Good afternoon. My name is Pema, and I will be your conference operator today. At this time, I would like to welcome everyone to The Southern Company Fourth 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. [Operator Instructions] As a reminder, today's conference is being recorded Thursday, February 18, 2021. I would now like to turn the call over to Mr. Scott Gammill, Investor Relations Director. Please, go ahead, sir.

Thank you, Pema. Good afternoon, and welcome to Southern Company's year-end 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 and subsequent filings. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measures 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.

Good afternoon, and thank you all for joining us. As you can see from the materials we released this morning, we reported strong adjusted earnings per share for 2020 that exceeded our guidance range. In addition, we have a solid outlook for 2021, and importantly, we are raising our projected long-term earnings per share growth rate. But before we turn to more on our year-end business update, I'd like to share some thoughts on 2020. In 2020, we essentially saw four pandemics: health, economic, social and political. Southern Company demonstrated excellence and resilience on every front, including prioritizing the health and safety of our workforce and communities, overcoming decreased electric demand while delivering both, strong financial and superior operating results, and continuing to address racial injustice and working with policymakers to advance a cleaner energy future. First, the health pandemic. The COVID-19 pandemic was, of course, the first and primary challenge that we faced last year and one that continues to impact our communities today. From developing a pandemic response reentry playbook, that was ultimately leveraged by many peer companies, to setting up a medical village at the Vogtle construction site and making heroic progress towards completion of those units, we placed the health and safety of our employees as a top priority. So by taking care of our workforce, we were able to continue taking care of our customers. The economic pandemic. Beginning in March and April of last year, the world has experienced significant economic duress. Southern Company originally projected a $250 million to $400 million loss in revenue as a result of the COVID-19 pandemic. Through thoughtful, disciplined O&M reductions, we were able to mitigate the estimated now $300 million revenue loss that we have experienced, while still providing reliability and industry-leading customer satisfaction to our customers.…

Thanks, Tom, and good afternoon, everyone. I hope you are all safe and healthy. As Tom mentioned, we had a very strong year in 2020 despite the many challenges we faced. For the full year, our adjusted earnings per share was $3.25, $0.14 higher than last year and $0.03 above the top of our guidance range. 2020 was certainly defined by milder weather and sales impacts due to COVID-19, and we were able to substantially overcome both, as evidenced in our solid results. Looking at the details. Retail electric sales on a weather-normalized basis were down by $0.14 year-over-year, including impacts related to COVID-19, offset by customer growth. Milder temperatures throughout 2020 resulted in an additional $0.21 negative earnings per share variance, as compared to the prior year. We substantially mitigated both weather and COVID-19 impacts through thoughtful, disciplined O&M reductions as well as continued investment at our state-regulated utilities. On a combined basis, these factors allowed us to exceed our adjusted EPS guidance for the year. A detailed reconciliation of our reported and adjusted results as compared to 2019 is included in today's release and earnings package. COVID-19 impacts reduced our projected weather normal kilowatt hour sales by 3% for the year. The slight uplift from the residential sector persisted throughout 2020 with more people working from home. In the fourth quarter, we continued to see improvement in kilowatt hour sales for both the commercial and industrial customer classes. However, we do not believe we have seen a full recovery in these sectors yet. Factoring in impacts across all customer classes, our non-fuel revenues declined by approximately $300 million, which was at the lower end of our original estimates as the pandemic began. As Tom mentioned, an important part of our COVID-19 response was, and continues to be, supporting…

Thanks, Drew. I'd like to circle back to your comments on fleet transition. Southern has two primary goals related to our greenhouse gas emissions. The first is to achieve zero -- net zero emissions by 2050. We will work constructively with the Biden administration to accelerate this time frame, as national policy evolves. The second one is to put in place an interim milestone to achieve a 50% reduction in greenhouse gases by 2030. Regarding the intermediate goal, we achieved our 2030 goal in 2020, with preliminary greenhouse gas emissions now down 52%. Now, certainly, 2020 was an unusual year, and we may see emissions reductions move around 50% for the next two years, but we believe we'll be sustainably above our 50% reduction level by 2023. While ESG issues have received increasing attention by investors over the past few years, at Southern Company, these issues have consistently received the heightened attention they deserve, and it's being recognized. We were once again ranked as one of the world's most admired companies by Fortune Magazine. The DiversityInc rated us as a top company for ESG. And for the fifth consecutive year, we've received a perfect Corporate Equality Index score by the Human Rights Campaign. In addition, we're very proud of the A- rating we recently received from the Carbon Disclosure Project for our environmental transparency and leadership. We recognize the value our investors and stakeholders place on transparency, and we are committed to continued enhancements. And before closing, I want to just take a moment to recognize our leadership transition announcement that we made at the end of last year. My trusted friend and one of my closest confidantes, Mark Lantrip, plans to retire in April after dedicating 40 years to Southern Company. Mark has helped position Southern Company as a leader that is building and shaping the future of energy. We are grateful for the many contributions Mark has made to our business, and we'll miss him dearly and wish him all the best. Mark is passing the baton to Chris Kaminski, who has been a valued member of the Southern Company leadership team for many years, holding key positions at both Georgia Power and Southern Power. In closing, over the past decade that I have been privileged to serve as CEO of Southern Company, I can think of no other year that I've been prouder of the way we've conducted ourselves and managed our business. Our engagement with and empathy for our employees, customers and communities in 2020 demonstrates our enduring commitment to be a citizen wherever we serve. Thank you for joining us this afternoon. Operator, we are now ready to take questions.

