, the policy down there is a bit of a disaster. It's a mess. And it's more of an electric issue versus a gas issue. But I know, obviously, under Pritzker's agenda, he did highlight a repeal of sort of the quip that you guys have been utilizing. Just love to get your thoughts here. Would this mean you find yourself in more frequent rate cases? Are you guys seeing any sort of traction with this part of his agenda?

Yes. So certainly supportive of anything that the governor makes as a priority within Illinois. What I would say about it is that our quip is a little bit different than what they have and what they experience on the electric side, in that the way the mechanism works, you have to move in rate case something out of the rider into primary rate base. And so we actually do that with quite a bit of frequency so that we can absorb the continued construction under what we call QIP. And so even if there were a change at the state level, I don't know that it would necessarily change our behavior materially in the way that, one, we construct; and two, that we seek recovery from customers.

Congrats.

And our next question comes from the line of Michael Weinstein with Credit Suisse.

When do you think you'll be ready to quantify that higher expected earnings growth rate that you mentioned after Vogtle's in service? And what would be the first priorities? Yes. What will be the first priority for use of cash flow to achieve higher growth rates?

Listen, I think a lot of this is baked in. Let's just kind of -- we're going to give you great detail, as we historically do, in our end of year earnings call, which, I guess, Drew, was in February.

Yes.

But it's stuff that we've covered in the past, and therefore, I thought it was okay to foreshadow it. As you start -- you guys know that there's essentially a penalty rate in which a lot of the Vogtle investment is earning right now. And we've still been able to stay within our 4% to 6% growth rate even with Vogtle under a penalty rate. The worst year for that penalty rate, frankly, is 2021. As we emerge from clearing Vogtle into service, and that's why we thought it was worth talking about now that we're estimating, we are expecting Vogtle to clear into in-service in the third quarter of 2021. From 2021 on, we start to have large increases in earnings per share. And in fact, the numbers roughly are, as we move from a debt rate roughly, the penalty rate associated with Vogtle into a full mix of capital, the net income effect is over $200 million. Now let's think about that. I don't care whether you use 2018 as your baseline or 2021 as your baseline, our earnings per share growth rate goes way up. Our capital, our cash flow goes up significantly. And as you would expect, our dividend payout ratio goes way down. And so people after me will have the decision as to what dividend policy they want to carry on from there. But we've said this on earlier calls, we'll give you great detail in February about all this.

Great. And thinking ahead, after the postelection environment, I mean, are you seeing any new willingness on the part of environmentalists to accept nuclear as part of an integral solution to their global warming problem? And are you still willing to consider additional new nuclear construction after this is -- considering all the hard-earned valuable experience you guys have gained over the years?

Michael, I want to finish up on the CapEx comment to on the last conversation we just had. But yes, absolutely. I would say one of the great thought leaders in America, a guy that was approved 98 to 0 by the Senate as Secretary of Energy was Ernie Moniz, he's on our Board. He's published extensively. I think he has credibility on both sides of the aisle. It's very clear that nuclear needs to be a part of this nation's energy profile going forward. And I think we suggested on prior calls that, as a matter of national security for the United States to maintain a profile of consistent nuclear development, I think it's important to us all. And so -- and maybe you just saw recently, United States signed a pact with Poland to think about new nuclear development. We know that there is new nuclear development considered under the kingdom of Saudi Arabia and UAE. So my sense is the United States will continue. Now when we think about our projections, and we have some pretty clear plans about how to transition the fleet, our next nuclear unit is probably in the '30s to '40s would be my guess. So back up, how many years? 8 years before you start those to get them in service. So somewhere in that time frame would be my sense, okay? The other thing that's important on new nuclear is some of the things that we are spending a lot of money on, a lot of brain power, but working with DOE, Bill Gates, he and I are on the Energy Innovation Forum or whatever it is, American Energy Innovation Council. This idea of kind of the next generation of nuclear, that is the nuclear fuel may have the physical characteristic of not being able to meltdown, and therefore, you don't need all the containment structures and therefore, you drive down capital costs and operating cost. I think there's lots of ideas, SMRs. Look, I -- this nation has to stay invested in nuclear in the next 5 years, 10 years, I don't know whether Southern will be or not, thank goodness for the benefit of the United States, we've stayed involved. But I think we're going to have to stay there eventually.

