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 four quarter 2020 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. At that time, if you have a question, please press the one followed by the four on your telephone. As a reminder, today's conference is being recorded Thursday, February 18th, 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. 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. 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 standing 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. As well, our long-term efforts with the states that we serve on economic development efforts continue, helping capital investment and job growth in the communities we're privileged to serve. The social pandemic. I am also proud of our ongoing commitment to foster racial justice. For years, this has been an effort of Southern's to focus on building a healthy culture. Even before the unrest last summer, we initiated an effort to donate $50 million to historically Black colleges and universities. Last summer, I told you that meaningful discussions were underway across our company related to our actions and response. While these conversations will continue, an initial outcome is that we have refocused our efforts towards a more holistic goal of diversity, equity, and inclusion, ensuring that all groups are welcomed, well-represented, engaged, and fairly treated throughout the organization. As an example of this commitment, the Southern Company Foundation recently announced a partnership with Apple, where each are investing $25 million to launch the Propel Center, a new digital learning hub, business incubator, and global innovation headquarters located in Atlanta for students throughout the nation of historically Black colleges and universities. Finally, the political pandemic. I also want to address the political discord that our nation has experienced over the past several months. At Southern, we have consistently prioritized working with policymakers regardless of political party, and we have been working constructively with the Biden administration for months. In fact, we have already engaged in matters related to energy policy, especially the transition to a net zero carbon future, as well as on matters related to national security. You'll see in the appendix a letter I sent to President-elect Biden pledging our support. As we continue to engage with the new administration, as well as legislators and regulators at both federal and state levels, our positions will continue to focus on energy policies that can enable a smart transition and be informed by our key objectives of providing clean, safe, reliable, and affordable energy to our customers. Let's now turn to an update on Plant Vogtle Units 3 and 4. We remain focused on meeting the November 2021 and November 2022 regulatory approved in-service dates for Units 3 and 4, respectively. With the start of hot functional testing expected in only a few weeks, we now expect a November completion for Unit 3. For Unit 4, we continue to utilize an aggressive site work plan as a tool to provide margin to the regulatory approved November 2022 in-service date. Unit 4's current site work plan targets a third quarter 2022 in-service date. From a cost perspective, Georgia Power's share of the total project capital cost forecast increased by $176 million, largely reflecting estimated COVID-19 impacts and other costs, along with a replenishment of contingency to fund future expected risks that will include lower productivity rates and increased support costs. As a result, Georgia Power recorded an after-tax charge of $131 million during the 4th quarter. 2020 marked another year of significant progress at the site. Throughout the year, as some other major projects around the country were shutting down or delayed due to COVID-19, Georgia Power and the Vogtle site team worked tirelessly to implement measures to keep the project progressing while prioritizing the safety of our workforce and the surrounding community. Similar to what was experienced across much of the U.S. during the last two months of the year and earlier this year, we saw a surge in COVID-19 cases at the Vogtle site, which, as you can see on slide six, peaked around the beginning of January. Excuse me. Since the onset of the pandemic, and most acutely during the 4th quarter of 2020, the impacts from COVID-19 have included high absenteeism and disruptions to planned or ongoing work as we isolated personnel. We estimate the pandemic has extended the schedule for both units by approximately three to four months, consuming much of the remaining margin to the November 2021 in-service date for Unit 3 and several months of margin for Unit 4. Unit 3 direct construction is now approximately 98% complete, and hot functional testing is expected to start in the coming weeks. On our last call, we identified three key risk factors to our timeline: electrical productivity, subcontractor performance, and what we call paper closure. Recall, paper closure relates to the turnover of systems to the testing group to help ensure that the as-built condition of the plant meets design specifications. Over the past few months, COVID-19 has hurt site productivity, negatively impacted electrical production, and impaired our ability to close paper issues that facilitate timely system turnovers and ultimately ITAAC submittals. The combination of these factors has delayed system turnovers and impacted our timeline for the start of hot functional testing. Based on our recent production trends, we now expect to start hot functional testing during the second half of March and start loading fuel during July. Starting hot functional testing and fuel load on this timeline would support a November 2021 in-service date, with up to one month of flexibility remaining in the schedule. Certainly, risks remain to this schedule. These risks may be thought of in 4 segments. First, the completion of system turnovers leading up to hot functional testing. Second, the successful completion of hot functional testing. Third, the completion of system turnovers leading to fuel load. 4, an orderly transition from fuel load to an efficient startup of the unit. Successful completion of hot functional testing this spring would significantly decrease the remaining operational risk to Unit 3 completion. Although certainly, challenges and risks will remain in focus as we focus to fuel load. ITAAC submittal and review is expected to continue to accelerate and will remain