Thank you, sir. We’ll now begin the question-and-answer session. [Operator Instructions] Our first question comes from the line of Julien Dumoulin-Smith with Bank of America. Please proceed.

Julien, how are you?

Hey. Good morning. Hey, buddy. Hey, thanks for the time. Congrats, guys. So maybe just to kick things off on a light basis. $5 to $7, how are you thinking about the base here? You guys gave the $4 to $4.30 number, but can you talk about what's the baseline year for that? And then if I can throw it in there at the same time, that five to seven, how are you thinking about upside CapEx, perhaps some of the spending opportunities that exist in a, shall we say, post-Vogtle world, as you think about this transition? How does that fit against the numbers you guys gave today?

Yes, man. You bet. We did it a little bit differently this year. The way you should think about the base here is kind of a 2024 number. That is $4 to $4.30 and then kind of reverse engineer back from that at the kind of top end of that range at a growth rate of 7% and the bottom end of that range at kind of 5%. That's how we come up with 5% to 7%. Certainly, as we move from 2021 to 2022, there's a step change, but I think you can see the math from there. With respect to that range, it's fascinating. As Drew pointed out, and I've said this before on other calls, the way we do CapEx forecasting, in my opinion, is really conservative. What we put out there, I know some companies – I shouldn't say this, but perhaps some companies use CapEx forecast to plug to a growth rate. We do almost the opposite. We only put in our CapEx forecast what we know or what we firmly expect, and we do not put in placeholders. So what is absent in that CapEx forecast is capital allocated to future projects at Southern Power. You know that we allocate, on current practice, about $0.5 billion a year to that business unit but none of that is showing up in the CapEx forecast. Certainly, as you look at fleet transitions that I think, from a policy standpoint, are being pushed in Washington, you will see growth in renewables. And it wouldn't surprise me that there will be plenty of opportunities to do more solar and wind in the future. Right now, we think those markets are very tough. So we elect not to put anything in the forecast. Secondly, we don't include any fleet transition. I think it's been very clear and I've been in the press here recently, talking about the transition of the fleet and working with the Biden team to think about how to move net zero 2050 to something sooner. I know President Biden, now would like to put out a marker of net zero by 2035 for this industry. We certainly – I think we can certainly achieve that. There are certain policy choices that will have to be made along the way, but we are engaged constructively in that conversation. If you go to something like that, I think you will accelerate fleet transition. Again, nothing in this CapEx forecast is reflected, associated with any of retiring coal plants sooner and building more renewables or more gas assets in this time frame. Drew, what else would you add?

I think the only thing I'd supplement maybe, Julien, is that if you kind of look at our historical performance, go back as far as 2018, we've been clearly growing rate base and growing earnings in sort of the 4% to – 5% to 7% range historically. We've had some changes in that pathway a little bit because we've taken penalty for Vogtle construction. We'll see a little bit of that change as we move Vogtle into service. And so you get a bit of a [lag] [ph] in the way our growth rate might be delineated on a linear basis. But what we're really trying to express is a longer-term potential for the business as we invest capital into it. Then I think the other important point that Tom made is that we have quite a bit of generation modernization to do that we have not yet quantified, because I think there are a number of ways that that could play out. If you think about broadly what that looks like, we've got about 10 gigawatts of coal fired facilities in aggregate. We'll have to find some method of meeting the reliability requirements of our customer base without relying on coal as a primary source of megawatt hour production. And so I think we'll -- over the next couple of years, we'll take stock of emerging technology, different things that work within our system to meet the goals that we have, and we'll kind of lay those out for you as they reveal themselves to us.

Hey, one other point, Drew, is -- and I didn't mention this one, I'll bet you there's at least another $1 billion of transmission. So when we talk about transitioning the fleet, it isn't just choices in generation, which we think we'll have. We do believe that there will be additional transmission associated with this transition that will occur. I see that easy to achieve over this five-year period. One last thing, and I'm not often doing this, but complementing the analyst community, you guys have done the math. If you back out this penalty period, we have been earning about 6% EPS growth once you exit that period. And so that actually creates a nice line going into the future. Julien, anything I didn't cover you wanted?

Listen, so let me clarify that, if I can, when does some of this CapEx start hitting, right? Whether the transition on generation, when you guys have this 4% rate base trajectory through 25?