Hey, one last thing I just want to say on the future CapEx and the future financial plan. As I finished talking, I kind of had a hint of what do you have to do? And my answer was we have to finish Vogtle. If you look at our CapEx provided in the slide, it doesn't really have big placeholders for new stuff. What you see in there is T&D CapEx and some relatively modest generation CapEx. What we're showing you, in my view, is a pretty conservative modest case. There's plenty of room to do more, to execute on $500 million a year placeholders at Southern Power, for example, is in renewables. We don't have that. So when we show this forecast, it is a conservative forecast in terms of what we must do to achieve. I want to make sure you understand that.

Yes. I mean, that was kind of what I was asking. So just curious about what other kinds of projects you might be thinking about. I'll leave it at that, and then I'll see to further questions, okay?

I think the answer to that question though is relatively straightforward. If you look at the content of our constructions over the next 5 years, something like $38 billion to $40 billion, or $8 billion or $9 billion per annum, most of that construction is being done in the transmission distribution segment, which is, I think, a highly important component of our mix, and a very durable asset base. And then over the next 10 years, we'll do a very large content of environmental remediation. And so as we move through those, the next generation of spend is likely to be modernization of the generating fleet. And so it's pretty easy to kind of suss out what the potential for CapEx is over a longer period of time.

Yes. I mean, at [1%].

Yes.

And I want to assure everybody on the call, when we come up with growth rates, we don't plug CapEx in order to solve to a growth rate. What we're showing you is a reasonably conservative posture with respect to investment. And so therefore, there's probably upside.

Our next question comes from the line of Angie Storozynski with Seaport Global.

So I have 2 questions. One is -- so Paul's 42 years at Georgia Power is almost unimaginable. But that change in the leadership is happening at the time when you really need support from the commission. You have elections, potential changes at the Georgia PSC. So how should we think about it, the ongoing support for the project, given the, again, elections and the management change at Georgia Power?

Oh, you bet. And thanks, and that's a natural question, so thank you for asking. Look, Paul turns 65 next year. He's had a terrific track record of performance, and he works around the clock. We fully bless Paul's desire to retire and spend time with his grandkids. He's got a home on the beach there in Pensacola, he's got a farm in Alabama. He is absolutely entitled to enjoy his time in retirement. When we think about the right time to do it, well, we could have waited until later in '21. But you know what? All of a sudden, in '22 now, we start filing the next triennial rate case. We start considering issues like prudence. And we thought it was a lot smarter to have somebody in the saddle well in advance of those issues, not as they are happening. The other thing that I know Paul and Chris both did a lot of media today, I think it expresses a tremendous amount of confidence by Paul and us all to make his retirement effective with fuel load on 3. I think that expresses a lot of confidence in our ability to execute from fuel load to in-service. And let me remind you, Chris Womack as President of External Affairs, he had a very broad palette of responsibility. Chris has been involved in all of the regulatory execution of filings and monitors and everything else. Paul served as the Chief Production Officer. He was in charge of generation and Georgia Power for part of his career. He was also in charge of external affairs at Georgia for part of his career. So what you're getting is arguably the top external officer we have in the system now in the CEO role at Georgia. He will do a terrific job.

Okay. My second question is, so you've always told us that there's going to be some -- a couple of weeks of additional work between the end of cold hydro testing and the beginning of hot functional testing. Now I was under the impression that we're talking maybe 3, 4 weeks. It's a little bit longer than that. Is there something that you guys identified during the cold hydro testing that's elongated that period in between those 2 steps?

Angie, no. Nothing at all. Cold hydro testing went fabulous. And in fact, it's kind of funny, we gotten to this argument -- not argument, discussion of 77 days versus whatever. We started doing pre-cold hydro test kind of well in advance of the final cold hydro test, such that when we finally did the cold hydro test, it took just a shade over 1 day to complete because we had done all this work in advance, okay? What we have done with the expected schedule is to give more time for some of this prework, so that when we get to hot functional test, it will go smoothly. Some of that prework involves the filing of ITAAC 100 kind of before. When I talked generally about paper, that is making sure the as-builts meet the engineering specs and therefore, provide us a very easy way to use the UIN process where they already have been approved to drop in the values and get things done on a very systematic way at the NRC, it gives us more time to deal with the paper. It gives us more time to finish with the electrical. Our pace of electrical is not dramatically different. There is a minor increase, but it is not dramatically different than our experience that we've been having so far. So what you see is the absence of an aggressive plan. It should lower the risk of getting to that date and then executing once we do get to that date.

