Earnings Call Transcript - SO Q4 2021

Operator, Operator

Good afternoon. My name is Chris and I will be your conference operator today. I’d like to welcome everyone to The Southern Company Fourth Quarter 2021 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. I would now like to turn the call over to Mr. Scott Gammill, Investor Relations Director. Please go ahead, sir.

Scott Gammill, Investor Relations Director

Thank you, Chris. Good afternoon and welcome to Southern Company’s year-end 2021 earnings call. Joining me today are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company, and Dan Tucker, Chief Financial Officer. Let me remind you, we’ll be making forward-looking statements today in addition to providing historical information. Various important factors could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our Form 10-K, Form 10-Qs and subsequent filings. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measure are included in the financial information we released this morning as well as the slides for this conference call, which are both available on our Investor Relations website at investor.southerncompany.com. At this time, I’ll turn the call over to Tom.

Tom Fanning, Chairman, President and CEO

Thank you, Scott. Good afternoon and thank you for joining us today. As you can see from the materials that we released this morning, we reported strong adjusted earnings per share for 2021, exceeding both our original 2021 guidance and the estimate that we provided on our third-quarter call. This performance is due in no small part to our outstanding service territories and the unparalleled commitment of our employees to deliver clean, safe, reliable and affordable energy to our customers. Our outstanding customer service, our commitment to the communities we serve and our proactive engagement with our stakeholders are reflected in the numerous honors we’ve highlighted in our slide deck, including recent recognition as number two in the nation on Forbes 2022 list of America’s Best Large Employers. Many of the initiatives that support this distinction are reflected in our inaugural transformation report which we released earlier this week. This report details our sustained commitment and actions to further advance equity, both within our company and our communities. These commitments allow Southern Company to help lead change within our communities and provide an enduring reflection of our values. We are proud of the progress we have made and continue to recognize the opportunity to do more. As an example of the work we’re doing to drive our customer satisfaction results, a meaningful portion of our capital plan in recent years has been allocated to the continued modernization of our electric grids. Our grid automation strategies and investments are delivering real value to customers. And in 2021, our customers experienced 15% fewer minutes of interruptions. Similar initiatives will continue to be a major component of our capital plans going forward. Across all of our stakeholder groups, including employees, customers, communities and investors, we’re focused on sustainability and a long-term view of value. That objective remains sound. The long-term financial plan that we outlined for you last year remains intact. And we are reaffirming our 5% to 7% long-term growth rate expectation, consistent with adjusted earnings per share in a range of $4 to $4.30 in 2024. Let’s now turn to an update regarding some of the recent developments related to our progress on Plant Vogtle units three and four. As you can see in the materials provided earlier today, we updated our expected completion timeline for both units, extending the in-service dates for each unit by three to six months. As we discussed on previous calls, the paper process is a critical aspect of turning plant components and systems over from construction to testing and operations. We have discovered incomplete and missing inspection records concerning much of the materials and equipment that have been installed at Unit 3. These inspection records are an important part of the documentation that is necessary to file ITAACs. Our progress on Unit 3 ITAAC has slowed as we address a backlog of tens of thousands of inspection records needing completion to support system turnovers. Through hard work over the last several weeks, we have reduced this backlog by more than 30%. Documentation within these inspection records is a critical aspect of getting it right, and the time and resources to complete the remaining inspection records and remediate construction issues identified in the process, including the impact of borrowing Unit 4 resources, are key drivers for the change in schedule. We have 123 ITAACs remaining for Unit 3. The revised ITAAC completion schedule we’ve included in our slide deck is consistent with a three-month change in the Unit 3 schedule. Over the past year, a number of challenges, including shortcomings in construction and documentation quality, have continued to emerge, adding to project timelines and cost. In recognition of the possibility for new challenges to emerge, we further risk-adjusted our current forecast by establishing a range of three to six additional months for each unit. And we’ve reserved for the maximum amount. We continue to make meaningful progress on both units. Notably for Unit 3, all 157 fuel assemblies have been loaded into the spent fuel pool in preparation for fuel load. For Unit 4, direct construction is now approximately 92% complete, open vessel testing has started, and we recently completed the structural integrity and integrated leak rate tests without issue. The aforementioned challenges on Unit 3 are serving as lessons learned for Unit 4 and have benefited our performance on Unit 4 to date, relative to Unit 3. First-time quality on both construction and documentation are key areas to focus. Our priority is bringing Vogtle Units 3 and 4 safely online, and again, to get it right, to provide Georgia with a reliable carbon-free energy resource for the next 60 to 80 years. With this most recent change in project costs and schedule, provisions in the Vogtle 3 and 4 co-owner agreement came to the forefront, requiring the owners to affirmatively vote to proceed with the project. Vogtle 3 and 4 is incredibly important to the state of Georgia and its robust growing economy. Furthermore, the addition of 2,000 megawatts of baseload carbon-free energy is vital to increasing the availability of net-zero energy resources across the state. Considering the facts and our proximity to commercial operation, Georgia Power has already voted to proceed. The other owners are required to vote by March 8th, which allows time for them to work through their own governance processes. Consistent with the schedule extension of up to six months additional for each unit, Georgia Power’s share of the total project capital cost forecast increased by $480 million, largely as a function of time, additional resources to complete the remaining work with the necessary focus on quality construction and documentation, and the replenishment of contingency. We continue working constructively with our co-owners to resolve different interpretations of the cost-sharing agreement within the expected potential range of outcomes of $100 million to $900 million. We have included $440 million of the $900 million in our total project cost estimates. In aggregate, Georgia Power’s resulting total capital cost forecast is $920 million. And as a result, Georgia Power recorded an after-tax charge of $686 million during the fourth quarter. We value our partners on Vogtle 3 and 4 and the relationship we’ve had with them across multiple assets for decades. We look forward to our continued partnership on each new unit as they transition to commercial operation, providing millions of Georgians with clean, safe, reliable, and affordable electricity for decades to come. Before turning the call over to Dan for an update on our 2021 financial performance and our long-term outlook, I’d like to briefly touch on Georgia Power’s triennial Integrated Resource Plan, or IRP, which was filed with the Georgia Public Service Commission late last month. The proposed plan sets forth a proactive, innovative and transformational roadmap for how Georgia Power expects to support customers in its growing service territory for decades to come. Consistent with Southern Company’s path to net zero carbon emissions, the plan describes a tangible path to transition Georgia Power’s generating fleet to cleaner, more economical resources. This plan includes the retirement of all of the coal units Georgia Power controls by 2028, except for Plant Bowen Units 3 and 4, which are scheduled to be retired no later than 2035. The plan also includes a request for the addition of 6,000 megawatts of renewable generation by 2035, more than doubling Georgia Power’s current renewable resources. Additionally, 1,000 megawatts of storage is requested by 2030 to improve the capacity value of these intermittent resources. In recognition of the changing energy landscape, Georgia Power proposed innovative programs to promote reliability and resilience, including a distributed energy resource program. The comprehensive long-term plan also addresses continued investment in our transmission system and energy efficiency programs for customers. The IRP is subject to the review and approval of the Georgia Public Service Commission. Hearings will take place during the first half of 2021, with a final decision due this summer.