Yeah, I mean…

It seems like that already translates to the 5% to 7%. When you actually get this CapEx uplift, it sounds like that drives you higher within that 5% to 7% range, as I'm hearing you, right, as you get some…

Yeah. So you know, and you all know that we never try to get ahead of our regulatory processes, and each of our states follow their own version of an integrated resource plan. And so as we file those plans and file, whether it's RSE in Alabama or the three-year rate case at Georgia or PEP in Mississippi, that we'll make those plans known and approved by the commissions as appropriate. The other thing you should know is that heading into this call, I guess, we showed 4% for electric, it was 5% probably a week ago, it's rounding, okay? So it's in the middle of 4% to 5%. The gas business is growing at like 10%. And so the overall support the growth trajectory, that is supportive of 5% to 7%. And you're right. When you think about starting with $4 to $4.30, there is upside to a mid-range forecast there based on how we deploy capital over time. But I think even with the base forecast that we're showing you today, we're within that range, and we're comfortable at 5% to 7% within that range in 24.

Yeah. Absolutely, great. Thank you to clarifying that all. Best of luck guys. Talk soon.

Thank you so much. Appreciate you calling in.

Thank you. And up next, we have a question from the line of Steve Fleishman with Wolfe Research. Please go ahead sir.

Hey, Steve. How are you?

Thank you. Hi, Tom. Good afternoon. So just a question, if you end up determining that you cannot meet the November deadline for Vogtle for some reason, could you remind us like do you have to -- what do you have to do with anything then? Do you have to make a filing, or is it just – you just – just update the schedule?

That's right. We'll just update the schedule. And certainly, I think we're pretty good about letting people know when things change. We did the press release with the expressed intention of moving off of what we had thought, I guess, back in October, may have been July HFT. As this third wave of COVID hit, it really did just knock us for a loop in terms of productivity and pushed us now. And actually, the numbers continue to move just a wee bit, but it puts us from February now into March. No, it really just has a function of cost, Steve, and it really depends on when you incur the costs, okay? So if it is a delay that causes us to get into hot functional tests, the amount of both units in Georgia Power dollars is about $40 million. If it's items – I mean, Unit 3 only, it's about $25 million. If, however, we shift, and it is a delay kind of from fuel load to in-service, in other words, it's some punch list that causes us to have a delay in the in-service declaration of a unit, it goes way down. For both units, it's $25 million a month. For Unit 3, it's only $10 million a month. So depending on when the delay occurs, there would just be an additional cost that we're factoring in. And I will say that with this now new estimate on estimated cost to complete, this $176 million we've added this time, it includes a November in-service for both units. It includes a CPI number that is like 1.8. It includes a construction per month that is consistent for Unit 4 with our experience from November to January. Now my hope is that we can improve on those numbers but we wanted to put out what we thought was a thoughtful and kind of reasonably conservative estimate so we wouldn't have to come back to this number again. No assurances that won't happen, but that's where we are.

Okay.

Steve I think…

So I know there’s November…

I think the only thing mechanically that occurs is that we continue to function under a penalty ROE until we bring the unit into service, and so that would be the material thing to model.

That's right. You start losing that penalty rate once you declare in service.

Okay. So because I know for a long time, we've had November as this like regulatory approved deadline. If there's a new deadline or whatever, you don't need to kind of go back and seek a new deadline or anything like that. You just finish it and go through the VCM process?

Yes, sir. There's nothing special. The VCM process we've been filing has been really effective at kind of handling those issues. And as you guys know, you follow those VCM filings very clearly. That's kind of the way we would handle it.

Okay. And then 1 other just quick Vogtle question. I think there's a new – or there's going to be a new chair of the NRC. Does that matter at all for you in terms of your timing process? I doubt that they're too much in the weeds of everything. But...

Oh, no, I would argue. Hey, look, Steve Kuczynski and I visit with each of the NRC commissioners regularly. And we're very happy with Chris Hanson. We were very happy with Kristine Svinicki. My sense is Chris Hanson will, I think, run an NRC consistent with the principles of Svinicki. Hanson has experience in a variety of fronts in Congress with Dr. Ernie Moniz, who's on our Board. We know him well, and we think he will be terrific. The NRC yeah -- the NRC is a very tough regulator, but we think they're very fair, and they've been very constructive in their treatment of Vogtle 3 and 4.

Great. Thanks so much.

Thanks, Steve.

Thank you. And our next question comes from Michael Weinstein with Credit Suisse. Please go ahead sir.

Hey, Michael, glad to have you with us.

Yeah. Glad to be here. So the -- just to follow-up on Julien's question, so the 4% rate base growth profile for electric, and if I look at that overall, I'm just thinking that once you get to the 2024 range and the penalties are out, right, the -- moving into penalties is the main driver of 5% to 7%, I'm guessing through 2024…

Yeah. That…

Yeah.

Yeah. Michael, excuse me those penalties will expire as we move to in service for the units. They expire by degree. So in effect, once we declare Unit 3 in-service and then Unit 4 in-service, we actually have a step change in growth that we're really not saying a whole lot about. The 5% to 7% is what we think we can sustain and have sustained over recent history without this step change in the Vogtle uplift moving in the rate base.

Okay. I mean, because I was thinking that the 5% to 7% is simply sustained by increasing the CapEx profile and increasing the rate base growth profile once…

It is a sustainable growth rate beyond the uplift from Vogtle.