an area of focus. To date, 180 ITAAC have been submitted to the NRC. We expect approximately 20 additional ITAAC to be submitted by the start of hot functional testing, and the remaining 200 to be submitted during hot functional testing and as we approach fuel load. Direct construction for Unit 4 is now over 75% complete. Last month, we started integrated flush, and we expect initial energization to occur during March. To support the November benchmark, we will need to average construction completion of approximately 1.5% per month, which is in line with the average rate achieved during the period from last November through January. As we progress in 2021, construction production is expected to increase in support of our upcoming testing milestones. Importantly, as Unit 3 nears hot functional testing, we expect to shift additional resources to Unit 4 to increase our current pace of construction completion. Now turning to cost. During the fourth quarter, Georgia Power allocated its remaining contingency plus an additional $5 million and subsequently added new contingency of approximately $171 million to support completion of the project. We estimate the pandemic has extended the schedule for both units by approximately three to four months at an estimated cost to Georgia Power of between $150 million and $190 million. This cost is embedded in our updated total project cost estimate. While COVID-19 related impacts were significant drivers of the change of our capital cost forecast, future risks, including construction productivity, were contributing factors. Earlier this week, the Georgia Public Service Commission unanimously approved VCM 23, which included project capital costs through June 30, 2020. As a part of the order, Georgia Power was directed to work with the PSC staff to develop a mutually agreeable recommendation to the commission by the end of March regarding the process, timing, and substance of filings related to the transition of Unit 3 costs into base rates. Additionally, Georgia Power files VCM 24 today. The months ahead represent a critical and exciting time for Vogtle. The project team has worked tirelessly amid conditions none of us could have imagined just a year ago. Our employees, contractors, co-owners, and community partners should be commended for their perseverance and dedication to the completion of this important project. Drew, I'll turn it over to you now for an update of the financials and our outlook. Thanks, Tom, 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 our customers. We have worked closely with customers across our regulated utilities, offering special payment plans for those with past due account balances and have delayed disconnects. You can see the impact of our COVID-19 related protocols for disconnects in our customer counts for the year. Last year, our state-regulated utilities added just over 53,000 new residential electric customers and nearly 30,000 residential natural gas customers. Our electric customer growth was approximately 30% higher than our expectations. Overall, we estimate that about 80% of the residential electric customer growth in 2020 was due to continued and accelerating in-migration to the region, particularly in Georgia. The remainder is likely related to the steps we have taken to keep customers connected during the pandemic, particularly through the use of extended payment plans. During this time, customer arrears have tended better than we anticipated across our operating companies. We also have constructive mechanisms approved by the commissions in many of our states, allowing us to address incremental COVID-19 related costs, including bad debt expense. Those will be considered in future regulatory proceedings. In a trend that differentiates our service territory, the pandemic has strengthened population and job growth in the Southeast, particularly in Georgia, which is one of the fastest-growing states in the U.S. Robust economic development in the Southeast region is also a positive indicator that our key states are weathering the pandemic relatively well. In 2020, we saw new investment of nearly $6 billion and nearly 25,000 jobs created across Georgia and Alabama. In fact, Georgia was the number two state in the country for job creation in December. Just last week, Microsoft confirmed Atlanta as a major East Coast hub, which is expected to bring significant job growth and investment. Our state-regulated operating companies play an integral role in leading economic development efforts in each of their states. Turning now to our expectation for 2021, our guidance range for the year is $3.25- $3.35 per share. In the first quarter of 2021, we estimate that we will earn $0.84 per share. Included in our full-year guidance is an assumption that we will continue to see modest impacts on retail sales from COVID-19, which we expect to continue to mitigate through thoughtful cost control. Additionally, we expect total retail sales growth normalized for any short-term COVID-19 impacts to be flat to 1%. For the foreseeable future, this expected growth rate is driven by a combination of customer growth and ongoing improvements in energy efficiency. Moving now to our outlook for long-term growth, we see our long-term EPS growth rate in the 5%-7% range, consistent with adjusted earnings in a range of $4-$4.30 per share by 2024. With 90% of total projected earnings over the five-year plan horizon coming from our state-regulated utilities, our expected EPS trajectory has a solid foundation. Likewise, our history of constructive regulation, stable credit metrics, and ongoing focus on cost control serve to underscore the achievability of our plan. Looking more closely at our long-term capital investment plan, we continue to allocate 95% of our capital investment to our state-regulated utilities. Our capital investment plan of $40 billion for 2021 through 2025 includes annual projected rate base growth at our state-regulated utilities of greater than 5%, with a continued emphasis on transmission, transportation, and distribution modernization and resilience. For Southern Power, the cumulative five-year investment plan is comprised entirely of previously approved renewables projects and maintenance capital for the existing generation fleet, which is over 90% contracted for the next 10 years. Any incremental growth opportunities at Southern Power are expected to enhance the long-term financial plan and be largely self-funded and credit neutral. Importantly, this CapEx projection