Okay. And now completely changing topics, given that in the utility sector, it seems like we have some sort of a strategic update almost every day. I know you guys are busy with Vogtle. But would you have any comments about potential ongoing consolidation in the electric utilities industry, especially in the Southeast? Should we think about it that once Vogtle 3 is online, that's when you're ready to entertain any types of future growth through acquisitions?

Well, now that's a loaded question. And Angie, you've been with us for some time, so I'm going to give you the old response. It remains true. It is the fiduciary responsibility of all CEOs to seek out opportunities, buying and selling. Anything that will accrue to the shareholder value is something we should do, okay? And we have demonstrated that, I think, over the years. The simple examples for us would have been Southern Company Gas, formerly AGL Resources, was a great buy by us. And then when you think about the strategic sales that we've done since then, be it Elizabethtown, Florida City Gas, Gulf Power. If it made sense, we bought at attractive levels and sold at levels that were unprecedented from a multiple standpoint, both in the gas industry and the electric industry. And so we will continue to do that going forward. The big caveat that you rightfully point out is this, is that throughout probably the remainder of time to complete for Vogtle 3 and 4, it makes a lot more sense for us to be doubly focused on getting that done well and executing. After that, we'll have lots of opportunities to consider things. But I would argue, even after Vogtle, we will still maintain that discipline. Drew, do you want to say anything else?

I think you hit it.

Okay.

Our next question comes from the line of Sophie Karp with KeyBanc.

Congrats on a strong quarter. Well, a lot has been discussed already, but maybe if you could give us a little bit more kind of color on now that you've done with cold hydro and you're moving towards the hot functional testing, what are some of the factors that can kind of push the date in between January and March, as you outlined, excess range? So what are the factors that can push it sooner or later within that range that we should maybe follow or think about?

Yes. Sophie, if it was me, and I'm just giving you my judgment on this call right now. So I laid out 3 risk areas that it would be broadly the paper, and then it would be electrical productivity and then it would be subcontractor performance. I probably did those in order. In other words, maybe the biggest risk factor would be making sure that the as-built condition conformed with the engineering plan and making sure, therefore, that the process we've laid out on ITAAC will work well. Because theoretically, if there's no material difference between what we build and what the engineering plans call for, then you should just be able to drop the values. In other words, the whole UIN process provided for the NRC to already say that the test was fair, the process to get to the test was fair, and therefore, all they really need to do is assess the value of the test. That's why we're able to accomplish so much in a short amount of time. So I think it's really -- and I think the as-built condition is in conformity with the engineering, but you have to go out and prove it. You actually have to have what we call field nonmanual labor on the part of Bechtel and Southern to work with our testing ITAAC team to assure that we have conformance in the test. I think we all get high focused on turning the wrenches and connecting the electrical equipment. That is really important. And I can tell you, we have a whole room at Vogtle. We've been there, gosh, I guess, every week now here at the last bits of this construction effort, making sure that that's going to go well. I would really focus on that one right now. But Look, the others could, too. We could have a lack of productivity. We could have subcontractors that don't perform well. Those 3 areas, I would really focus on the paper right now.

Right. So it sounds like the cold hydro testing went well, like you pointed out. And so nothing that you've learned from that or gathered from that could be -- could potentially delay hot functional test, and it sounds like that's not the case?

No, Sophie. No. It went great. In fact, when we finally ran the test, part of cold hydro was to pressurize all this equipment. There's always a tolerance in a test. We went right through all the pressurization activities and only achieve something like 1/10 of the allowable variances. I mean, we killed it on that test. It went exceedingly well.

Terrific. Terrific. And one last one, just to clarify. The ITAAC's approval, should we expect them to sort of come in, in batches? Or kind of on a more straight-line time line towards the completion? Is that something that we should be tracking?