It sounds like it actually any -- yeah. I'm thinking any increase in renewable CapEx or recognization CapEx actually improves on that 5% to 7% versus…

Yes, It would, absolutely.

Mike, we’re pretty focus the durability of spend, I think, is the way we think about it, and so trying to extend the 5% to 7% range as long as we can. The -- if you sort of draw the line between what we've laid out today is our earnings expectation for 2021 and then take a look at our projection for 2024, you can see that sort of falls without -- outside of the range that we've intimated at 5% to 7%. We think of that really as being more of a longer term growth -- sustainable growth rate in absence of single large project risk.

Yeah. And then the way you should think about it is almost a reverse engineer. Start with what we're thinking about is a reasonable range with this CapEx forecast for 2024 and then reverse engineer backwards using 5% to 7% growth rate. We think that's the right way to think about this.

And it looks like most of the increase or almost one-third of the increase in CapEx in this new plan is at Southern Power. That's this year. And is that just a function of you just not wanting to put placeholders in there? So each year, you'll simply have a major increase around the same amount for?

No. And I'd say in particular to Southern Power, it was more that we had earmarked capital in 2020 that was committed but not yet in place. We'll actually deploy that capital in 2021, which increases the expenditure. But if you look at it over a longer period of time, a three-year, five-year average, very close to the $500 million that you're marking that business.

Yes. So I mean, let me just say it another way. Were we to spend the dollars that we allocate in our minds to Southern Power, that's an additional $2.5 billion to the CapEx forecast that doesn't show up in the forecast.

Yes. That's right. I hear where you're heading.

Yes. And like I said before, there's probably an additional $1 billion. I mean, who knows on transmission. And then whatever happens on fleet transition, there's something else there. Yes. I think what we've given you is kind of a bare bones approach, which we think is appropriate. And then that supports the 5% to 7%.

And what we've represented for Southern Power in particular at $1.3 billion are committed projects that we will execute on within this calendar year or represents maintenance of those facilities over time.

Now I mean, you mentioned that the increase or the extension of tax credits and the promotion of renewable power by the Biden administration going forward could present more opportunities for Southern Power. In the past, you've been a little more, I guess, more cautious on it, saying that returns have been tight. You've been pulling back on spending at Southern Power. Are we – are you reversing that stance now? Are you thinking of it may be more opportunity, not less going forward?

No. In fact, I thought I'd put those words in there. The returns have been – the terms and conditions have been tougher. The duration of the contract has been shorter. And so all I'm saying is, and that's really the reason why we don't include capital commitment to Southern Power in our forecast, we think it's a very tough market. Now I was only postulating that with an administration that is really bullish on pushing more renewables, that the markets may get a little looser. But they're certainly not now.

Got you. Okay. Thank you.

Yes, sir. Thank you.

Thank you. And our next question comes from the line of Angie Storozynski with Seaport Global. Please go ahead.

Hello, Angie. How are you?

Great. How are you guys. So I have a question, one, obviously, about Vogtle. So we're all waiting to have functional testing to start. We have some concerns if it's going to uncover any sort of catastrophic flaw of the project. I mean is there anything you guys have learned about Unit 3 that would make you feel more comfortable with how hot functional testing is going to go?

Yes. Angie, knock on wood, and don't show overconfidence or what have you. The Chinese plants that went through hot functional test went through it pretty well without any incident. We have every reason to believe that will be our experience as well. I just can't predict the future. That's all. There’s nothing that I know of that will cause me concern right now. And hey – and Angie, the other thing is we've done all these partial system tests along the way. And I think we've even surprised ourselves how well those have gone.

Okay. And something completely unrelated. Given what's been happening in Texas, and I understand it's a completely different design of market, but we're about to have this debate about what types of plants are needed on the system in order to maintain a reliable electric service. And again, lots of differences between your service territory and ERCOT. But in light of what has happened, is it changing your perspective of what types of power plants your utilities should have? You talked about some generation replacement. How does, again, the last week play into this planning?

Yeah. Let me offer up a few comments. I was on CNBC this morning, and it was a great topic of interest and discussion about what about Texas. And it really gets into this idea of organized markets versus integrated regulated markets. You know I've been a fan of integrated regulated markets. Through our integrated resource plans, we can effectively begin with optimal capacity portfolios and iterate around transmission that supports those optimal portfolios. We can also build in resilience requirements and socialize those costs over a large customer base. And we've been able to do that for a decade, and it has worked exceedingly well. A real criticism of the so-called organized markets is that they are set up -- and I think the people inside those markets operate quite rationally, but they either operate within punitive constraints or profit incentives that are broadly -- and every market is different, as you know, but they're broadly designed around maximizing short run marginal properties. So minimizing short run marginal cost, that's no way to build a portfolio. And I would argue that the outcome of those designs is, as you start to include other value attributes like transmission, like -- I'm sorry, not transition, like a backup generation, like resiliency, like other things, you get to really complex approaches in a market. I think PJM has been wrestling with how to value all those things. I guess, the second thing is that you really don't get a sense of valuing long-term base-load capacity as it should be. And I think we've seen that in the markets where, for heaven's sakes, very valuable nuclear generation is getting priced out of the market. And those valuable assets, especially as we consider a carbon reduced future are getting priced out of the market and getting turned down. I think there’s better approaches here. And so it was interesting. Not only did I have this conversation on CNBC this morning, and I guess I'll just be a little obtrusive about this, but I was called by the Biden administration. From a national security standpoint, what can we do as an industry to avoid these things? Unfortunately, given the market structure of ERCOT, there's probably not a lot we can do in the near term. But I think long-term, this notion of resilience versus reliability, reliability is how we handle the vagaries of weather and economic load and machine reliability under known conditions. Resilience is the idea of keeping your system up under unknown and unexpected conditions. Whether they be operational, weather-driven or cyber related, these are things we must do as an industry. And I think Southern is in a good position to help lead that dialogue.