for the whole company does not include amounts for accelerated fleet transition and any associated transmission growth, nor does it account for new generation projects at Southern Power. We will be evaluating a number of paths over the next few years as it relates to fleet transition, but we do not establish placeholders in our plan, with virtually all projects being known in the process of or having already been engineered or have already begun. Taking a look at the balance sheet, we currently forecast no equity needs over our five-year plan horizon, even when considering the potential increase in capital investment I just described. We believe we are well-positioned to further strengthen our balance sheet and to improve our credit metrics materially during this time. I'll highlight that in January, we became the first large cap utility in the U.S. to publish a sustainable financing framework, and in the days that followed, Southern Power issued a five-year green bond under that framework that resulted in a record low coupon rate. This framework highlights Southern's ongoing commitment to a wide range of sustainability and social issues and should allow us to leverage our work in these areas to help optimize our balance sheet and benefit our customers. We will also continue our focus on societal priorities in the upcoming years. Before I turn it back to Tom, I'd like to echo his opening remarks. The resilience of our business has demonstrated amid the pandemic is a testament to the hard work our employees put forth each and every day. The ability of our employees to continually provide outstanding service to our customers, combined with the support of our communities and the constructive relationships we maintain with regulators and public officials, underpin our ability to also deliver such solid performance. I would like to particularly thank the people who work for and on behalf of our customers to meet our priorities, even in light of a global pandemic. We are all grateful. Thank you. Tom, I'll turn it back over to you. 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 net zero emissions by 2050. We will work constructively with the Biden administration to accelerate this timeframe 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%. Certainly, 2020 was an unusual year, and we may see emissions reductions move around 50% for the next two years. We believe we'll be sustainably above a 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. 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-minus 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. Before closing, I want to just take a moment to recognize a leadership transition announcement that we made at the end of last year. My trusted friend and one of my closest confidants, 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 Womack, 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. If you would like to register a question, please press the one, followed by the four on your telephone. You'll hear a three tone prompt, so it knows your request. If your question has been answered and you would like to withdraw your registration, press the one followed by the three. Once again, please press the one followed by the four now. One moment please for the first question. Our first question comes from the line at 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. You bet. Maybe just to kick things off on a light basis. 5%-7%, how are you thinking about the base year? You guys gave the $4-$4.30 a number. Can you talk about what's the baseline year for that? If I can throw it in there at the same time, that 5%-7%, how are you thinking about outside 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? Yeah, man, you bet. Hey, we did it a little bit differently this year. The way you should think about the base year is kind of a 2024 number that is $4-$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 the 5%-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. 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 half a 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. We elect not to put anything in the forecast. Secondly, we don't include any fleet transition. I think it's been very clear. 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. I think we can certainly achieve that. There are certain policy choices that will have to be made along the way. We are engaged constructively in that conversation. If you go to something like that, I think you will accelerate fleet transition. 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 with maybe Julien is that if you 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 5%-7% range historically. We've had some changes in that pathway a little bit because we've taken a penalty for Vogtle Construction. We'll see a little bit of that change as we move Vogtle into service. You get a bit of a wag in the way our growth rate might be delineated on a linear basis. What we're really trying to express is a longer-term potential for the business as we invest capital into it. 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 GW 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. I think 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, I didn't mention this one, I'll bet you there's at least another $1 billion of transmission. 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, I'm not often doing this, but complimenting 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. That actually creates a nice line going into the future. Yep. Julien, anything I didn't cover you wanted? Well, hey, listen, let me clarify that if I can, right? When does some of this CapEx start hitting? Whether it's in transmission or generation. When you guys have this 4% rate base trajectory through 2025. Well, I mean- It seems like that already translates to the 5%-7%. When you actually get this CapEx uplift, it sounds like that drives you higher within that 5%-7% range as I'm hearing you, right? Did you get something to say quickly here? Yeah. 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. 