Dan Tucker, CFO

Thanks, Tom, and good afternoon, everyone. All of our major subsidiaries had a strong 2021. As a result, our full-year adjusted earnings were $3.41 per share, $0.16 higher than adjusted results in 2020 and $0.06 above the top end of our original 2021 guidance range. Financial performance for the year was highlighted by strong customer growth, improving retail sales trends and continued investment in our state-regulated utilities. These positive factors were partially offset by milder temperatures throughout 2021, resulting in a negative $0.05 variance for weather as compared to 2020 and a negative $0.14 variance compared to normal weather. Additionally, 2021 non-fuel O&M reflected the trend towards more normal operating conditions relative to the significantly reduced levels in 2020. A detailed reconciliation of our reported and adjusted results compared to 2020 is included in today’s release and earnings package. Weather-adjusted retail electricity sales were up 2.4% compared to 2020, approximately 1% better than our forecast for 2021. Almost all of this positive variance can be accounted for in residential electricity sales as a result of continued robust customer growth and an extension of the increased usage trends, which began in 2020. Residential sales outpaced our expectation for the year by 2.7%, reflecting what we think could represent a transition to sustained hybrid work practices across our service territories. We continue to analyze retail electricity sales relative to pre-pandemic levels. And in aggregate, in the fourth quarter, our weather-normalized retail electric sales exceeded sales in the fourth quarter of 2019. We are encouraged by these trends, and we’ll continue to monitor the implications of supply chain constraints, labor force participation, and inflation pressures on our outlook. Our stronger-than-expected customer growth is a trend that differentiates our service territories. Over the last two years, we’ve added an average of nearly 55,000 new residential electric customers and 30,000 residential natural gas customers across our regulated utilities. Average residential electric customer additions were 43% higher over the past two years than the average for the five years ended in 2019. Customer growth continues to be driven by a strong labor market recovery, and our Southeast territories are on track to reach pre-pandemic levels of employment later this year. Further supporting these trends, the economic development pipeline within our Southeast service territories remains robust. For example, the average number of job announcements was 22% higher and business investment in Georgia was 39% higher than average for the years leading up to the pandemic. Macro trends in e-commerce and electric transportation, combined with a diverse well-trained workforce and a low cost of living, have combined to drive major locations and expansions of distribution centers, data centers, manufacturing facilities, and headquarters into our service territories. Turning now to our expectations for 2022. Our adjusted earnings guidance for the year is $3.50 to $3.60 per share. The $3.55 midpoint represents a growth rate of approximately 7.5% from the midpoint of our original 2021 guidance range. In the first quarter of 2022, we estimate that we will earn $0.90 per share. Included in our guidance is a more normalized assumption for retail electric sales growth of 0% to 1%, although a continuation of recent trends could deliver upside to that assumption. We continue to see long-term adjusted EPS growth in the range of 5% to 7%, consistent with adjusted earnings in a range of $4 to $4.30 per share in 2024. With 90% of total projected earnings over the five-year planning horizon coming from our state-regulated utilities, our expected EPS trajectory has a solid foundation. Additionally, our history of constructive regulation, strong credit ratings, and disciplined O&M spending served to strengthen our outlook. Underlying our long-term adjusted EPS growth rate of 5% to 7% is a robust capital investment plan that continues to be driven by significant investment in our state-regulated businesses. Our base capital investment plan of approximately $41 billion, which excludes the capital required to complete Vogtle Units 3 and 4, supports our 2024 estimate for adjusted earnings per share of $4 to $4.30. This forecast represents a $2 billion increase in state-regulated utility investment for the common years 2022 through 2025 from our forecast a year ago. These increases in our forecast are the result of greater visibility into investments to upgrade our enterprise applications, serve major known customer expansions or additions, further improve our grid and protect our technology infrastructure as well as investments related to the transition of our fleet. We have long maintained a disciplined approach to capital forecasting within our state-regulated utility businesses. We don’t use placeholders, and we don’t include capital that isn’t expected to earn our allowed returns. The result of this approach is that our forecasts tend to grow, especially in the latter years as our visibility into customer growth increases, as regulatory processes unfold, as compliance obligations evolve, and as our long-term system planning is refined. We fully expect this trend to continue, including in relation to Georgia Power’s IRP. For example, neither the long-term hydro investment nor the proposed company-owned energy storage systems are fully reflected in our forecast. Additionally, none of the renewable additions proposed in the IRP are included due to both their time frames and the potential for selecting purchased resources. Furthermore, we continue to believe Southern Power has significant opportunity to continue growing through investments to facilitate fleet transitions and the growth in clean energy infrastructure broadly across the United States. Southern Power’s model has been distinctive since its beginning in the early 2000s, focused on long contracts with creditworthy counterparties and a risk-adjusted return profile that marries well with our overall value proposition. While we expect near-term opportunities to meet our criteria to be modest, we do believe opportunities will accelerate in future years. We have allocated up to $3 billion to Southern Power over the five-year plan, with approximately $250 million in 2022, $500 million in 2023, and $750 million annually for the remainder of the forecast. Again, these allocations of capital are not included in our base capital forecasts. In aggregate, our financial plan is anchored to our base capital forecast of $41 billion, and we believe upside potential exists in our state-regulated utility forecasts and our Southern Power allocation, representing spending of over $44 billion as part of our strategy to sustainably drive long-term growth in earnings and dividends. We also believe many of the same drivers for additional potential investment over the next five years could translate to investment opportunities beyond 2026 as we continue on our journey to net zero. And finally, we’ve included an updated three-year financing plan in the appendix to our slide deck today. This plan, which is consistent with our updated capital investment plans and the potential capital investment opportunities we’ve highlighted, continues to assume no equity need over our five-year plan horizon. Credit quality and strong investment-grade credit ratings remain a top priority. The expected improvement in our consolidated FFO to debt metrics equates to 200 to 300 basis points increase from 2021 to 2022 levels by 2024. We’ve included a slide in the appendix to highlight some of the drivers for this expected improvement. Combined with the expected reduction in construction risk over the next 12 to 18 months, we believe we are well positioned to support our credit quality objectives.