Awesome. Thank you.

You bet.

Thank you. Continuing on, our next question comes from the line of Andrew Weisel with Scotiabank. Please go ahead.

Hello Andrew. Thanks for joining us.

Hi. Good afternoon. Question -- you talked quite a bit about the updating the decarbonization strategy. I guess my question more specifically to Georgia is given the political changes, it's now a pretty solid blue state that Saturday Night Live made a funny sketch about. Does that change your thinking at all about how the pace and the method at which you plan to reduce your carbon footprint in Georgia coming into the IRP?

We don't try to evaluate long-term strategies based on the current politics of any state or elected official or what have you. We have, I think, a very solid long-term plan. Now, I think the broader kind of issue that we'll be dealing with is how fast do we want to get to net zero and how will we do that. How will we evaluate the relative merits of just trading out one form of generation for another. How will we help fund and push some long research and development, energy innovation as solutions that will make this transition, hopefully, easier and more efficient in the years ahead? CNBC also did a segment just before mine with Bill Gates. He and I are on the American Energy Innovation Council, and we're working on several ideas. Whether they are storage-based, hydrogen-based fourth generation, nuclear-based or even energy efficiency-based, letting energy innovation work for us and maybe joining into a reimagined partnership with government to make that happen is, I think, a very wise energy policy to follow. And like I say, we're already engaged with the Biden administration on some of those concepts, and I look forward to their ideas as they advance.

Okay. I guess, maybe a different way to ask a similar question is you're very – you're ahead of schedule as far as your interim carbon emission reduction goal for 2030. Do you see opportunity to accelerate the net zero target from 2050 currently?

Sure. I think it really is a matter, though, of working with our local jurisdictions in each of the states. To do that in a wise manner. So we'll be doing that.

Okay, great. And one unrelated question. On dividends, the growth has obviously been fairly modest at $0.08 or about 3% per year. I recognize the high current payout ratio, but you talked about the Vogtle penalties going away in 12 and 24 months and then the 5% to 7% earnings growth thereafter. What's your current thinking on the outlook for dividend growth once we're past the Vogtle construction?

So of course, that's a decision of the Board, and we'll make obviously recommendations to the Board. But you guys can do the math as well as we do. And I'm looking at my friend, Drew Evans, right now and kind of laughing. I have a certain half-life with my career here. Certainly, as we grow into this long-term earnings guidance that we've put before you, one of the choices that I think the people that follow me will be able to make very easily will be whether to take the dividend payout ratio down perhaps below 70% or whether to increase the rate of growth of dividends per share. That is certainly a strategic option on the table. But we'll carry that with the Board at the right time.

Yes. No, I'd just say, Andrew, we've been incredibly protective of our creditworthiness. We're very focused on ratings and conversations with the rating agencies related to Vogtle construction in particular. And we think it's most prudent to hold dividend growth at a modest level until we come out from under the large-scale construction that we're performing down in Augusta. Once we get through Vogtle and headline risk is behind us and our credit metrics start to strengthen in the categories we think are more at home with how we've operated in the past, we'll start to take a look at what dividend policy would be. And we'll also really start to hone in on what our target credit rating might be. Southern has operated at a -- as a premium to its peer group relatively in PE in periods where we didn't post headline risk. And in periods where our credit was a little bit stronger than where we stand today, and so all these things are going to be considerations as we go forward.

And consistent with what Drew just said, we typically say it on every call, we didn't say it yet, one of the other outcomes of this reset and moving to these higher rates, not just earnings per share growth improvement, cash flow improvement is pretty significant, over $800 million in increased cash flow per year.

That’s right.

Terrific. Thank you very much.

Thank you.

Thank you. Our next question comes from the line of Jeremy Tonet with JPMorgan. Please go ahead sir.

Hi, Jeremy. How are you?

Hi, good. Thanks for having me. Good afternoon.

Good afternoon.

Just want to reach out to the 2024 guidance as you laid out there. And thinking about Georgia, the Georgia Power ROE and recovery of Vogtle overspend. If you could paint any kind of broad strokes on what assumptions might be baked in on those two items into your guidance there?

We're always, I think, reasonably cautious and relatively conservative on our guidance. The only thing I would just say is that for the system, it is a reasonable estimate of what we expect to earn across the system. We're not pushing numbers in order to hit those ranges.