It does feel like batches. Yes, it is lumpy. And recall, I'm sure it's our fault, but there were some idea out there that we should see ratable monthly. That's not it. Everything is associated with a milestone. So there are systems that we have to finish in order to start hot functional testing. As we finish those systems, we will file ITAAC. Those are the first 100. There are systems that we will test successfully through hot functional, that's the next 100. And then recall, when we finish the test, essentially, you dismantle a lot of the equipment and check to see how it performed. You actually open the engine, if you will, and look to see how the pistons and the stock -- I mean, the sparkplugs and all that other stuff perform. And sure enough, we'll file the final ITAAC on that. So it will look lumpy to you.

Our next question comes from the line of Jeremy Tonet with JPMorgan.

I just want to think about kind of looking at the future a little bit. For the period after Vogtle's completion here, do you see any kind of incremental investment opportunities that kind of come out of your net zero carbon by 2050 goal that you recently announced here? And how should we think generally about renewable spending opportunities across the Southern footprint? And can you give us an update on the sentiment towards renewable integration across your jurisdictions here? And how are commissions thinking about the integration of batteries with solar here? Just wanted to touch base on all that.

Yes. So let's start with the long-term plan. I think the United States certainly is adopting a net zero carbon posture. We were one of the -- I would argue that we were the first one to come out with low to no -- I think that's equivalent to net zero. net zero becomes important because it gives us flexibility on the very last kilowatts that we need to be carbon-free. In other words, it might have been electric transportation or it might have been more carbon capture on gas generation. If we are able to make net zero technology, either direct capture, biomass or hybrid biomass, those incremental kilowatt hours at the end of the tail to get to net zero are cheaper. Now we need to continue to invest R&D to get there. If you look at the state of Georgia, for example, they have been out there in terms of a state. Remember, Georgia Power, I want to say, was called out by the solar industry as the investor-owned utility of the year. And in fact, we had no mandate to do solar. They do it because it makes sense in the portfolio and it's good for customers. Alabama recently has considered solar and put it into a special focus in some hearings that will be upcoming. I think even gas has some very interesting plans on net zero. So I would argue, our state certainly understand the idea. And our state have been so constructive in the past in terms of balancing kind of an environmental need with what's best for customers. I think it's going to be a great place to do business. And I think also when you consider the role of batteries, I have said consistently, and I know this may be a little bit apart from some of my brothers and sisters in the industry, we are going to need some material science advances in order to make batteries a comprehensive solution. We have to incorporate not 4- and maybe even 6-hour battery technology, but seasonal battery technology. Recall the most important renewable probably in the Southeast, not wind, it's solar. And you know that during the summertime, you get a pretty good profile for solar generation. But as you go to the winter months, you have a much shorter period, and therefore, you need seasonal storage strategy. So we got to figure that one out. In Georgia already, they have addressed considering batteries and solar as part of the solutions for the future. But I think for us to get where we need to be, and for Southern, the numbers are roughly 50% renewables, which is the lion's share is going to be solar, we're going to need some advances in R&D on battery technology. That's going to make us, I think, get there. Jeremy, did that answer your question?

Yes, that's very helpful. And then kind of shifting gears here. Is there anything we should be thinking about in regards to potential changes on the Georgia Commission as elections approach here? If there is a change, how do you think Georgia Power is positioned? I realize this is kind of a difficult question to answer, but just wanted to know if you had any thoughts on that.

Well, it's almost impossible to answer. I mean, look, this company has been designed over the years to thrive in any kind of administration at a federal level. Does Trump win, and the Senate win? Or is there a blue wave? I think Southern Company has the optionality, if you will, and the credibility, if you will, to do great under both administrations. Likewise, in our states, we have inextricably intertwined our operation with the good, the well-being of the communities we serve. And I think on both sides of the aisle, whether it's Republican or Democrat, people understand that a healthy utility, one that is involved in something bigger than our bottom line that we are inextricably intertwined with the community we're privileged to serve, is a good thing for the state. When you think about our economic development and the role we have played historically, I think it has stayed forever as a premise by politicians on both sides that Georgia Power is one of the great citizens in our service area. The same holds true for Alabama and Mississippi and the Southern Gas utility. No matter what happens, we'll be fine.

Our next question comes from the line of Andrew Weisel with Scotia Bank.