Tom Fanning, Chairman, President and CEO

Thanks, Dan. Southern Company strives to deliver superior risk-adjusted total shareholder returns, and I believe the plan that we’ve laid out supports that objective. Our customer and community-focused business model, our growing investments into our premier state-regulated utility franchises, the priority we place on credit quality, and our commitment and actions towards net zero all contribute towards making Southern Company a sustainable premier investment. A remarkable track record for dividends is another major contributor to that equation. For nearly three-quarters of a century, we have paid a quarterly dividend that is equal to or greater than the previous quarter, including dividend increases in each of the past 20 years. As we look ahead, assuming adjusted earnings within our estimated range of $4 to $4.30 per share in 2024, a payout ratio that is expected to be at or below 70%, and a sustainable long-term adjusted EPS growth rate of 5% to 7%, we believe that once Vogtle 3 and 4 are completed, our Board will have the opportunity to consider an increase in the rate of growth of dividends, further solidifying our long-term value proposition. Thank you for joining us this afternoon. Operator, we are now ready to take questions.

Operator, Operator

Thank you. Our first question is from Julien Dumoulin-Smith with Bank of America.

Julien Dumoulin-Smith, Analyst

Hey. I want to break down the incremental cost you mentioned. Regarding the $440 million in incremental costs, how much is attributed to the co-owners agreement? Could you provide a detailed breakdown? You mentioned $180 million from the sharing band. What percentage of the costs above that sharing band is related to warrants? Can you clarify the different components? Additionally, what was the initial project cost agreed upon with co-owners, and how were COVID-related costs determined? I would appreciate emphasis on that last point.

Dan Tucker, CFO

So, Julien, this is Dan. You are correct about the $440 million. Included in that is $180 million, which aligns with our agreement with co-owners, stipulating that Georgia Power covers a fixed percentage of incremental costs up to a certain limit. Consequently, $180 million is the maximum exposure under those terms. Beyond the specified thresholds, Georgia Power takes on the cost responsibility, which totals $260 million. This means Georgia Power is fully responsible for all costs exceeding the threshold. The $260 million is already included in the $480 million figure. This captures the portion attributable to the co-owners that we plan to tender. What was the second part of your question, Julien?

Julien Dumoulin-Smith, Analyst

COVID-related costs. I got a follow-up, more holistic as well.

Dan Tucker, CFO

Yes. So, as we’ve disclosed and we talked about last quarter, there is differing interpretations in this co-owner agreement as to exactly how those provisions work and exactly what the starting point works. So, rather than air those specific differences here on the call, let’s let those conversations take place in the proper form. But suffice it to say, the two differing points of view is the starting point for where the initial provisions kick in and how COVID costs ultimately adjust any cost before sharing.

Tom Fanning, Chairman, President and CEO

And Dan, one more point, I think, and please, I know you’ll correct me if I get this wrong, but we’ve associated the cost with tender in this estimate. We have not given any credit for the value of megawatts tendered. At the high end of the estimate, the amount of megawatts tendered, if everybody tendered, maybe around 75 to 80 megawatts. At the level in which we’ve estimated, we think it could be around 30.

Dan Tucker, CFO

That’s correct, Tom.

Julien Dumoulin-Smith, Analyst

And maybe can you speak a little bit to this process then, right? You talked about this March 8th date with the co-owners here. Any initial indications on where they stand? Obviously, this 90% is a high bar. But theoretically, they could vote to proceed and then related to that, they could tender the incremental cost to you, right? I just want to make sure I understand the kind of two separate parallel processes here.