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, we'll make those plans known and approved by the commissions, as appropriate. The other thing you should know that heading into this call, I guess we showed 4% for electric. It was 5% probably a week ago. It's rounding. Okay? It's in the middle of 4%-5%. The gas business is growing at, like, 10%. The overall kind of supports a growth trajectory that is supportive of 5%-7%. You're right, when you think about starting with $4- $4.30, there is upside to a mid-range forecast there based on how we deploy capital over time. I think even with the base forecast that we're showing you today, we're within that range and we're comfortable at 5%-7% within that range in 2024. Yeah, absolutely. Great. Thank you for clarifying that all. Best of luck, guys. Talk soon. Thank you so much. Appreciate you calling in. Thank you. Up next, we have a question from the line of Steve Fleishman with Wolfe Research. Please go ahead, sir. Hey, Steve, how are you? How are you? Thank you. Hey, Tom. Good afternoon. Just a question. If you end up determining that you cannot meet the November deadline for Vogtle for some reason, could you remind us, what do you have to do with anything then? Do you have to make a filing? No You just kind of 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 express intention of moving off of what we had thought, I guess back in October, may have been a 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. 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? 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 I mean, Unit 3 only, it's about $25 million. If, however, we shift and it is a delay 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. Depending on when the delay occurs, there would just be an additional cost that we're factoring in. 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 that 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 the only thing mechanically. No, this November. Yeah. 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. That would be the material thing to model. That's right. You start losing that penalty rate once you declare in-service. Okay. Because I know for a long time we've had November as this regulatory approved deadline. Yeah. If there's a new deadline or whatever, you don't need to go back and seek a new deadline or anything like that? You just finish it. No. Go through the VCMs as is? Yes, sir. There's nothing special. The VCM process we've been filing has been really effective at kind of handling those issues. As you guys know, you follow those VCM filings very clearly. That's kind of the way we would handle it. Okay, one other just quick global question that 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. Oh, no. I would argue. Hey, look, Stephen 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. Okay. You know, the NRC is a very tough. Thank you. Yeah. Yeah. The NRC is a very tough regulator. 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. 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. Just to follow up on Julien's question, the 4% rate base growth profile for electric and when I look at that overall, I'm just thinking that once you get to the 2024 range and the penalties are out, right? Removing the penalties is the main driver of five to seven, I'm guessing, the through 2024. Yeah, that. Yeah. Yeah. Michael, excuse me. Those penalties will expire as we move to in-service for each of the units. They expire by degree. Right. If 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%-7% is what we think we can sustain and have sustained over recent history without this step change in the Vogtle uplift moving into rate base. Okay. I was thinking that the five to seven is simply sustained by increasing the CapEx profile and increasing the rate base growth profile. It is a sustainable growth rate beyond the uplift from Vogtle. It sounds like it actually. Yeah. I'm thinking any increase in renewable CapEx or decarbonization CapEx actually improves on that at five to seven, right? Pushes you up. Yes, it would. Yeah. Absolutely. Yeah, Mike, we're pretty focused. The durability of spend, I think, is the way we think about it, trying to expend a 5%-7% range as long as we can. If you sort of draw the line between what we've laid out today as our earnings expectation for 2021, take a look at our projection for 2024, you can see that sort of falls outside of the range that we've intimated at 5%-7%. We think of that really as being more of a longer-term sustainable growth rate in absence of single large project risk. Yeah. The way you should think of that 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%-7% growth rate. We think that's the right way to think about this. It looks like most of the increase, or almost a third of the increase in CapEx in this new plan is at Southern Power. That's this year. 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 or so? No, in fact, 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. If you look at it over a longer period of time, a three or a five-year average, very close to the $500 million that you're marking that business. Yeah. 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 this forecast. Yeah. That's right. A year you'll be adding. Yep. Like I said before, there's probably an additional $1 billion, who knows, on transmission. Whatever happens on fleet transition, there's something else there. Yeah. I think what we've given you is kind of a bare-bones approach, which we think is appropriate. That supports the five to seven. 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 represent maintenance of those facilities over time. You've 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, cautious on it, saying that returns have been tight. You've been pulling back on spending at Southern Power. Are you reversing that stance now? Are you thinking, oh, there may be more opportunity, not less, going forward? No. In fact, I hope I put those words in. I thought I put those words in there. The returns have been thin. The terms and conditions have been tougher. The duration of the contract has been shorter. All I'm saying is, and that's really the reason why we don't include capital commitments 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. They're certainly not now. Got you. Okay. Thank you. Yes, sir. Thank you. Thank you. 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? Fantastic. I have two questions. One, obviously, about Vogtle. We're all waiting for hot functional testing to start. We have some concerns if it's going to uncover any sort of a catastrophic flaw of the project. 