Quick one here. Just in terms of coal generation, the pie chart you show is really impactful, and of course, consistent with the strategy toward decarbonization. My question is, with demand down so much this year and milder weather, should we think about the reduction in coal and even natural gas as being temporary? In other words, if next year, we get demand to rebound and it starts to look more like 2019, would it be right to assume that you'd be running the coal plants more, and the SKU might look similar to how it did?

Yes. The premise of your question is 100% correct, so let's just go through it real quick. Interestingly, what I love about the data point on that chart about coal being 16%, half of that is 1 plant. It's Plant Miller in Alabama Power, and it is a terrific plant. Highly efficient, cheap energy, really good stuff. So the whole rest -- that is one plant, the entire remaining portfolio of coal at Southern Company is only 8% of our energy. What does that tell you? It tells you that it's back in the stack. In other words, its marginal cost to run is more expensive than most of the gas that you see here. So what are some things that could sway it? One is that gas prices go up. If there was some ban on fracking, if for some reason gas prices spiked, you may see an increase in coal. If, however, two, demand moves up, so if you think about the stack of generation, if the demand line moves to the right, you will pick up more expensive resources. That's absolutely right. And that could cause you to increase your generation of coal. But the inescapable truths are that, with environmental pressures, cost pressures, supply pressures, the importance of coal is waning in the portfolio of Southern Company generation. Did that get it?

Okay, great. That's helpful -- yes, yes. And then do you have sort of a pro forma -- or what's your latest thinking on a pro forma energy mix, say, in 2023 when the 2 nuclear units are on? Do you have round numbers available?

Yes, I do. Yes, I'm going to just get my hands on them. It's something like this. I think depending on what -- there's a little bit of an assumption there about what happens with environmental and what happens with coal and gas prices, but I think you're going to see something similar to this 2020 mix. Nuclear will go up a wee bit, maybe in the 2%, so maybe 19% would be nuclear, something like that. Gas would drop down. The marginal cost of nuclear is very cheap. Coal, it depends on what happens with environmental. And that really depends a lot, to a large extent, on the elections going forward. If you have a blue wave, it may be that we would see perhaps tighter regulation and coal waning importance, but we'll see. The other big factor is you should see renewables increase in importance. And I think we're going to see, particularly at Georgia Power, something like 2.2 gigawatts of solar by 2023. It will be a big deal. Now whether we purchase it or own it, renewables will continue a steady advance into the future. So right now, it says 15. When I took over, it was 0. And this is with a company that -- round numbers, I know this is incorrect now. Don't hold me to it. I used to say that we're a little bit less than the size of Australia. Australia has grown faster than we have, but we're still pretty big is the whole point. To go from 0 to 15 in the time I've been here is pretty important. And I think between now and 2050, getting to 50 is a big deal. So expect renewables to continue with steady increase in the percent. And those renewables are most likely to be solar rather than wind.

Okay. Just to make sure I'm clear, though. So are you saying that renewables will be more than nuclear as soon as 2023?

I think that's a possibility, sure. Yes, you could see renewables get up into the 20% range. What's fun about that is to say, renewables plus nuclear, if you're 20% and 19%, you're 40% carbon-free. And recall, we've also said, we set in place an interim goal of achieving 50% reductions by 2030. I think it's going to be 2025 anyway. It could even be better than that. But we'll see.

Our next question comes from the line of Charles Fishman with Morningstar Research.

Tom, you've answered all my questions on Vogtle, COVID-19. I wonder if I could just ask one sort of long-range strategic question. You have a situation where you've got this nuclear capacity coming on in the next few years. You're building a lot of solar, you'll continue to build solar. Southern is in a mild climate. It makes a lot of us that live up north jealous, mild in the winter. Higher summer peak versus winter peak. In your discussions, have you thought about the fact that you do some electrification of space heating? Because you're in a mild climate, air source heat pumps are efficient and economical, does that enter into your thinking with respect to net zero carbon?