Tom Fanning, Chairman, President and CEO

Yes. Julien, the way we would think about that is make them completely separate, okay? Well, the process is simple. By the contract that we entered into way back when, what was it, 2018, I guess, and I guess we signed it in early ‘19. But that kind of provision spoke to a potential outcome that was really onerous, like there was some cataclysmic problem, and we could all go our way. Our calculus was pretty simple. We are this close to loading fuel and ultimately getting Unit 3 on service and then ultimately Unit 4. To us, it was an easy decision to proceed.

Julien Dumoulin-Smith, Analyst

But the processes are separate. From their perspective, they could vote to proceed and then ultimately allocate their megawatts to you, as you just discussed a moment ago, right?

Dan Tucker, CFO

It’s completely separate processes. Yes.

Tom Fanning, Chairman, President and CEO

So, they could decide to proceed and separately they can tender.

Dan Tucker, CFO

That’s right. And there’s a 120-day to 180-day clock that we’ve disclosed in our 10-K as well that is really the time period to clarify tender or not. And the ultimate calculation, we alluded to megawatts, we alluded to dollars, all of that would not get buttoned up until Unit 4 was in service and all of the costs were known.

James Ward, Analyst

Hey. Tom, it’s actually James Ward on for Shar. Thank you for taking my question. Tom, at a high level, when we think about the IRPs and let’s say, Georgia Power specifically, as you were mentioning before, I understand that any storage or hydro improvement spend would be incremental. But what about transmission? Is there any IRP-related spend baked into the $41 billion base plan, or is anything that comes out of the IRP going to be incremental?

Dan Tucker, CFO

Hey, James, this is Dan. Yes, there is some transmission spending included in the forecast for the next five years, although it is modest. Remember that the plan involves retiring coal units around 2027 and 2028, and again in 2035. The timeline for planning, permitting, and constructing these transmission projects will span most of this forecast period, with significant spending occurring afterwards. Additionally, I want to clarify something regarding your question. There is some storage included in the capital forecast, but it represents only a small fraction of what was initially assumed in the IRP. The project that Georgia Power is seeking approval for is part of our capital plan.

Tom Fanning, Chairman, President and CEO

And the only other thing I’ll add is that you can proceed.

James Ward, Analyst

Sorry, please go ahead.

Tom Fanning, Chairman, President and CEO

I want to mention that as we consider retiring Bowen 3 and 4, we will need to address the demand in North Georgia. We have discussed that further analysis is necessary to determine the best way to replace that capacity. This could involve more solar energy, a combined cycle solution, or importing megawatts from the south to the north, which would require additional transmission. We have not completed that analysis yet.

James Ward, Analyst

Got you. Okay. That’s very helpful. I appreciate the color there. Switching gears to asset optimization, understanding that you do not need equity in the five-year plan. You’ve been very clear about that. But when you look at LDCs trading hands at nearly 2 times rate base, how do you think about the opportunity to sell an asset at that level and then reinvest the proceeds into decarbonization efforts at your electric utilities?

Tom Fanning, Chairman, President and CEO

We have consistently shown that we are both buyers and sellers in the M&A landscape. Our goal is to place assets in the hands of the most suitable owners, which is a fundamental principle for us. Our gas properties have notably contributed around 10% growth in earnings per share, mainly due to safety-oriented pipeline replacement initiatives. Since acquiring what is now Southern Company Gas, we have significantly surpassed our initial expectations for that acquisition. When evaluating capital allocation, especially regarding the potential sale of our Illinois asset in relation to reinvesting in our core businesses, we always consider what will best support our long-term growth while being mindful of risk. This approach will continue to guide our decisions.

Dan Tucker, CFO

Yes. And James, you made the point in your question. I mean, we don’t have an identified equity need in the forecast, and we think our LDCs are a great property.

Tom Fanning, Chairman, President and CEO

Yes. It would be purely a value play as opposed to a need.

James Ward, Analyst

And then one final one here just to follow on from Julien’s question earlier to clarify here. So given that the Vogtle co-owners are already protected by cost caps, and this is just at a high level here, is there any incentive or other reasons that we should be aware of or that might be worth keeping in mind for why Oglethorpe or MEAG would not want to proceed at this point since they have those cost caps in place? Just help us understand how they might be thinking.

Tom Fanning, Chairman, President and CEO

We’re not aware of any reason that exists like that.

Dan Tucker, CFO

They have to go through different processes, James.

Jeremy Tonet, Analyst

Could you provide some clarification on Vogtle? Specifically, have any of the missing inspection reports led to reworking any completed sections of the plant? I'm also interested to know if the NRC has provided any input on the ITACC issue. Lastly, do you have any thoughts on potential controls that could be implemented for Vogtle 4 to prevent similar issues in the future?

Tom Fanning, Chairman, President and CEO

Yes. I was recently in Augusta visiting with Glen Chick, who I believe is an exceptional manager of the site, along with Steve Kuczynski. We went through various systems at this stage and are working on the inspection report, focusing on what we consider the most challenging issues. I can't guarantee anything, but we are 30% complete, and so far, we haven't identified a need for any major rework. Of course, we will address anything that doesn't meet specifications or inspection requirements, but nothing extensive as you've indicated. What’s your second question?

Jeremy Tonet, Analyst

I was just curious, and that’s helpful. Thank you for that. Has the NRC provided any input on the ITACC issues?

Tom Fanning, Chairman, President and CEO

NRC. Yes. Thanks, Jeremy. Hey. The NRC’s posture, again, I think I say this pretty regularly. They’re a very tough requiring regulator, but we think they do a great job. And that’s the reason why the United States nuclear fleet is the envy of the world. Getting it right, as we so often say, will allow us to have an asset that will provide energy carbon-free, resilient for 60 to 80 years. So, we’re all in on getting it right. The NRC, likewise, is their primary focus. In other words, they’re not as concerned, I’m guessing, with schedule and cost. They want to make sure that whatever we build is as appropriate to nuclear safety standards as exist in America today. So, they support our efforts to find these things. And I think for the amount of ITACCs that we’ve already submitted, something like 275 or so, I think we’ve had very few problems with those ITACCs. That process has gone well, which says that once we get the work packages turned over and all the paper done in nuclear standard as it is supposed to be, we’ve had an enormous success rate in dealing with the NRC part of the equation.