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? Yeah. Angie, knock on wood, and don't show overconfidence or what have you. The Chinese plant that went through hot functional tests 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. Okay. There's nothing that I know of that would cause me concern right now. Hey, 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. Something completely unrelated. Given what's been happening in Texas, I understand it's a completely different design of the power market, 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. Again, lots of differences between your service territory and ERCOT. 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. It was a great topic of interest and discussion about what about Texas? 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. We've been able to do that for decades, 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. Minimizing short-run marginal costs. 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, I'm sorry, not transmission, like backup generation, like resiliency, like other things, you get to really complex kind of 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 baseload capacity as it should be. 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. 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. It was interesting, not only did I have this conversation on CNBC this morning, and I guess I'll just be a little abstruse 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. 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's 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. Hey, 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, as 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 along 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. 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 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. We'll be doing that. Okay, great. 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%-7% earnings growth thereafter. What's your current thinking on the outlook for dividend growth once we're past the Vogtle construction? Of course, that's a decision of the board, and we'll make, obviously, recommendations to the board. 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. 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 as a premium to its peer group, relatively in PE, in periods where we didn't pose headline risk, and in periods where our credit was a little bit stronger than where we stand today. All these things are going to be considerations as we go forward. Consistent with what Drew just said, and we typically say it on every call, we didn't say it yet, one of the other outcomes of kind of this reset and moving to the higher rate, not just earnings per share growth improvement, cash flow improvement's 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. Hey, Jeremy. How are you? Hey, good. Thanks for having me. Good afternoon. Good afternoon. I just want to reach out to the 2024 guidance as you laid out there, and thinking about 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. Maybe just one on 2021 itself, guidance there. It implies kind of a smaller step-up year-over-year. Are there any meaningful drivers to this outside of Vogtle ROE penalty? 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. Thank you. We now have a question from the line of Michael Lapides with Goldman Sachs. Please go ahead. Hey, Tom. Hey, Michael. How are you? I'm well. Yes, sir. 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 kind of the merchant power markets. It just made me think of having seen a little bit of those filings and trying to understand kind of where the long-term goal is. The long-term goal is for us to not break what's working. 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 SEEM 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. We broaden 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 appreciated. Yes, sir. Thank you. Thank you. We now have a question from the line of 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 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. 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. Yeah. Southern Power is an interesting animal. 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've found over the last couple of years have been largely in the wind arena, because we're able to find better contract terms, better contract counterparties, and construction risk is generally handled by others. 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. That'll give us a tremendous amount of experience in attaching storage to solar that we'll look at deploying across the balance of fleet and in other locations. Great. 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 remaining ITAAC approvals done by March, which would've been over 240. Now when we get to mid-March, which is the start date of your hot functional testing, there'll still be about 200 that you need to get in hand based on the number 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. Thank you, 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 four and a quarter or somewhere. And we've adopted the practice of the UINs. That is, we've filed the form and substance of an ITAAC and had that approved. 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. Recall, we got NRC personnel all over the plant working with us to make sure all this happens. Paul, the issue is 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 put in the values in these ITAACs and submit them. I said this, I think, on the last call, and I made a big deal about it. When I say paper, that almost feels too glib. This idea of having engineers present, this would be Bechtel, 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. 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 so much. Thanks for joining us. Thank you, sir. Now we have a question from the line of Andrew Levi with HITE Hedge. Please go ahead, sir. Andrew, how you doing? Hey, guys. I'm all right. I think most of my questions were answered. I was thinking as listening to this call, you'll probably get Vogtle 4 done before this New England offshore wind gets done. What do you think? I think I can make money betting on that. It's funny how things happen. 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 far as the timeline, so I guess, at some point this year, hopefully sooner rather than later, we hear from the Biden administration on kind of what their plan is as far as their energy plan. 