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Southern Co
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Good afternoon. My name is Chris and I will be your conference operator today. At this time, 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. [Operator Instructions] I would now like to turn the call over to Mr. Scott Gammill, Investor Relations Director. Please go ahead, sir.
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.
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 employee 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 with 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 on line, 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 unnecessary 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 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 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, I’ll turn the call over now to you. Please take it away.
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 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 nonfuel 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 forecast 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 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 remains a top priority. The expected improvement in our consolidated FFO to debt metrics equates to 200 to 300 -- a 200 to 300 basis-point 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, I’ll turn the call back over to you.
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.
Thank you. [Operator Instructions] Our first question is from the line of Julien Dumoulin-Smith with Bank of America.
Hey. Listen, on the incremental cost, I just want to break this down, if you will. I mean it’s -- a lot of numbers flying around here, if you can. So, of the $440 million you talked about in incremental cost, how much of that is driven by the co-owners agreement? Can you break that down, right? So you’ve got $180 million from the sharing band. And then above that sharing band, what percentage of the cost is -- warrants you, if you will. So, can you kind of break down the sort of the successive pies, if you will? And then, of that, what was the base project cost that was agreed upon with co-owners? And what was the decision on COVID-related costs, right? Emphasis on that last piece, if you don’t mind.
So, Julien, this is Dan. So, the $440 million, you absolutely hit it right. Within there is $180 million. That $180 million is consistent with provisions in our agreement with co-owners, where Georgia Power bears a fixed percentage of incremental cost up to a certain point. And so, that $180 million is the maximum amount of exposure under those provisions. Above the thresholds for those provisions is where this option to tender cost responsibility to Georgia Power kicks in. And that number embedded in $440 million is $260 million. So, what that represents is Georgia Power’s assumption of bearing $260 million, said a different way, 100% of all the dollars above the threshold. So that $260 million represents -- their share is already captured in the $480 million. This is capturing the co-owners piece that is assumed in these numbers to be tendered. And what was the second part of your question, Julien?
COVID-related costs. I got a follow-up, more holistic as well.
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.
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.
That’s correct, Tom.
And we’ve given no credit to any value associated with those megawatts. We’ve talked about this on prior calls, the fact that you may have megawatts that’s going to be carbon-free, resilient for decades to come, we think it would have real value. We’ve reflected no value in any of these estimates.
And just to put a finer point on all this, Julien, we’ve included this $440 million, and that represents an estimate of an outcome. We do not, at this stage, have an agreement with our co-owners. We still have that difference of opinion.
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.
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.
But the processes are separate. And from their perspective, they could vote to proceed and then ultimately allocate -- tender their megawatts to you, as you just talked about a moment ago, right?
It’s completely separate processes. Yes.
So, they could decide to proceed and separately they can tender.
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.
Our next question is from the line of Shar Pourreza with Guggenheim. Please go ahead.
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?
Hey. James, this is Dan. So yes, there is transmission spend in there. In this forecast period for the five years, it is modest. Keep in mind that the plan includes retiring coal units in the ‘27, ‘28 time frame and then further again in 2035. So, the time line to construct and frankly, plan and permit these transmission projects is going to take the bulk of this forecast period and spending really occurs beyond. The other just detail, James, in the way you asked your question, I just want to make sure it’s clear. There is some storage reflected in the capital forecast, but not -- it’s a fraction of what has been assumed as a planning assumption in the IRP. It’s the one project that Georgia Power is specifically asking for approval of is in our capital plan.
And the only other thing I’ll add is that -- go ahead.
Sorry, please go ahead.
The only other thing I will add, I think I’ve done this before in kind of private conversations with you all one-on-one. But, as you start thinking about retiring Vogtle -- I mean -- I’m sorry, Bowen 3 and 4, there creates a need in North Georgia. And we’ve talked about that further study is required in order to evaluate how you replace that? Is that going to be more solar? Is it going to be a combined cycle? Is it going to be importing megawatts from the south to the north and therefore, incremental transmission. We just haven’t done all that work yet.
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?
Well, I think we demonstrated over the years that we’re both -- in the world of M&A, we’re both buyers and sellers. What we’re always seeking to do is put assets in the hands of the best owner. That’s just kind of our dogma, and I think we follow through on it. What’s interesting about our gas properties is that they have been able to contribute like 10% earnings per share growth, primarily focused on safety-related pipeline replacement programs. Since the acquisition of what is now Southern Company Gas, we have well exceeded our expectations on the acquisition. So, in order to think about cap allocation, as you do and we think about it all the time, selling something like our asset in Illinois relative to reinvesting in the core, we always have to consider what’s best for our long-term growth rate, what’s best on a risk-adjusted basis. We’ll continually do that.