Jeremy Tonet, Analyst

And then, just pivoting a bit towards SMRs, just wondering if you could discuss Southern’s involvement with SMRs? And where you see the tech going over the coming years? And do you think there will be support to rate base spend if the technology has proven up in the future? Just wondering if you’ve had conversations with commissioners or other stakeholders on if this could be a potential down the road?

Tom Fanning, Chairman, President and CEO

Yes. My discussions about future nuclear technologies haven't included talks with the states. That responsibility falls to Mark Crosswhite in Alabama, Chris Womack in Georgia, or Anthony Wilson in Mississippi. I have had conversations with the Department of Energy and others in the administration. Personally, I’m not as optimistic about small modular reactors (SMRs) as some others are, as there are substantial security and local opposition issues to consider with nuclear energy. I believe nuclear technology is best utilized at scale. However, SMRs do have a vital role in our nuclear future, particularly in specific areas like military bases, where they are already being used on submarines and aircraft carriers. This also enhances resilience. Our team is involved in SMR development, and while we've been asked to engage significantly, our focus has remained on completing Vogtle 3 and 4. On another note, we see great potential in the development of Generation IV reactors, particularly molten chloride salts, and we have collaborated with Bill Gates and his team on this. We've made considerable progress in the foundational science of these reactors, but the next stages of development will require significant investment. I've spoken with Secretary Granholm and Deputy Secretary Turk about the possibility of the DOE funding technology development, which could facilitate our partnership with the federal government to advance Gen IV reactors toward commercialization. In our planning, we anticipate these reactors could become viable options in the late 2030s, around 2035 to 2040. Economically, they will likely compete with carbon capture and storage technologies applied to combined cycle systems. Depending on the evolution of technology and costs, we will either keep utilizing combined cycles while capturing and sequestering carbon or pursue the new Gen IV reactors. However, these considerations will arise in the very late 2030s.

Jeremy Tonet, Analyst

Got it. Maybe just a real quick follow-up here. Curious on advanced nuclear. Thanks for your thoughts there. But as far as what technologies could make the most sense? Just wondering, light water, what Vogtle is doing versus molten salt or other technologies. Just wondering what you think of give and takes between them.

Tom Fanning, Chairman, President and CEO

Well, I think the obvious difference between kind of what we’re building at Vogtle and the so-called Gen IV reactors is this issue of the fuel and the core. Effectively, the Gen IV reactors have the characteristic that a meltdown is virtually impossible. And therefore, you need less containment structures and therefore less capital cost in order to put those units into play and have them be as safe as we expect them to be. That is the real big difference. It’s a capital cost difference associated with how the reactors’ meltdown characteristics could occur.

Angie Storozynski, Analyst

So, I have a question. I don’t think I’ve ever actually asked the question about Southern Power. So, looking at your past disclosure, and it seems like your gas plants are only hedged to about 80%, meaning the contracts are for about 80% of the output. We’ve seen quite an expansion of spark spreads across the country. I struggle with your regions. So, what, Georgia, Alabama, and North Carolina, and I’m not sure if that translates into higher dispatch or earnings of these assets. Again, if you could comment.

Tom Fanning, Chairman, President and CEO

Yes. Angie, I don’t know we’d have to run the numbers down with you. Our own math would say, they’re 92% contracted for about 10 years.

Dan Tucker, CFO

Yes. And importantly, Angie, so in front of the Georgia Public Service Commission, as part of the IRP, the vast majority of the gas PPAs that are in front of them for approval are Southern Power gas plants. And so, that’s going to extend those units' coverage for another 10 years.

Tom Fanning, Chairman, President and CEO

And recall that we follow the same kind of rubric in contracting our assets as opposed to merchant players. In that, we don’t take fuel risk. We earn a return on and return of capital and pass through the fuel and energy price.

Angie Storozynski, Analyst

Just moving on...

Tom Fanning, Chairman, President and CEO

I’ll just give you one more data point. We have 95% contracted through 2026 and 92% through 2031. That’s the detailed information.

Angie Storozynski, Analyst

Good. Now just going back to Vogtle. Yes, I reread the ownership agreement and the additional COVID-related costs. It seems we are still in the COVID era, so I assume some of these incremental costs related to the asset are still due to COVID. How does that factor into the discussion about the sharing agreement with the co-owners? Additionally, you haven't mentioned inflation, and I'm curious about its impact on the cost profile of this construction project.

Tom Fanning, Chairman, President and CEO

Yes. And thanks for that. This is my opinion I’m giving you as opposed to fact, I guess. But in my opinion, it is unquestionable. It is unreasonable to assume that COVID had no impact. And so, the real art of the deal is to figure out how much of that impact manifested itself. If you dial back on to those dark days when the first COVID thing hit and we were deciding whether to shut the project down or not, I think it’s very clear that we had to operate under a completely different operating regime on the site. Remember, we stood up a medical village. We did all sorts of things in order to continue this very important project. We have estimates that we provided to the Georgia Public Service Commission. I don’t think we’ve updated those recently. But certainly, I think any reasonable person would say that there have been COVID impacts on the site.

Dan Tucker, CFO

Yes. And I would just say in terms of this most recent cost increase, it’s certainly not the driver. It’s not a major driver. But Tom’s point, it’s logically an element of what’s going on.