Yes. Charles, I know I catch some grief for this, this notion of electrify everywhere. Gas will have an important part in the future, don't get me wrong. But switching to electricity, it does make a lot of sense in many cases. Let me disabuse you at one point, though, and that is this summer peak. That used to be the case. So if you did your research, it was probably old data. Absolutely, Alabama is a winter-peaker right now. And what's fascinating about that is when you're a winter-peaker, your reserve margin -- in the old days when we were reliably a summer-peaker, you would have lots of warning about peak days in the summer. You could see heat waves coming. There was very elegant modeling about how that persisted and grew over the space of, say, a week, and you could really nail it. And what we used to say was you needed 13.5% reserve margin in the current period, and 15% for the next 2 years in order to meet your needs. With winter peaking becoming a reality, particularly in Alabama, and with the penetration of solar generation not being available during the time you need winter peaks, right, that's 7 a.m. in the morning, roughly. You better have good storage, maybe that works, maybe it doesn't. And now you need reserve margin that are may be in the 30s, okay? So it's a much different kettle of fish as we plan the system. Now right now, what we see is one of the important issues, and I really want to flip this over to Drew because Drew, as we bought Southern Company and as we bought AGL Resources, was the CEO of AGL Resources and really understands this conversion market very well. But I think the statistics for us right now is that heating loads, electric versus gas right now in the Southeast, is about 50-50. And so I think the really interesting question is where does that go? Drew?

Yes. It is interesting, and I do carry a bit of a bias because of my background. And it does vary by climate for sure. The one nuance I'd say is that winter heating with electricity is a little bit more difficult to manage, I would say, than probably an alternative fuel in that it's not that our demand is greater in sheer megawatts as we plan, but the volatility around it can be quite large. And so the peak requirements that you have to plan for are very high. It's exacerbated by exactly what Tom described, which is solar availability is lowest when we meet the highest peak in the middle of January at 6 a.m. on a Monday morning as people prepare for work. The state, though, has done a good job. There has been very robust competition, particularly in Georgia between gas and electric. And where it makes the most sense, it has migrated in that direction. And so, as Tom described, about half of our customers across the Southeast utilize electricity as their heat source. In our Illinois jurisdiction, it's much more difficult to even contemplate that electricity could be an alternative to natural gas because of its efficiency and because we really have to focus on reliability and affordability for that customer base just as we do in the Southeast. And so you will see continued electrification where it makes sense, but we have to be realistic about where those limits are for our -- for the particular customer that we serve.

Yes. Absolutely. No, Drew knows his stuff. Thanks, bud.

Yes. No, that's interesting. I certainly appreciate in Illinois, it's not going to work. But I would assume that the air source heat pumps are competitive in your Southeast region.

In many. And generally below the latitudes where Atlanta exists. And so it's -- everything, as you move down into the plains.

It's kind of the gnat line, right? It's kind of making across. That's what they call the gnat line down here.

(inaudible)

We do see it.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

So all I have left here is I just wanted to follow up to you on PowerSecure. And just -- I know you guys have been shaping the business over the years since you bought it, you've sold a few things and what have you. But you guys mentioned -- you called out that COVID sort of had negative impact on it. And I was just wondering, how should we think about PowerSecure, a, I mean, I don't think of it as a big earnings driver but does it have a significant earnings change that we should think about in the future? And also, just does it -- how does it look for you? Are you thinking maybe that more of it should be sold? Or just strategically, how does it sort of figure in the future?