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 there's going to be? I guess 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%-6%. I don't want to put numbers out there that you're not comfortable talking about, that's kind of like a timeline and a thinking that I have as far as finding out and where we may end up going with all this. Well, I'll tell you, my friend. Let me give you a couple of ways to think about it. Number one, the key is going to be these IRPs, where we do this integrated resource planning. No kidding. As we submit those and have those approved ultimately with each of our states, we'll 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 bit. That'll be very illuminating. In advance of those important regulatory processes, we already have an ELG kind of requirement put out for our coal unit. 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 commission. Rest assured, you know us exceedingly well. In fact, 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 in 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 as it shows up. Yeah. Andy, I would just add that this is a complex topic. I'll just start by saying ELG, effluent limitation guidelines, unlikely to use an acronym on the call, which will regulate sort of mercury and selenium and a couple of other things that come out of our facilities. We'll have to make some choices about 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. If you wanted to put a big broad bow or wrap around it, if we have to do 10 GW, and let's say that seven of that is replacement or that 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%-20% of that total CapEx in addition in transmission or distribution. There are ways to kind of come to what's the size of this ultimately, I think, for the company. Let me give you a head start. Everybody's thinking, what are you going to say? I would argue you have kind of this. I'm giving you caveman math now. Looking at that forecast, I'll bet you, I kind of gave a few numbers already. If you were to fill out our half a billion per year, there's $2.5 billion. Add another $1 billion for transmission. Then on top of that, put in some estimate, probably back-end loaded, on generation replacement. It's easy to see that I think you could get to, don't hold me to this, and we're not forecasting this way, but added to the CapEx forecast, $5 billion-$8 billion over this timeframe. I don't think that's unreasonable. You can do the math on what that does to your growth rates. Right. That's easy stuff to do. Okay. Yeah, I can add, subtract, multiply, and divide. I'm good. No, you're a genius. I love this stuff. Proven. Okay. Thank you very much, guys. Oh, you're the best. Thank you. Thank you. Now we have a question from the line of Paul Patterson with Glenrock Associates. Please proceed, sir. Hey, Paul. Thanks for being with us. Hey, good to be here. Just on the COVID impact on Vogtle, looks like you guys have taken into account not just your current experience, but what you expect in the future. I see what you guys give us good data on how the infection rates have been trending. I'm just wondering, what is your expectation going forward about the impact of COVID on construction of Vogtle? I apologize if I missed this, are your people getting vaccinated? Are there essential workers, it varies from state to state, it seems. I was just wondering sort of what people elaborate. Yeah. Sure, bud. You know 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. You got to be proud of this industry through this crazy hurricane season we had last year. We were able to adopt kind of cutting-edge COVID protocols and get the lights back on, the wires up, and the plants running again. 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, Joe, 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 about how to make sure that the folks that can get the vaccines, 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. Just sort of on COVID-19, as you know, there's 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 your growth or whatever would be impacted by that or 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 just roughly speaking, sort of the way to sort of think about this? Hey, Paul, let Drew and I tag-team this one. Let me go first, and I'll shut up and let you go. Here's what I see. From my past work at the Fed, I love to break the industrial segment, particularly as a great leading indicator into 10 big segments for Southern. 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. The momentum statistics are really illuminating now, and they have turned positive. Of the 10 segments that make up something like 80% of our industrial sales, eight of them from a momentum standpoint are turning positive. 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. I think COVID incidences are starting to decline. Maybe that's the normal sine 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? Surely that'll have an impact. The economic data I see would show a recovery, I don't know, down 3% last year, maybe up 2%-3% this year, with industrials starting to respond in a favorable manner. I always worry about the long-term implications of something like this, because the pressure that we put on folks on the margin or that COVID puts on folks on the margin will reveal itself. We've been sort of 60 days away from COVID ending for now 10 months, 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. 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. It was a very different outcome. Commercial customers found a way to do business in a different way. Not all, but most. Industrial went through a period where there was sort of a reduction in output 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. As Tom said today, the momentum is generally positive, and we're encouraged by the fact that people have adapted their businesses to earn pro - fits in a way that they maybe hadn't anticipated two years ago. Yeah, 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-farm 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%. You see events like Microsoft coming in, developing Atlanta as their third hub, their 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 as driven by a large outage in particularly one plant in Alabama. Some global demand for chemical, which might change the marginal economics of a single facility for sure. What kind of looks bright? 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. 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 it did in 2020, just a great debt of gratitude. I want to call out 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. 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. 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.