Tom Fanning, Chairman, President and CEO

We included a chart in the appendix material that shows the significant spike during the December to January period due to Omicron. This clearly had an impact, particularly noticeable over the holidays when we typically expect higher absenteeism and other related issues. We experienced that effect as well.

Dan Tucker, CFO

But it’s fair to say, like everyone is, with every wave, with every impact, we are getting better at working in this environment, and it becomes increasingly less disruptive and thus less of a cost impact.

Tom Fanning, Chairman, President and CEO

And let me hit one other kind of controversial point, but we watch this like hawks. Recall, at one time, we had 9,000 people on site. And there was a lot of concern was this somehow COVID hotbed. Well, in fact, the data shows that our COVID experience is just about similar to the surrounding communities. We don’t have a different experience on the site than in the surrounding counties.

Angie Storozynski, Analyst

Yes. Thank you. How about inflation though? Is it already embedded in this additional cost estimate?

Tom Fanning, Chairman, President and CEO

Yes. But, Angie, most of the inflation-sensitive stuff is already procured. Our supply chains are already spoken for all the major equipment there. I suppose there would be some labor. We’re paying top decile right now. I suppose that could come up later, but it hasn’t been a big effect now.

Angie Storozynski, Analyst

Okay, and then for the last question. Looking at stronger earnings over the past couple of years, even with unfavorable weather, is load growth the primary factor, or is it just cost efficiencies? What is contributing to your performance being consistently at the upper end of your guidance despite these weather challenges?

Tom Fanning, Chairman, President and CEO

Dan has effectively managed the cost structures within the system, although his involvement was not direct; it was the people in the operating companies who contributed. The big surprise, which I mentioned earlier on Squawk Box and is supported by the data we've shared, is that we exceeded our residential estimates by 2.7%. We had anticipated a decline, but instead, we experienced an increase. This shift appears to be linked to changes in lifestyle. Our budget had assumed a return to the workplace, predicting a 2.2% drop in residential sales as more people returned to work. However, data from Southern Company shows that our former model indicated about 80% of the workforce was present daily, while only about 25% are now in the office every day, with 50% adopting a hybrid approach, coming in and out a few days a week. Approximately 25% remain virtual. Interestingly, residential sales were maintained at a level significantly higher than expected; we had anticipated a decline, but instead, they saw a slight increase. This unexpected uplift positively impacted our performance this year.

Dan Tucker, CFO

And just as you look at our forecast, look, we certainly haven’t assumed that that continues into the future because one year doesn’t make a trend, but we reasonably believe it might. So if you look at our forecast for residential sales for 2022, it actually reflects year-over-year negative. And that’s, frankly, mitigated by the assumption of strong customer growth. So, to your point, Angie, there’s certainly upside even in 2022 if we see these trends continue.

Tom Fanning, Chairman, President and CEO

The customer growth has been awfully attractive for us, so over 50,000 on the electric side, what was it 27,000, something like that on the gas side. So, we continue to do that. And we think that is kind of a function too of people being able to work remotely. And so, they tend to go to places that have low input costs, attractive place to live. Our economic development data shows that as well. So, I think some of the stuff, Dan, you talked about in the script, it just looks good, particularly for Georgia, but even Alabama is coming back, and we’re doing well. We have reason to be bullish about the long-term viability of our franchise.

Steve Fleishman, Analyst

So, I have two questions. First, regarding the Vogtle ITACC issues, I understand that you were aware of the importance of the paperwork and the documentation from the beginning, and that you have been diligently working on it. Can you provide us with some insight into what went wrong, considering this has been a primary focus for you since the start?

Tom Fanning, Chairman, President and CEO

Absolutely, Steve. I mentioned this earlier in the media, and it's still true. Every day, I think about Vogtle, from morning to night, even in the middle of the night. The team at the site has been particularly frustrated by the recent developments. When we last spoke, around late October or early November, everyone on-site was optimistic about moving forward with filing for 103(g) and loading fuel. However, as we dove into the final systems related to the last ITACC, we realized that while we had completed a significant amount of testing, we still had some issues to address. We had conducted physical and visual inspections, but upon preparing the necessary documentation, we found that many inspection reports were incomplete or missing. For instance, we need to verify the origin of every bolt used in the plant. If an inspection report doesn't confirm the provenance of a bolt, we must either replace it with a certified one or test it to ensure it meets our standards. This situation unfolded just as we were about to finalize the process before filing for 103(g). Discovering these issues required us to pause and conduct a thorough review of all inspection reports. This is frustrating, but it's necessary. This is the first plant we've built in 40 years, and it's also the first time we're dealing with nuclear documentation in that time. I wish we had identified these problems sooner, but we did not.

Steve Fleishman, Analyst

Okay. And then, totally separate topic. You were, I think, Tom, pretty accurate with caution about the build back better getting done last year. And I’m just curious how you’re feeling about maybe a climate-only type package getting done in Congress this year?

Tom Fanning, Chairman, President and CEO

Strictly my opinion, and I was in the meeting with the President and all that. You know what’s interesting, and I work with both sides of the aisle here. I think long-term, both parties agree that we should do some something. I think the methods of doing something, especially in light of the inflation signals we are seeing and potentially the national security issues we are seeing right now lend themselves to nothing happening for the rest of the year. I wish it would. I don’t think it will.

Paul Fremont, Analyst

I guess, my first question is going to be on turnovers. I think initially, you had talked about doing some of the turnovers, those that were necessary to load fuel and delaying other turnovers that you thought were less necessary. In light of the documentation issues, are you now looking to do all of the turnovers before you load fuel?