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.
Yes. It would be purely a value play as opposed to a need.
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.
We’re not aware of any reason that exists like that.
Got it.
They have to go through different processes, James.
Our next question is from the line of Jeremy Tonet with JP Morgan. Please go ahead.
Maybe just coming back to Vogtle real quick here. Just trying to get a little bit more clarity. Have any of the missing inspection reports resulted in the need to rework completed sections of the plant? And also just curious if the NRC has kind of weighed in here on the ITACC issue? And any thoughts you have as far as what could be done in the future for Vogtle 4 to -- controls that could be implemented to avoid these issues?
Yes. Interestingly, I was just in Augusta visiting with Glen Chick, our -- I think he’s just a superlative manager of the site, along with Steve Kuczynski. And we actually went through different systems, at this point, and we are trying, we are efforting to begin with the inspection report fixed with what we believe are the toughest, hardest issues to deal with. I can’t guarantee that. But so far, with 30% complete, we haven’t found a need for any of that comprehensive rework. Certainly, as we see things that aren’t according to specs or per an inspection requirement, then we will fix it. But nothing comprehensive, as you’re suggesting. Second question?
Well, I was just curious, I guess -- that’s helpful there. Thank you for that. And the NRC, if they’ve kind of weighed in on the ITACC issues and any kind of...
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.
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?
Yes. My conversations with kind of future nuclear technologies have really been more -- I haven’t talked to the states at all. That really would be the realm of Mark Crosswhite in Alabama or Chris Womack in Georgia or Anthony Wilson in Mississippi. In my conversations with DOE, with folks in that or in the administration, I’ve had those conversations, too. In my opinion, I know other people are more bullish on SMRs than I am. But you still have to deal with enormous security issues. You still have to deal with kind of the NIMBY issues associated with nuclear. So, I’ve always felt that nuclear lends itself to scale, now. SMRs do absolutely have an important place in our nuclear future. My opinion, it would be in the niche areas like military bases. The military already does SMRs on submarines and aircraft carriers. So, it’s easy to conceive SMRs showing up on big nuclear installations. So, it also provides them a degree of resilience. I get that. We have been -- and we participate in SMRs, you should know that. So, our nuclear team and our R&D team are involved in the SMR process. We’ve actually been asked to get involved in a significant way in SMRs and given -- I don’t want to be distracted with anything other than getting Vogtle 3 and 4 done, we’ve really stayed away from that. On the other hand, we view great progress, potential with the so called Gen IV reactors, the molten chloride salts. We’ve worked with Bill Gates and his team on that. We are -- when you think about the R&D S curve, I think we’ve done a lot of work on the science, and I would call it the bench science of it and the very small kind of element of starting up that S curve. The next kind of big slugs of development on the Gen IV reactors will require hundreds of millions of dollars. I know I’ve talked to Secretary Granholm; Deputy Secretary, Turk, other folks that it would be great as the DOE is looking to put money to work, especially in the technology development area. This is a place where we could partner with the federal government and really move quickly up that S curve to make Gen IV reactors a commercial reality. In our own planning processes, they start to show up as an option, probably in the late 2030. So, let’s say, 2035 to 2040. And as an economic matter, they tend to compete with CCS-controlled combined cycle technologies. So depending on how the technology and cost expectations evolve, you will see us either continue with combined cycles and capturing the carbon and sequestering it or pursuing new Gen 4 reactors. But again, that’s an issue that’s going to show up in the very late 2030s.
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.
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 melt down characteristic could occur.
Our next question is from the line of Angie Storozynski with Seaport Global. Please go ahead.
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.
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.
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.
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.
Just moving on...
In fact, Angie, -- Angie, excuse me. I’ll just give you one more data point. 95% contracted through 2026, 92% through 2031. That’s the nerdy data.
Good. Now just going back to Vogtle. So, yes, I read -- I actually just reread the agreement -- the ownership agreement and that additional around about COVID-related costs. So, we’re still seemingly in the COVID era. So, I’m assuming that some of this incremental cost related to the asset is still related to COVID and how does that come into this whole discussion about the sharing agreement with the co-owners? And then, secondly, we haven’t -- you haven’t mentioned inflation. And so, I’m just wondering, how is that impacting the cost profile of this construction project?
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 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.
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.
And I think we provided the chart in the appendix material, you can see even this most recent whatever this -- Omicron, it had an enormous spike in the December to January time frame. So, certainly, it had an impact. We saw it in -- especially over the holidays, we always expect to see more absenteeism and a variety of other things. We certainly saw it there as well.
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.
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 hot bed. 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.
Yes. Thank you. How about inflation though? Is it already embedded in this additional cost estimate?