Got it. That's helpful. And then maybe just one on 2021 itself guidance there implies, kind of, a smaller step up year-over-year. Are there any meaningful drivers to this outside of Vogtle ROE penalty?

No. I would say that the Vogtle ROE penalty is the single largest driver that depresses earnings in 2021, almost $0.24 a share related to our constructions there, very consistent with an agreement that was reached with the commission a couple of years ago.

Very helpful. That’s it for me. Thanks.

You bet.

Thank you.

Thank you. And we now have a question from the line of Michael Lapides with Goldman Sachs. Please go ahead.

Hi, Michael. How are you?

I’m well. Thank you for taking my question. There's been some interesting dynamics at the FERC with some of the utilities having made filings regarding having the FERC review potentially a grid operator like structure in the Southeast. Can you just give your views on where you think that's going? What do you think the point is? What do you think the consensus is? You talked a little bit about the difference between regulated markets and the merchant power markets. And it just made me think of having seen a little bit of those filings and trying to understand where the long-term goal is.

The long-term goal is for us to not break what's working. And so when you look at these markets down here, we've been able to provide for clean, safe, reliable power for decades for our customers' benefit. And the data just overwhelmingly supports that. When you look at the so-called organized markets, I think there's a certain amount of chaos in those markets where I think, originally, people with great goodwill thought they would reap great benefits. I don't think the risk return that we see in those markets benefits customers at all. You know recently, we've submitted, we think, even an improvement to our own wholesale markets. That is the same effort, which, frankly, is a model that allows us to benefit renewables, particularly solar in a more efficient way, and it broadens the market to bring in people like Duke and TVA and others. And so we've broadened the market. I think we've made it more attractive to renewables because we believe that renewables are going to be really important as we transition the fleet. We'll continue to seek ways to improve our markets over time, but they're working well. I can't believe anybody would find the wisdom to throw that out right now.

Got it. Thank you, Tom. Much appreciate it.

Yes, sir. Thank you.

Thank you. We now have a question from the line Paul Fremont with Mizuho Securities. Please go ahead.

Hello, Paul. Great to hear from you.

Great talking with you. My first question is a pretty technical question. For Southern Power, are the targeted investments inclusive of tax equity, or are the – or does that represent your share of what you are planning on spending?

I would say that today, this represents our share. But as we evaluate all of these projects and as they go into commercial operation, we've looked at a number of alternatives or ways to optimize the returns that we receive there. This 1.3 actually represents all capital being deployed at Southern Power.

And I think the big chunk of that is a wind deal. There is a little bit of a storage deal. The wind deal, we kind of like. It's got the 10-year profile. Where we did a lot of the tax equity, I guess, was on the solar. We had the big pop in one year, and we didn't particularly like the impact of all that in our financials.

So Southern Power is an animal [ph]. I would say that rather than us trying to define an amount of capital that we're interested in deploying there, projects tend to draw capital from the parent when they can meet certain criteria. Many of the things that we found over the last couple of years have been largely in the solar – I'm sorry, in the wind arena because we're able to find better contract terms, better contract counterparties, and construction risk is generally handled by others. And we've been pretty fortunate, I think, the last couple of years this particular plan includes a couple of identified wind transactions. And as Tom said, two battery transactions in the California marketplace where we're building attendant to our own solar, and that will give us a tremendous amount of experience in attaching storage to solar that we'll look at deploy across the balance of fleet and in other locations.

Great. And then my second question, if I go back to staff testimony, I think what they were suggesting back in the fall was that you guys were hoping to get all of your ITAAC – remaining ITAAC approvals done by March, which would have been like over 240. But now when we get to mid-March, which is the start date of your hot functional testing, they'll still be about 200 that you need to get in hand based on the numbers that you provided today.

That's right.

What gets you to, sort of, accelerate the level of ITAAC approvals to such a high extent to allow you to load the fuel in July?

You bet. And thank you for -- Paul, for shining light on that important issue. We believe that the ultimate filing of ITAACs, we've accomplished a lot with the NRC, frankly, over the life of this project, and we've shrunk down, what was it, about 875 or something down to about 4.25 or somewhere. And we've adopted the practice of the UIN. That is we filed the form and substance of an ITAAC and have that approved. So really, all we have to do now is essentially fill in the blanks as to the result of a test. As a result, by working with the NRC in this constructive way, I think once we get the systems in place to submit the results in the ITAAC, I think the ITAAC process is going to go really well. Like I say, the NRC has been great in this regard. And recall, we got NRC personnel all over the plant, working with us to make sure all this happen. Paul, the issue was not ITAACs. The issue is getting the systems done, getting the turnover appropriate with the testing appropriate and, the paper, as we pointed out before, appropriate, so that we can file in -- put in the values in these ITAACs and submit them. So I said this, I think, on the last call, and I made a big deal about it, when I say paper, it almost feels too glib. This idea of having engineers present, this would be back to our own, the NRC, that will evaluate the as built condition of the plant and harmonizing that to the design basis of the plant and making sure it exactly meets our standards, is really taking a lot of time, and it is a complex exercise. The most important thing we can do is assure that we have quality. That will permit the ITAAC process to go well. Frankly, it will permit the testing processes that we will do now HFT to go well. So the filing of ITAAC is simply associated with system turnover of these important processes within the plant.