Tom Fanning, Chairman, President and CEO

No. I think there’s a set you have to turn over in order to get to 103(g). And there could be some others in between 103(g) and loading fuel. Let me give you a little bit of kind of where we are. So on Unit 3, now I’m doing big hunky thing. There’s a little less than 100 systems, 96 or so. You would split those into 162 subsystems, okay? So, there’s 11 total to go. And since our last call, we’ve gotten 5 of those turnovers complete. If I think about what’s remaining here, I would say that we have 3 to go for 103(g) and 6 to go on fuel load and 2 that we can complete after fuel load. They’re not necessary to the nuclear safety side of things. Was that helpful?

Paul Fremont, Analyst

Absolutely. In the past, I think you’ve estimated or you’ve put out estimates of COVID-related costs that went as high as 400. In the upcoming VCM 26 filing, are you going to update your estimate of COVID-related costs or not?

Tom Fanning, Chairman, President and CEO

Yes. The 400 to 444 was at 100% dollars, and our share of that was 160. I don’t have the current statistics on that. It hasn’t come up recently, so I believe it remains an open issue.

Dan Tucker, CFO

Yes. And there was some degree of estimating future impacts in the original number, and I think it’s been consistent with that.

Paul Fremont, Analyst

So, is that 440 the sort of the most recent number that you’ve put out publicly?

Tom Fanning, Chairman, President and CEO

Yes.

Dan Tucker, CFO

Yes. And so, you typically see us disclose it as 160 to 200, that’s our share. The 440 is 100% dollars. And just to be clear, no change reflected in VCM 26.

Paul Fremont, Analyst

You’re saying no change?

Dan Tucker, CFO

Correct.

Paul Fremont, Analyst

And then the numbers you put out for the cost sharing, potential write-offs are after-tax numbers. Can we get pretax numbers for those? The $480 million and the $440 million?

Dan Tucker, CFO

Yes. Those are pretax, Paul. Those are pretax.

Tom Fanning, Chairman, President and CEO

So, that adds $920 million, $686 million is the after-tax portion.

Dan Tucker, CFO

Yes. If you look at our deck on slide 6, there’s $920 million listed there, which is pretax. The total after tax for that is $686 million, and we’ve provided a breakdown of the components, but all of that breakdown is pretax.

Paul Fremont, Analyst

All that is pretax. Okay. And then, the highest number of ITACCs that you’ve done in a given month is 18. How confident are you in being able to achieve mid-30s type numbers once you complete the catch-up work on the documentation?

Tom Fanning, Chairman, President and CEO

Yes. Paul, what you have to understand and back where we were in October, November, we’re basically finishing the work, and what we found is the inspection reports were lacking. So, this work is ready to go. The table is set. Once we get the documentation done, we’ll be ready to send those things in. We feel good about the schedule. It’s not that we’re finishing construction.

Paul Fremont, Analyst

Are you completely finished with all of the construction or remediation work for Unit 3 that you identified in the fall?

Tom Fanning, Chairman, President and CEO

Yes. No, I just mentioned like an example of some of the remediation that might have to be done in order to conform with an inspection report. So, there’s other examples, but that’s it.

Paul Fremont, Analyst

Okay. For the last question, regarding the contracting of the Southern Power plants under the Georgia IRP, it seems that the net income you're generating is based on some book value calculation for the plan. If the Georgia IRP is adopted, would the earnings from those plants be expected to remain about the same, or would there be any significant changes?

Dan Tucker, CFO

I think the short answer, Paul, is no material change. These are market contracts. So, all of these contracts are being awarded to Southern Power under a competitive RFP process. And so, it’s going to reflect the current market for those senior contracts.

Tom Fanning, Chairman, President and CEO

Over the life of the contract, the internal rates of return would be similar. As we have indicated about the market overall, we have reduced our activity in the market elsewhere in the United States due to an oversupply, declining demand, and significant uncertainty. We noticed that profit margins were becoming very tight, so we decided to step back. However, for the projects we do engage in, we anticipate fairly consistent internal rates of return and return on equity. The return on equity is usually slightly better than what we observe in our regulated areas, reflecting the higher risk involved.

Paul Fremont, Analyst

Great. And then last question for me. The $686 million, should we assume either equity or asset sales to fund that?

Dan Tucker, CFO

Yes. So, again, I think I said in my prepared remarks, Paul, that we don’t see a need for equity in this five-year outlook. So, let me just hit that a little more broadly because I think it’s important. But absolutely, nothing has changed about our near-term or long-term objectives when it comes to credit quality. We’ve said kind of the last several months that as we move closer to completion of the project, any change in the cost or schedule will evaluate to see if equity is needed, essentially because we are getting so close to the end and because of all the proactive things that we did in response to other changes, and frankly, we did a little bit more than what was needed. So that has positioned us really well. And I want to also emphasize the improvement in the metrics that comes later on. I think we put a slide in the appendix that shows some of the component of the uplift in FFO that will occur in a ‘23, ‘24 time frame. That also is near enough in time horizon to give us comfort our overall financial profile.

Michael Lapides, Analyst

Commodity prices have risen significantly, and that's a challenge that goes beyond what any single team or individual can handle. Considering the impact of these rising commodity prices and the investments you're making, such as Vogtle, which aims to decrease commodity exposure, how should we evaluate the overall bill for your major businesses? Specifically, I'm thinking about the bills for customers in Alabama and Georgia Power, as well as Southern Company Gas. What can we expect regarding the total bill for customers as we move into 2022 and plan for 2023?

Tom Fanning, Chairman, President and CEO

Yes, it's quite interesting. When you examine the data, gas prices increased by 92% from 2020 to 2021, with averages of around $3.82 per million Btu compared to $1.99 the previous year. This is significant. Each of our jurisdictions has managed their unrecovered fuel balances fairly well. Georgia recently received an increase, which is beneficial but doesn't completely eliminate the balance. Meanwhile, Alabama used some of its earnings last year to completely eliminate its fuel balance. We are very aware of the burden on customers and manage that diligently. Overall, I believe we are in a strong position right now.