Yes. But, Angie, most of the inflation sensitive stuff is already procured. Our supply chains are already spoken for all the major equipments 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.
Okay. And then, the last question. So, looking on stronger earnings where -- I mean, have been actually over the last couple of years. Now, despite unfavorable weather, so is the load growth the main driver, or is it just cost efficiencies? What is putting you above the high end of your guidance almost consistently despite unfavorable weather?
Well, Dan’s done a great job managing the cost structures of the system. Actually, Dan didn’t have anything to do with it all, but people in the operating companies did. But, I’ll tell you the big surprise. I said this on Squawk Box this morning and the data we’ve provided you, shows it. We beat our residential estimates by 2.7%. In other words, we were projecting that to be down, and it was actually up. And we think that that is due to a change in lifestyle. I think we budgeted as if we thought there was this return to work and therefore, we would see like a 2.2% reduction in residential sales because people are showing up at work. Well, in fact, our own data, if you look at Southern Company’s experience, our old model was about 80% of the people came to work every day. I think -- and they were 20% that were virtual, probably call centers. Now, we’re seeing about only 25% are here every day with about 50% hybrid. They’re coming in and out a few days a week, some more, some less, and then about 25% virtual. What’s interesting about that is the sales in the residential sector were sustained at a much higher level than what we thought. We thought they’d drop off. They actually increased a bit. That uplift really helped us this year.
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 assumption of strong customer growth. So, to your point, Angie, there’s certainly upside even in 2022 if we see these trends continue.
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 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.
Our next question is from the line of Steve Fleishman with Wolfe Research. Please go ahead.
So, two questions. First, just on the Vogtle ITACC issues. So, I know you knew all along that the paperwork and that the trail of all that was super important, and you’ve been doing all the work. So, kind of -- could you give us a little flavor of just what has gone wrong here because obviously, it’s something that you were very focused on from the beginning?
100%, Steve. And I think I said this in media earlier, but it’s true. I get up every morning throughout the day, in the middle of the night, think about Vogtle and what we can do and all that. And I was, the folks at the site have been particularly frustrated at this recent development. When we left you on the call and I guess it was late October, early November, everybody, the site too, was very bullish on the fact that man, here we go, we’re getting ready to file for 103(g) and load fuel in the whole bit. And when we started getting into the final systems related to the final ITACC, so right, we’ve done 100 and -- I mean, we’ve done 275, we had 123 left. We had already done in order to complete these tests and a lot of this equipment is already operated within the testing regimes. We had done physical and visual inspections, but what we found when we got ready to turn over these systems for the paper, and important part of the paper are these inspection reports. And we found in many cases, they were just either incomplete or missing. Let me give you an example. But, this is an example. This is relevant. For every bolt in that plant theoretically, we would have to ascertain certificate the provenance of that bolt. In other words, we’d have to prove that we know that the metallurgy worked and where it came from and everything else to the extent an inspection report did not account for the provenance of a bolt, we had to either take the bolt out and put in the bolt that was certified or take the bolt out and test it to make sure that it met our standards. This is at the very end of the process for the very final equipment and systems that were related to the turnover before we filed for 103(g). This is at the tail end of the process. And when we found this out, we just had to go stop, we’ve got to do a complete review of all of these inspection reports. And that’s what you see right now. I am frustrated about it, but it is something we have to do. We talk about this is the first plant we’ve constructed in 40 years. Well, this is the first nuclear documentation we’ve had to do in 40 years. I wish we had found it sooner. We just didn’t.
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?
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.
Our next question is from the line of Paul Fremont with Mizuho. Please go ahead.
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?
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?
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?
Yes. The 400 -- 444 was at 100% dollars, our share of that was 160. I don’t know the stats of that. It didn’t come up recently. So, I think it’s still an open issue.
Yes. And there was some degree of estimating future impacts in the original number, and I think it’s been consistent with that.
Yes. We’ve not provided…
So, is that 440 the sort of the most recent number that you’ve put out publicly?
Yes.
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.
You’re saying no change?
Correct.
In VCM 26?
We just haven’t created an addition based on the latest Omicron effects. I mean, clearly, there were, we just haven’t updated the estimate.
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?
Yes. Those are pretax, Paul. Those are pretax.
So, that adds $920 million, $686 million is the after-tax portion.
Yes. If you look at our deck on slide 6, there’s $920 million listed there. That’s pretax. Total after tax for that is $686 million, and then we’ve broken down the components. But all those -- all that breakdown is pretax.
All that is pretax. Okay. And then, the most -- the highest number of ITACCs that you’ve done in a given month, I think, is 18. How confident are you in being able to sort of do mid-30s type numbers once you’re able to sort of do the catch-up work on the documentation?