Yes. We've actually put a bright young guy in charge of kind of the confluence of Southern Power, PowerSecure, and the part of Southern Company Gas, it's called Sequent. Now here's the issue, I think, that we've raised. COVID could have an impact, but it's because people are less likely to have people travel to their site to go get involved in the kind of things that PowerSecure does for a living, right? If you think about it in this iconic century-old business model we have of large-scale central station, making, moving and selling energy, you may recall, we bought PowerSecure as an idea that would position us to be able to influence through technology and working with changing customer requirements to essentially miniaturize that model and put it on the customer premises. So make, move and sell now at a Home Depot store or at a defense installation. And you can imagine everything in between. We have -- and Paul, you absolutely hit the nail on the head, we have been putting it into our fashion since we bought it. That is we got rid of electric lighting business. We got rid of a utility services business. We're really focused on that intersection of independent power generation, and kind of equipment you would think about in the move and sell, that would be proprietary switchgear and micro grids. I know this statistic is dated, but I'll quote it anyway. It's probably what, 2 years old? That some magazine said that Southern Company and PowerSecure was responsible for something like 85% market share of microgrids in the United States. So when you hear about microgrids, most likely that's us. Now I'll just bet those numbers have decreased over time. More people are getting into that market. But we remain by far the dominant, I think, solution for customers that can integrate all the way through that make, move and sell value chain. Some people will get in there with control equipment, some of them will get in there with distributed generation. But we are the integrator, and in fact, provider of all of that solution. The importance of Sequent is that giving people control over fuel stocks -- I mean, over there, electricity production and all is really important, but they don't know how to procure fuel, be it natural gas or hydrogen or whatever it is. The people at Sequent can. And so giving their capability to the Southern Power generation centric, and the PowerSecure broader equipment microgrid-centric approach makes a lot of sense. [Chris Kaminski] in our system is charged with making all of that makes sense. And that isn't just a kind of arm's length little deal that we're trying to do in 50 states in the United States. I think we're virtually in every state in the United States doing that. One of the other big deals, as PowerSecure's earnings are a virtual peanut compared to Southern Company earnings, it is important that our host utilities learn what's happening on other people's beaches. You're more vulnerable to this approach that is miniaturizing make, move and sell if you do not have a strong cost profile or customer service or reliability. Those areas of weakness for some companies are areas of strength for our offering. Now fortunately, in the South, we do really well with price, service and reliability. What we always say about PowerSecure is, and really the union of those 3 efforts is, it is an offensively oriented defensive strategy whose value relies in its option value. That is, once those markets get some oxygen and take off, we will be poised to play hard and influence. That's our idea. But in terms of our financials, it just doesn't matter. Not now.

Okay. So there's not any significant drag or anything that we should be thinking?

No.

You guys mentioned that there might be a goodwill impairment, and you've been mentioning that in the last couple of quarters in your Q. And I was just -- a, it seems a little bit surprising in that it seemed like it was COVID-related, which I would think was sort of temporary, and I was a little surprised that it might have an impact on goodwill. But I mean just in general, though, it sounds like -- is that just sort of an accounting -- hard factoring something in?

Yes, Paul, I would see it as kind of a -- I mean, it's a disclosure item. I think it's kind of a minor point. I think the real shareholder interest in PowerSecure is as I described, this idea of driving make, move and sell for the future.

Right. Well, power grids are picking up so -- I mean, there's a lot -- I mean, microgrids are picking up, so it sounds like there could be opportunity.

And Paul, I just should add, they just had, I think, the best quarter ever. So listen, when I say that, don't get the idea, we're going to increase our sales -- I mean, our EPS forecast on PowerSecure, they're just small, but they're doing well.

And that will conclude today's question-and-answer session. Mr. Fanning, I'll turn it to you once again for your closing remarks.

Thanks, everybody. What a great quarter. Such exciting times to have the progress at Vogtle 3 and 4. And just for everybody's benefit, I asked Paul Bowers to join us. He did join us on this call. And I know Paul was CFO and knows so many of you on the call today. I just want to give him the space to end the call. Paul, what would you like to say?

Well, thanks, Tom. And I'll put context in the decision associated with retirement. And that's a major decision personally, but also you got to think about the context of how it impacts the company. And as Tom outlined in the opening, our confidence in delivering Unit 3 on or before our regulatory date of November is one of the reflecting points for me to make my decision about retirement. Now you think about the third quarter being that period in which we think it will be commercial operations. So when I'm contemplating timing for a leadership change for Georgia Power, and as Tom and I discussed, the transition seem obvious associated with the fuel load because that's the signal in and of itself that we're about complete with Unit 3. So with that, and as we have disclosed that concurrent to us loading fuel in Unit 3, we'll make the leadership change at Georgia Power. We have a great leader under Chris Womack to take the reins as we move forward. It's been a great privilege and honor to be part of this team and serving a lot of different capacities over the years. But as you think about Southern Company, and you think about what we had before us, the momentum continues to grow and it's got a great future in terms of what we can deliver for not only our customers, but all our shareholders. And as Tom pointed out, I am getting old. So thanks.

I pointed that out a lot.

Thanks though.

Okay. Thanks, Paul. You've been a champion through your whole career here and been a great friend and an awesome business leader for the south. Anyway, thanks, everybody on the call. Great stuff. We'll talk to you soon.

Thank you, sir. Ladies and gentlemen, this concludes the Southern Company Third Quarter 2020 Earnings Call. You may now disconnect. Thank you once again. Have a great day.