Michael Lapides, Analyst

Okay. I know you’ve done a lot of work over the years with the Federal Reserve in Atlanta. I'm curious about how you view the economic impact on your service territory, which is experiencing high growth compared to many of your peers. How do you consider this when discussing economic growth with people outside of the Company?

Tom Fanning, Chairman, President and CEO

Yes, very interesting points. Looking at the data, we see that while our industrial sales appear to be slowing down slightly, the momentum indicators suggest otherwise. In fact, two segments that saw a year-over-year decline were chemicals and paper, with the paper segment experiencing significant plant closures. If we exclude these closures, our industrial sales actually exceeded our expectations, which is quite positive. However, it's clear that inflation will eventually impact economic growth. Recently, I've been exploring some Federal Reserve insights, and it seems people have been feeling wealthier and are spending as if inflation hasn't affected them yet. However, it's hard to believe this will continue indefinitely. We've witnessed strong retail sales, but as inflation continues to take its toll, those sales are likely to decline. Consequently, a slowdown in the economy seems inevitable. The major question is when inflation will begin to decrease. Current indicators suggest that this could be a concern in 2023 if the supply chain stabilizes. There is currently a significant imbalance between supply and demand, which keeps prices elevated, and the lead time for procuring certain goods and services remains prolonged. We're looking at a situation where unwinding the supply chain and adapting to higher prices will likely lead to reduced spending and slower economic growth. Overall, the economy in the Southeast looks strong right now, but it’s hard to envision that it won't slow down over the next year or so.

Michael Lapides, Analyst

Got it. And then, one last one, just thinking about whether you do the gigawatt of storage at Georgia Power, obviously, that kind of depends on the end of the IRP process as well as if you were to wind up doing more incremental solar at either Georgia or Alabama Power or at Southern Power. How are you thinking about the renewable supply chain? Because there’s been lots of discussion and commentary. One or two of your peers have talked about supply chain becoming an issue for their non-regulated contracted solar business. I’m just curious what insights your team is getting in terms of the ability to procure things like panels or lithium-ion and the ability to actually install at the pace you’d like to install?

Dan Tucker, CFO

Yes. So Michael, this is Dan. So right now, we’re not in a big construction period. And so, we’re fortunate to not be experiencing as acutely as some of our peers right now, some of those plays. We’ve seen some. We are in the middle of the storage project out in California; we’ve seen some modest delays, but nothing that’s going to impact the project overall. That’s part of the supply chain and then really combined with I think how everyone is seeing the near-term markets is why we also have this ramp-up in our expectations for Southern Power. You heard me say we’ve allocated just the $250 million this year, $500 million the following year. And that’s really in recognition that there are projects actively on our radar screen today, and we’re a bit aspirational that those might come to fruition. But to the extent they don’t, I think what you’ll see us logically do is push those dollars out a little further in time and have opportunities later.

Tom Fanning, Chairman, President and CEO

There’s another conversation I’ve been having in D.C., whether it’s Secretary Granholm, who’s been terrific or Dep Sec, David Turk who is a terrific. As a matter of national security, as a matter of economic opportunity, one of the things that we need to do as the nation is resource these important supply chains domestically that will grow manufacturing, grow jobs, grow personal income. It’s a real winner. And I think some of the money that’s been put out in the incentives, whether it’s inside DOE right now or in the infrastructure bill elsewhere is to think about ways to promote the domestic supply of these things and really get it going. Now, when I say that, you’re talking five years from now. That isn’t going to happen immediately, but people are considering it. And I bet you, you would get broad bipartisan support for that strategy.

Michael Lapides, Analyst

Got it. Thank you, Tom. Thanks, Dan.

Tom Fanning, Chairman, President and CEO

You bet, Michael.

Operator, Operator

And that does conclude our question-and-answer session. Sir, are there any closing remarks?

Tom Fanning, Chairman, President and CEO

No. Thank you all for attending with us this afternoon. This is an important call. This is a frustrating time for us all. We were ready to go there; we thought kind of early this year. And now with this delay, it looks as if we’ll be end of the year for Unit 3. And we’ve allowed for an additional quarter, just given the uncertainty that we’ve seen in the past. We think these schedules align closer to what the staff and the commission has been kind of thinking about. But I can assure you we’re on the case. We all spend our time at the site. Those people are fixated on getting it right along with our partners, Bechtel. And when we build this thing, when we get it in service, we are right at the end of that process, it will be of the quality that is necessary in the United States nuclear industry. And we’re going to be proud of it for decades to come. Otherwise, the Company is performing as well as it possibly can, whether it’s our reliability, our resilience, our customer satisfaction, the way our employees feel, we were number one in military employer. Look, all of these data, they sound like kind of headlines and billboards and pablum. But I think they really speak to our dogma here at Southern that this is a company built to last, that these indicators are things that will prove that we are sustainable in our business model for years and years to come, and we’re very proud of that. And I want to thank all the thousands of employees at Southern for making that their part of their day, every day. It’s way beyond making, moving and selling. It’s all wound up and making sure that the communities we serve are better off because we’re there. We do that every day, and we will continue to do that. We look forward to getting the projects behind us and getting into 2024, and a financial position, the integrity of this company will be better than it ever has been, in my experience. So, thank you, and we’ll talk to you soon.

Operator, Operator

Thank you, sir. Ladies and gentlemen, this concludes the Southern Company fourth quarter 2021 earnings call. You may now disconnect.