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.
And in terms of the -- so are you completely done with all of the construction or the remediation work for Unit 3 that you had identified sort of in the fall?
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.
Okay. And then, maybe the last question. The contracting of the Southern Power plants under the Georgia IRP, it sounds like the net income that you’re earning is based on some book value calculation on the plan. So, would the Georgia IRP, if it were adopted, at least with respect to the Southern Power plants, likely the earnings from those plants would remain roughly the same, or would there be any type of sort of -- would there be any material change?
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.
Over the life of the contract, the IRRs would be similar. And when you think about -- what we have said about the market broadly is that we’ve kind of pulled back on the market. This is kind of elsewhere in the United States because there was so much supply and the demand was waning and there was a lot of uncertainty. We saw the margins really getting tight and so we didn’t play. But for the things we do that we ultimately will sign up for pretty consistent IRRs and pretty consistent ROEs. The ROEs typically are a wee bit better than what we would find in our regulated jurisdiction, reflective of a little bit of the higher risk.
Great. And then last question for me. The $686 million, should we assume either equity or asset sales to fund that?
Yes. So, again, we -- 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 with our overall financial profile.
Our next question is from the line of Michael Lapides with Goldman Sachs.
Commodity prices are up across the board, obviously, that’s a bigger issue than any one team or person can manage. How should we think about -- given what’s happened to commodity prices, and given the investment you’re making, some of which like Vogtle will help reduce the commodity exposure. How should we just think about the bill across your biggest businesses? So I’m thinking in Alabama and Georgia Power, I’m thinking about the bill and for Southern Company Gas. Like what’s happening to the total bill for the customer as we enter 2022 and think about ‘23 as well?
Yes. It’s interesting stuff, man. When you look at the data, gas prices increased ‘21 versus ‘20, 92%, like we averaged, I think, $3.82 per million Btu versus $1.99 a year ago. So that’s kind of a big deal. Now each of our jurisdictions have managed, I think, well, their unrecovered fuel balances. Georgia just got an increase, doesn’t wipe it out completely, but it did really well. Alabama used some of its earnings otherwise in 2021 to completely wipe out its fuel balance. So, one of the things we are very mindful of -- and I appreciate the way you phrased the question. We are very mindful of burden to customers, and we manage that like hawks. I think we’re in really good shape right now.
Okay. I know you’ve done a lot of work over the years with the Federal Reserve in Atlanta. Just curious how -- when you think about just the economic impact to the service territory and you’ve got a high-growth service territory relative to a lot of your peers. How does this kind of -- how do you think about it when you meet with folks outside of the Company about what it means for economic growth?
Yes. Very interesting stuff. If you look at the data, we’re seeing -- even our industrial numbers, I said this on Squawk today, while it will show that it looks like things are slowing down a bit on the industrial sales side, the momentum numbers would tell you that and potentially the first derivative. In fact, two of the segments that underperformed or decreased year-over-year were chemicals and paper, but the paper was newsprint had a big closure of a plant there. The chemicals was a -- chemical plant, caustic soda and chlorine, that closed as well. If you wipe away those two big plant closures, our industrial sales actually were better than what we expected again. So pretty good stuff. Now, it is very clear that inflation will eventually eat into the growth in the economy. I was kind of visiting with some of the Fed work and all that here recently, you’re familiar with the old permanent income hypothesis. I think people have felt wealthier lately, and people are still spending as if inflation hasn’t visited them yet. It is inconceivable though that that won’t catch up at some point. You saw these hot retail sales. My sense is as inflation effects continue that those sales will start to wane. So, there will be a slowdown in the economy. Now, the real $50,000 question is, when does inflation start to recede a bit? A lot of stuff right now says that’s a 2023 issue that we could start to see inflation getting back to a more normal level. I think the underlying presumption in that one is that the supply chain works itself out. Right now, we’ve had such an imbalance in supply and demand that prices invariably are high. And for the lead time to procure certain goods and services, it is really sticky right now. So, the big swings are supply chain unwinding and getting back to normal, people adjusting to higher prices and therefore, reduced spending and therefore, reduced heat in the economy. Those are all the factors that I think will go into this point. For now, the economy looks really good in the Southeast, but it’s inconceivable to me that it won’t slow down a bit over the next year or so.
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 other, and the ability to actually install at the pace you’d like to install?
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.
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 a 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.
Got it. Thank you, Tom. Thanks, Dan.
You bet, Michael.
And that does conclude our question-and-answer session. Sir, are there any closing remarks?
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 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.
Thank you, sir. Ladies and gentlemen, this concludes the Southern Company fourth quarter 2021 earnings call. You may now disconnect.