Mr. Fremont, do you have any further questions?

No, thank you.

Thanks, Paul.

Thank you sir. And now we have a question from the line of Andrew Levi with HITE Hedge. Please go ahead sir.

Andrew, how you're doing?

I’m all right. I think most of my questions were answered. I was taken as listening this call, you'll probably get Vogtle before you're seeing offshore wind gets done. What do you think? I think -- bidding on that. It's funny how things happen. So seriously, though, I think I understand everything that you're saying as far as the potential renewable spend and the transmission and possibly distribution around that. Just on -- as far as the time line, so I guess at some point this year, hopefully soother rather than later, we hear from the Biden administration on what their plan is as far as their energy plan. And then probably, I guess, November, hopefully, knock on wood, Vogtle 3 goes into operation. At that point, I guess, is that when you'll kind of have a better idea of how much incremental CapEx is going to be? And I guess, kind of just kind of doing back-of-the-envelope and some conversations I had with you guys, I'm thinking it probably could add 200 basis points to the electric utility rate base growth longer term from the 4% to the 6%. Again, I don't want to put numbers out there that you're not comfortable talking about, but that's kind of like a time line and thinking that I have as far as finding out and will remain that – going with all this.

Well, I'll tell you my friend, here's let me give you a couple of ways to think about it. Number one, the key is going to be these IRPs that – where we do this integrated resource planning, no kidding. And so as we submit those and have those approved ultimately with each of our states, we have a very good idea as to how the CapEx forecast will change, whether fleet transition occurs, to what degree, what about transmission, the whole pit, that will be very illuminating. In advance of those important regulatory processes, we already have an ELG kind of requirement put out for our coal unit. And so some of those units are already on the thin economic margin as you add new requirements to them. I think that may cause us to accelerate that conversation with our commissions. But rest assured, you guys -- you know us exceedingly well. I think you and I were laughing with each other not long ago. I think you and I go back maybe 30 years in talking about our dogma in dealing with state regulation. We will not get in front of the regulators and the regulatory processes with you or anyone else. We're going to let those things play out, and then we'll reflect that in our plan but as it shows up.

Yes. And Andy, I would just add that this is a complex topic, and I'll just start by saying ELG limitation guidelines, I'd like to use an acronym on the call, which will regulate sort of mercury and slim and a couple of other things that come out of our facilities, we'll have to make some choices about how we – whether or not we control those facilities, put them into limited use or ultimately retire those facilities. The one thing that is certain is that if you look at the technology that's available to us today, it's not a simple substitution of what we currently generate with to what the future might look like. There are certain changes in material science that need to occur. There are certain complexities related to clean, safe and reliable power that have to be met. There are transmission considerations that have to be taken into account. And – but if you wanted to put a big, broad bow to wrap around it, if we have to do 10 gigawatts, and let's say that 7 of that is replacement or that 3 needs to be held in reserve for some period of time, you could think about numerically what the replacement of something like that amount of generation would require and make the assumption that we probably have to do 15% or 20% of that total CapEx in addition in transmission distribution. So there are ways to kind of come around – come to what's the size of this, ultimately, I think, for the company.

And so let me give you a head start like what do you want to say. I would argue you have kind of this. I'm giving you caveman math now. So looking at that forecast, I'll bet you, I kind of gave a few numbers already. If you were to fill out our $0.5 billion per year, there's $2.5 billion, add another $1 billion for transmission. And then on top of that, put in some estimate, probably backend loaded on generation replacement. And it's easy to see that I think you could get to don't hold me to this, and we're not forecasting it flat. But added to the CapEx forecast, $5 billion to $8 billion over this time frame. I don't think that's unreasonable. And you can do the math on what that does to your growth rates. That's easy.

Okay, okay. Yeah I can add, subtract, multiply and divide.

No, you're a genius. I love this.

Thank you. Thank you very much guys.

Oh, you're the best. Thank you.

Thank you. And now we have a question from the line of Paul Patterson with Glenrock Associates. Please proceed sir.

Hi, Paul thanks for being with us.

Hi. Good to be here. So just on the COVID impact on Vogtle, it looks like you guys have taken into account not just your current experience but what you expect in the future. And I see what you guys give us good data on how infection rates have been trending. I'm just wondering, what is your expectation going forward about the impact of COVID on construction of Vogtle? And I apologize if I missed this, but are your people getting vaccinated? Are there essential workers that -- it varies from state to state it seems. So I was just wondering -- I was just wondering sort of what -- if you can just elaborate?

Yeah. Sure, you bet. So I help lead the ESCC, Electricity Subsector Coordinating Council, for this industry. It started with cyber and went to physical national security matters. It has grown into storm response and now COVID. We have had lots of good dialogue with HHS and a variety of other people about the right classification for utility workers. And you got to be proud of this industry through this crazy hurricane season we had last year, we were able to adopt cutting-edge COVID protocols and get the lights back on, the wires up and the plants running again. So we've done a good job. I would argue that these guys, particularly the people that work hard to keep the lights on, and our hearts go out to them and thank them for their hard work this year. They should be treated as critical resources for this nation and, therefore, get a very high priority to receive vaccination. It is, though, at the end of the day, despite what the CDC will recommend, it is the option of each state to deploy those vaccines. Now we've got great relations in each state, particularly in Georgia, where Vogtle is, there's been a lot of discussion. And I have to make sure that the folks that can get the vaccines are -- it's available to the folks at the site. I'm going to guess that they may be able to get vaccines maybe within a month or so, but that's highly uncertain and depends upon the ultimate deployment within the state.

Okay. Okay. And then just on COVID-19. I'm just as you know, there have been some papers and stuff out there indicating that perhaps the long-term economic impact could be pretty substantial. When you talk about your plans and just talk about utilities in general, one doesn't really tend to think that that -- your growth or whatever would be impacted by that or that whether there have to be some big deviation if, in fact, the economy does change as a result of COVID-19, or what have you. Is that pretty much -- is that just roughly speaking, sort of, the way to think about this?

Paul, let's Drew and I tank this one. Let me go first and I'll shut up and let you go. But here's what I see. From my past – to the Fed, I'd love to break the industrial segment, particularly as a great leading indicator into 10 big segments for Southern. And then not only do I look at period-versus-period results. Virtually all of it is still negative compared to a year ago, obviously, pre COVID. But the momentum statistics are really illuminating now, and they have turned positive. So of the 10 segments that make up something like 80% of our industrial sales, eight of them from a momentum standpoint are turning positive. So that tells me, and with a quote that has been put out there by me in the past, America is learning to live with COVID. A, I think COVID incidences are starting to decline. Maybe that's the normal sign wave we see from any surge, which we just went through. And maybe it's the longer-term effect of getting more people vaccinated. Didn't the Biden administration say recently, they want everybody vaccinated by July or sometime this summer? So surely, that will have an impact. But the economic data I see would show a recovery, I don't know, down 3% last year, maybe up 2% to 3% this year, with industrial starting to respond in a favorable manner.

Yes. I always worry about the long-term implications of something like this because the pressure that we put on folks on the margin or the COVID puts on folks on the margin will reveal itself. We've been served 60 days away from COVID ending for now 10 months. And so it'll be interesting to see where we come out. Our expectation around how it would impact our particular customers actually was quite different than what we expected on the onset. So we expected that retail customer usage would increase as people stayed home. We actually expected industrial production would maintain itself – would decline a little bit but not quite as drastically as it has and that commercial customers would be impacted most acutely, and it was very – it was a very different outcome. Commercial customers found a way to do business in a different way, not all, but most. And industrial went through a period where there was sort of a reduction in output as because inventories were at a reasonable level and they could sort of pare down that inventory as they saw the economy progress. We've now seen sort of a tightening in supply in a number of the industrial segments, and production has started to pick up. And there have always been two or three standout weak segments in any particular two or three month period. But as Tom said today, the momentum is generally positive, and we're encouraged by the fact that people have adapted their businesses to earn profits in a way that they maybe hadn't anticipated two years ago. But yes. I or – a year ago, I always worry that the longer anything goes, the more pressure you're going to put on somebody on the margin for sure.

In quick punchy stats, non-pharma employment fell nationally 6.2%. In the southeast, it was only 1.7%. Last year, in our territory, we had record job creation, best we've ever done. We're seeing an increase. I want to say the increase in jobs projected in our economic development group that we're showing that's kind of our headlights, up 17%. And then you see events like Microsoft coming in developing Atlanta as their third hub. There are other hubs being, of course, Seattle and San Francisco or Silicon Valley. Look, I'm not going to paint a super rosy picture, but I will say the southeast is really resilient. What's down right now? Chemicals are down mostly. We see that is driven by a large outage in particularly one plant in Alabama.

And some global demand for chemical, which might change the marginal economics of a single facility for sure.

And what kind of looks bright, it looks like pipeline, especially as we start seeing gas continue to displace coal, the pipes are doing pretty well.

Okay, great. I really appreciate it. Thank you.

You bet. Thank you.

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

Well, thank you. These are exciting times, and I know the folks around our system that made the system perform as well as they did in 2020, just a great debt of gratitude. And I want to commend specifically our recovered workers, particularly IBEW and the folks from the broad building trades all around the system, particularly at Plant Vogtle 3 and 4, the leadership of the IBEW, the leadership of the building trades, they are terrific business partners for us, and we could not have achieved this level of success without their great leadership and the great work of the folks that are members there. I really like the cards we have. I like the fact that we have a lot of optionality no matter what the future holds. And I think we've run this business over the past decade to leave it stronger than ever. We'll get through Vogtle 3 and look forward to the progress there. We'll get through Vogtle 4 next year, and we're off and running. Thanks, everybody, for your attention today, and we'll talk to you soon. That's all.

Thank you, sir. Ladies and gentlemen, this concludes The Southern Company fourth quarter 2020 earnings call. You may now disconnect. Thank you all once again. Have a great day.